ITEM 1. BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren was formed in 1997 by the merger of UE and CIPSCO, the former parent company of CIPS. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary asset is the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP. Ameren’s subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for a more detailed description of the Ameren Companies and the development of their businesses.
The following table presents our total employees at December 31, 2004:
(a) Total for Ameren includes Ameren Registrant and non-Registrant subsidiaries.
The IBEW, the IUOE, the NCF&O, and the Laborers and Gas Fitters labor unions represent approximately 63% of Ameren’s total employees, and 73%, 68%, 67%, 63%, 63% and 70% of the employees of UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. An IBEW contract representing a portion of UE workers expires in 2006. Contracts with the Laborers and Gas Fitters labor unions that represent a portion of IP employees also expire in 2006. IP is in discussions to have those agreements extended. The remaining agreements covering UE, CIPS, Genco, CILCORP, CILCO and IP employees expire in 2007.
For additional information regarding our business operations and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report. For additional information regarding reporting segments, see Note 18 - Segment Information to our financial statements under Part II, Item 8, of this report.
RATES AND REGULATION
Rates
Rates that UE, CIPS, CILCO and IP are allowed to charge for their services are the single most important item influencing their and Ameren’s consolidated results of operations, financial position, and liquidity. The rates charged to UE, CIPS, CILCO and IP customers are determined by governmental organizations. Decisions by these organizations are influenced by many factors, including the cost of providing service, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views. Decisions made by these organizations regarding rates could have a material impact on the results of operations, financial position and liquidity of UE, CIPS, CILCORP, CILCO, IP and Ameren on a consolidated basis.
UE, CIPS, CILCO and IP are subject to regulation by the ICC. UE is also subject to regulation by the MoPSC, as to rates, service, issuance of equity securities, issuance of debt having a maturity of more than 12 months, mergers, affiliate transactions, and various other matters. Genco is not subject to regulation by the ICC or the MoPSC. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for information regarding UE’s proposed discontinuance of its utility operations subject to ICC
jurisdiction by transferring its Illinois-based electric and natural gas transmission and distribution business to CIPS.
UE, CIPS, Genco, CILCO and IP are also subject to regulation by the FERC as to their ability to charge market-based rates in connection with the wholesale sale of energy and transmission in interstate commerce, mergers, affiliate transactions, and various other matters. Less than 5% of our electric revenues relate to transmission revenues regulated by the FERC. Issuance of short-term and long-term debt by Genco is subject to approval by the FERC.
The following table presents the approximate percentage of electric operating revenues subject to regulation by the MoPSC and the ICC for each of the Ameren Companies for the year ended December 31, 2004:
(a) Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
The following table presents the approximate percentage of gas operating revenues subject to regulation by the MoPSC and the ICC for each of the Ameren Companies for the year ended December 31, 2004:
(a) Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
If certain criteria are met, UE’s, CIPS’, CILCO’s and IP’s electric and gas rates may be adjusted without the necessity of a traditional rate proceeding. PGA clauses allow for prudently incurred natural gas purchase costs to be passed directly to the consumer in Missouri and Illinois. There is no similar provision that would allow regulated electric operations fuel or purchased power costs to pass directly to the consumer. Environmental adjustment rate riders authorized by the ICC permit the recovery of prudently incurred MGP remediation and litigation costs from UE’s, CIPS’, CILCO’s and IP’s Illinois electric and natural gas utility customers. As a part of the order approving Ameren’s acquisition of IP, the ICC authorized IP to implement a tariff rider to recover 90% of the costs of asbestos-related litigation claims in excess of $20 million from its electric utility customers, subject to certain terms, beginning in 2007. MoPSC natural gas pipeline replacement cost clauses allow the recovery of infrastructure replacement costs from gas utility customers. However, UE agreed to not seek recovery under these clauses before January 1, 2006, in conjunction with its 2003 Missouri gas rate case settlement.
For further information on rate matters, including UE’s 2002 Missouri electric rate case settlement, UE’s 2004 Missouri gas rate case settlement, IP’s 2004 pending gas rate case, and the ending of rate moratoriums in Missouri and Illinois in 2006, see Results of Operations in Management’s Dis-cussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
General Regulatory Matters
As a holding company registered with the SEC under the PUHCA, Ameren is subject to the regulatory provisions of the PUHCA, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, affiliate transactions, financial reporting requirements, the services performed by Ameren Services and AFS, and the activities of certain other subsidi-aries. Issuance of common stock and short-term and long-term debt and other securities by Ameren and CILCORP and issuance of debt having a maturity of 12 months or less by UE, CIPS, CILCO and IP are subject to approval by the SEC under the PUHCA.
Genco is certified by the FERC as an “exempt wholesale generator” under the Energy Policy Act of 1992; Genco is not a “public utility company” under the PUHCA. As an exempt wholesale generator, Genco is exempt from most of the provisions of the PUHCA that otherwise would apply to it as a subsidiary of a registered holding company. Issuance of securities by Genco is not subject to approval by the SEC under the PUHCA. The SEC may impose limitations on Ameren in connection with its financing for the purpose of investing in exempt wholesale generators and foreign utility companies if Ameren’s aggregate investment in those activities exceeds 50% of its consolidated retained earnings. At December 31, 2004, Ameren’s aggregate invest-ment in exempt wholesale generators was 32% of its consolidated retained earnings. Ameren has no investment in foreign utility companies.
Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its Facility Operating License expires on October 18, 2024. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydro plant, as licensed projects under the Federal Power Act, are subject to the FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for the Osage plant expires on February 28, 2006, and the license for the Taum Sauk plant expires on June 30, 2010. In November
2004, the FERC formally accepted UE’s February 2004 license renewal application and solicited terms and conditions from the U.S. Department of Interior and various state agencies to renew the license for its Osage hydroelectric plant for an additional 50-year term. UE’s Keokuk plant and dam located in the Mississippi River between Hamilton, Illinois and Keokuk, Iowa, are operated under authority, unlimited in time, granted by an Act of Congress in 1905.
For information on regulatory matters, see Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
Environmental Matters
Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment, including the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including stan-dards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on us, including the imposition of criminal or civil liability by regulatory agencies or civil fines and liability to private parties, and the required expenditure of funds to bring us into compliance. We believe that we are in material compliance with existing statutes and regulations.
For additional discussion of environmental matters, including potential NOx, SO2, and mercury emission reduction requirements, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
SUPPLY FOR ELECTRIC POWER
During 2004, the Ameren Companies’ peak demand from retail and wholesale customers was 15,991 megawatts and the peak capability to deliver power from owned generation and power supply agreements was 19,439 megawatts. Forecasted peak demand from retail and wholesale customers for 2005 is 17,441 megawatts. Ameren-owned generation and purchased power are used to meet the energy needs of our customers with a 15% reserve margin. Factors that could cause us to purchase power include, among other things, absence of sufficient owned generation, generating plant outages, extreme weather conditions, and the availability of power at a cost lower than our cost of generating it.
The acquisition of IP included IP’s rate-regulated electric and gas transmission and distribution business. IP owns no significant generation assets; it obtains almost all of the electricity that it supplies to retail customers through short-term and long-term power purchase agreements. For additional information on IP’s power purchase agreements, see Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report.
The following table presents the source of electric generation, excluding purchased power, used for the years ended December 31, 2004, 2003 and 2002:
(a) Excludes amount for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries and
intercompany eliminations.
(b) Less than 1% of total fuel supply.
(c) 2002 amounts represent predessor information.
The following table presents the cost of fuels for electric generation for the years ended December 31, 2004, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003.
(b) The fuel cost for natural gas represents the actual cost of natural gas and variable costs for transportation, storage, balancing, and fuel losses for delivery to the plant. In
addition, the fixed costs for firm transportation and firm storage capacity are included to calculate a “fully loaded” fuel cost for the generating facilities.
(c) Represents all costs for fuels utilized in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, and handling.
(d) amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
Coal
UE, Genco and CILCO have agreements in place for the purchase of coal to supply electric generating facilities through 2010. Coal supply agreements typically have an initial term of five years, with approximately 20% of the contracts expiring annually. As of December 31, 2004, almost 92% of UE’s, Genco’s and CILCO’s expected 2005 coal usage was under contract, and approximately 58% of the expected coal usage for 2006 to 2009 was under contract. Ameren burned 38 million tons of coal in 2004.
UE, Genco and CILCO have a policy of maintaining coal inventory consistent with their historical usage. Inventory levels may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. The following table presents the number of days supply of coal in inventory as of December 31, 2004 and 2003:
Nuclear
UE has agreements or inventories to fulfill its Callaway nuclear plant needs for uranium and conversion, enrichment and fabrication services through 2006. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel. UE is a member of Fuelco, which provides benefits to UE and Fuelco’s other members in all aspects of the nuclear fuel cycle. UE is able to combine its fuel needs with the other members, and thereby increase its purchasing power and the opportunities for volume discount pricing. In addition, Fuelco is able to pursue sources of supply that would not otherwise be available to UE alone. Diversification of supply is enhanced and security of supply is better managed collectively. In fuel fabrication, UE is able to draw upon the expertise of the other members to enhance fuel performance. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling took place in May and June 2004; the next refueling is scheduled for September 2005.
Natural Gas Supply for Power Generation
Our natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to our generating units. We do this by optimizing transportation and storage options; by minimizing cost and price risk through various supply and price hedging agreements that allow us to maintain access to multiple gas pools, supply basins, and storage; and by reducing the impact of price volatility. For 2005, 96% of the estimated required natural gas supply for generation was under contract; 35% of the required gas supply was hedged for price risk as of December 31, 2004.
Purchased Power
We believe that we can obtain enough purchased power to meet future needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected. The Ameren transmission system has a minimum of 18 direct connections to other control areas, which allow access to numerous sources of supply. UE, CIPS, CILCO and IP are members of the MISO. Effective April 1, 2005, the MISO is expected to begin operating a newly designed market that is expected to offer improved transparency of power pricing and efficiency in generation dispatch.
Through the end of 2006, CIPS, CILCO and IP have contracts in place to supply almost all of their power needs. For a description of IP’s primary power supply contract with Dynegy and a description of CIPS’ and CILCO’s power supply contracts with affiliates, see Note 2 - Acquisitions and Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report.
On December 31, 2006, the current Illinois electric rate freeze expires, as do the supply contracts for generation to serve the power requirements of CIPS, CILCO and IP. Prior to December 31, 2006, determinations must be made as to how all Illinois electric distribution companies will procure their generation needs and how they will set future rates for the generation components and delivery service components of customer rates.
During 2004, the ICC held workshops to get input from interested parties on the framework to be used for retail electric rate determination and generation procurement after the current Illinois electric rate freeze and supply contracts expire on December 31, 2006. A report issued by the ICC in late 2004, outlined a process that received strong support in the workshops: It would have CIPS, CILCO and IP procure power through an auction monitored by the ICC. The form of power supply would meet the full requirements of the utility, and the risk of fluctuations in power requirements would be borne by the supplier. In addition, the report noted that many stakeholders, including Ameren, supported a process whereby the price of power resulting from the auction would be the price used to determine the generation component of customer rates. This price of power would be charged to customers by a pass-through mechanism. With regard to the delivery service component of customer rates, it is expected that all Illinois delivery service companies will file rate cases, at which time the delivery service component of customer rates will be updated. Genco and AERG would probably participate in the auction, but there may be a limit imposed by the ICC on the maximum amount of power they could supply CIPS, CILCO and IP. In February 2005, CIPS, CILCO and IP filed with the ICC: A proposed format for the generation procurement auction, a rate mechanism to pass generation costs through to customers, and a process to update the delivery service portion of rates, among other things. These proposals are subject to review and approval by the ICC within 11 months of the filings. In addition, the Illinois legislature began hearings in February 2005 regarding the framework for retail rate determination and generation procurement. We cannot predict what actions, if any, the Illinois legislature will take, or whether the ICC will approve our proposals for generation procurement or electric rate determination.
NATURAL GAS SUPPLY FOR DISTRIBUTION
UE, CIPS, CILCO and IP are responsible for the purchase and delivery of natural gas to their gas utility customers. UE, CIPS, CILCO and IP develop and manage a portfolio of gas supply resources, including firm gas supply under term agreements with producers, interstate and intrastate firm transportation capacity, firm storage capacity leased from interstate pipelines, and on-system storage facilities to maintain gas deliveries to our customers throughout the year and especially during periods of peak demand. UE, CIPS, CILCO and IP primarily use the Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, Mississippi River Transmission Corporation, and Texas Eastern Transmission Corporation interstate pipeline systems for transportation of natural gas to our systems. In addition to physical transactions, financial instruments, including the NYMEX futures market and OTC financial markets are used to hedge the price paid for natural gas. Prudently incurred natural gas purchase costs are passed on to UE, CIPS, CILCO and IP gas customers in Illinois and Missouri dollar-for-dollar under PGA clauses, subject to review by the ICC and the MoPSC.
For additional information on our fuel and purchased power supply, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation, and Changing Prices under Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report, and Note 1 - Summary of Significant Accounting Policies, Note 9 - Derivative Financial Instruments, Note 14 - Related Party Transactions, Note 15 - Commitments and Contingencies, and Note 16 - Callaway Nuclear Plant to our financial statements under Part II, Item 8, of this report.
INDUSTRY ISSUES
We are facing issues common to the electric and gas utility industry. These issues include:
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the potential for more intense competition in generation and supply;
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the potential for changes in the structure of regulation;
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changes in the structure of the industry as a result of changes in federal and state laws, including the
formation of non-rate-regulated generating entities and regional transmission organizations;
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fluctuations in power prices due to the balance of supply and demand and commodity prices;
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continually developing and complex environmental laws, regulations and issues, including proposed new air-quality standards;
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public concern about the siting of new facilities;
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construction of new power generating facilities;
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proposals for programs to encourage energy efficiency and renewable sources of power;
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public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste;
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consolidation of electric and gas companies; and
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global climate issues.
We are monitoring these issues. We are unable to predict at this time what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 3 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
RISK FACTORS
Ameren may not be able to integrate IP successfully into its other businesses or achieve the benefits it anticipates.
Ameren cannot ensure that it will be able to integrate IP successfully with its other businesses. The integration of IP with its other businesses will present significant challenges; Ameren may not be able to operate the combined company as effectively as expected. Ameren may also fail to achieve the anticipated benefits of the acquisition as quickly or as cost- effectively as anticipated; it may not be able to achieve those benefits at all. Ameren expects that this acquisition will be accretive to earnings per share in the first two years. This expectation is based on important assumptions, which may be incorrect, including assumptions related to expected financing arrangements, regulatory treatment, interest rates, market prices for power, and synergies. As a result, if Ameren is unable to integrate its businesses effectively or to achieve the benefits anticipated, its results of operations, financial position, and liquidity may be materially adversely affected.
The electric and gas rates that certain Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006. These “rate freezes,” along with other actions of regulators that can significantly affect our earnings, liquidity, and business activities, are largely outside our control.
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, and liquidity of the Ameren Companies. Our industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental organizations outside of our control, including the MoPSC, the ICC, and the FERC. We are also subject to regulation by the SEC under the PUHCA. Decisions made by these regulators could have a material impact on our results of operations, financial position, and liquidity.
As a part of the settlement of UE’s Missouri electric rate case in 2002, UE is subject to a rate moratorium that prohibits changes in its electric rates in Missouri before July 1, 2006, subject to limited statutory and other exceptions. In addition, a provision of the Illinois legislation related to the restructuring of the Illinois electric industry put a rate freeze into effect in Illinois until January 1, 2007, for UE, CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective Illinois jurisdiction in excess of certain levels be refunded to UE’s, CIPS’, CILCO’s and IP’s Illinois customers through 2006. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC on January 13, 2004, UE agreed to a rate moratorium. It will make no changes in its gas delivery rates prior to July 1, 2006, subject to certain exceptions. Also, in the order approving Ameren’s acquisition of IP, the ICC prohibited IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP’s pending request for a gas delivery rate increase. The ICC conducted workshops seeking input from interested parties on the framework to be used for retail rate determination and for generation procurement by customers after the current Illinois rate freeze and supply contracts end in 2006.
As a part of the settlement of UE’s Missouri electric rate case in 2002, UE also undertook to use commercially reasonable efforts to make critical energy infrastructure investments of $2.25 billion to $2.75 billion from January 1, 2002 through June 30, 2006, for among other things, the addition of more than 700 megawatts of new generation capacity. UE added 240 megawatts of CTs in 2002. UE is also seeking to acquire 550 megawatts of CTs from Genco in 2005. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership, in conjunction with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate moratorium in Missouri and UE’s, CIPS’, CILCO’s and IP’s rate freezes mean that capital expenditures will not become recoverable in rates, and will not earn a return, before July 1, 2006, for UE and January 1, 2007, for CIPS, CILCO and IP. Therefore, undertakings with respect to energy infrastructure investments and funding new programs, coupled with the rate reductions and rate moratoriums, could result in increased financing requirements for UE, CIPS, CILCO and IP and thus have a material impact on our results of operations, financial position, and liquidity.
The Ameren Companies do not have in either Missouri or Illinois a fuel adjustment clause for their electric operations that would allow them to recover from customers costs for purchased power or increased fuel used for generation. Therefore, to the extent that we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent that fuel for our electric generating facilities and power must be purchased on the open market in order for us to serve our customers.
Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, the FERC has been mandating changes in the regulatory framework for transmission-owning public utilities such as UE, CIPS, CILCO and IP. In Missouri, restructuring bills have been introduced in the past, but no legislation has been passed. In Illinois, which since the acquisition of IP, supplies over 50% of Ameren’s electric revenues, the Illinois Customer Choice Law provides for electric utility restructuring and retail competition.
Principally because of rate reductions and rate moratoriums that affect certain Ameren Companies, increased costs and investments have resulted in decreased returns in our distribution utility businesses. In 2005, Ameren will begin the process for preparing and filing proposals for utility rate adjustments in Illinois and Missouri to take effect after the expiration of the applicable rate moratoriums.
We are not able to predict what rate treatment certain Ameren Companies will receive after the rate moratoriums expire in Missouri and Illinois. There are currently activities under way in Illinois to determine the framework for retail electric rate determination and generation procurement after the current Illinois electric rate freeze and supply contracts expire in 2006. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report. In response to competitive, economic, political, legislative and regulatory pressures, we may be subject to further rate moratoriums, rate refunds, or rate reductions, any and all of which could have a significant adverse affect on our results of operations, financial position, and liquidity.
Increased federal and state environmental regulation could require UE, Genco and CILCO to incur large capital expenditures and increase operating costs.
Approximately 65% of Ameren’s generating capacity is coal-fired. The balance is nuclear, gas-fired, hydro, and oil-fired. The EPA issued proposed regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. These new rules, if adopted, would require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. The EPA has delayed finalization of the proposed rules so that Congress may first consider the Bush Administration’s Clear Skies legislation. The Clear Skies legislation calls for roughly 70% cuts in NOx, SO2, and mercury emissions, phased in through 2018. Clear Skies legislation will probably be introduced in the U.S. Congress and debated in 2005. Preliminary estimates of capital costs, based on Ameren systems’ current technology, to comply with the EPA proposed SO2, NOx , and mercury emission regulations, range from $1.4 billion to $1.9 billion by 2015.
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. Coal-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. The related Kyoto Protocol was signed by the United States, but it has since been rejected by the president, who instead has asked for an 18% voluntary decrease in carbon intensity. In response to the administration’s request, six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the Tennessee Valley Authority (TVA), signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% - 5% decrease in carbon intensity from the utility sector between 2002 and 2012 on a voluntary basis. Currently, Ameren is considering various initiatives to comply with the MOU. These include enhanced generation at our nuclear and hydro power plants, increased efficiency measures at our coal-fired units, and investing in renewable energy and carbon sequestration projects.
We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives ,or legislation on our results of operations, financial position, or liquidity. Any of these factors would add significant pollution control expenditures and operating costs to UE’s, Genco’s and CILCO’s generating assets and, therefore, could also increase financing requirements for some Ameren Companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to the MoPSC or the ICC approval in a rate proceeding, as applicable, there is no similar mechanism for recovery of costs by Genco or CILCO in Illinois.
UE’s, CIPS’, CILCO’s and IP’s participation in the MISO could increase costs, reduce revenues, and reduce UE’s, CIPS’, CILCO’s and IP’s control over their transmission assets. Genco could also incur increased costs or reduced revenues as a result of participation in the MISO Day Two Markets.
On May 1, 2004, functional control of the UE and CIPS transmission systems was transferred to the MISO through GridAmerica LLC. On September 30, 2004, IP transferred functional control of its transmission system to the MISO. CILCO had transferred functional control of its transmission system to the MISO before the acquisition. The participation by UE, CIPS and IP in the MISO is expected to increase annual costs by $10 million to $25 million in the aggregate because the companies will be subject to the MISO’s administrative costs. This could also result in a decrease in annual revenues of $5 million to $15 million in the aggregate,
because of the MISO’s method of allocating transmission revenues. UE, CIPS, CILCO and IP may also be required to expand their transmission systems according to decisions made by MISO rather than according to their internal planning process. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
In July 2002, the FERC issued its standard market design NOPR. The NOPR proposed three important of changes to the way the current wholesale transmission service and energy markets are operated: the placement of all jurisdictional transmission facilities under the control of an independent transmission provider (similar to the MISO); a new transmission service tariff that would provide a single form of transmission service for all users of the transmission system, including bundled retail load; and a new transmission management system. This new design would use market-based pricing to compensate market participants for power, as well as for transmission congestion and losses. The current system requires generators to make advance reservations for transmission service.
In April 2003, the FERC issued a white paper reflecting comments received in response to the NOPR. The white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service. The FERC will ensure in its final rule that existing bundled retail customers retain their existing transmission rights and their rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule’s implementation. We believe that the proposed NOPR could have a negative impact on the cost and reliability of service to retail customers. It could lead to trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies.
Although issuance of the final rule is uncertain and its implementation schedule unknown, the MISO is implementing a separate market design similar to the market design proposed by the NOPR. This new market design is referred to as the MISO Day Two Market. The MISO Day Two Market, scheduled to begin operation on April 1, 2005, is designed to result in improved transparency of power pricing and efficiency in generation dispatch. Since this is a new and complex market, there could be significant initial price volatility. Ultimately, price transparency and dispatch efficiency could result in lower prices on market-based power sales by UE, Genco, AERG and CILCO to their customers. In addition, the movement of power could result in unanticipated transmission congestion charges or credits. MISO has allocated FTRs to UE, CIPS, Genco, and CILCO. FTRs are financial instruments that are intended to hedge this risk, but UE, CIPS, Genco, CILCO and IP may not have been allocated the appropriate number of these FTRs. In addition, these instruments could prove ineffective in hedging risk.
Until we achieve some degree of operational experience participating in the MISO, including the MISO Day Two Market, we are unable to predict the impact that the MISO participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our results of operations, financial position, or liquidity.
The market-based rate authority currently held by UE, CIPS, Genco, CILCO, AERG, Development Company, Marketing Company, and Medina Valley could be revoked or restricted as a result of the FERC’s new market power analysis screen order.
In an order issued in April 2004, the FERC replaced the Supply Margin Assessment Screen previously used to review applications by sellers of electricity at wholesale for authorization to sell power at market-based rates. The new screen uses two measures of market power: (1) a pivotal supplier analysis, and (2) a market share analysis, which is to be prepared on a seasonal basis. Applicants located in a RTO with sufficient market structure and a single energy market were permitted to base their calculations of market power on the size of the market in the geographic region under the control of the RTO, but other applicants were required to base their calculations of market power on the size of the market in the control area where they operate. If the applicant passes both screens, a rebuttable presumption will exist that it lacks generation market power. If the applicant fails either screen, a rebuttable presumption will exist that it has market power. Under such circumstances, the applicant may either seek to rebut the presumption by preparing a delivered price test (identifying the amount of economic capacity from neighboring areas that can be delivered to the control area) or propose mitigation measures. Unless some other mitigation measure is adopted, the applicant’s authority to sell power at market-based rates in areas where it has market power will be revoked, and the applicant will be required to sell at cost-based rates in those areas.
UE, CIPS, Genco, CILCO, AERG, Development Company, Marketing Company, and Medina Valley are currently authorized by the FERC to continue to sell power at market-based rates. However, the FERC indicated in its April 2004 order that it would apply the new market analysis screens to pending and future market-based rate applications, including three-year market-based rate reviews. All of the aforementioned Ameren entities currently have three-year market-based rate reviews pending at the FERC.
As required, these Ameren companies filed an updated market power analysis with the FERC in December 2004. All of the Ameren companies pass both screen measures for the market consisting of the entire MISO footprint. Also in their December filings, these Ameren companies offered to supplement their filings with information that applies the new
tests to smaller markets consisting of the control areas in which the Ameren companies sell power, if the MISO Day Two Markets does not begin on March 1, 2005, as originally scheduled. In January 2005, the Missouri Joint Municipal Electric Utility Commission (MJMEUC) filed a protest to the Ameren companies’ December filing. In February 2005, the Ameren companies filed a response to the MJMEUC’s protest, which rebutted its claims that the Ameren companies possess market power.
We are unable to anticipate how or when the FERC will respond to our December filings and to any supplemental filings that we might make.
Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee- related benefits may adversely affect our results of operations, financial position, and liquidity.
We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial assumptions have a significant impact on our earnings and funding requirements. Assuming that we continue to receive federal interest rate relief beyond 2005, we do not expect contributions to our defined benefit plans to be required until 2008 and 2009, when an aggregate $400 million is expected to be paid. This amount is an estimate; it may change because of actual stock market performance, changes in interest rates, or any pertinent changes in government regulations, any of which could also result in a requirement to record an additional minimum pension liability.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits may adversely affect our results of operations, financial position, or liquidity.
UE’s, Genco’s, CILCO’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, and increased purchased power costs.
UE, Genco, CILCO, AERG, Medina Valley, and EEI own and operate coal, nuclear, gas-fired, hydro, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output and efficiency levels. Included among these risks are:
·
increased prices for fuel and fuel transportation as existing contracts expire;
·
facility shutdowns due to a failure of equipment or processes or operator error;
·
longer-than-anticipated maintenance outages;
·
disruptions in the delivery of fuel and lack of adequate inventories;
·
labor disputes;
·
inability to comply with regulatory or permit requirements;
·
disruptions in the delivery of electricity;
·
increased capital expenditures requirements, including those due to environmental regulation; and
·
unusual or adverse weather conditions, including catastrophic events such as fires, explosions, floods or other similar occurrences affecting electric generating facilities.
A substantial portion of Genco’s and CILCO’s generating capacity is committed under affiliate contracts that expire at the end of 2006. Upon expiration of these contracts, Genco’s and CILCO’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.
Genco and CILCO, through AERG, own 4,751 megawatts and 1,165 megawatts, respectively, of non-rate-regulated electric generating facilities. Of these non-rate-regulated electric generating facilities, approximately 3,300 megawatts are currently under full-requirements contracts with our affiliates. The remainder of the generating capacity must compete for the sale of energy and capacity.
To the extent electric capacity generated by these facilities is not under contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries will generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
·
the current and future market prices for natural gas, fuel oil, and coal;
·
current and forward prices for the sale of electricity;
·
the extent of additional supplies of electric energy from current competitors or new market entrants;
·
the pace of deregulation in our market area and the expansion of deregulated markets;
·
the regulatory and pricing structures developed for Midwest energy markets as they continue to evolve and the pace of development of regional markets for energy and capacity outside of bilateral contracts;
·
future pricing for, and availability of, transmission services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit the ability to sell energy in markets adjacent to Illinois;
·
the rate of growth in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs; and
·
climate conditions prevailing in the Midwest market.
In a report issued by the ICC in late 2004, a process was outlined that would have CIPS, CILCO and IP procuring power through an auction monitored by the ICC after the current Illinois rate freeze and supply contracts end in 2006. Genco and AERG would probably participate in this auction, but there might be a limit on the maximum amount of power they could supply to Ameren’s Illinois utilities. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
Genco and UE have signed an agreement to dispatch their generating facilities jointly, which produces benefits and efficiencies for both generating parties. Pending or future federal and state regulatory proceedings and policies may evolve in ways that could affect Genco’s ability to participate in these affiliate transactions on current terms. For example, as a result of the MoPSC order approving the transfer of UE’s Illinois-based utility business to CIPS, certain terms of the joint dispatch agreement were ordered to be modified; this could result in margins from interchange sales of $7 million to $24 million being transferred from Genco to UE. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a more detailed description of these modifications. The termination of the joint dispatch agreement, or modifications to it, could have a material adverse effect on UE or Genco.
UE’s ownership and operation of a nuclear generating facility creates business, financial, and waste disposal risks.
UE owns the Callaway nuclear plant, which represents approximately 14% of UE’s generation capacity. Therefore, UE is subject to the risks of nuclear generation, which include the following:
·
potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
·
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE’s nuclear operations or those of others in the United States;
·
uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate;
·
increased public and governmental concerns over the adequacy of security at nuclear power plants;
·
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE’s facility operating license for the Callaway nuclear plant expires in 2024); and
·
costly and extended outages for scheduled or unscheduled maintenance.
The NRC has broad authority under federal law to impose licensing and safety requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, although UE has no reason to anticipate a serious nuclear incident at its plant, if an incident did occur, it could harm UE’s results of operations, financial position, or liquidity. 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.
Operating performance at UE’s Callaway nuclear plant has resulted in unscheduled or extended outages including the extension of Callaway’s scheduled refueling and maintenance outage in 2004. In addition, Ameren and UE incurred significant unanticipated replacement power and maintenance costs. As a result, the operating performance at UE’s Callaway nuclear plant has declined in comparison with both its past operating performance and the operating performance of other nuclear plants in the U.S. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. They are reviewing management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, and overall organizational effectiveness. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and UE.
Our energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings.
We are exposed to changes in market prices for natural gas, fuel, electricity, and emission credits. Prices for natural gas, fuel, electricity, and emission credits may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We use long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot assure you that these strategies will be successful in managing our pricing
risk, or that they will not result in net liabilities to us as a result of future volatility in these markets.
Although we routinely enter into contracts to hedge our exposure to the risks of demand, market effects of weather, and changes in commodity prices, we do not always hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, and liquidity.
Our counterparties may not meet their obligations to us.
We are exposed to risk that counterparties who owe us money, energy or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements (which include agreements for a subsidiary of Dynegy and others to supply electricity to IP during 2005 and 2006) fail to perform, IP might be forced to replace the underlying commitment at then-current market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.
Our facilities are considered critical infrastructure and may be targets for acts of terrorism.
Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs to repair, which could have a material adverse effect on our results of operations, financial position, and liquidity.
Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.
We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements, including those related to future environmental compliance, not satisfied by our operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and expand our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets that could increase our cost of capital or impair our ability to access the capital markets.
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the last three years. CILCORP and CILCO are included only for the periods after January 31, 2003. IP is included for the period after September 30, 2004.
(a)
Represents capability throughout 2004, including the fourth quarter.
(b)
Excludes 125 megawatts of IP’s ownership in EEI that IP agreed to sell to a nonaffiliate as part of its acquisition settlement with the FERC.
(a)
Represents peak day throughput since the acquisition date of January 31, 2003. CILCO’s peak day throughput in January 2003 was 404 MMBtus.
(b)
Represents peak day throughput since the acquisition date of September 30, 2004. IP’s peak day throughput for the first three quarters of 2004 was 654 MMBtus.
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren’s Internet Web site (http://www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.
The Ameren Companies also make available free of charge through Ameren’s Web site (http://www.ameren.com) the charters of Ameren’s board of directors’ audit committee, human resources committee, nominating and corporate governance committee, and nuclear oversight committee and the corporate governance guidelines, shareholder communications policy, and director nomination policy which apply to the Ameren Companies. These documents are also available in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149.
ITEM 2.
ITEM 2. PROPERTIES.
For information on our principal properties, including planned additions, replacements and transfers, see the generating facilities table below and Liquidity and Capital Resources and Regulatory Matters in Manage-ment’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. See also Note 3 - Rate and Regulatory Matters, Note 6 - Long-term Debt and Equity Financings and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
Ameren is a member of MAIN, a regional electric reliability council organized to coordinate the planning and operation of bulk power supply in Illinois and portions of Michigan, Wisconsin, Iowa, Minnesota and Missouri. The Ameren membership covers UE, CIPS, CILCO and IP. Ameren has provided formal written notice to the MAIN board of directors of its intent to withdraw from MAIN effective January 1, 2006, provided the configuration of MAIN remains the same. Ameren intends to join another RRO prior to its withdrawal from MAIN. Ameren may cancel its notice of intent to withdraw from MAIN at any time. Until the withdrawal is effective, Ameren will continue to honor all of its obligations as a member of MAIN. Before Ameren acquired it, IP gave notice to MAIN of its intent to withdraw effective December 31, 2004. However, as a result of Ameren’s acquisition of it, IP remains a member of MAIN through the Ameren membership.
The bulk power system of UE, CIPS and Genco is operated as an Ameren-wide control area and transmission system under the FERC-approved joint dispatch agreement. The joint dispatch agreement provides a way for UE and Genco to participate in the coordinated operation of CIPS’ and UE’s transmission facilities. This allows UE and Genco to achieve economies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of that coordinated operation. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of changes to the joint dispatch agreement that may arise out of a February 2005 MoPSC order. In 2004, we had a minimum of 18 direct connections with other control areas for the exchange of electric energy, directly and through the facilities of others. CILCO continues to operate as a separate control area, so CILCO’s generating plants, including those of its subsidiary, AERG, have not been jointly dispatched with the generating plants owned by UE and Genco. UE, CIPS, CILCO and IP are transmission-owning members of the MISO, and they have transferred functional control of their systems to the MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems are provided pursuant to the terms of the MISO OATT on file with the FERC. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.
The following table presents information with respect to our electric generating facilities and capability at the time of our expected 2005 peak summer electrical demand:
(a)
“Net Kilowatt Capability” is generating capacity available for dispatch from the facility into the electric transmission grid.
(b)
“Net Heat Rate” is the amount of energy to produce a given unit of output; it is expressed as Btu per kilowatthour.
(c)
For information regarding a lease arrangement applicable to these CTs, see Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.
(d)
CT has the capability of operating on either oil or natural gas (dual fuel).
(e)
Represents CTs to be added in 2005.
(f)
Approximately 550 megawatts of generating capacity (Pinckneyville and Kinmundy) are expected to be sold by Genco to UE subject to receipt of necessary regulatory approvals.
(g)
This amount represents Ameren’s 80% interest in EEI. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
(h)
There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).
(i)
These CTs are owned by Genco and leased to its parent, Development Company. The operating lease is for a minimum term of 15 years expiring September 30, 2015. Genco receives rental payments under the lease in fixed monthly amounts that vary over the term of the lease and range from $0.8 million to $1.0 million.
(j)
Genco has granted the city of Columbia, Missouri options to purchase an undivided ownership interest in these facilities, which would result in a sale of up to 72 megawatts (about 50%) of the facilities. Columbia can exercise one option for 36 megawatts at the end of 2010 for a purchase price of $15.5 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other option can be exercised for another 36 megawatts at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5 million, or at the end of 2023 for a purchase price of $4 million. A power purchase agreement pursuant to which Columbia is now purchasing up to 72 megawatts of capacity and energy generated by these facilities from Marketing Company will terminate if the city exercises the purchase options.
(k)
These facilities were contributed by CILCO to AERG in October 2003. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
As of December 31, 2004, UE owned 3,200 circuit miles of electric transmission lines and operated two propane-air plants and 3,050 miles of natural gas transmission and distribution mains. As of December 31, 2004, CIPS owned 1,900 circuit miles of electric transmission lines and operated one propane-air plant, three underground gas storage fields with a total working capacity of 3 billion cubic feet, and 5,000 miles of natural gas transmission and distribution mains. As of December 31, 2004, CILCO owned 350 circuit miles of electric transmission lines. CILCO operates two underground gas storage fields with a total working capacity of 6 billion cubic
feet and 3,800 miles of gas transmission and distribution mains. As of December 31, 2004, IP owned 1,700 circuit miles of electric transmission lines. IP owns seven underground gas storage fields with a total working capacity of 15 billion cubic feet and 8,500 miles of natural gas transmission and distribution mains. Our other properties include distribution lines, under-ground cables, office buildings, warehouses, garages, and repair shops.
We have fee title to all principal plants and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bond indebtedness and to certain permitted liens and judgment liens), except that:
·
A portion of UE’s Osage plant reservoir, certain facilities at UE’s Sioux plant, most of UE’s Peno Creek CT facility, Genco’s Columbia CT facility, certain of Ameren’s substations and most of our transmission and distribution lines and gas mains are situated on lands we occupy under leases, easements, franchises, licenses or permits;
·
The United States or the state of Missouri may own or may have paramount rights to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River, on which certain of UE’s generating and other properties are located; and
·
The United States, the state of Illinois, the state of Iowa or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of UE’s Keokuk plant is located.
Substantially all of the properties and plant of UE, CIPS, CILCO and IP are subject to the direct first liens of the indentures securing their mortgage bonds. In October 2003, CILCO transferred substantially all of its generating property and plant to its non-rate-regulated electric generating subsidiary, AERG. As part of the transfer, CILCO’s transferred generating property and plant was released from the lien of the indenture securing its first mortgage bonds. During 2005, UE plans to transfer its Illinois electric and gas transmission and distribution properties to CIPS, depending on the outcome of pending regulatory proceedings. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information. As a part of the transfer, UE’s Illinois electric and gas transmission and distribution properties will be released from the lien of the indenture securing its first mortgage bonds and will become encumbered by the direct first lien of the indenture securing the CIPS first mortgage bonds.
In December 2002, UE conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city for a 20-year term. As a part of the transaction, most of UE’s Peno Creek property and plant was released from the lien of the indenture securing UE’s first mortgage bonds. Under the terms of this capital lease, UE retains all operation and maintenance responsibilities for the facility, and ownership of the facility will return to UE at the expiration of the lease. When ownership of the Peno Creek facility is returned to UE by Bowling Green, the property and plant may again become encumbered by the direct first lien of any outstanding UE first mortgage bond indenture.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business, some of which involve sub-stantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.
For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1. Business above, Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report , Note 3 - Rate and Regulatory Matters, and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth quarter of 2004 with respect to any of the Ameren Companies.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2004, all positions and offices held with the Ameren Companies, tenure as officer, and business background for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.
AMEREN CORPORATION:
Officers are generally elected or appointed annually by the respective board of directors of each company following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor to our knowledge, any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the officers. Except for Martin J. Lyons, Richard J. Mark, Michael L. Moehn, and Donna K. Martin, each of the above-named executive officers has been employed by an Ameren company for more than five years in executive or manage-ment positions.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER
PURCHASES OF EQUITY SECURITIES.
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren began trading on January 2, 1998, following the merger of UE and CIPSCO on December 31, 1997. Ameren has submitted to the NYSE a certificate of the chief executive officer of Ameren certifying that he is not aware of any violation by Ameren of NYSE corporate governance listing standards.
Ameren common shareholders of record totaled 86,986 on January 31, 2005. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2004 and 2003.
There is no trading market for the common stock of UE, CIPS, Genco, CILCORP, CILCO or IP. Ameren holds all outstanding common stock of UE, CIPS, CILCORP and IP; Development Company holds all outstanding common stock of Genco; and CILCORP holds all outstanding common stock of CILCO.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries, including amounts retained by Ameren Corporation during 2004 and 2003:
(a)
CILCO paid dividends of $10 million, $18 million, $23 million, and $21 million in the periods ended June 30, 2004, and June 30, September 30 and December 31, 2003, respectively.
(b)
Prior to October 2004, the ICC prohibited IP from paying dividends. If permitted to be paid, IP’s dividends would have been paid directly to Illinova or indirectly to Dynegy.
On February 11, 2005, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 63.5 cents per share. The common share dividend is payable March 31, 2005, to stockholders of record on March 9, 2005.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.
The following table presents Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:
* These shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligations upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.
None of the other Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the period October 1 to December 31, 2004.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
(a)
At Ameren, UE and Genco, revenues were netted with costs upon adoption of EITF No. 02-3 and the rescission of EITF No. 98-10 in 2003. The amounts were netted as follows at Ameren: 2002 - $738 million; 2001 - $648 million; at UE: 2002 - $458 million; 2001 - $392 million; and at Genco: 2002 - $253 million; 2001 - $256 million.
(b)
On May 1, 2000, CIPS transferred its electric generating assets and related liabilities, at net book value, to Genco, in exchange for a subordinated promissory note from Genco in the principal amount of $552 million and 1,000 shares of Genco’s common stock.
(c)
Amounts for IP have not been reclassified to conform to Ameren classifications for 2001 and 2000. Amounts for CILCORP and CILCO have not been reclassified to conform to Ameren classifications for 2000.
(d)
Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for CILCORP since the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report.
(e)
Estimated future removal costs embedded in accumulated depreciation within our regulated operations at December 31, 2002, of $652 million at Ameren, $528 million at UE, $124 million at CIPS, $27 million at CILCORP, $141 million at CILCO, and $69 million at IP were reclassified to a regulatory liability to conform to current period presentation. Prior periods were not reclassified for any of the Ameren Companies, except IP, which includes reclassifications of $68 million and $62 million for 2001 and 2000, respectively. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for further information.
(f)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(g)
The consolidated financial statements of IP for the years ended December 31, 2001 and 2000, were audited by independent accountants that have ceased operations. Please read “Report of Independent Public Accountants” in the accompanying audited financial statements.
(h)
Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent, Dynegy. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for further information.
(i)
Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN No. 46R. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for further information.
(j)
Ameren, Genco, CILCORP, CILCO and IP net income included income (loss) from cumulative effect of change in accounting principle of $18 million ($0.11 per share), $18 million, $4 million, $24 million and $(2) million for the year ended December 31, 2003. Ameren, UE and Genco net income included loss from cumulative effect of change in accounting principle of $7 million ($0.05 per share), $5 million and $2 million for the year ended December 31, 2001. CILCORP had a $2 million loss from discontinued operations in 2001 that is included in net income.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Overview
The most significant event for Ameren in 2004 was the announcement, financing and September 30th completion of the $2.3 billion acquisition of IP and an additional 20% ownership interest in EEI.
In 2004, Ameren recorded solid net earnings of $2.84 per share due to weather-adjusted demand growth, the incremental earnings contribution resulting from the acquisitions of IP on September 30, 2004, and CILCORP Inc. on January 31, 2003, and increased earnings from our excess power sales. This earnings performance was accomplished despite very mild summer weather, a planned refueling and maintenance outage at our Callaway nuclear plant and the early issuance of common shares to fund the IP acquisition. Earnings in 2003 included unusual gains of 30 cents per share related to the adoption of an accounting standard and settlement of a dispute with a coal supplier, and there was no Callaway outage required in 2003.
Earnings
Total revenues in 2004 increased 12% to $5.2 billion from 2003. Growth in revenues was generated by the acquisitions of IP and CILCORP, which added $484 million in revenues in 2004. In addition, revenues benefited from weather-adjusted growth, increased excess power sales due to greater availability of low-cost generation and improved power prices, and higher natural gas delivery rates.
During 2004, factors that mitigated this improvement in revenues included extremely mild summer weather and the final $30 million annual rate reduction under the electric rate case settlement in Missouri that went into effect on April 1, 2004. Summer weather in 2004 in our service territory was the seventh mildest of the past 109 years, according to the National Weather service. Mild 2004 weather reduced revenues by an estimated $38 million in 2004, relative to 2003.
Operations and maintenance expenses increased 9% to $1.3 billion in 2004 from 2003, again, primarily because of the acquisitions. Expenses were also higher because of the two-month refueling and maintenance outage at our Callaway nuclear plant, which increased expenses by $39 million, and purchased power costs by $24 million. A 70-day to 75-day outage is scheduled for 2005 in order to replace major equipment that is expected to increase the generating capacity of the Callaway plant by over 50 megawatts and improve future safety and reliability. Employee benefit costs also increased in 2004 as compared with 2003.
Operations expenses benefited from the $18 million refund of exit fees paid to the MISO upon re-entry to that system in 2004 and lower labor costs.
Liquidity
Cash flows from operations of $1.1 billion in 2004 at Ameren, along with other funds, were used to pay dividends to common shareholders of $479 million and fund capital expenditures of $806 million. Cash flows from operations were reduced by a $295 million contribution to our pension plan.
Ameren issued approximately 30 million shares of common stock in 2004 to finance the acquisition of Illinois Power and an additional 20% interest in EEI. Net proceeds of $1.3 billion were used to pay the cash portion of the purchase price of $443 million, and reduce high-cost debt and pay related fees at IP. Other financing activities primarily related to refinancing higher cost or maturing debt in Ameren’s other subsidiaries.
Outlook
We expect continued economic growth in our service territory to benefit electric demand in 2005 with natural gas and coal prices supporting power prices similar to 2004 levels. Ameren’s coal and related transportation costs rose in 2004 and are expected to rise 3% to 4% in 2005 and 2006. These costs are expected to increase more beyond 2006 as existing contracts are replaced. We also expect to realize synergies from the IP acquisition in 2005 and 2006.
Electric rates for Ameren’s operating subsidiaries have been fixed or declining for periods ranging from 12 years to 22 years. In addition, power supplied by Ameren’s non-rate-regulated generation subsidiaries has been subject to contracts to supply our Illinois distribution subsidiaries. In 2006, electric rate adjustment moratoriums and intercompany power supply contracts expire in Ameren’s regulatory jurisdictions. We believe that the prices reflected in these power supply contracts are below current market prices. In 2005, we will begin the process of preparing and filing utility cost-of-service studies and filing a proposed framework for power procurement that will determine electric rates in 2006 and beyond.
The EPA has proposed more stringent emission limits on all coal-fired power plants. Between 2005 and 2015, Ameren expects its subsidiaries will be required to spend between $1.4 and $1.9 billion to retrofit its power plants with pollution control equipment. Approximately two-thirds of this investment will be in the Company’s regulated Missouri operations and therefore is expected to be recoverable over time from ratepayers. The recoverability of amounts invested in non-rate-regulated operations will depend on whether market prices for power adjust for this increased investment by the industry.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois as discussed below. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for a detailed description of our principal subsidiaries.
·
UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois.
·
CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
·
Genco operates a non-rate-regulated electric generation business.
·
CILCO is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business, through its subsidiary, AERG, and a rate-regulated natural gas distribution business in Illinois.
·
IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for further information.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the periods prior to September 30, 2004, and Ameren’s Consolidated Balance Sheet as of December 31, 2003, do not reflect IP’s results of operations or financial position. Financial information of CILCORP and CILCO reflected in Ameren’s consolidated financial statements include the period from January 31, 2003, when these companies were acquired. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for further information on the accounting for the IP and CILCORP acquisitions. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, certain information is expressed in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information is useful because it enables readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding during the applicable year.
IP Acquisition
On September 30, 2004, Ameren completed the acquisition from Dynegy of all the common stock and 662,924 shares of preferred stock of IP (based in Decatur, Illinois) and an additional 20% ownership interest in EEI and its subsidiaries. Ameren acquired IP to complement its existing Illinois electric and gas operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving approximately 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP. For a discussion of the regulatory agency approvals granted in connection with this acquisition, see Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
The total transaction value was $2.3 billion. It included the assumption of $1.8 billion of IP debt and preferred stock and consideration, including transaction costs, of $443 million cash, net of $51 million cash acquired. In February 2005, Ameren received $5 million from Dynegy as a final working capital settlement. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow account, pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for information on the IP environmental matter to which the indemnification and escrow applies. In addition, this transaction included a fixed-price power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. The contract was marked to fair value at closing of the IP acquisition. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. The remaining 30% of its power needs in 2005 and 2006 will be supplied under other arrangements. In the event that any of IP’s suppliers are unable to supply the electricity required by existing agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing IP to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial condition, or liquidity.
Ameren’s financing plan for funding this acquisition included the issuance of new Ameren common stock. Ameren issued an aggregate of approximately 30 million common shares in February 2004 and July 2004, which generated net proceeds of about $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce high-cost IP debt assumed as part of this transaction and to pay related premiums. See Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for information on redemptions and repurchases of certain IP indebtedness after the acquisition.
Ameren expects the acquisition of IP to be accretive to earnings in the first two years of ownership. That belief is based on a variety of assumptions related to power prices, interest rates, and synergies, among other things. In December 2004, 230 IP employees accepted a voluntary separation opportunity, which provides an enhanced separation benefit and extended medical and dental benefits. Employees who accepted the voluntary separation opportunity will leave IP throughout 2005 as business needs warrant. These voluntary separations are consistent with Ameren’s plan for the integration of IP and conditions in the ICC order approving the acquisition, which relate to the realization of administrative synergies from the acquisition. Estimated separation costs of $26 million have been deferred as a regulatory asset of future recovery from customers, which is also consistent with the ICC order.
For income tax purposes, Ameren and Dynegy have elected to treat Ameren’s acquisition of IP stock as an asset acquisition under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended.
RESULTS OF OPERATIONS
Earnings Summary
Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations caused by winter heating and summer cooling demand. With approximately 85% of Ameren’s revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. Our non-rate-regulated sales are subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, supply and demand levels and many other factors. We do not have fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas delivery businesses. The electric and gas rates for UE in Missouri are set through June 2006, and are set for CIPS, CILCO and IP in Illinois through the end of 2006, so that cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates affect our cost of borrowing and pension and postretirement benefits. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems and the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control in order to optimize our results of operations, financial position, and liquidity.
Ameren’s net income for 2004, 2003, and 2002, was $530 million ($2.84 per share), $524 million ($3.25 per share), and $382 million ($2.60 per share), respectively. In 2003, Ameren’s net income included an after-tax gain of $31 million (19 cents per share) related to the settlement of a dispute over mine reclamation issues with a coal supplier and a net cumulative effect after-tax gain of $18 million (11 cents per share) associated with the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” The coal contract settlement gain recaptured coal costs, plus accrued interest, previously paid to a coal supplier for future reclamation of a coal mine that principally supplied a UE power plant. The SFAS No. 143 net gain resulted principally from the elimination from accumulated deprecation of accrued costs of removal for non-rate-regulated assets; these accrued costs of removal were not legal obligations.
The following table presents net cumulative effect after-tax gains (losses) recorded upon adoption of SFAS No. 143 in 2003:
(a) Excludes amounts for IP and CILCORP as SFAS No. 143 was adopted prior to the acquisitions by Ameren.
(b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c) Represents predecessor information.
In 2002, Ameren’s net income included after-tax restructuring charges of $58 million (40 cents per share) for a voluntary employee retirement program; the retirement of some facilities at UE’s Venice, Illinois power plant; and the temporary suspension of operation of two coal-fired generating units at Genco’s Meredosia, Illinois power plant. See Note 7 - Restructuring Charges and Other Special Items to our financial statements under Part II, Item 8, of this report for further information.
The following table presents a reconciliation of Ameren’s net income to net income, excluding restructuring charges and other special items discussed above, as well as the effect of SFAS No. 143 adoption, all net of taxes, for the years ended December 31, 2004, 2003 and 2002. Ameren believes that this reconciliation presents results from continuing operations on a more comparable basis. However, net income, or earnings per share, excluding these items is not a presentation defined under GAAP, and it may not be comparable to other companies’ presentations or more useful than the GAAP presentation included in Ameren’s financial statements.
Excluding the gains on the adoption of SFAS No. 143 and the settlement of the coal mine reclamation dispute in the prior year, Ameren’s net income increased $55 million, and earnings per share decreased 11 cents, in 2004 as compared with 2003. The change in net income was primarily due to organic growth in revenues; increased margins on interchange sales, primarily due to greater availability of low-cost generation (16 cents per share); gas delivery rate increases (10 cents per share); lower labor costs (8 cents per share); the MISO refund of previously paid exit fees upon UE’s and CIPS’ re-entry into the MISO in the second quarter of 2004 (6 cents per share); and results of CILCORP’s inclusion for an additional month and IP’s inclusion for three months in 2004. Partially offsetting these increases to income were increased fuel and purchased power costs and other operations and maintenance costs as a result of UE’s Callaway nuclear plant refueling and maintenance outage in the second quarter of 2004 (22 cents per share), extremely mild 2004 weather conditions (estimated at 12 to 16 cents per share), electric rate reductions (13 cents per share), and higher employee benefit costs (11 cents per share). Increased common shares outstanding also reduced Ameren’s earnings per share in 2004 as compared with 2003.
Excluding the gains related to the coal mine reclamation settlement and an accounting change in 2003 and the restructuring loss in 2002, Ameren’s net income in 2003 increased $35 million, and earnings per share decreased 5 cents as compared to 2002. The change in net income was primarily due to the acquisition of CILCORP; favorable margins on interchange sales (35 cents per share), due to improved power prices in the energy markets and greater low-cost generation available for sale; organic growth; lower labor costs due to the voluntary employee retirement program implemented in early 2003 (11 cents per share); lower maintenance expenses in Ameren’s pre-CILCORP acquisition operations (25 cents per share); and a decrease in Other Miscellaneous Expense as a result of the expensing of economic development and energy assistance programs in the second quarter of 2002 related to the UE Missouri electric rate case settlement. These benefits to Ameren’s 2003 net income were partially offset by unfavorable weather conditions (estimated at 40 to 50 cents per share), primarily due to cooler summer weather in Ameren’s pre-CILCORP territory than the normal conditions experienced in 2002; an electric rate reduction in UE’s Missouri service territory that went into effect in April 2003 (11 cents per share); lower sales of emission credits (7 cents per share); and higher employee benefit costs (8 cents per share). Increased common shares outstanding
also reduced Ameren’s earnings per share in 2003 as compared with 2002.
As a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the years ended December 31, 2004, 2003 and 2002:
(a)
Includes earnings from unregulated interchange power sales that provided in 2004, $75 million of UE’s net income (2003 - $58 million; 2002 - $20 million) and $39 million of Genco’s net income (2003 - $30 million; 2002 - $10 million).
(b)
Excludes net income prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
Excludes net income prior to the acquisition date of September 30, 2004.
(d)
Includes corporate general and administrative expenses, transition costs associated with the CILCORP and IP acquisitions and other non-rate-regulated operations.
Acquisition Accounting
The amortization of noncash purchase accounting fair value adjustments at IP increased Ameren’s and IP’s net income by $26 million for the three months ended December 31, 2004, as compared with the prior-year period. The amortization of the fair value adjustments at IP that increased net income were related to pension and postretirement liabilities, long-term debt, a power supply contract with EEI that expires in 2005, and a power supply contract with Dynegy for 2,800 megawatts that expired in 2004. Partially offsetting these items was the amortization of the fair value adjustment related to a power supply contract for 700 megawatts that also expired in 2004. Concurrent with its acquisition of IP, Ameren negotiated a contract with Dynegy to supply IP 2,800 megawatts for 2005 and 2006. The fair value adjustments associated with this agreement and the EEI contract noted above will be amortized over the terms of the contracts and will have a net favorable impact on IP’s net income. The following table presents the favorable (unfavorable) impact on IP’s net income related to the amortization of purchase accounting fair value adjustments during the three months ended December 31, 2004:
(a)
Related to the adjustment to fair value of the pension plan and postretirement plans.
(b)
Related to the adjustment to fair value of all the IP debt assumed at acquisition on September 30, 2004. The net write-up to fair value of all the IP debt assumed, excluding early redemption premiums, is being amortized over the anticipated remaining life of the debt. See Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for additional information.
(c)
Related to the amortization of fair value adjustments to power supply contracts.
(d)
Tax effect of the above amortization adjustments.
The amortization of noncash purchase accounting fair value adjustments at EEI decreased Ameren’s net income. The amortization of fair value adjustments at EEI related to the additional 20% interest acquired by Ameren on September 30, 2004, for plant in service, emission credits and a power supply agreement with IP that expires in 2005. The amortization of the fair value adjustment of the power supply agreement of $3 million in 2004 between IP and EEI had no affect on net income at a consolidated Ameren level because IP is amortizing its fair value adjustment for the same power supply agreement. The following table presents the favorable (unfavorable) impact on net income related to the amortization of purchase accounting fair value adjustments of EEI during the three months ended December 31, 2004:
(a)
Related to the amortization of emission credits and a power supply contract.
(b)
Includes the amortization of the fair value adjustment related to plant assets.
(c)
Tax effect of the above amortization adjustments.
The amortization of noncash purchase accounting fair value adjustments at CILCORP increased Ameren’s and CILCORP’s net income in 2004 by $6 million compared with $24 million for the 11 months in the prior year. The amortization of the fair value adjustments that increased net income were related to pension and postretirement liabilities, coal contract liabilities, and long-term debt. The amortization of fair value adjustments that decreased net income were related to electric plant in service, purchased power, and emission credits. The following table presents the favorable (unfavorable) impact on Ameren’s and CILCORP’s net income related to the amortization of purchase accounting fair value
adjustments during 2004 and the 11 months ended December 31, 2003:
(a)
Related to the adjustment to fair value of the pension plan and postretirement plans; retail customer contracts and investment assets.
(b)
Related to CILCORP’s 9.375% senior notes due 2029 and 8.70% senior notes due 2009 being written up to fair value and amortized over the average remaining life of the debt. See Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for additional information.
(c)
Related to emission credits and coal contracts.
(d)
Related to plant assets at Duck Creek, E.D. Edwards, and Sterling Avenue being amortized over the remaining useful lives of the plants.
(e)
Tax effect of the above amortization adjustments.
The total purchase accounting adjustments for IP, EEI and CILCORP had a net favorable impact on Ameren’s net income of $29 million for the year 2004.
Electric Operations
The following tables present the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power costs, from prior year for the years ended December 31, 2004 and 2003. We consider electric and interchange margins useful measures to analyze the change in profitability of our electric operations between periods. We have included the analysis below as a complement to our financial information provided in accordance with GAAP. However, electric and interchange margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we are providing elsewhere in this report.
The variation for Ameren shows the contribution from IP for the last three months of 2004 and the contribution from CILCORP for January 2004 as separate line items, which allows an easier comparison with other margin components. The variation in IP electric margins in 2004 include the purchase accounting adjustments discussed above; they are compared with the full years 2003 and 2002, when Ameren did not own IP and it did not contribute to Ameren’s electric margins. The variations in CILCORP and CILCO electric margins in 2004 and 2003 are compared with the full years 2003 and 2002. Before January 31, 2003, Ameren did not own CILCORP and CILCO and they did not contribute to Ameren’s electric margins.
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b) Includes predecessor information for periods prior to January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c) Includes predecessor information for periods prior to September 30, 2004.
Ameren
versus 2003
Ameren’s electric margin increased $128 million in 2004 as compared with 2003. Excluding the additional month of CILCORP results and three months of IP results in the current year, electric margin increased $4 million for 2004. Strong organic growth due to improved economic conditions and increased margins on interchange sales more than offset the effect of unfavorable weather conditions, increased fuel and purchased power costs due to the second quarter 2004 Callaway nuclear plant refueling and maintenance outage, and rate reductions in the current year as compared with the prior year. In addition, revenues from emission credit sales decreased $7 million in 2004 as compared with 2003.
According to the National Weather Service, summer weather in 2004 in Ameren’s service territory was the seventh mildest in the past 109 years. Cooling degree-days during that period in our service territory were down approximately 20% from both normal conditions and the prior year. Warmer winter weather in 2004 also resulted in heating degree-days that were down approximately 7% in 2004 in our service territory as compared with 2003, and down approximately 10% from normal conditions. Excluding the additional month of CILCORP sales and three months of IP sales in the current year, residential sales were flat compared to the prior year, as organic growth offset the impact of the unfavorable weather conditions. Commercial and industrial sales increased 2% in 2004 due to improved economic conditions.
Rate reductions resulting from the 2002 UE electric rate case settlement in Missouri negatively affected electric revenues during 2004. Annual reductions of $50 million, $30 million, and $30 million were effective April 1, 2002, 2003, and 2004, respectively.
Margins on interchange sales increased $37 million in 2004 as compared with the same period in 2003, because of increased availability of low-cost generation resulting from record power generation and reduced demand from native load customers due to the mild summer weather. In addition to increased availability of low-cost power, the current year also benefited because both higher natural gas and coal prices contributed to increased power prices. Average realized power prices on interchange sales increased to approximately $34 per megawatthour in 2004 from approximately $32 per megawatthour in 2003. In 2004, Ameren’s base load coal-fired electric generating plants’ average capacity factor was approximately 76%, despite the extremely mild weather, as compared with 73% in 2003, and the equivalent availability factor was approximately 87%, as compared with 85% in the prior-year period.
EEI’s revenues decreased in 2004 compared with 2003 because of reduced emission credit sales and decreased sales to the DOE, which also resulted in a decrease in purchased power. EEI’s sales of emission credits were $2 million in 2004 as compared with $10 million in 2003.
Ameren’s fuel and purchased power costs increased $54 million, excluding the additional month of CILCORP and the additional three months of IP in the current year, as compared with 2003, because of increased power purchases necessitated by the Callaway refueling and maintenance outage as well as increased fossil generation and fuel prices.
versus 2002
Ameren’s electric margin increased $187 million in 2003 as compared with 2002. Increases in electric margin in 2003 were attributable primarily to the acquisition of CILCORP, increased margins on interchanges sales, and organic sales growth, partially offset by unfavorable weather conditions relative to 2002, lower sales of emission credits, and rate reductions. CILCORP’s contribution to Ameren’s electric margin for the 11 months ended December 31, 2003, was $236 million. Margins on interchange sales increased $92 million in 2003 because of improved power prices in the energy markets and increased low-cost generation availability. Average realized power prices on interchange sales increased to approximately $32 per megawatthour in 2003 from approximately $25 per megawatthour in 2002. Availability of coal-fired generating plants increased to 85% in 2003 from 82% in 2002 because there were fewer scheduled and
unscheduled outages. In addition, there was no refueling outage at our Callaway nuclear plant in 2003.
The unfavorable weather conditions were the cooler summer weather in 2003 versus warmer than normal conditions in the same periods in 2002. Cooling degree-days were down approximately 25% in 2003 in our service territory compared with 2002 and down approximately 10% from normal conditions. Heating degree-days in 2003 were comparable to 2002 and normal conditions. In Ameren’s pre-CILCORP acquisition service territory, weather-sensitive residential and commercial electric kilowatthour sales declined 4% and 2%, respectively, in 2003 compared with 2002. Industrial electric kilowatthour sales increased 2% in 2003 in Ameren’s pre-CILCORP acquisition service territory because of improving economic conditions.
Annual rate reductions of $50 million and $30 million were effective April 1, 2002 and 2003, respectively, as a result of the 2002 UE electric rate case settlement in Missouri. Those reductions negatively affected electric revenues in 2003 and 2002.
EEI’s revenues decreased in 2003 as compared with 2002 because of lower emission credit sales and decreased sales to the DOE, which also resulted in a decrease in fuel and purchased power. EEI’s sales of emission credits were $10 million in 2003 as compared with $38 million in 2002.
Ameren’s fuel and purchased power increased in 2003 compared with 2002 because of increased kilowatthour sales, related primarily to the addition of CILCORP. Excluding CILCORP, fuel and purchased power decreased in 2003 primarily because of the greater availability of low-cost generation.
UE
UE’s electric margin decreased $15 million in 2004 as compared with 2003. Residential sales were comparable with prior-year sales as the effect of mild summer weather was offset by organic growth. Rate reductions from the 2002 rate case settlement negatively affected electric revenues during 2004. Partially offsetting these decreases to electric revenues were increased interchange margins and higher emission sales. Margins on interchange sales increased $23 million in 2004 as compared to 2003, because of increased availability of low-cost generation and higher power prices. Revenues from emission credit sales decreased $3 million in the current year as compared with 2003. Fuel and purchased power increased $20 million in 2004, primarily because of increased purchased power of $24 million resulting from the Callaway refueling and maintenance outage during the second quarter of 2004, partially offset by decreased demand due to mild summer weather conditions in 2004.
UE’s electric margin decreased $22 million in 2003 as compared with 2002. Decreases in electric margin in 2003 were primarily attributable to the unfavorable weather conditions and the rate reductions resulting from the 2002 Missouri electric rate case settlement mentioned above. However, margins on interchange sales increased $64 million because of improved power prices in the energy markets and increased low-cost generation availability. Fuel and purchased power decreased slightly in 2003 as compared with 2002, primarily because of lower transmission costs.
CIPS
CIPS’ 2004 electric margin was comparable with the margin in 2003. Electric margin was favorably affected by an industrial customer’s switching from CIPS to Marketing Company and the elimination of the negative margin associated with this customer. Unfavorable weather conditions offset the above increases to margin.
CIPS’ electric margin decreased $27 million in 2003, as compared with 2002, primarily because of the unfavorable weather conditions and several customers’ switching from CIPS to Marketing Company. Commencing in 2002, all of CIPS’, CILCO’s, IP’s and UE’s Illinois residential, commercial and industrial customers had a choice in electric suppliers according to the Illinois Customer Choice Law. CIPS continues to provide electric delivery service to these customers, and it charges them ICC-approved delivery service tariff rates for that service. Customer switching resulted in a $95 million decline in CIPS revenues which is included in the line item growth and other in the table above, offset by a related decrease of $85 million in purchased power for 2003.
Genco
Genco’s electric margin increased $61 million in 2004, as compared with 2003. The increase in electric margin was primarily attributable to an increase in wholesale and retail margins due to sales to new customers and increased availability of lower-cost generation. Interchange margins increased $14 million in 2004, as compared with 2003 because power prices were higher and more low-cost power was available for sale due to the mild weather.
Genco’s electric margin increased $43 million in 2003 as compared with 2002. Increases in electric margin in 2003 were primarily attributable to increased margins on interchange sales. Interchange margins on interchange sales increased $33 million in 2003 because of improved power prices in the energy markets. Fuel and purchased power increased $2 million in 2003 because of higher purchased power costs associated with higher energy prices and lower generation availability. These increased costs were partially offset by lower generation costs due to a 12% decline in megawatthour generation. The decline in generation during 2003 was primarily attributable to the timing of outages at Genco’s power plants and unexpected downtime and unfavorable margins associated with Genco’s CTs.
CILCORP and CILCO
Electric margin decreased $14 million at CILCORP and $7 million at CILCO in 2004 as compared with 2003. Decreases in electric margin were primarily attributable to reduced revenues due to two large CILCO industrial customers switching to Marketing Company in July and October 2003 and transfers of other non-rate-regulated customers to Marketing Company ($168 million). Fuel and purchased power also decreased because several customers switched to Marketing Company.
CILCORP’s electric margin decreased $13 million and CILCO’s electric margin decreased $14 million in 2003 as compared with 2002. Decreases in electric margin in 2003 were primarily attributable to lower margin per megawatthour sold on a non-rate-regulated basis to electric customers outside CILCO’s service territory, the switch of the two large CILCO customers to Marketing Company discussed above, and unfavorable weather conditions. In addition, fuel and purchased power at CILCORP increased as compared with CILCO, because of the net effect of purchase accounting fair value adjustments related to emission allowances, partially offset by those associated with coal contracts.
IP
IP’s electric margin increased $16 million in 2004 as compared with 2003. The increase in electric margin was principally due to lower purchased power costs as a result of purchase accounting adjustments ($26 million). Revenues were reduced because of unfavorable summer weather. Electric margin was also unfavorably affected by industrial customers who chose alternative suppliers.
The decrease in electric margin of $47 million in 2003 as compared with 2002 reflected lower residential and commercial sales volume due to cooler summer weather, the full-year impact of the 5% residential rate decrease that was effective May 1, 2002; and lower industrial sales due to the combined effect of customers who chose alternative suppliers and general economic conditions. Electricity purchases increased in 2003 as compared with 2002. A higher average cost per unit was offset by lower purchased volumes due to the cooler weather and economic conditions. Decreased interchange revenues in 2003 resulted from the favorable reversal of previously recorded litigation reserves with an interchange customer in 2002.
Gas Operations
The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, as compared with the prior periods for the years ended December 31, 2004 and 2003. We consider gas margin to be a useful measure to analyze the change in profitability of our gas utility operations between periods. We have included the table below as a complement to our financial information provided in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we are providing elsewhere in this report.
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
Includes predecessor information for periods prior to January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
Includes predecessor information for periods prior to September 30, 2004.
Gas margins at Ameren, UE, CIPS, CILCORP and CILCO increased in 2004 primarily because of delivery rate increases, partially offset by milder winter weather conditions. Ameren’s gas margin also increased $13 million because of the additional month of CILCORP results and $40 million because of the three months of IP results in 2004. Excluding the additional month of CILCORP and the three months of IP in 2004, Ameren’s sales were down 5% as a result of the mild winter weather conditions. IP’s gas margin decreased $4 million in 2004 as compared with 2003, primarily because of milder winter weather in 2004.
Ameren’s gas margin increased in 2003 as compared with 2002, primarily because of $73 million added by the acquisition of CILCORP. The gas margins at UE, CIPS, CILCORP and CILCO in 2003 were comparable to 2002 as heating degree-days were consistent with 2002. Gas margin at IP was higher in 2003 as compared with 2002 because of colder weather in the first quarter of 2003 in IP’s service territory.
Operating Expenses and Other Statement of Income Items
Other Operations and Maintenance
Ameren
Ameren’s other operations and maintenance expenses increased $113 million in 2004 as compared with 2003. The additional month of CILCORP results and three months of IP results in the current year accounted for $15 million and $43 million, respectively, of other operations and maintenance expense in 2004 as compared with 2003. Additionally, expenses at Ameren increased $55 million in 2004, primarily because of increased maintenance expenses stemming from
the refueling and maintenance outage at UE’s Callaway nuclear plant during the second quarter of 2004. The outage lasted 64 days and resulted in incremental maintenance costs of $39 million. Refueling and maintenance outages occur approximately every 18 months. They typically include the replacement of fuel and the performance of maintenance and inspections. The previous refueling and maintenance outage occurred in the fall of 2002. In addition to the Callaway nuclear plant outage expenses, employee benefit costs were $43 million higher, primarily because of increased pension and postretirement medical costs. The adoption in the second quarter of 2004, retroactive to January 1, 2004, of FASB Staff Position SFAS No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” resulted in the recognition of nontaxable federal subsidies expected to be provided under the Medicare Prescription Drug, Improvement and Modernization Act (the Medicare Prescription Drug Subsidy), which partially offset the employee benefit cost increases noted above ($11 million). See Note 1 - Summary of Significant Accounting Policies and Note 11 - Retirement Benefits to our financial statements under Part II, Item 8, of this report for further information. Expenses at Ameren, UE and CIPS were reduced in 2004 by $18 million, $13 million, and $5 million, respectively, from the refund to UE and CIPS of previously paid exit fees upon their re-entry into the MISO. Lower labor costs ($21 million) in 2004 also partially offset the above increases to other operations and maintenance expenses.
Ameren’s other operations and maintenance expenses increased $64 million in 2003 as compared with 2002, primarily due to the $135 million added by the acquisition of CILCORP, transition costs related to the CILCORP acquisition, higher employee benefit costs ($17 million), and a net increase in injuries and damages costs based on claims experience ($6 million). These increases in other operations and maintenance expenses were partially offset by lower labor costs resulting primarily from the voluntary employee retirement program implemented in early 2003 and lower plant maintenance costs because of the number and timing of outages ($60 million). There was no refueling outage at the Callaway nuclear plant in 2003.
UE
Other operations and maintenance expenses at UE increased $38 million in 2004 as compared with 2003, primarily because of increased power plant maintenance expenses as a result of the refueling and maintenance outage at UE’s Callaway nuclear plant discussed above ($39 million). In addition to the Callaway outage expenses, employee benefit costs were increased by $8 million. These were primarily increased pension costs, partially offset by reduced postretirement costs due to the adoption of FASB Staff Position SFAS No. 106-2, noted above. In addition, the refund of exit fees upon UE’s re-entry into the MISO as discussed above ($13 million) also partially offset the increased costs.
UE’s other operations and maintenance expenses decreased $49 million in 2003 as compared with 2002, primarily because of lower labor costs related to the voluntary employee retirement program implemented in early 2003 and lower plant maintenance costs ($34 million), partially offset by the higher employee benefit costs ($10 million) and an increase in injuries and damages costs ($3 million).
CIPS
CIPS’ other operations and maintenance expenses decreased $8 million in 2004 as compared with 2003, primarily because of CIPS’ portion of the MISO exit fee refund ($5 million) as discussed above and lower labor costs, partially offset by increased employee benefit costs ($2 million).
CIPS’ other operations and maintenance expenses decreased $5 million in 2003 as compared with 2002, primarily because of lower labor costs related to the voluntary employee retirement program implemented in early 2003, and a decrease in environmental remediation costs ($3 million), partially offset by an increase in injuries and damages costs of $8 million.
Genco
Other operations and maintenance expenses at Genco decreased $6 million in 2004 as compared with 2003, primarily because of a reduction in power plant maintenance ($10 million) as a result of fewer outages and lower labor costs, partially offset by increased employee benefit costs ($5 million).
Genco’s other operations and maintenance expenses decreased $21 million in 2003 as compared with 2002, primarily because of a reduction in consulting costs at its coal-fired generation plants, a decrease in commitment fees for the use of UE’s and CIPS’ electric transmission lines ($5 million), and a net decrease in injuries and damages costs ($3 million).
CILCORP and CILCO
CILCORP’s other operations and maintenance expenses increased by $41 million in 2004 as compared with 2003, primarily because of higher employee benefit costs ($12 million), and additional injuries and damages costs ($4 million). Pursuant to an arrangement entered into between Ameren and AES in conjunction with the acquisition of CILCORP, AES indemnified CILCORP and CILCO for the $13 million after-tax cost of the $21 million settlement of a litigation claim by Enron Power Marketing Inc. As a result, other operations and maintenance expenses includes the net
cost of $8 million while income taxes reflect a tax benefit of $8 million, resulting in no net income statement effect. See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information on the Enron Power Marketing, Inc. litigation claim.
CILCO’s other operations and maintenance expenses increased $33 million in 2004 as compared with 2003, primarily because of the litigation settlement, discussed above, additional injuries and damage costs ($4 million), increased maintenance ($3 million), increased technology expenses ($3 million), and higher overhead allocations. Partially offsetting these increases to other operations and maintenance expenses at CILCORP and CILCO were reduced labor costs in 2004.
CILCORP’s other operations and maintenance expenses in 2003 were comparable to 2002. CILCO’s other operations and maintenance expenses increased $19 million in 2003 as compared with 2002, primarily due to higher employee benefit costs ($19 million) and higher bad debt expense ($5 million), substantially offset by reduced environmental costs ($9 million) for remediation of elevated boron levels at the Duck Creek power plant recycle pond in 2002.
IP
IP’s other operations and maintenance expenses decreased $19 million in 2004 as compared with 2003. The decrease primarily resulted from the reimbursement of the MISO exit fee and RTO development costs ($9 million), as well as reduced labor costs and other operating efficiencies ($12 million), partially offset by higher employee benefit costs ($8 million) and costs associated with injuries and damages reserves.
The increase in other operations and maintenance expenses at IP of $12 million for 2003 over 2002 was primarily due to higher employee benefit costs ($11 million) and insurance claims and an increase in legal reserves ($16 million), partially offset by operating efficiencies and reduced technology expenditures ($14 million).
Voluntary Retirement and Other Restructuring Charges and Coal Contract Settlement
See Note 7 - Restructuring Charges and Other Special Items to our financial statements under Part II, Item 8, of this report.
Depreciation and Amortization
versus 2003
Ameren’s, UE’s and IP’s depreciation and amortization expenses increased $38 million, $10 million and $2 million, respectively, in 2004 as compared with 2003, because of capital additions. Depreciation and amortization expenses at Ameren also increased in 2004 because of the inclusion of the additional month of CILCORP expenses of $6 million and three months of IP expenses of $21 million. Amortization of regulatory assets at IP decreased $9 million in 2004 from 2003 as the transition cost regulatory asset was written off in purchase accounting in conjunction with Ameren’s acquisition of IP.
Depreciation and amortization expenses at CIPS and Genco in 2004 were comparable to 2003.
Depreciation and amortization expenses at CILCORP and CILCO decreased $9 million and $6 million, respectively, in 2004 as compared with 2003, primarily because reduced expenses as a result of property retirements at the end of 2003 exceeded the increased expense from new capital additions in 2004. CILCORP depreciation was also favorably affected by reduced purchase accounting amortization adjustments.
versus 2002
Depreciation and amortization expenses increased $88 million and $6 million at Ameren and Genco, respectively, in 2003 as compared with 2002. The increase at Ameren was primarily due to the inclusion of $72 million of CILCORP expense in 2003. In addition, depreciation and amortization expenses increased at Ameren and Genco because of new capital additions.
Depreciation and amortization expenses increased $3 million at UE in 2003 as compared with 2002, primarily because of capital additions, partially offset by a decrease of $5 million resulting from a reduction in depreciation rates. The reduction in depreciation rates of $5 million in 2003 was based on the updated analysis of asset values, service lives, and accumulated depreciation levels that was required by UE’s 2002 Missouri electric rate case settlement.
Depreciation and amortization expenses increased $6 million at CILCORP in 2003 as compared with 2002, primarily because of purchase accounting adjustments that increased the book value of the Duck Creek and E.D. Edwards power plants and the Sterling Avenue peaking station ($7 million).
Depreciation and amortization expenses at CIPS, CILCO and IP in 2003 were comparable to 2002. Amortization of regulatory assets at IP decreased $32 million in 2003 from 2002 primarily due to reduced amortization of the transition cost regulatory asset. In 2002, IP’s increased financial performance allowed for additional recognition of amortization as compared with 2003.
Taxes Other Than Income Taxes
versus 2003
Taxes other than income taxes increased $13 million at Ameren in 2004 as compared with 2003. Excluding the additional month of CILCORP ($6 million) and the three months of IP $15 million included in the current year, taxes other than income taxes decreased $8 million. The decrease was primarily due to decreased gross receipts taxes, partially offset by increased property taxes.
UE’s taxes other than income taxes increased $9 million in 2004 as compared with 2003, primarily because property taxes were higher in 2004.
Taxes other than income taxes at CIPS, Genco and IP in 2004 were comparable to 2003.
Taxes other than income taxes decreased at CILCORP and CILCO by $13 million and $14 million, respectively, in 2004 as compared with 2003, primarily because gross receipts taxes were down as a result of customers’ switching to Marketing Company.
versus 2002
At Ameren, taxes other than income taxes increased $37 million in 2003 as compared with 2002, primarily because the acquisition of CILCORP added $34 million.
At UE, taxes other than income taxes decreased $5 million in 2003 as compared with 2002, because of a decrease in gross receipts taxes ($2 million) related to lower native load customer sales in milder weather and a decrease in real estate taxes resulting from lower assessments in 2003.
Taxes other than income taxes at IP increased $10 million in 2003 as compared with 2002, primarily because 2002 expenses benefited from a favorable audit conclusion on gross receipts taxes of $4 million.
At Genco, taxes other than income taxes increased $9 million in 2003 as compared with 2002, primarily because of adjustments related to property tax assessments and increased property taxes associated with the four CTs added in the third and fourth quarters of 2002.
CIPS’, CILCORP’s and CILCO’s taxes other than income taxes in 2003 were comparable to 2002.
Other Income and Deductions
versus 2003
Ameren’s other income and deductions increased $18 million in 2004 as compared with 2003, primarily because of increased interest income ($8 million) from the temporary investment of proceeds from Ameren’s February and July 2004 equity offerings and increased allowance for funds used during construction ($6 million). The additional month of CILCORP results and three months of IP results in the current year had a minimal impact on other income and deductions.
Total other income at IP decreased $35 million in 2004 as compared with 2003, primarily because interest income was reduced after the elimination of IP’s Note Receivable from Former Affiliate in conjunction with Ameren’s acquisition of IP. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for a discussion of the note elimination. Other income and deductions includes interest income of $128 million for 2004 as compared with $170 million in 2003 under IP’s Note Receivable from Former Affiliate.
Other income and deductions at UE, CIPS, Genco, CILCORP and CILCO were comparable in 2004 to 2003. See Note 8 - Other Income and Deductions to our financial statements under Part II, Item 8, of this report for further information.
versus 2002
Ameren’s and UE’s net other income increased $34 million and $20 million, respectively, in 2003 as compared with 2002, primarily because of the expensing of economic development and energy assistance programs required by the UE Missouri electric rate case settlement in 2002 ($26 million). Ameren’s other income also increased in 2003 because of a decrease in the minority interest related to EEI’s lower earnings in 2003. The increase in UE’s other income was partially offset by a net decrease in earnings from UE’s ownership interest in EEI and decreased gains on derivative contracts.
CIPS’ other income decreased in 2003 as compared with 2002, primarily because of a decline in intercompany interest income ($3 million) CIPS received on the Genco subordinated promissory note due to a lower outstanding principal balance. In addition, CIPS’ other income decreased in 2003 as compared with 2002, because of a decrease in contributions in aid of construction ($2 million).
Genco’s, CILCORP’s and CILCO’s other income and deductions in 2003 were comparable to 2002.
IP’s total other income increased $5 million in 2003 as compared with 2002, due to a gain recognized in 2003 related to an asset retirement obligation, along with reduced losses on disposal of property and a general reduction in nonoperating expenses.
Interest
versus 2003
Interest expense for Ameren in 2004 was comparable to 2003. However, excluding the additional month of CILCORP results and three months of IP results in the current year, interest expense decreased at Ameren by $20 million. The decrease was primarily due to the redemption of $150 million of Ameren floating rate notes at the end of 2003 and reduced short-term borrowings, as well as redemptions of long-term debt during 2004 and 2003 at its subsidiaries, as noted below.
Genco’s interest expense was reduced $7 million in 2004 as compared with 2003, primarily due to a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren along with decreased borrowings from Ameren’s non-state-regulated subsidiary money pool. The balance of intercompany notes payable to CIPS and Ameren was $283 million at December 31, 2004, as compared to $411 million at December 31, 2003, and $462 million at December 31, 2002.
Interest expense decreased $1 million at CILCO in 2004 as compared with 2003, primarily because of the redemption of long-term debt of $119 million in 2004 and $100 million in 2003, partially offset by increased intercompany borrowings.
Interest expense was flat at CILCORP in 2004 as compared to 2003. Redemptions of debt at CILCO, noted above, and repurchases of an aggregate of $40 million of CILCORP debt in 2004 and 2003, respectively, were offset by increased intercompany borrowings.
Interest expense decreased $32 million at IP in 2004, as compared to 2003, primarily due to redemptions and repurchases of indebtedness of $700 million in 2004 and $190 million in 2003, reductions in the notes payable to IP SPT, and purchase accounting amortization. See Note 5 - Short-term Borrowings and Liquidity and Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for further information.
Interest expense at UE and CIPS in 2004 was comparable to 2003.
versus 2002
Interest expense increased $63 million at Ameren in 2003 as compared to 2002, primarily because the assumption of CILCORP debt added $48 million to interest expense. In addition, interest expense was higher in 2003 because Genco issued $275 million of 7.95% senior notes in June 2002 ($10 million).
Interest expense decreased $7 million at CIPS in 2003 as compared with 2002, primarily because of the maturity or redemption of first mortgage bonds in the third quarter of 2002 ($2 million) and in the second quarter of 2003 ($5 million).
Interest expense increased $15 million at Genco in 2003 as compared with 2002, primarily because of increased borrowings from Ameren’s non-state-regulated subsidiary money pool ($9 million), partially offset by a reduction in the principal amounts outstanding on subordinated intercompany promissory notes to CIPS and Ameren in May 2003 ($4 million). In addition, Genco’s interest expense increased in 2003 as compared with 2002, primarily because $275 million of 7.95% senior notes were issued in June 2002.
Interest expense decreased $12 million at CILCORP and $5 million at CILCO in 2003 as compared with 2002, primarily because of the redemption of long-term debt, partially offset by expenses associated with debt redemption. In addition, CILCORP interest expense decreased $7 million from the amortization of purchase accounting adjustments that recorded CILCORP's debt at fair value.
Interest expense increased $51 million at IP in 2003 primarily because of the additional issuances of $150 million and $400 million 11.50% mortgage bonds in 2003 and 2002, respectively, partially offset by the reduction in IP SPT transitional funding trust notes, the redemption of IP’s $100 million and $90 million mortgage bonds in August and September 2003, respectively, and the repayment of IP’s $300 million term loan ($200 million repaid in December 2002 and $100 million repaid in May 2003).
UE’s interest expense in 2003 was comparable to 2002.
Income Taxes
versus 2003
Income tax expense was lower at Ameren in 2004 as compared with 2003, because of a lower effective tax rate. The effective tax rate was lower primarily because of the recording in 2004 of the expected nontaxable federal Medicare Prescription Drug Subsidy and a tax benefit related to CILCO’s settlement of a litigation claim.
Income tax expense increased at CIPS in 2004 as compared to 2003, primarily due to higher pretax income in 2004 and an Illinois tax settlement in the third quarter of 2003, which resulted in reduced income taxes in the prior-year period. Income tax expense increased at Genco and IP in 2004 as compared with 2003, primarily because of higher pretax income in 2004. Income tax expense decreased at UE primarily because of lower pretax income in 2004. The recording of the nontaxable federal Medicare Prescription Drug subsidy lowered taxable income at all the Ameren companies. Income tax expense decreased at CILCORP and CILCO primarily because of a tax benefit of $8 million as a result of CILCO’s settlement of a litigation claim and lower
pretax income in 2004. See also Note 13 - Income Taxes to our financial statements under Part II, Item 8, of this report for information regarding effective tax rates.
versus 2002
Income tax expense increased at Ameren, UE and Genco in 2003 as compared with 2002, primarily because of higher pretax income, partially offset by a lower effective tax rate at Ameren. The lower effective tax rate was primarily due to an Illinois tax settlement ($7 million) at CIPS in the third quarter of 2003. Income tax expense decreased at CILCO and IP primarily because of lower pretax income. CILCORP’s income tax expense in 2003 was comparable to 2002.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. For cash flow, Genco principally relies on sales to an affiliate under a contract expiring at the end of 2006 and sales to other wholesale and industrial customers under long-term contracts. In addition, we plan to use short-term borrowings to support normal operations and other temporary capital requirements.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
Includes predecessor information for periods prior to January 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
amounts include financial information prior to the acquisition date of September 30, 2004; all amounts prior to September 30, 2004, represent predecessor information.
Cash Flows from Operating Activities
versus 2003
Cash flows provided by operating activities increased for Ameren in 2004 as compared with the same period in 2003. The increase in cash flows provided by operating activities was primarily due to incremental earnings from the acquisition of IP in the fourth quarter of 2004, lower cash taxes paid with the pension contribution, IP debt redemption premiums, and accelerated tax depreciation. Ameren and UE also received $36 million in 2004 as compared with $15 million in 2003, as a result of UE’s settlement in 2003 of a dispute over mine reclamation issues with a coal supplier, which benefited cash flows from operating activities.
Cash flows from operating activities from all the Ameren Companies, except IP, were negatively affected in 2004 by a $295 million pension contribution made by Ameren (UE - $186 million; CIPS - $33 million; Genco - $29 million; CILCORP and CILCO - $41 million).
Cash flows provided by operating activities increased for CIPS, CILCORP, CILCO and IP in 2004 as compared with 2003, primarily because of the increased earnings discussed under Results of Operations and less cash taxes paid. CILCORP and CILCO also benefited from net income tax refunds of $40 million and $20 million, respectively. IP’s cash flows from operations benefited from the 2004 recovery of prepayments related to IP natural gas purchase contracts made in 2003. These benefits in 2004 were partially offset at UE, CIPS, Genco, CILCORP, and CILCO by the pension contribution. IP’s cash flows from operations were negatively affected by the timing of IP’s income tax reimbursements to Dynegy and the effect of the acquisition on tax payments to Dynegy. Deferred taxes at IP in 2004 benefited from debt redemption premiums and accelerated tax depreciation resulting from the acquisition.
Genco’s cash flows provided by operating activities decreased in 2004 as compared with 2003, primarily because of the timing differences associated with income taxes and the increased pension contributions, partially offset by increased earnings.
versus 2002
Cash flows provided by operating activities increased for Ameren and Genco and decreased for UE, CIPS, CILCORP and CILCO in 2003 as compared with 2002. The increase in cash flows provided by operating activities for Ameren and Genco was primarily a result of the increased net earnings discussed above under Results of Operations. Ameren’s increase in earnings in 2003 as compared with the same period in 2002 was partially attributable to 11 months of CILCORP’s earnings in 2003 associated with the acquisition. Genco’s cash flows from operating activities also increased with the receipt of a $76 million tax refund. The increase at Ameren was reduced by two noncash components of net earnings. One was associated with the gain of $18 million related to the adoption of SFAS No. 143. The other was the $51 million pretax gain related to UE’s settlement of the coal mine reclamation issues, of which only $15 million was received in cash during 2003.
Partially offsetting these benefits to cash flows from operating activities were increased materials and supplies inventories resulting from higher natural gas volumes put into storage and higher natural gas prices.
Cash provided by operating activities decreased for UE, CIPS, CILCORP and CILCO in 2003 as compared with 2002 primarily because of increased working capital requirements and timing differences. UE’s decrease in cash flows from operating activities was attributable to increased tax payments and natural gas inventory increases, partially offset by lower operations and maintenance expenses and UE’s settlement of the coal mine reclamation issues, of which $15 million was received in cash during 2003. CIPS’ decrease in cash flows from operating activities was primarily attributable to increased tax payments in 2003 as compared with 2002.
IP’s cash flows provided by operating activities decreased in 2003 as compared with 2002 because of the increased earnings discussed above in Results of Operations and because of changes in working capital primarily related to timing differences in cash flows. Cash flows were positively affected in 2003 by the receipt of one additional month of interest income on IP’s Note Receivable from Former Affiliate. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of the Note Receivable from Affiliate. IP’s decrease in cash flows provided by operating activities was partially offset by higher priced natural gas inventories and higher prepayments due to increased collateral requirements on natural gas purchases.
Pension Funding
The Ameren Companies, excluding IP, and EEI made cash contributions totaling $295 million in 2004 and $27 million in 2003 to Ameren’s defined benefit retirement plan qualified trust. The cash contributions in 2004 and 2003 to Ameren’s defined benefit retirement plan qualified trusts will, among other things, provide cost savings because they will allow us to avoid paying a portion of the insurance premiums to the Pension Guarantee Trust Corporation and will mitigate future benefit cost increases. Based on our assumptions at December 31, 2004, we expect to be required under ERISA to fund an aggregate of $400 million for the period of 2005 to 2009 in order to maintain minimum funding levels for our pension plan; no minimum contribution will be required until 2008, assuming continuation of the current federal interest rate relief beyond 2005. We expect UE’s, CIPS’, Genco’s, CILCO’s and IP’s portion of the future funding requirements to be approximately 50%, 9%, 9%, 11% and 21%, respectively. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any prior voluntary contributions. See Note 11 - Retirement Benefits to our financial statements under Part II, Item 8, of this report for additional information.
Cash Flows from Investing Activities
versus 2003
Cash flows used in investing activities increased for Ameren, UE, CILCORP and CILCO and decreased for Genco in 2004 as compared with 2003. Included in Ameren’s cash flows used in investing activities was $443 million of net cash paid for the acquisition of IP and Dynegy’s 20% interest in EEI in 2004 and $479 million of net cash paid for the acquisition of CILCORP and Medina Valley in 2003. Excluding the cash paid for acquisitions in 2004 and 2003, Ameren’s cash flows used in investing activities increased in 2004 as compared with 2003, primarily because of increased capital expenditures, discussed below, at UE, CILCORP, and CILCO, and the addition of IP’s capital expenditures after the acquisition date.
CIPS’ cash flows provided by investing activities increased in 2004 as compared with 2003 principally because of increased cash receipts related to the intercompany note receivable from Genco. The note receivable from Genco was issued in conjunction with the transfer of CIPS’ generating assets and liabilities to Genco in 2000. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for further discussion of the note receivable. CIPS’ cash flows provided by investing activities also increased due to decreased capital expenditures incurred in 2004 as compared with 2003.
Genco’s cash flows used in investing activities decreased, principally because capital expenditures were lower in 2004 than in 2003.
IP’s cash flows used in investing activities increased principally because of contributions made to the money pool in 2004.
versus 2002
Cash flows used in investing activities increased for Ameren and UE and decreased for CIPS, Genco, CILCORP and CILCO in 2003 as compared with 2002. Ameren’s increase in cash used in investing activities in 2003 as compared with 2002 was primarily related to $479 million in net cash paid for the acquisitions of CILCORP and Medina Valley in early 2003 and capital expenditures for CILCORP in 2003. These increased investing activities in 2003 were partially offset by lower construction expenditures at other Ameren subsidiaries and lower nuclear fuel expenditures in 2003. The increase for UE in 2003 over the prior-year period was primarily related to the 2002 receipt of $84 million UE had invested in the utility money pool, partially offset by lower construction and nuclear fuel expenditures in 2003. The decrease in 2003 cash flows used in investing activities from the prior-year period for Genco was primarily related to lower construction expenditures as Genco completed construction of CTs in 2002. In addition, Genco paid $140 million in the first quarter of 2002 to Development Company for a CT purchased, but not yet paid for, at December 31, 2001. The decrease for CILCORP and CILCO was primarily due to lower construction expenditures related to the completed installation of pollution-control equipment at their coal-fired power plants. The increase in cash provided by investing activities for CIPS was primarily due to principal payments received on its intercompany note receivable from Genco.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2004, 2003, and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
amounts represent predecessor information. 2003 amounts include January 2003 predecessor information of $16 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
and 2002 amounts represent predecessor information. 2004 includes amounts totaling $100 million incurred prior to the acquisition date of September 30, 2004.
(d) Consists primarily of capital expenditures by Ameren Services and includes intercompany transactions between Development Company and Genco related to Genco's purchase of a CT in 2002.
Ameren’s capital expenditures for 2004 principally related to various upgrades at UE’s power plants, including the replacement of condenser bundles, low-pressure rotor equipment and steam generators, and other upgrades completed during the refueling and maintenance outage at UE’s Callaway nuclear plant. The replacement and upgrade work at UE’s Callaway plant resulted in capital expenditures of $40 million in 2004. UE also incurred capital expenditures related to the installation of new CTs at its Venice plant and replacement of turbines at its Sioux and Rush Island power plants in 2004. In addition, UE’s capital expenditures included environmental and other upgrades at UE power plants and expenditures incurred for new transmission and distribution lines. CILCORP’s and CILCO’s capital expenditures in 2004 were primarily related to power plant upgrades made at the Edwards and Duck Creek plants in order for CILCO’s non-rate-regulated subsidiary, AERG, to have more flexibility in future fuel supply for power generation. Genco’s use of cash in 2004 for capital expenditures was primarily attributed to the replacement of a turbine generator at its Coffeen power plant. Capital expenditures at IP consisted of numerous projects to upgrade and maintain the reliability of IP’s electric and gas transmission and distribution systems and to add new customers to the system.
Ameren’s capital expenditures for 2003 principally related to various upgrades at UE’s and Genco’s coal-fired power plants, NOx reduction equipment expenditures at CILCO’s generating plants, replacements and improvements to the existing electric transmission and distribution system and natural gas distribution system, and construction costs for CTs at UE. In 2002, UE placed into service 240 megawatts of CT capacity (approximately $135 million). In addition, Genco placed into service 470 megawatts of CT capacity (approximately $215 million). Also in 2002, Genco paid approximately $140 million to Development Company for a CT purchased but accrued for in December 2001. In addition, selective catalytic reduction technology was added on two units at one of Genco’s coal-fired power plants at a cost of $42 million.
The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2005 through 2009, including construction expenditures, capitalized interest and allowance for funds used during construction (except for Genco which has no allowance for funds used during construction) and estimated expenditures for compliance with environmental standards:
(a)
AERG capital expenditures related to CILCO’s non-rate-regulated generating business.
(b)
Includes amounts for non-Registrant Ameren subsidiaries.
UE’s estimated capital expenditures include the replacement of steam generators at UE’s Callaway nuclear plant, estimated at $70 million, and transmission, distribution and other generation-related activities, as well as for compliance with new NOx control regulations discussed below. Also included in the estimate is the addition of new CTs with approximately 330 megawatts of capacity at UE’s Venice, Illinois power plant site by the end of 2005. Total costs expected to be incurred for these units at the Venice power plant are $125 million.
UE committed to make between $2.25 billion to $2.75 billion of infrastructure investments during the period January 1, 2002, to June 30, 2006, as part of UE’s 2002 Missouri electric rate case settlement, including the addition of 700 megawatts of generation capacity. The new capacity requirement is expected to be satisfied by the addition of 240 megawatts in 2002 and the proposed transfer from Genco to UE, at net book value (approximately $240 million), of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois. As of December 31, 2004, UE had expended $1.5 billion toward the 2002 rate case settlement. In addition, commitments totaling at least $15 million for gas infrastructure improvements between July 1, 2003, and June 30, 2006, were agreed upon as part of UE’s 2003 Missouri gas rate case settlement See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further discussion of these regulatory proceedings.
CIPS’ and CILCO’s estimated capital expenditures are primarily for transmission and distribution-related activities. Genco’s estimated capital expenditures are primarily for upgrades to existing coal and gas-fired generating facilities and other generation-related activities. CILCO’s estimate also includes capital expenditures for generation-related activities, as well as for compliance with new NOx control regulations at AERG’s generating facilities.
IP’s estimated capital expenditures include energy infrastructure improvements of $275 million to $325 million through 2006. This commitment was made to the ICC by Ameren in conjunction with the acquisition of IP. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further explanation of IP’s infrastructure commitment.
We continually review our generation port-folio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.
Environmental Capital Expenditures
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program created marketable commodities called allowances. Each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances that are based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, the use of low-sulfur fuels, and through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program applies to all electric generating units in Illinois beginning in 2004; it applies to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low NOx burners, over fire air systems, combustion optimization, and selective catalytic reduction systems.
As of December 31, 2004, UE, Genco, CILCO and EEI held 1.6 million, 0.4 million, 0.2 million, and 0.3 million tons, respectively, of SO2 emission allowances with vintages from 2004 to 2012. Each company possesses additional allowances for use in periods beyond 2012. As of December 31, 2004, UE, Genco, CILCO and EEI Illinois facilities held 290 tons, 22,400 tons, 6,300 tons and 8,600 tons, respectively, of NOX emission allowances with vintages from 2004 to 2007. The Illinois EPA is still determining some NOx emission allowance allocations for this period and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Allocations of NOx allowances for Missouri facilities will be made when rules are finalized by Missouri regulators. New environmental regulations, including the Clean Air Interstate Rule as discussed below, the timing of the installation of pollution control equipment, and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations.
In mid-December 2003, the EPA issued proposed regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions from coal-fired power plants. The new rules, if adopted, will require significant additional reductions in these emissions from UE, Genco and CILCO power plants in phases, beginning in 2010. The rules are currently under a public review and comment period and may change before being issued as final. We do not expect regulations to be finalized until the first half of 2005. The
following table presents preliminary estimated capital costs based on current technology for the Ameren systems to comply with the Clean Air Interstate Rule and mercury rules, as proposed.
The timing of estimated capital costs between periods at UE will be influenced by whether excess emission credits are used to comply with the proposed rules, thereby deferring
capital investment. Amounts for 2005 and 2006 to 2009 are included in our estimated capital expenditures table above.
See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a further discussion of environmental matters.
Cash Flows from Financing Activities
versus 2003
Cash flows from financing activities increased for Ameren in 2004 as compared with 2003 principally because more proceeds were received from the issuance of common stock, short-term debt, and long-term debt; it totaled $2.2 billion in 2004 as compared with $1.1 billion in 2003. Proceeds of $1.3 billion received from the issuance of common stock in February 2004 and July 2004 were used to fund the cash portion of the purchase price for the acquisition of IP and Dynegy’s 20% interest in EEI and to reduce high-cost IP debt assumed as part of the transaction and to pay related premiums. Proceeds received from the issuance of common stock in 2003 and 2002 were principally used by Ameren for the acquisition of CILCORP in January 2003. See Note 2 - Acquisitions and Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for further information. Proceeds received from the issuance of common stock in 2004 were temporarily used to repay a $100 million term loan at CILCO and to repay short-term debt totaling $181 million pending their use for the acquisition and recapitalization of IP. A portion of the short-term debt was also used to temporarily fund UE’s maturity of long-term debt totaling $85 million in December 2004.
Ameren’s increase in cash flows from financing activities was partially offset by increased redemptions, repurchases and maturities of short-term debt, long-term debt, and preferred stock, and by the nuclear fuel lease termination payment totaling $1.5 billion in 2004 as compared with $1.0 billion in 2003. The issuance of additional common shares and long-term debt cost Ameren an incremental $26 million in capital issuance costs in 2004 as compared with 2003. Ameren also paid an additional $69 million in common dividends because more common shares were outstanding in 2004 than in 2003.
UE’s cash flows used in financing activities increased in 2004 as compared with 2003. In 2004, cash provided by borrowings from the utility money pool, short-term debt, and long-term debt issuances totaling $631 million were used for the redemption and refinancing of long-term debt. In January 2004, UE made a $67 million payment in order to terminate its nuclear fuel lease arrangement. Also contributing to UE’s increase in cash used in financing activities were higher incremental dividend payments made to Ameren in 2004 than in 2003.
CIPS’ cash flows used in financing activities increased in 2004 compared with 2003, principally because of $53 million of repayments to the utility money pool arrangement in 2004, compared with $121 million of borrowings from the money pool arrangement in 2003. Increased dividend payments of $13 million to Ameren in 2004 as compared with 2003 contributed to CIPS’ increase in cash used in financing activities. Proceeds received from the issuance of long-term debt in 2004, along with decreased redemptions, repurchases, and maturities of long-term debt and preferred stock in 2004 as compared with 2003 partially offset CIPS’ increase in cash used in financing activities in 2004.
Genco’s cash flows used in financing activities decreased in 2004 as compared with 2003, primarily because of a capital contribution of $75 million received indirectly from Ameren in 2004. The capital contribution received by Genco in 2004 was used for Genco’s prepayment of $75 million of the principal amount outstanding under its intercompany note payable to CIPS. The contribution and cash flows from operations allowed Genco to reduce money pool borrowings in 2004 as compared with 2003. Genco had increased dividend payments in 2004 as compared with 2003.
As of December 31, 2004, Genco had affiliate notes payables of $249 million and $34 million to CIPS and Ameren, respectively, which by their current terms have final payments of principal and interest due on May 1, 2005. The note payable to CIPS was issued in conjunction with the transfer of its electric generating assets and related liabilities to Genco. Genco and CIPS expect to renew or modify the CIPS note to extend the principal maturity, which is expected to include continued amortization of the principal amount. Genco and Ameren are currently evaluating various alternatives with respect to the note payable to Ameren. In the event that the maturities of these notes are not extended or restructured, Genco may need to access other financing sources to meet the maturity obligation to the extent it does not have cash available from its operating cash flows. Such sources of financing could include borrowings under the non-state-regulated subsidiary money pool, or infusion of equity capital,
or new direct borrowings from Ameren, all subject to applicable regulatory financing authorizations and provisions in Genco’s senior note indenture.
CILCORP’s cash flows from financing activities decreased in 2004 as compared with 2003, because of lower borrowings. CILCORP’s borrowings from the utility money pool arrangement and direct intercompany borrowings from Ameren totaled $47 million in 2004 as compared with $195 million in 2003. A capital contribution from Ameren of $75 million and increased cash flows from operations allowed CILCORP to reduce borrowings from the utility money pool. Borrowings from the utility money pool in the first quarter of 2004 were the source of funds for the repayment of CILCO’s $100 million secured bank term loan facility. Proceeds from the issuance of long-term debt were used to redeem a portion of CILCO’s long-term debt in 2004.
CILCO’s cash flows used in financing activities decreased in 2004 as compared with 2003, primarily because of reduced dividend contributions made to CILCORP in 2004 as compared with 2003, and a $75 million capital contribution received indirectly from Ameren in 2004. CILCO’s increase in cash flows from financing activities was partially offset by reduced borrowings from the utility money pool arrangement in 2004 as compared with 2003.
Cash flows from financing activities increased modestly for IP in 2004 as compared with 2003. Capital contributions of $871 million received from Ameren in the fourth quarter of 2004 were used to redeem and repurchase long-term debt of $700 million and to pay related premiums of $103 million; that compares with $376 million in redemptions of short-term debt and long-term debt in 2003. In 2003, proceeds from the issuance of long-term debt and prepaid interest received from an affiliate, which totaled $278 million, were used to redeem short-term and long-term debt.
versus 2002
Cash flows from financing activities decreased for Ameren, Genco, CILCORP and CILCO and increased for UE and CIPS in 2003 as compared with 2002. The decrease in cash flows from financing activities for Ameren, CILCORP and CILCO was primarily due to an increase in redemptions, repurchases, and maturities of long-term debt. The decrease in cash flows from financing activities for Ameren was also due to the termination payment on the UE nuclear fuel lease and the incremental payment of dividends on common stock by Ameren due to increased shares outstanding. In addition, Ameren had decreased proceeds from the issuance of long-term debt and common stock, which totaled $1.1 billion in 2003 as compared with $1.6 billion in 2002. Proceeds from the sale of common shares by Ameren in 2003 and 2002 were primarily used to fund the acquisition of CILCORP, which was completed in January 2003. See Note 2 - Acquisitions to our financial statements under Part II, Item 8, of this report for further detail. Genco’s decrease in cash flows from financing activities resulted from decreased borrowings from the non-state-regulated subsidiary money pool, as well as no issuances of long-term debt in 2003. The decreases in cash flows from financing activities at CILCORP and CILCO were partially offset by proceeds received from intercompany borrowing arrangements by CILCORP and CILCO in 2003.
Cash flows from financing activities increased at UE in 2003 as compared with 2002, primarily because of additional proceeds received from the issuance of long-term debt offset by increased redemptions of debt in 2003 as compared with 2002. Cash flows used in financing activities decreased at CIPS in 2003 as compared with 2002, primarily because of increased proceeds from borrowings from the utility money pool, offset by increased long-term debt payments.
Cash flows from financing activities decreased at IP in 2003 as compared to 2002, principally due to less proceeds received from the issuances of short-term debt and long-term debt totaling $150 million in 2003 as compared with $460 million received in 2002. The proceeds received from these issuances in 2003 and 2002, along with the prepaid interest received from an affiliate totaling $128 million in 2003, and cash flows from operating activities was used to redeem short-term debt and long-term debt totaling $376 million in 2003 as compared with $420 million in 2002. Decreased redemptions of debt partially offset IP’s decrease in cash flows from debt issuances in 2003 as compared with 2002.
Short-term Borrowings and Liquidity
Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities generally from 1 to 45 days. See Note 5 - Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report.
The following table presents the various committed bank credit facilities of certain of the Ameren Companies and EEI as of December 31, 2004:
(a)
Ameren Companies may access these credit facilities through intercompany borrowing arrangements.
At December 31, 2004, certain of the Ameren Companies had committed bank credit facilities totaling $1,164 million, $789 million of which was available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool agreement. At December 31, 2004, UE had $375 million of commercial paper borrowings outstanding, which reduced the available amounts under these facilities. All of the $789 million was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, by CILCORP through direct short-term borrowings from Ameren, and by most of the non-rate-regulated subsidiaries, including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non-state-regulated subsidiary money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for rate-regulated and non-rate-regulated entities. In addition, a unilateral borrowing agreement among Ameren, IP, and Ameren Services enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreements. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement. The committed bank credit facilities are used to support our commercial paper programs under which $375 million was outstanding for Ameren on a consolidated basis at December 31, 2004 ($150 million in 2003). Access to our credit facilities for all Ameren Companies is subject to reduction based on use by affiliates.
The following table summarizes the expiration of amounts available under bank credit facilities that were committed at December 31, 2004:
In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At December 31, 2004, Ameren had $69 million of cash and cash equivalents.
Ameren and UE are authorized by the SEC under PUHCA to have an aggregate of up to of $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. In addition, CIPS, CILCORP and CILCO have PUHCA authority to have an aggregate of up to $250 million each of short-term unsecured debt instruments outstanding at any time. Genco is authorized by the FERC to have up to $300 million of short-term debt outstanding at any time.
We rely on access to short-term and long-term capital markets as a significant source of funding for capital requirements not satisfied by our operating cash flows. Our inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets. Such events might cause our cost of capital to increase or our ability to access the capital markets to be adversely affected.
Long-term Debt and Equity
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt and preferred stock (including any redemption premiums) for the years 2004, 2003 and 2002 for the Ameren Companies, Medina Valley and EEI. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.
(a)
A component of the adjustable conversion-rate equity security units. See Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.
(b)
Includes issuances of common stock of 2.3 million shares in 2004, 2.5 million shares in 2003 and 2.3 million shares in 2002 under DRPlus and 401(k) plans.
(c)
Amounts for CILCORP prior to January 31, 2003, and IP prior to September 30, 2004, have not been included in the total long-term debt and preferred stock redemption and repurchases at Ameren.
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain of the Ameren Companies as of January 31, 2005:
(a)
Ameren issued securities totaling $875 million under the August 2002 shelf registration statement and $459 million under the September 2003 shelf registration statement.
(b)
UE issued securities totaling $200 million in 2003, $404 million in 2004 and $85 million in January 2005.
In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. Ameren is also currently selling newly issued shares of its common stock under certain of its 401(k) plans pursuant to effective SEC Form S-8 registration statements. Under DRPlus and our 401(k) plans, Ameren issued 2.3 million shares of common stock in 2004 valued at $107 million. Under DRPlus and our 401(k) plans, Ameren issued 2.5 million and 2.3 million shares of common stock in 2003 and 2002, respectively, that were valued at $105 million and $93 million for the respective years.
Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under the open registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
See Note 5 - Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for a discussion of the covenants and provisions contained in certain of the Ameren Companies’ bank credit facilities. Also see Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
Dividends
Common Dividends
Ameren paid common stock dividends to its shareholders totaling $479 million, or $2.54 per share, in 2004, $410 million, or $2.54 per share, in 2003, and $376 million, or $2.54 per share, in 2002. This resulted in a payout rate based on net income of 90%, 78% and 98% in 2004, 2003 and 2002, respectively. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 42%, 40% and 44%, respectively.
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has so far not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues including Ameren’s historic earnings and cash flow, projected earnings, cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics and overall business considerations. On February 11, 2005, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on March 31, 2005, to shareholders of record on March 9, 2005.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends. Ameren would experience restrictions on dividend payments if it were to defer contract adjustment payments on its equity security units. UE would experience restrictions on dividend payments if it were to extend or defer interest payments on its subordinated debentures. CIPS has provisions restricting its dividend payments based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit making any dividend payments if debt service coverage ratios are below a defined threshold. CILCORP has restrictions if leverage ratio and interest coverage ratio thresholds are not met or if CILCORP’s senior long-term debt does not have specified ratings as described in its indenture. CILCO has restrictions on dividend payments relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock and amounts to be set aside for any sinking fund retirement of its 5.85% Series preferred stock. At December 31, 2004, none of the conditions described above that would restrict the payment of dividends existed. In its approval of the acquisition of IP by Ameren, the ICC issued an order that provides for the ability of IP to pay dividends on its common stock subject to certain conditions related to credit ratings of IP and Ameren and the elimination of IP’s 11.5% mortgage bonds. Given the current credit ratings of IP and the amount of IP’s 11.5% mortgage bonds that remain outstanding, IP’s payment of dividends on its common stock is restricted to $80 million in 2005 and $160 million cumulatively through 2006. In addition, in accordance with the order issued by the ICC, IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities and consistent with achieving and maintaining a common equity to total capitalization ratio between 50% and 60%.
The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents and also includes amounts retained by Ameren Corporation for the years ended December 31, 2004, 2003, and 2002:
(a)
Prior to February 2003, CILCORP’s dividends would have been paid to AES. These amounts are excluded from the total dividends paid to Ameren. CILCO paid dividends of $10 million, $62 million, and $40 million in 2004, 2003, and 2002, respectively.
(b)
Prior to October 2004, the ICC prohibited IP from paying dividends. If permitted to be paid, IP’s dividends would have been paid directly to Illinova or indirectly to Dynegy.
Preferred Dividends
Certain of the Ameren Companies have issued preferred stock on which they are obliged to make preferred dividend payments. Each company board of directors declares the preferred stock dividends to shareholders of record on a certain date, stating the date on which it is payable and the amount that will be paid. See Note 10 - Stockholder Rights Plan and Preferred Stock to our financial statements under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2004. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for information regarding Ameren’s, UE’s and IP’s capital expenditure commitments, related to UE’s 2002 Missouri electric rate case settlement, UE’s 2003 Missouri gas rate case settlement, and Ameren’s acquisition of IP. See Note 11 - Retirement Benefits to our financial statements under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plan. These capital commitments and expected pension funding amounts are not included in the table below.
(a)
Includes amounts for Registrant and non-Registrant Ameren subsidiaries and intercompany eliminations.
(b)
Excludes fair market value adjustments of long-term debt for CILCORP and IP totaling $83 million and $61 million, respectively.
(c)
The weighted average variable rate debt has been calculated using the interest rate as of December 31, 2004.
(d)
Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $1 million annual obligation for these items is included in the Less than 1 year, 1 - Years, and 4 - Years columns. Amounts for More than 5 Years are not included in the total amount due to the indefinite periods.
(e)
Represents purchase contracts for coal, gas, nuclear fuel and electric capacity. Also represents a decommissioning liability at IP.
(f)
Routine short-term purchase order commitments are not included.
Off-Balance Sheet Arrangements
At December 31, 2004, none of the Ameren Companies had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance sheet financing arrangements in the near future.
Credit Ratings
The following table presents the principal credit ratings by Moody’s, S&P and Fitch as of December 31, 2004:
On July 8, 2004, Moody’s confirmed Ameren’s A3 senior unsecured debt and bank loan ratings along with its A3 issuer rating. Moody’s outlook for these ratings is stable. This rating action concluded Moody’s review of Ameren's long-term ratings that was initiated on February 4, 2004, in connection with Ameren's agreement to purchase IP from Dynegy. Ameren's Prime-2 rating for short-term debt, including commercial paper, was not under review, and was affirmed.
On July 30, 2004, S&P affirmed its A- long-term corporate credit ratings on Ameren, UE, CIPS, Genco, CILCORP and CILCO and removed the ratings from CreditWatch with negative implications. The A-2 short-term credit ratings for Ameren and UE were not on CreditWatch. The outlook is negative for the long-term ratings.
On October 1, 2004, S&P raised its corporate credit rating and senior secured debt rating on IP from B to A- as a result of the completed acquisition of IP by Ameren. At the same time, S&P removed the rating from CreditWatch with positive implications and assigned a negative outlook to the rating. Also on this date, Moody’s upgraded the senior secured debt rating of IP from Ba3 to Baa3 also as a result of the closing of the acquisition. Moody’s has a stable outlook assigned to this rating. These new ratings assigned to IP by S&P and Moody’s are investment-grade.
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and/or increase the cost of borrowings, resulting in a negative impact on earnings. At December 31, 2004, if the Ameren Companies were to receive a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP could have been required to post collateral for certain trade obligations amounting to $76 million, $27 million, $-, $4 million, $2 million, $2 million, and $25 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease based on credit ratings. A credit rating is not a recommendation to buy, sell or hold securities; and it should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the assigning rating organization.
OUTLOOK
We expect the following industrywide trends and Ameren-specific issues to affect earnings in 2005 and beyond:
·
Ameren, CILCORP, CILCO and IP expect to continue to focus on realizing integration synergies associated with these acquisitions, including lower fuel costs at CILCORP and CILCO and reduced administrative and operating expenses at IP.
·
We expect continued economic growth in our service territory to benefit electric demand in 2005.
·
In 2005, we expect natural gas and coal prices to support power prices similar to 2004 levels. Power prices in the Midwest affect the amount of revenues UE, Genco and AERG can generate by marketing any excess power into the interchange markets. Power prices in the Midwest also influence the cost of power we purchase in the interchange markets.
·
Ameren’s coal and related transportation costs rose in 2004 and are expected to rise 3% to 4% in 2005 and again in 2006, and to increase further beyond 2006.
·
Due to recent or future regulatory proceedings, there could be changes to the agreement between UE and Genco to dispatch electric generation jointly. Any change would likely result in a transfer of electric margins between Genco and UE and could ultimately affect the pricing of electric transfers between Genco and UE. Ameren’s earnings could be affected if and when electric rates for UE are adjusted by the MoPSC to reflect any such transfers, amendments to the joint disptach agreement and other changes in costs of providing electric service. See Note 3 - Rate and Regulatory Matters and Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for a more detailed description of the joint dispatch agreement and potential impacts.
·
UE is currently seeking approval from the MoPSC to add Noranda Aluminum to its service territory. This customer’s load requirements represent approximately 5% of UE’s current load. UE is also seeking to transfer its Illinois service territory to CIPS. Genco and UE are seeking to transfer 550 megawatts of CTs from Genco to UE. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
·
UE’s Callaway nuclear plant will have a refueling and maintenance outage in the fall of 2005, which is expected to last 70 to 75 days. During this outage, major capital equipment will be replaced, which means that the outage will last longer than a typical refueling outage, which usually lasts 30 to 35 days and occurs approximately every 18 months. The delivery of some major equipment for this outage is dependent on adequate water levels in the Missouri River. Any delays or damage during shipment could result in additional costs and deferral of the project. During a refueling outage, maintenance and purchased power costs increase, so the amount of excess power available for sale decreases versus non-outage years.
·
Over the next few years, we expect increased expenses for rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may have to take, at UE’s Callaway nuclear plant and our other operating plants.
·
We are currently undertaking cost reduction or control initiatives associated with the strategic sourcing of purchases and streamlining of administrative functions. UE, Genco and CILCO are also seeking to raise the equivalent availability and capacity factors of power plants from our 2004 levels.
·
Electric rates for Ameren's operating subsidiaries have been fixed or declining for periods ranging from 12 years to 22 years. In 2006, electric rate adjustment moratoriums and intercompany power supply contracts expire in Ameren's regulatory jurisdictions. Approximately 8 million megawatthours supplied annually by Genco and 6 million megawatthours supplied annually by AERG have been subject to contracts to provide CIPS and CILCO, through AERG, with power. The prices in these power supply contracts of $34.00 per megawatthour for AERG and $38.50 per megawatthour for Genco were below estimated market prices for similar contracts in February 2005. CIPS, CILCO and IP made a filing with the ICC, in February 2005, outlining, among other things, a proposed framework for generation procurement after 2006. In 2005, Ameren will also begin the process of preparing utility cost-of-service studies for filing in Illinois and Missouri in late 2005 or early 2006 to determine rates for UE, CIPS, CILCO and IP. Based on current assumptions, Ameren expects the average rates for its Illinois utilities, in a combined basis, may increase by 10% to 20% in 2007 over present bundled rate levels, with 50% to 70% of this increase resulting from higher power costs. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
·
The EPA has proposed more stringent emission limits on all coal-fired power plants. Between 2005 and 2015, Ameren expects that certain of the Ameren Companies will be required to invest between $1.4 and $1.9 billion to retrofit their power plants with pollution control equipment. These investments will also result in higher ongoing operating expenses. Approximately two-thirds of this investment will be in Ameren’s regulated Missouri operations and therefore is expected to be recoverable over time from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on the adjustment of market prices for power as a result of this increased investment.
The outcome and developments related to the above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, and opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. Our application of these policies involves judgments regarding many factors which, in and of themselves, could materially affect the financial statements and disclosures. In the table below, we have outlined the critical accounting policies that we believe are most difficult, subjective or complex. A future change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
Accounting Policy
Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery
All of the Ameren Companies, except Genco, defer costs as regulatory assets in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and make investments that they assume will be collected in future rates.
Regulatory environment, external regulatory decisions and requirements
Anticipated future regulatory decisions and their impact
Impact of deregulation, rate freezes, and competition on ratemaking process and ability to recover costs
Basis for Judgment
We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. If facts and circumstances led us to conclude that a recorded regulatory asset was probably no longer capable of being recovered, we would record a charge to earnings, which could be material.
Environmental Costs
We accrue for all known environmental contamination where remediation can be reasonably estimated, but some of our operations have existed for over 100 years and previous contamination may be unknown to us.
Extent of contamination
Responsible party determination
Approved methods for cleanup
Present and future legislation and governmental regulations and standards
Results of ongoing research and development regarding environmental impacts
Basis for Judgment
We determine the proper amounts to accrue for known environmental contamination by using internal and third-party estimates of cleanup costs in the context of current remediation standards and available technology.
Accounting Policy Uncertainties Affecting Application
Unbilled Revenue
At the end of each period, we estimate, based on expected usage, the amount of revenue to record for services that have been provided to customers, but not billed.
Projecting customer energy usage
Estimating impacts of weather and other usage-affecting factors for the unbilled period
Estimating loss of energy during the process of transmission and delivery
Basis for Judgment
We base our determination of the proper amount of unbilled revenue to accrue each period on the volume of energy delivered as valued by a model of billing cycles and historical usage rates and growth by customer class for our service area, as adjusted for the modeled impact of seasonal and weather variations based on historical results.
Valuation of Goodwill, Long-Lived Assets and Asset Retirement Obligations
We assess the carrying value of our goodwill and long-lived assets to determine whether they are impaired. We also review for the existence of asset retirement obligations. If an asset retirement obligation is identified, we determine the fair value of the obligation and subsequently reassess and adjust the obligation, as necessary. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
Management's identification of impairment indicators
Changes in business, industry, technology, or economic and market conditions
Valuation assumptions and conclusions
Estimated useful lives of our significant long-lived assets
Actions or assessments by our regulators
Identification of an asset retirement obligation
Basis for Judgment
Annually, or whenever events indicate a valuation may have changed, we use internal models and third parties to determine fair values. We use various methods to determine valuations, including earnings before interest, taxes, depreciation and amortization multiples, and discounted, undiscounted, and probabilistic discounted cash flow models with multiple scenarios. The identification of asset retirement obligations is conducted through the review of legal documents and interviews.
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of providing future employee benefits in accordance with SFAS Nos. 87, 106 and 112, which provide guidance on benefit plan accounting. See Note 11 - Retirement Benefits to our financial statements under Part II, Item 8, of this report.
Future rate of return on pension and other plan assets
Interest rates used in valuing benefit obligations
Health care cost trend rates
Timing of employee retirements and mortality assumptions
Basis for Judgment
We use a third-party consultant to assist us in evaluating and recording the proper amount for future employee benefits. Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension assets is based on our review of available current, historical and projected rates, as applicable.
Impact of Future Accounting Pronouncements
See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
EFFECTS OF INFLATION AND CHANGING PRICES
Our rates for retail electric and gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by the FERC. Our Missouri electric and gas rates were set through June 30, 2006, as part of the settlement of our Missouri electric and gas rate cases. Our Illinois electric rates are legislatively fixed through January 1, 2007. Even without these moratoriums on rate changes, adjustments to rates are based on a regulatory process that primarily reviews a historical period. As a result, revenue increases will lag changing prices. Inflation affects our operations, earnings, stockholders’ equity, and financial performance.
The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed
to provide recovery of historical costs through depreciation might not be adequate to replace the plant in future years. The generation portion of our business in the Illinois jurisdiction is principally non-rate-regulated and therefore does not have regulated recovery mechanisms.
In our retail electric utility jurisdictions, there are no provisions for adjusting rates to accommodate changes in the cost of fuel for electric generation or the cost of purchased power. In our retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses. UE, Genco, CILCORP and CILCO are affected by changes in market prices for natural gas to the extent they must purchase natural gas to run CTs. They have structured various supply agreements to maintain access to multiple gas pools and supply basins to minimize the impact to the financial statements. See Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk under Part II, Item 7A, of this report for further information.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk represents the risk of changes in value of a physical asset or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates. The following discussion of our risk-management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, are not represented in the following discussion.
Our risk-management objective is to optimize our physical generating assets within prudent risk parameters. Our risk-management policies are set by a Risk Management Steering Committee, which comprises senior-level Ameren officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
·
long-term and short-term variable-rate debt;
·
fixed-rate debt;
·
commercial paper; and
·
auction-rate long-term debt.
We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.
The following table presents the estimated increase (decrease) in our annual interest expense and net income if interest rates were to increase by 1% on variable rate debt outstanding at December 31, 2004:
(a)
Calculations are based on an effective tax rate of 35%.
The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.
Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables, executory contracts with market risk exposures, and leverage lease investments. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2004, no nonaffiliated customer represented greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, Genco and Marketing Company have credit exposure associated with accounts receivables from non-affiliated companies for interchange sales. At December 31, 2004, UE’s, Genco’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange sales was $2 million, net of collateral (2003 - $4 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk-management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition prior to entering into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We are currently
evaluating our credit exposure associated with the expected implementation of the MISO Day Two on April 1, 2005, but we are unable to predict at this time what impact it will have, if any.
Equity Price Risk
Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rate of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of our plan assets was affected by declines in the equity market in 2000 through 2002 for the pension and postretirement plans. As a result, at December 31, 2002, we recognized an additional minimum pension liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” which resulted in an after-tax charge to OCI and a reduction in stockholders’ equity of $102 million. In 2004, an after-tax charge to the minimum pension liability was increased, resulting in OCI of $6 million, offsetting the $46 million of OCI in 2003 from a reduction in the minimum pension liability and an increase in stockholders’ equity. The following table presents the minimum pension liability amounts, after taxes, as of December 31, 2004 and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004, and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
Represents predecessor information in 2003.
The amount of the pension liability as of December 31, 2004, was the result of asset returns, interest rates, and our contributions to the plans during 2004. In future years, the liability recorded, the costs reflected in net income, or OCI, or cash contributions to the plans could increase materially without a recovery in equity markets in excess of our assumed return on plan assets of 8.5%. If the fair value of the plan assets were to grow and exceed the accumulated benefit obligations in the future, then the recorded liability would be reduced and a corresponding amount of equity would be restored, net of taxes.
UE also maintains trust funds, as required by the NRC and Missouri and Illinois state laws, to fund certain costs of nuclear plant decommissioning. As of December 31, 2004, these funds were invested primarily in domestic equity securities (67%), debt securities (29%), and cash and cash equivalents (4%) and totaled $235 million at fair value (2003 - $212 million). By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be utilized to fund nuclear decommissioning costs within acceptable parameters of risk. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets and the fixed-rate, fixed-income securities are exposed to changes in interest rates. UE actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the assets of the trusts to various investment options. UE’s exposure to equity price market risk is, in large part, mitigated, due to the fact that UE is currently allowed to recover decommissioning costs in its electric rates, which would include unfavorable investment results.
Commodity Price Risk
We are exposed to changes in market prices for electricity, fuel, and natural gas to the extent they cannot be recovered through rates. We pursue a philosophy of mitigating financial risks through structured risk-management programs and policies, structured forward-hedging programs as well as derivative financial instruments (primarily forward contracts, futures contracts, option contracts and financial swap contracts are used). A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset.
Ameren’s generation position is partially hedged through regulated and unregulated sales to electric customers. The regulated sales are subject to rate approval mechanisms. UE has an electric rate freeze in place in Missouri through June 30, 2006. UE, CIPS, CILCO and IP have electric rate freezes in place in Illinois through January 1, 2007.
IP has contracts to purchase power that expire at the end of 2006. Should power acquired under these agreements be insufficient to meet IP’s load requirements, IP will be required to buy power at market prices. Some purchased power agreements oblige the suppliers to provide power up to the reservation amount, and at the same prices, even if individual units are unavailable at various times. Purchased power agreements with other suppliers do not oblige them to acquire replacement power for us in the event of a curtailment or shutdown of their plants. Any costs not covered by rates could not be passed on to ratepayers, which could have an unfavorable impact on IP’s results of operations.
With regard to our exposure to commodity price risk for purchased power and market-based electricity sales, Ameren has two subsidiaries, Ameren Energy and Marketing Company, whose primary responsibilities include managing market risks associated with changing market prices for electricity purchased and sold on behalf of UE, Genco and CILCO. Purchases are generally transacted when they are economically beneficial to serve load requirements. In addition, Genco and CILCO have sold nearly all of their available non-rate-regulated peak generation capacity for the
summers of 2005 and 2006 at various prices, most of which are fixed.
Similar techniques are used to manage risks associated with fuel exposures for generation. Most UE, Genco and CILCO fuel supply contracts are physical forward contracts. Since UE, Genco and CILCO do not have a provision similar to the PGA clause for electric operations, UE, Genco and CILCO have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel in order to manage their exposure to fuel prices. The coal hedging strategy is intended to produce reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased will be determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. We will generally purchase coal up to five years out, but we may purchase coal beyond five years based on favorable market conditions or deal structure. Conversely, the strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.
Transportation costs to deliver coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and mitigate transportation price volatility. The natural gas transportation expenses for the distribution companies and the gas fired generation units are controlled by the FERC via published tariffs with rights to extend the contracts from year to year. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariffs for our requirements.
The following table presents the estimated annual increase in our total fuel expense and decrease in net income if coal and coal transportation costs were to increase by 1% on any requirements currently not covered by fixed-price contracts for the five-year period 2005 through 2009:
(a)
Calculations are based on an effective tax rate of 35%.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
In the event of a significant change in coal prices, UE, Genco and CILCO would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure or fuel sources.
With regard to exposure for commodity price risk for nuclear fuel, UE has fixed-priced and base price with escalation agreements and/or inventories to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services through 2006. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected remainder of the life of the plant, at prices which cannot now be accurately predicted. UE’s strategy is to hedge at least 75% of its three-year requirements. This strategy permits optimum timing of new forward contracts given the relatively long price cycles in the nuclear fuel markets. It also provides security of supply to protect against unforeseen market disruptions. Unlike electricity and natural gas markets, there are no sophisticated financial instruments in nuclear fuel markets, so most hedging is done via inventories and forward contracts.
With regard to our electric generating operations for UE, Genco and CILCO that are exposed to changes in market prices for natural gas used to run the CTs, the natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas while minimizing costs. This is accomplished by optimizing transportation and storage options and price risk by structuring supply agreements to maintain access to multiple gas pools and supply basins.
Through the market allocation process, UE, CIPS, Genco, CILCO and IP have been granted FTRs associated with the advent of the MISO Day Two Market. Marketing Company has been granted FTRs for its participation in the PJM-Com Ed market. We sought and received FTRs with the intent to hedge (offset) expected electric transmission congestion charges related to our physical electricity business. Depending on the congestion on the grid and prices at various points on the electric transmission grid, FTRs could result in either charges or credits. We use complex grid modeling tools to determine which FTRs we wish to nominate in the FTR allocation process. There is a risk that we incorrectly modeled the amount of FTRs we will need, and there is the potential that some of the FTR hedges could be ineffective.
With regard to UE’s, CIPS’, CILCO’s and IP’s natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact there are gas cost recovery mechanisms (PGA clauses) in place in both Missouri and Illinois. These gas cost recovery mechanisms allow UE, CIPS, CILCO and IP to pass on to retail customers prudently incurred costs of natural gas. To prudently manage costs, our strategy is designed to reduce the effect of market fluctuations on our regulated natural gas customers. We cannot eliminate the effects of gas price volatility. However, the gas procurement strategy utilizes similar risk management techniques and instruments outlined earlier combined with management of physical assets including storage and operator and balancing agreements.
The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant and natural gas for our gas-fired generation (CTs) and retail distribution, as appropriate, which are price-hedged over the five-year period 2005 through 2009:
(a)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(b)
Represents the percentage of natural gas price hedged for the peak winter season which includes the months of November through March. The year 2005 represents the period January 2005 through March 2005. The year 2006 represents November 2005 through March 2006. This continues each successive year through March 2009.
See Supply for Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear, natural gas, hydro and oil. Also see Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information.
Fair Value of Contracts
Most of our commodity contracts qualify for treatment as normal purchases and normal sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits.
Price fluctuations in natural gas, fuel and electricity cause:
·
an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices;
·
market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory under firm commitment; and
·
actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by risk-management policies that control the use of forward contracts, futures, options and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring sufficient volumes are available to meet our requirements. See Note 9 - Derivative Financial Instruments to our financial statements under Part II, Item 8, of this report for further information.
The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2004. The sources used to determine the fair value of these contracts were primarily active quotes and other external sources. All of these contracts have maturities of less than three years.
(a)
Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:
We have completed an integrated audit of Ameren Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
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 Ameren Corporation and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
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 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The 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 opinions on management’s assessment and on the effectiveness of the Company’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 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Illinois Power Company from its assessment of internal control over financial reporting as of December 31, 2004 because it was acquired by the Company in a purchase business combination during 2004. We have also excluded Illinois Power Company from our audit of internal control over financial reporting. Illinois Power Company is a wholly-owned subsidiary of Ameren Corporation whose total assets and total revenues represent 18% and 7%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Union Electric Company:
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 Union Electric Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Central Illinois Public Service Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Ameren Energy Generating Company:
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 Ameren Energy Generating Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company'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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of CILCORP Inc.:
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 CILCORP Inc. and its subsidiaries at December 31, 2004 and 2003 (successor), and the results of their operations and their cash flows for the year ended December 31, 2004 (successor) and for the periods February 1, 2003 to December 31, 2003 (successor) and January 1, 2003 to January 31, 2003 (predecessor) in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the years ended December 31, 2004 and 2003 listed in the index appearing under Item 15(a)(2) presents fairly, in
all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The predecessor financial statements of the Company for the year ended December 31, 2002 and the financial statement schedule for the year ended December 31, 2002, were audited by other auditors whose report, dated April 11, 2003, expressed an unqualified opinion on those statements.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Central Illinois Light Company:
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 Central Illinois Light Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the years ended December 31, 2004 and 2003 listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of the Company for the year ended December 31, 2002 and the financial statement schedule for the year ended December 31, 2002, were audited by other auditors whose report, dated April 11, 2003, expressed an unqualified opinion on those statements. As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Illinois Power Company:
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 Illinois Power Company at December 31, 2004 (successor) and 2003 (predecessor), and the results of their operations and their cash flows for the periods October 1, 2004 to December 31, 2004 (successor) and January 1, 2004 to September 30, 2004 (predecessor) and for the years ended December 31, 2003 and 2002 (predecessor) in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003. As discussed in Note 1, the Company adopted certain provisions of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities an interpretation of ARB 51 (revised December 2003), as of December 31, 2003.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 22, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of CILCORP Inc.
Peoria, Illinois
We have audited the accompanying consolidated statements of income, stockholder’s equity, and cash flows for the year ended December 31, 2002 of CILCORP Inc. and subsidiaries (the “Company”). Our audit also included the 2002 financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit.
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 the financial statements are free of material misstatement. An audit includes 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, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such 2002 consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of CILCORP Inc. and subsidiaries as of December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2002 financial statement schedule, when considered in relation to the basic 2002 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/Deloitte & Touche LLP
Deloitte & Touche LLP
Indianapolis, IN
April 11,
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of Central Illinois Light Company
Peoria, Illinois
We have audited the accompanying consolidated statements of income, stockholders’ equity, and cash flows for the year ended December 31, 2002 of Central Illinois Light Company and subsidiaries (the “Company”). Our audit also included the 2002 financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.
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 the financial statements are free of material misstatement. An audit includes 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, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such 2002 consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Central Illinois Light Company and subsidiaries as of December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2002 financial statement schedule, when considered in relation to the basic 2002 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/Deloitte & Touche LLP
Deloitte & Touche LLP
Indianapolis, IN
April 11,
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY (Consolidated)
CILCORP INC. (Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2004
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see Glossary of Terms and Abbreviations.
·
UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri and supplies electric and gas service to a 24,500 square mile area located in central and eastern Missouri and west central Illinois. This area has an estimated population of 3 million and includes the greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 140,000 customers. See Note 3 - Rate and Regulatory Matters for information regarding the proposed transfer of UE’s Illinois electric and natural gas transmission and distribution businesses to CIPS and the proposed addition of a large new electric customer.
·
CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1902. It supplies electric and gas utility service to portions of central and southern Illinois having an estimated population of 1 million in an area of 20,000 square miles. CIPS supplies electric service to 325,000 customers and natural gas service to 170,000 customers.
·
Genco, or Ameren Energy Generating Company, operates a non-rate-regulated electric generation business. Genco was incorporated in Illinois in March 2000, in conjunction with the Illinois Customer Choice Law. Genco commenced operations on May 1, 2000, when CIPS transferred its five coal-fired power plants representing in the aggregate approximately 2,860 megawatts of capacity and related liabilities to Genco at historical net book value. The transfer was made in exchange for a subordinated promissory note from Genco in the amount of $552 million and shares of Genco’s common stock. Since Genco commenced operations, it has acquired 25 CTs, which give it a total installed generating capacity of approximately 4,751 megawatts as of December 31, 2004. Genco is a subsidiary of Development Company, a subsidiary of Resources Company, which is a subsidiary of Ameren. See Note 3 - Rate and Regulatory Matters for information regarding the proposed transfer of Genco’s CTs located in Pinckneyville and Kinmundy, Illinois to UE.
·
CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business, and a rate-regulated natural gas distribution business in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and gas utility service to portions of central and east central Illinois in areas of 3,700 and 4,500 square miles, respectively, with an estimated population of 1 million. CILCO supplies electric service to 205,000 customers and natural gas service to 210,000 customers. In October 2003, CILCO transferred its coal-fired plants and a CT facility, representing in the aggregate approximately 1,100 megawatts of electric generating capacity, to a wholly owned subsidiary known as AERG, as a contribution in respect of all the outstanding stock of AERG and AERG’s assumption of certain liabilities. The net book value of the transferred assets was $378 million. No gain or loss was recognized, as the transaction was accounted for as a transfer between entities under common control. The transfer was made in conjunction with the Illinois Customer Choice Law. CILCORP was incorporated in Illinois in 1985.
·
IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren acquired IP on September 30, 2004, from Dynegy, which had acquired it as Illinova in early 2000. IP was incorporated in 1923 in Illinois. It supplies electric and gas utility service to portions of central, east central, and southern Illinois, serving an estimated population of 1.4 million in an area of approximately 15,000 square miles, contiguous to our other service territories. IP supplies electric service to 600,000 customers and natural gas service to 415,000 customers, including most of the Illinois portion of the greater St. Louis area. In 1998, in conjunction with the impairment of the Clinton
nuclear power plant, IP underwent a quasi-reorganization. In October 1999, IP transferred its wholly owned coal-fired generating assets and other generation-related assets and liabilities at net book value to a non-rate-regulated subsidiary of Illinova in exchange for an unsecured note receivable. In 1999, IP sold its Clinton nuclear power plant to AmerGen and entered into a power purchase agreement with AmerGen, which required IP to purchase power through December 31, 2004. AmerGen also assumed responsibility for operating and ultimately decommissioning the nuclear power plant. Concurrent with the sale to Dynegy in early 2000, the fossil fuel assets and liabilities were transferred from the Illinova non-rate-regulated subsidiary to DMG. The unsecured note receivable was eliminated from IP’s balance sheet in conjunction with Ameren’s acquisition of IP. See Note 2 - Acquisitions and Note 14 - Related Party Transactions for further information.
Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks and provision of other shared services. Ameren has an 80% ownership interest in EEI through UE and Resources Company, which each own 40% of EEI. This 80% ownership in EEI includes a 20% interest indirectly acquired by Resources Company from a Dynegy subsidiary on September 30, 2004. Ameren consolidates EEI for financial reporting purposes, while UE and Resources Company report EEI under the equity method.
We use the words “our,” “we” or “us” with respect to certain information to indicate that such information relates to all Ameren Companies. When we refer to financing or acquisition activities, or liquidity arrangements, we are defining Ameren as the parent holding company. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the periods prior to September 30, 2004, and Ameren’s Consolidated Balance Sheet as of December 31, 2003, do not reflect IP’s results of operations or financial position. Financial information of CILCORP and CILCO reflected in Ameren’s consolidated financial statements include the period from January 31, 2003, when these companies were acquired. See Note 2 - Acquisitions for further information on the accounting for the IP and CILCORP acquisitions. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, certain information is expressed in cents per share. These amounts reflect factors that directly impact Ameren's earnings. We believe this per share information is useful because it better enables readers to understand the impact of these factors on Ameren's earnings. All references in this report to earnings per share are based on diluted shares.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. Certain reclassifications have been made to make prior-year financial statements conform to 2004 reporting.
As part of the acquisition of IP on September 30, 2004, Ameren “pushed down” the effects of purchase accounting to the financial statements of IP. Accordingly, IP’s postacquistion financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for preacquisition (predecessor) and postacquistion (successor) periods, separated by a bold black line. As a result of the acquisition of IP, certain reclassifications have been made to make IP prior-year financial statements conform to our current presentation. Additionally, as part of the acquisition of CILCORP on January 31, 2003, Ameren “pushed down” the effects of purchase accounting to the financial statements of CILCORP, but not to any of CILCORP’s subsidiaries. Accordingly, CILCORP’s postacquistion financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for predecessor and successor periods. CILCO’s financial statements are presented on a historical basis of accounting for all periods presented.
Regulation
Ameren is subject to regulation by the SEC. Certain Ameren subsidiaries are also regulated by the MoPSC, the ICC, the NRC, and the FERC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” UE, CIPS, CILCO and IP defer certain costs pursuant to actions of our rate regulators. These companies are currently recovering such costs in rates charged to customers. See Note 3 - Rate and Regulatory Matters for further information.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. The allowance is determined based on application of a historical write-off factor to the amount of outstanding receivables, including unbilled revenue, and a review for collectibility of certain accounts over 90 days past due.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average cost method. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2004 and 2003:
(a)
amounts exclude amounts for IP; includes amounts for Ameren Registrant and non-Registrant Ameren subsidiaries as well as intercompany eliminations.
(b)
amounts represent predecessor information.
(c)
Consists of coal, oil, propane, and tire chips.
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, is also added for our rate-regulated assets. Interest during construction is added for non-rate-regulated assets. Maintenance expenditures and the renewal of items not considered units of property are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage value, are charged to accumulated depreciation. Asset removal costs incurred by our non-rate-regulated operations, which do not constitute legal obligations, were expensed as incurred, beginning in 2003. Asset removal costs accrued by our rate-regulated operations, which do not constitute legal obligations, are classified as a regulatory liability. See Accounting Changes and Other Matters relating to SFAS No. 143 below and Note 4 - Property and Plant, Net for further information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis. The provision for depreciation for the Ameren Companies in 2004, 2003 and 2002 ranged from 3% to 4% of the average depreciable cost. Beginning in January 2003, with the adoption of SFAS No. 143, depreciation rates for our non-rate-regulated assets were reduced to reflect the discontinuation of the accrual of dismantling and removal costs. See Accounting Changes and Other Matters relating to SFAS No. 143 below for further information.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, which is a utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The following table presents the allowance for funds used during
construction ranges of rates that were used during 2004, 2003 and 2002:
(a)
Excludes rates for CILCORP and CILCO prior to January 31, 2003, and IP prior to the acquisition date of September 30, 2004.
(b)
Represents predecessor information for CILCORP prior to January 31, 2003, and for IP prior to September 30, 2004.
Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. We evaluate goodwill for impairment in the fourth quarter of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren’s, CILCORP’s and IP’s goodwill relates to the acquisitions of IP and an additional 20% ownership interest in EEI in 2004 and CILCORP and Medina Valley in 2003. See Note 2 - Acquisitions for additional information regarding the acquisitions.
Leveraged Leases
Certain Ameren subsidiaries own interests in assets that have been financed as leveraged leases. Ameren’s investment in these leveraged leases represents the equity portion, generally 20% of the total investment, either as an undivided interest in the equipment or as a part owner through a partnership. At the time of lease inception, a debit for rents receivable and estimated residual value was recorded with a credit to unearned income. These amounts are then adjusted over time as rents are received, income is realized, and the asset is eventually sold. Ameren and CILCORP account for these investments as a net investment in these assets; they do not include the amount of outstanding debt because the third-party debt is nonrecourse to Ameren and the Ameren subsidiaries.
Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets as compared with the carrying value of the assets. If impairment has occurred, we recognize the amount of the impairment by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value.
Environmental Costs
Environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Estimated environmental expenditures are based on internal and third-party estimates, which are regularly reviewed and updated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.
Revenue
Utility Revenues
Our utility operating companies (UE, CIPS, CILCO and IP) record operating revenue for electric and gas service when delivered to customers. We accrue an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period.
Interchange Revenues
The following table presents the interchange revenues included in Operating Revenues - Electric for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
Includes interchange revenues at EEI of $53 million for the year ended December 31, 2004 (2003 - $56 million; 2002 - $59 million).
(c)
amounts represent predecessor information. 2003 amounts include January 2003 predecessor information, which was $3 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(d)
and 2003 amounts represent predecessor information. 2004 amount includes January - September 2004 predecessor information which was less than $1 million.
Trading Activities
We present the revenues and costs associated with certain energy contracts designated as trading on a net basis in Operating Revenues - Electric and Other.
Purchased Power
The following table presents the purchased power expenses included in Operating Expenses - Fuel and Purchased Power for the years ended December 31, 2004, 2003 and 2002. See Note 14 - Related Party Transactions for further information on affiliate purchased power transactions.
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
amounts represent predecessor information. 2003 amounts include January 2003 predecessor information, which was $12 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
and 2003 amounts represent predecessor information. 2004 amount includes January - September 2004 predecessor information which was $496 million.
Fuel and Gas Costs
In UE’s, CIPS’, CILCO’s and IP’s retail electric utility jurisdictions, there are no provisions for adjusting rates in response to changes in the cost of fuel for electric generation. In UE’s, CIPS’, CILCO’s and IP’s retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses.
UE’s cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost, based on net kilowatthours generated and sold, is charged to expense.
Stock-based Compensation
Effective January 1, 2003, Ameren adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-based Compensation,” by using the prospective method of adoption under SFAS No. 148, “Accounting for Stock-based Compensation - Transition and Disclosure,” for all employee awards granted or with terms modified on or after January 1, 2003.
Prior to 2003, Ameren, CILCORP and IP accounted for stock options granted under long-term incentive plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees.” No stock-based employee compensation cost was recognized for options granted under Ameren’s plan, either under the AES Stock Option Plan in which CILCORP’s employees participated or under the equity compensation plans of Dynegy in which IP employees participated, as all options granted under the plans had an exercise price equal to the market value of the underlying common stock on the date of grant.
Effective January 1, 2003, predecessor IP adopted the fair value recognition provisions of SFAS No. 123, with respect to options granted to its employees under Dynegy’s plans, by using the prospective method of adoption under SFAS No. 148. As a result, all stock options granted after January 1, 2003, were accounted for on a fair value basis. IP incurred compensation expense over the vesting period of the options in an amount equal to the fair value of the options. On October 1, 2004, as a result of Ameren’s acquisition of IP, all unvested stock options granted to IP employees became null and void.
In December 2004, the FASB issued SFAS No. 123 (as revised SFAS No. 123R), “Share Based Payment,” which revises SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123R will require companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The fair value of the award will be remeasured subsequently at each reporting date through the settlement date; the changes in fair value will be recognized as compensation cost in each period. The fair-value based method in this statement is similar to the fair-value based method in SFAS No. 123 in most respects. SFAS No. 123R is effective for Ameren for the quarterly period ending September 30, 2005. The statement applies to all awards granted or modified after the effective date. The adoption of this statement is not expected to have a material adverse impact on our results of operations, financial position, or liquidity upon adoption.
Had compensation cost for all stock options and stock awards granted prior to 2003 been determined on a fair-value basis consistent with SFAS No. 123, net income would have approximated the following pro forma amounts for the years ended December 31, 2004, 2003 and 2002, respectively.
(a)
Ameren and CILCORP have not granted stock options after January 1, 2003. CILCORP information subsequent to 2002 is not presented, as all CILCORP options were either paid out or assumed by AES in connection with Ameren’s acquisition of CILCORP. For IP, compensation expense recorded for stock options granted after January 1, 2003, was negligible for the nine months ended September 30, 2004, and the years ended December 31, 2003 and 2002. On October 1, 2004, as a result of Ameren’s acquisition of IP, all unvested stock options granted to IP employees became null and void. Therefore, information subsequent to September 30, 2004 is not presented.
See Note 12 - Stock-based Compensation for further information.
Excise Taxes
Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are
recorded gross in Operating Revenues and Taxes Other than Income Taxes. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the years ended 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; and excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003.
(b)
amounts represent predecessor information. 2003 amounts include January 2003 predecessor information, which was $2 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
With the exception of taxes reflected on CILCO customer bills issued prior to October 27, 2003, excise taxes at CILCO are recorded as tax collections payable and are included on the Balance Sheet as Taxes Accrued.
(d)
and 2003 amounts represent predecessor information. 2004 amount includes January - September 2004 predecessor information, which was $30 million.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and tax return purposes. These deferred tax assets and liabilities are determined by statutory enacted tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded due to decreases in the statutory rate, were credited to a regulatory liability. A regulatory asset has been established to recognize the probable future recovery in rates of future income taxes resulting principally from the reversal of Allowance for Funds Used During Construction - Equity and temporary differences related to property, plant, and equipment acquired before 1976, which were an unrecognized temporary difference prior to the adoption of SFAS 109.
Investment tax credits used on tax returns of prior years have been deferred for book purposes; they are being amortized over the useful lives of the related properties. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability, which recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits, was recorded. See Note 13 - Income Taxes for the treatment of IP’s unamortized investment tax credits and deferred tax liabilities upon the acquisition of IP by Ameren.
Earnings Per Share
There were no differences between the basic and diluted earnings per share amounts for Ameren in 2004 and 2003. The inclusion of assumed stock option conversions in the calculation of earnings per share resulted in dilution of $0.01 per share for 2002. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 196,709 shares in 2004, 289,244 shares in 2003 and 332,909 shares in 2002. As only the Ameren parent company has publicly held common stock, earnings per share calculations are not relevant, so they are not presented for any of the other Ameren Companies.
Accounting Changes and Other Matters
SFAS No.143 - “Accounting for Asset Retirement Obligations”
We adopted the provisions of SFAS No. 143, effective January 1, 2003. SFAS No. 143 provides the accounting requirements for asset retirement obligations associated with tangible, long-lived assets. SFAS No. 143 requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments in asset retirement obligations based on changes in estimated fair value. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing or amount of cash flows associated with an asset retirement obligation affect our estimates of fair value.
Upon adoption of the standard, Ameren and Genco recognized a net after-tax gain of $18 million in the first quarter of 2003 for the cumulative effect of change in accounting principle. Prior to Ameren’s acquisition of CILCORP, predecessor CILCORP and CILCO recognized a net after-tax gain in 2003 of $4 million and $24 million, respectively, for the cumulative effect of change in accounting principle. In addition, in accordance with SFAS No. 143, estimated net future removal costs associated with Ameren’s, UE’s, CIPS’, CILCORP’s and CILCO’s rate-regulated operations that had previously been embedded in accumulated depreciation were reclassified as a regulatory liability.
Prior to Ameren’s acquisition of IP, predecessor IP recognized a net after-tax loss upon adoption of SFAS No. 143 of $2 million for the cumulative effect of change in accounting principle. At January 1, 2004, IP’s asset retirement obligation liability totaled $1 million for obligations under an operating lease. This asset retirement obligation related to the dismantling of the generation plant and remediation of the plant site at Tilton, Illinois, which IP had leased to DMG. In July 2004, IP sold the Tilton assets to DMG and eliminated the related asset retirement obligation liability as part of the accounting for that transaction. Thus, IP had no asset retirement obligation liabilities recorded at December 31, 2004.
Upon adoption of SFAS No. 143, UE recorded asset retirement obligations related to UE’s Callaway nuclear plant decommissioning costs and to retirement costs for a UE river structure. Additionally, Genco recorded an asset retirement obligation for the retirement costs for a Genco power plant ash pond. CILCORP and CILCO recorded asset retirement obligations related to CILCO’s power plant ash ponds (now owned by AERG).
Asset retirement obligations at Ameren and UE increased by $24 million for the year ended December 31, 2004, to reflect the accretion of obligations to their present value. Increases to Genco’s, CILCORP’s and CILCO’s asset retirement obligations due to accretion were immaterial during this period. Substantially all of this accretion was recorded as an increase to regulatory assets. Additionally, Ameren and CILCO’s asset retirement obligations increased by approximately $2 million during the year ended December 31, 2004, due to revisions in estimated future cash flows to retire CILCO’s ash ponds.
In addition to those obligations that have been identified and valued, we determined that certain other asset retirement obligations exist. However, we were unable to estimate the fair value of those obligations because the probability, timing, or cash flows associated with the obligations were indeterminable. We do not believe that these obligations, when incurred, will have a material adverse impact on our results of operations, financial position, or liquidity.
The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted: It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the regulatory asset recorded in connection with the adoption of SFAS No. 143.
In June 2004, the FASB issued an exposure draft on a proposed interpretation of SFAS No. 143. The FASB is expected to issue a final interpretation in the first quarter of 2005. Under the interpretation, a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of SFAS No. 143. Accordingly, an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability's fair value can be estimated reasonably. The exposure draft provides examples of conditional asset retirement obligations that may need to be recognized under the provisions of the interpretation, including asbestos removal. This proposed interpretation could require accrual of additional liabilities by Ameren and its subsidiaries and could result in increased expense, which, while not yet quantified, could be material. This proposed interpretation would be effective for us no later than December 31, 2005, if issued in its current form.
FIN No. 46 - “Consolidation of Variable-interest Entities”
In January 2003, the FASB issued FIN No. 46, which changed the consolidation requirements for special-purpose entities (SPEs) and non-special-purpose entities (non-SPEs) that meet the criteria for designation as variable-interest entities (VIEs). In December 2003, the FASB revised FIN No. 46 (FIN No. 46R) to clarify certain aspects of FIN No. 46 and to modify the effective dates of the new guidance. FIN No. 46R provides guidance on the accounting for entities that are controlled through means other than voting rights by another entity. FIN No. 46R requires a VIE to be consolidated by a company if that company is designated as the primary beneficiary.
The Ameren Companies do not have any interests in entities that are considered SPEs, other than IP's investment in IP LLC. FIN No. 46R was effective on March 31, 2004, for any interests the Ameren Companies held in non-SPEs. The adoption of FIN No. 46R did not have a material impact on the consolidated financial statements of the Ameren Companies. However, in connection with the adoption of FIN No. 46R, we have determined that the following significant variable-interests are held by the Ameren Companies:
·
EEI. Ameren has an 80% ownership interest in EEI through UE’s 40% interest and Resources Company’s 40% interest. Under the FIN No. 46R model, Ameren, UE, and Resources Company have a variable-interest in EEI, and Ameren is the primary beneficiary. Accordingly, Ameren will continue to consolidate EEI, and UE will continue to account for its investment in EEI under the equity method of accounting. The maximum exposure to loss as a result of these variable-interests in EEI is limited to Ameren’s, UE’s, and Resources Company’s equity investments in EEI.
·
Tolling agreement. CILCO has a variable-interest in Medina Valley through a tolling agreement to purchase steam, chilled water, and electricity. We have concluded that CILCO is not the primary beneficiary of Medina Valley. Accordingly, CILCO does not consolidate Medina Valley. The maximum exposure to loss as a result of this variable-interest in the tolling agreement is not material.
·
Leveraged lease and affordable housing partnership investments. Ameren, UE and CILCORP have investments in leveraged lease and affordable housing partnership arrangements that are variable-interests. We have concluded that none of these companies is a primary beneficiary of any of the VIEs related to these investments. The maximum exposure to loss as a result of these variable-interests is limited to the investments in these arrangements. At December 31, 2004, Ameren and CILCORP had net investments in leveraged leases of $140 million and $113 million, respectively. At December 31, 2004, Ameren, UE, and CILCORP had investments in affordable housing partnerships of $19 million, $6 million, and $7 million, respectively.
·
IP SPT. Ameren acquired a variable-interest in IP SPT with the acquisition of IP on September 30, 2004. IP has a variable-interest in IP SPT, which was established in 1998 to issue TFNs. IP has indemnified and is liable to IP SPT if IP does not bill the applicable charges to its customers on behalf of IP SPT or if it does not remit the collection to IP SPT; however, the note holders are considered the primary beneficiaries of this special-purpose trust. Accordingly, Ameren and IP do not consolidate IP SPT.
FASB Staff Position SFAS No. 106-1 and FASB Staff Position SFAS No. 106-2 - “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare
Prescription Drug Act) became law. The Medicare Prescription Drug Act introduced a prescription drug benefit for retirees under Medicare as well as a federal subsidy for sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Through its postretirement benefit plans, Ameren provides retirees with prescription drug coverage that we believe is actuarially equivalent to the Medicare prescription drug benefit. In January 2004, the FASB issued FSP SFAS 106-1, which permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Medicare Prescription Drug Act. We made this one-time election allowed by FSP SFAS 106-1.
In May 2004, the FASB issued FSP SFAS 106-2, which superseded FSP SFAS 106-1. FSP SFAS 106-2 provides guidance on accounting for the effects of the Medicare Prescription Drug Act for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Ameren elected to adopt FSP SFAS 106-2 during the second quarter ended June 30, 2004, retroactive to January 1, 2004. See Note 11 - Retirement Benefits for additional information on the impact of adoption of FSP SFAS 106-2.
Predecessor IP’s adoption of FSP SFAS 106-2 on July 1, 2004, had no impact on IP’s results of operations, financial position or liquidity because its drug benefit was not actuarially equivalent to the drug benefit under Medicare Part D.
EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments”
In March 2004, the EITF reached a consensus on EITF Issue No. 03-1, which provides guidance on evaluating whether an investment is other-than-temporarily impaired. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, ‘The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,’ ” in September 2004. During the period of delay, we will continue to evaluate our investments, which primarily constitute our Nuclear Decommissioning Trust Fund, as required by existing authoritative guidance.
NOTE 2 - ACQUISITIONS
IP and EEI
On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of IP (based in Decatur, Illinois) and an additional 20% ownership interest in EEI from Dynegy and its subsidiaries. Ameren acquired IP to complement its existing Illinois gas and electric operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP. For a discussion of the regulatory agency approvals granted in connection with this acquisition, see Note 3 - Rate and Regulatory Matters.
The total transaction value was $2.3 billion, including the assumption of $1.8 billion of IP debt and preferred stock and consideration, including transaction costs, of $443 million in cash, net of $51 million cash acquired. In February 2005, Ameren received $5 million from Dynegy representing the final working capital adjustment pursuant to the terms of the stock purchase agreement. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow account pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. See Note 15 - Commitments and Contingencies for information on the IP environmental matter to which the indemnification and escrow applies. In addition, this transaction included a fixed-price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. The contract was marked to fair value at closing of the acquisition. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. The remaining 30% of IP’s power needs in 2005 and 2006 will be supplied by other companies. In the event that any of these suppliers are unable to supply the electricity required by these agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing itself to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial position, or liquidity.
Ameren’s financing plan for funding this acquisition included the issuance of new Ameren common stock. Ameren issued an aggregate of 30 million common shares in February 2004 and July 2004, which generated net proceeds of $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce IP debt assumed as part of this transaction and to pay related premiums. See Note 6 - Long-term Debt and Equity Financings for information on redemptions and repurchases of certain IP indebtedness after the acquisition.
The following table presents the estimated fair values of the assets acquired and liabilities assumed at the date of Ameren’s acquisition of IP and the additional 20% ownership interest in EEI. Ameren is completing its valuations of the net assets and liabilities of IP and EEI acquired, including third-party valuations of property and plant, intangible assets, pension and other postretirement benefit obligations, and contingent obligations. As a result, the allocation of the purchase price is preliminary and subject to further adjustment. We expect to finalize purchase accounting in 2005. The fair value of IP’s
power supply agreements including the fixed-price capacity power supply agreement with DYPM, discussed above recorded at the acquisition date resulted in a net liability of $109 million. In addition, we recorded a fair value adjustment, resulting in a net asset of $24 million, for IP’s power supply agreement with EEI that expires at the end of 2006. The excess of the purchase price for IP’s common stock and preferred stock over tangible net assets acquired has been allocated preliminarily to goodwill in the amount of $320 million, net of future tax benefits. For income tax purposes, we expect that a portion of the purchase price will be allocated to goodwill and that such portion will be deducted ratably over a 15-year period. No specifically identifiable intangible assets have been identified.
The following unaudited pro forma financial information presents a summary of Ameren’s consolidated results of operations for the years ended December 31, 2004 and 2003, as if the acquisition of IP had been completed at the beginning of 2003, including pro forma adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information does not include cost savings that may result from the combination of Ameren with IP.
This pro forma information is not necessarily indicative of the results of operations as they would have been had the transaction been effected on the assumed date, nor is it an indication of trends for future results.
IP’s Note Receivable from Former Affiliate of $2.3 billion was eliminated as of September 30, 2004, and prior to Ameren’s acquisition of IP to meet the conditions of the closing. Steps to eliminate the Note were made: (1) reducing the principal balance by offsetting certain payables owed by IP to Illinova and other Dynegy entities; (2) offsetting the principal balance by the amount of interest that had been paid by Illinova to IP, but not yet earned; and (3) eliminating a portion in consideration of Illinova’s assumption of IP’s net deferred tax obligation and IP’s contemporaneous repurchase (and cancellation immediately thereafter) of 39,892,213 of IP common shares. The 12,751,724 IP treasury shares held as of December 31, 2003, were canceled in 2004. The remaining principal balance of IP’s Note Receivable from Former Affiliate was eliminated, as part of IP’s overall recapitalization, with a corresponding reduction to IP’s retained earnings. The elimination of IP’s Note Receivable from Former Affiliate had no impact on IP’s predecessor results of operations.
The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI now held by Resources Company was $125 million. This transaction was accounted for as a step acquisition. The excess of the purchase price for this ownership interest over 20% of the fair value of EEI’s net assets acquired has been preliminarily allocated to property and plant ($80 million) and emission allowances ($41 million), partially offset by a net liability for power supply agreements ($24 million) and a reduction to net deferred tax assets ($38 million). The remaining excess was allocated to goodwill in the amount of $54 million, subject to change based on our final valuation.
CILCORP and Medina Valley
On January 31, 2003, Ameren completed the acquisition of all of the outstanding common stock of CILCORP from AES. CILCORP is the parent company of CILCO (based in Peoria, Illinois). With the acquisition, CILCO became an indirect Ameren subsidiary, but it remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, Ameren also completed the acquisition from AES of Medina Valley, which indirectly owns a 40-megawatt, gas-fired electric generation plant. The results of operations for CILCORP and Medina Valley were included in Ameren’s consolidated financial statements effective with the respective January and February 2003 acquisition dates.
The total acquisition cost was $1.4 billion and included the assumption by Ameren of CILCORP and Medina Valley debt of $895 million and consideration of $479 million in cash, net of $38 million cash acquired. The purchase price allocation for the acquisition of CILCORP and Medina Valley was finalized in January 2004, resulting in an $8 million decrease in goodwill primarily due to January 2004 adjustments to property and plant, income tax accounts, and accrued severance expenses. The following table presents the final estimated fair values of the assets acquired and
liabilities assumed at the dates of our acquisitions of CILCORP and Medina Valley.
Specifically identifiable intangible assets of $6 million comprise retail customer contracts, which are subject to amortization with an average life of 10 years. Goodwill of $561 million (CILCORP - $554 million; Medina Valley - $7 million) was recognized in connection with the CILCORP and Medina Valley acquisitions. None of this goodwill is expected to be deductible for tax purposes.
NOTE 3 - RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings. With respect to pending matters, we are unable to predict the ultimate outcome of these regulatory proceedings the timing of the final decisions of the various agencies or the impact on our results of operations, financial position, or liquidity.
IP and EEI Acquisition
Ameren received all the regulatory agency approvals necessary to acquire IP and a 20% interest in EEI from Dynegy on September 30, 2004.
The principal ongoing condition of the FERC’s approval of the acquisition was that 125 megawatts of EEI’s power be sold to a nonaffiliate of Ameren. The Missouri Office of Public Counsel and a group of electric industrial customers of UE, both interveners in the FERC proceeding, have asked the FERC to reconsider its order deferring to the MoPSC on the question of whether UE should be required to preserve its current entitlement to the output of EEI’s Joppa power plant facility. These appeals, which are pending, did not impede the completion of the acquisition on September 30, 2004. IP joined the MISO on September 30, 2004, satisfying an additional condition of the FERC’s approval of the acquisition.
The ICC order approving Ameren’s acquisition of IP contains several important provisions, including the following:
·
The order requires IP to submit quarterly reports in 2005 and 2006 on certain milestones regarding IP’s progress in achieving an estimated $33 million in annual synergies by the beginning of 2007, and provides for adjustments in IP’s next electric and gas rate cases if IP fails to achieve those milestones.
·
Commencing in 2007, IP will recover over four years, through rates, $67 million in reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. As of December 31, 2004, $59 million of reorganization costs were incurred and deferred as a regulatory asset.
·
The order approves a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy; if cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund; once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.
·
Ameren commits to cause an aggregate of at least $750 million principal amount of IP’s long-term debt, including IP’s $550 million principal amount of mortgage bonds 11.50% Series due 2010, to be redeemed, repurchased or retired on or before December 31, 2006. As of December 31, 2004, $700 million principal amount of IP debt was retired in accordance with this provision.
·
The order provides IP with the ability to declare and pay $80 million of dividends on its common stock in 2005 and $160 million of dividends on its common stock cumulatively through 2006, provided IP has achieved an investment grade credit rating from S&P or Moody’s. If, however, IP’s $550 million principal amount of mortgage bonds 11.50% Series mortgage bonds due 2010 are not eliminated by December 31, 2006, IP may not thereafter declare or pay common dividends without seeking authority from the ICC. As of December 31, 2004, less than $1 million of the 11.50% Series mortgage bonds due 2010 were outstanding.
·
IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities consistent with achieving and maintaining a common equity to total capitalization ratio between 50% to 60%.
·
Ameren will commit IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership.
Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory
In July 2004, the FERC approved the transfer from Genco to UE, at net book value ($240 million) of 550 megawatts of CTs, but the transfer remains subject to SEC approval under the PUHCA. Approval by the ICC is not required, contingent upon prior approval and execution of UE’s transfer of its Illinois public utility operations to CIPS, as discussed below. Approval by the MoPSC is not required in order for this transfer of generating capacity to occur.
However, the MoPSC has jurisdiction over UE’s ability to recover the cost of the transferred generating facilities from its electric customers in its rates.
In May 2003, UE announced its plan to limit its public utility operations to the state of Missouri and to discontinue operating as a public utility subject to ICC regulation. UE is seeking to accomplish this by transferring its Illinois-based electric and natural gas businesses, including its Illinois-based distribution assets and certain of its transmission assets, at net book value, to CIPS. In 2004, UE’s Illinois electric and gas service territory generated revenues of $165 million and had a net book property and plant value of $126 million at December 31, 2004. UE's electric generating facilities and a certain minor amount of its electric transmission facilities in Illinois would not be part of the transfer. UE proposes to transfer about half of the assets directly to CIPS in consideration for a CIPS subordinated promissory note, and approximately half of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. The transfer was approved by the FERC in December 2003. In September 2004, the ICC authorized the transfer of UE’s Illinois-based natural gas utility business. The ICC had already authorized the transfer of UE’s Illinois-based electric utility business to CIPS in 2000. In February 2005, the MoPSC issued an order that approved the transfer subject to various conditions described below. The transfer of UE's Illinois-based utility businesses will also require the approval of the SEC under the provisions of the PUHCA. A filing seeking approval of both the transfer of UE’s Illinois-based utility businesses and Genco’s CTs was made with the SEC in October 2003. If completed, the transfers will be accounted for at book value with no gain or loss recognition, which is the appropriate treatment for transactions of this type between two entities under common control.
The MoPSC order approving UE’s transfer of its Illinois-based utility businesses to CIPS included the following principal conditions:
·
The order prevents UE from recovering in rates up to 6% of unknown UE generation-related liabilities associated with the generation that was formerly allocated to UE’s Illinois service territory unless UE can show the benefits of the transfer of the Illinois service territory outweigh these costs in future rate cases.
·
The order requires an amendment to the joint dispatch agreement among UE, Genco and CIPS, to declare that margins on short-term power sales will be divided based on generation output as opposed to load. This amendment is expected to provide UE with additional annual margins and Genco with reduced annual margins of $7 million to $24 million. However, this reduction to Genco’s margins is expected to be mitigated by margins received from additional power sales by Genco (through Marketing Company) to CIPS to serve the transferred UE Illinois-based electric power business through the end of 2006 under the current power supply contracts.
·
The order requires that, in a future rate case, revenues UE could have received for incremental energy transfers under the joint dispatch agreement resulting from the service territory transfer be imputed based on market prices unless UE can show the benefits of the transfer of the Illinois service territory outweigh the difference between the market prices and the actual cost-based charges for such incremental energy transfers.
Although not expressing dissatisfaction with the MoPSC order, UE, in February 2005, moved the MoPSC to clarify its order to provide that UE may complete the transfer prior to receipt of all regulatory approvals necessary to effectuate the required amendment to the joint dispatch agreement and also to provide that for rate-making purposes, the joint dispatch agreement amendment should be deemed to be made by UE as of the date the transfer is closed. This clarification of the MoPSC order is needed, according to UE’s motion, to facilitate timely electric service to Noranda Aluminum, Inc. as discussed below. Also in February 2005, the Missouri Office of Public Counsel filed an application for rehearing of the MoPSC order asserting that the order is unlawful, unjust, unreasonable and arbitrary in various ways.
See Note 14 - Related Party Transactions for a more detailed discussion of the joint dispatch agreement.
Missouri
Electric
In August 2002, a stipulation and agreement resolved an excess earnings complaint brought against UE by the MoPSC staff following the expiration of UE's experimental alternative regulation plan. The resolution became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement includes the following principal features.
Missouri
Electric
·
The phase-in of $110 million of electric rate reductions through April 2004, $50 million of which was retroactively effective as of April 1, 2002, $30 million of which became effective on April 1, 2003, and $30 million of which became effective on April 1, 2004.
·
A rate moratorium providing for no changes in rates before July 1, 2006, subject to certain statutory and other exceptions.
·
A commitment to contribute $14 million to programs for low-income energy assistance and weatherization, promotion of energy efficiency and economic development in UE’s service territory in 2002, with additional payments of $3 million made annually on June
30, 2003 through June 30, 2006. This entire obligation was expensed in 2002.
·
A commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at UE’s Callaway nuclear plant. The 700 megawatts of new generation is expected to be satisfied by UE’s addition of 240 megawatts in 2002 and the proposed transfer at net book value to UE of approximately 550 megawatts of generation assets from Genco, which is subject to receipt of necessary regulatory approvals. See Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory within this Note for additional information on the proposed transfer.
·
An annual reduction in UE’s depreciation rates by $20 million, retroactive to April 1, 2002, based on an updated analysis of asset values, service lives, and accumulated depreciation levels.
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A one-time credit of $40 million that was accrued during the plan period. The entire amount was paid to UE’s Missouri retail electric customers in 2002 for settlement of the final sharing period under the alternative regulation plan that expired June 30, 2001.
·
A cost of service study must be filed by January 1, 2006.
Gas
In January 2004, a stipulation and agreement resolved a request by UE to increase annual natural gas rates. The resolution became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement authorized an increase in annual gas delivery rates of $13 million, effective February 15, 2004. Other principal features of the stipulation and agreement include:
·
A rate moratorium prohibiting changes in gas delivery rates before July 1, 2006, absent the occurrence of a significant, unusual event that has a major impact on UE.
·
A commitment to make $15 million to $25 million in infrastructure improvement investments from July 1, 2003, through December 31, 2006, including replacement of cast iron main and unprotected steel service lines. UE agreed not to propose rate adjustments to recover infrastructure costs through a statutory infrastructure system replacement surcharge prior to January 1, 2006.
·
Commitments to contribute an aggregate of $310,000 annually to programs for low-income weatherization, energy assistance, and energy-efficient equipment in UE’s service territory.
Authority to Serve Noranda
UE filed in December 2004 with the MoPSC for authority to extend its Missouri electric service territory to include the area where Noranda Aluminum, Inc. (Noranda) is located. Earlier in December, Noranda and UE signed a 15-year agreement to supply up to approximately 470 megawatts (peak load) electric service (or approximately 5% of UE’s generating capability, including purchases) to Noranda’s primary aluminum smelter in southeast Missouri. The supply agreement would become effective June 1, 2005, subject to the satisfaction of certain conditions. The conditions include the MoPSC granting UE authority to extend its service territory to include the Noranda facility; completion of the transfer to UE of 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, by Genco, as discussed above in this Note under Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory; completion of the transfer of UE’s Illinois service territory, also as discussed under that caption in this Note; and approval by the MoPSC of a proposed large customer transmission service rate. In February 2005, UE and other parties executed and filed a stipulation resolving all of the outstanding issues pending before the MoPSC. The stipulation is consistent in all material respects with UE’s application filed in December 2004. The MoPSC is expected to issue an order by the end of March 2005. The transmission arrangements to allow for UE to serve Noranda are subject to FERC approval. In February 2005, the MJMEUC filed a protest at the FERC as to UE’s filing made in January 2005 to amend the Interchange Agreeement. In its protest, the MJMEUC recommended that the FERC approve UE’s proposed amendment, but requested that the FERC condition its approval on UE being required to comply, after the fact, with the MISO Study Process. In early March 2005, UE filed its response contending that the FERC should not impose any conditions on the filing. A decision by the FERC is expected in late March 2005.
Illinois
Electric
In 2002, all of the Illinois residential, commercial and industrial customers of UE, CIPS, CILCO and IP had a choice in electric suppliers under the provisions of 1997 Illinois legislation related to the restructuring of the Illinois electric industry (the Illinois Customer Choice Law). Under the Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen through January 1, 2005. Due to an amendment to the Illinois Customer Choice Law, the rate freeze was extended through January 1, 2007. As a result of this extension, and pursuant to orders of the ICC, CIPS and Marketing Company and CILCO and AERG extended their respective power supply agreements through December 31, 2006. See Note 14 - Related Party Transactions for a discussion of these affiliate power supply agreements.
The Illinois Customer Choice Law contains a provision requiring that half of excess earnings from the Illinois jurisdiction for the years 1998 through 2006 be refunded to UE’s, CIPS’, CILCO’s and IP’s Illinois customers. Excess earnings are defined by the Illinois Customer Choice Law as the portion of the two-year average annual rate of return on common equity in excess of 1.5% of the two-year average of the Index. The Index is defined as the sum of the average for the 12 months ended September 30 of the average monthly yields of the Treasury long-term average plus 7% for both UE and CIPS, 11% for CILCO and 8.5% for IP. Estimated refunds totaling less than $1 million to UE’s Illinois customers are expected to be made during the period from April 1, 2004, through March 31, 2005, resulting from excess earnings during the year ended December 31, 2003. No refunds to CIPS’, CILCO’s or IP’s Illinois customers are expected to be made during that period.
On December 31, 2006, the current Illinois electric rate freeze expires, as do supply contracts for generation to serve the power requirements of CIPS, CILCO and IP expire. Prior to December 31, 2006, determinations must be made as to how all Illinois distribution companies will procure their generation needs and how they will set future rates for the generation components and delivery service components of customer rates.
During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and generation procurement after the current Illinois electric rate freeze and supply contracts expire on December 31, 2006. A report issued by the ICC in late 2004 outlines a process that received strong support in the workshops: It would have CIPS, CILCO and IP procure power through an auction monitored by the ICC. The form of power supply would meet the full requirements of the utility and the risk of fluctuations in power requirements would be borne by the supplier. In addition, the report noted that many stakeholders, including Ameren, supported a process whereby the price of power resulting from the auction would be the price used to determine the generation component of customer rates. This purchased power would be charged to customers through a pass-through mechanism. With regard to the delivery service component of customer rates, it is expected that all Illinois delivery service companies will file rate cases, at which time the delivery service component of customer rates will be updated. Genco and AERG would probably participate in the auction, but there may be a limit imposed by the ICC on the maximum amount of power they could supply CIPS, CILCO and IP. In February 2005, CIPS, CILCO and IP filed with the ICC a proposed format for the generation procurement auction, a rate mechanism to pass generation costs through to customers, and a process to update the delivery service portion of rates, among other things. These proposals are subject to review and approval by the ICC within eleven months of the filings. In addition, the Illinois legislature began hearings regarding the framework for retail rate determination and generation procurement in February 2005. We cannot predict what actions, if any, the Illinois legislature will take, or whether the ICC will approve our proposals for generation procurement or electric rate determination.
Gas
In June 2004, IP filed with the ICC seeking authority to raise its natural gas delivery rates. In supplemental testimony, IP revised its requested rate increase to $25 million annually. The ICC staff in its rebuttal testimony recommended an increase in rates of $10.5 million. In January 2005, IP and the other parties in the proceeding submitted a partial settlement. If approved by the ICC, it will permit a rate increase of $11 million to $14 million. Issues relating to the proposed disallowance of costs associated with IP’s Hillsboro storage field were not resolved by the parties’ settlement; they were the subject of hearings held in January 2005. By law, the ICC is required to issue its decision about the partial settlement and the contested issues by May 2005. In the order approving Ameren’s acquisition of IP, the ICC prohibits IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP’s pending request for a gas delivery rate increase. The ICC staff has proposed a disallowance of $7.6 millions part of IP’s 2003 PGA reconciliation proceeding related to the Hillsboro storage field.
In October 2003, the ICC issued orders awarding CILCO, CIPS and UE increases in annual natural gas delivery rates of $9 million, $7 million and $2 million, respectively. These new rates went into effect in November 2003.
Federal
Regional Transmission Organization
In December 1999, the FERC issued Order 2000, which required all utilities subject to the FERC jurisdiction to state their intentions for joining a RTO. The MoPSC issued an order in early 2004 authorizing UE to participate in the MISO for a five-year period, with participation after that period subject to further approvals by the MoPSC. Subsequently, the FERC issued a final order allowing UE’s and CIPS’ participation in the MISO. Under these orders, the MoPSC continues to set the transmission component of UE’s rates to serve its bundled retail load. CILCO was already a member of the MISO; it transferred functional control of its transmission system to the MISO prior to our acquisition of CILCO. Genco does not own transmission assets, but pays the MISO to use the transmission system to transmit power from the Genco generating plants.
On May 1, 2004, functional control, but not ownership, of UE’s and CIPS’ transmission systems was transferred to the MISO through GridAmerica LLC. On September 30, 2004, prior to the completion of Ameren’s acquisition of IP as required by the FERC’s order approving the acquisition, IP transferred functional control, but not ownership, of its transmission system to the MISO. The transfers had no accounting impact on UE, CIPS and IP because they continue to own the transmission system assets. The participation by UE, CIPS and IP in the MISO is expected to increase annual costs by $10 million to $25 million in the aggregate. This could also result in a decrease in annual revenues of between $5 million and $15 million in the aggregate, depending upon the MISO’s tariff structure. UE, CIPS, CILCO and IP may also be required to expand their transmission systems according to decisions made by the MISO rather than according to their internal planning process.
As a part of the transfer of functional control of UE’s and CIPS’ transmission systems to the MISO, Ameren received $26 million, which represented the refund of the $13 million exit fee paid by UE and the $5 million exit fee paid by CIPS, both of which were expensed when they left the MISO in 2001, plus $1 million interest on the exit fees and the reimbursement of $7 million that was invested in the proposed Alliance RTO. These refunds resulted in after-tax gains of $11 million, $8 million, and $3 million for Ameren, UE, and CIPS, respectively, which were recorded in other operations and maintenance expenses during the quarter ended June 30, 2004. As part of the transfer of functional control of IP’s transmission system to the MISO at the end of September 2004, IP also received a refund of its MISO exit fee, plus interest on the exit fee, and RTO development costs resulting in after-tax gains of $9 million during the quarter ended September 30, 2004.
During late 2003 and early 2004, the FERC had ordered the elimination of regional through-and-out rates assessed by the MISO on transmission service between the MISO and PJM regions, to be effective May 1, 2004. However, in March 2004, the FERC accepted an agreement among affected transmission owners that retained the regional through-and-out rates until December 1, 2004. It also provided for continued negotiations aimed at developing a long-term transmission pricing structure based on specified principles to eliminate seams between the PJM and the MISO regions. In November 2004, the FERC announced that it had approved the new pricing structure to eliminate the seams between the MISO and PJM. The new rate structure applies for a fixed period ending January 31, 2008, and is based on the “license plate” rate design currently in place in both the MISO and PJM, under which payment of a single fee applicable to the transmission pricing zone in which the transmission customer’s load is located entitles that customer to transmission service over the entire combined system. However, to avoid an abrupt cost shift as a result of the elimination of pancaked rates between the MISO and PJM, the FERC also ordered the adoption of Seams Elimination Cost Adjustments (SECA). In late November 2004, UE, CIPS, CILCO and IP made SECA filings with the FERC. Numerous comments were filed in January 2005. In February 2005, the FERC accepted for filing the SECA filings submitted in the proceeding to become effective December 1, 2004, subject to refund and surcharge as appropriate, and it established hearing procedures. Until the SECA filings have finally been approved by the FERC, we cannot predict the ultimate impact that such rate structure will have on UE’s, CIPS’, CILCO’s and IP’s costs and revenues.
In March 2004, the MISO tendered for filing at the FERC a proposed Open Access Transmission and Energy Markets Tariff (the Energy Markets Tariff), which is intended to supersede its existing OATT. The Energy Markets Tariff establishes rates, terms and conditions necessary for implementation of a centralized economic dispatch platform, including locational marginal-cost pricing and FTRs for transmission service within the MISO region. The Energy Markets Tariff also establishes market monitoring and mitigation procedures and codifies existing resource adequacy requirements placed on the MISO members by their states or applicable RRO. The MISO initially proposed to make the Energy Markets Tariff effective on December 1, 2004, subject to its ability to implement the Energy Markets Tariff. However, implementation of the Energy Markets Tariff is now expected to be effective on April 1, 2005. On August 6, 2004, the FERC accepted the MISO’s Energy Markets Tariff, subject to further compliance filings. On November 8, 2004, the FERC issued an order denying the requests for rehearing that were filed by a number of the MISO stakeholders including Ameren. However, a final order from the FERC on the compliance filings made by the MISO in response to the FERC’s August 6 order is still pending. At this time, Ameren is unable to determine the full impact that the Energy Markets Tariff will have until further information is available regarding the implementation of the Energy Markets Tariff.
Until UE, CIPS, CILCO and IP achieve some degree of operational experience participating in the MISO, we are unable to predict the ultimate impact that such participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our results of operations, financial position, or liquidity.
Hydroelectric License Renewal
In November 2004, the FERC formally accepted UE’s February 2004 license renewal application, and it solicited terms and conditions from the U.S. Department of Interior and various state agencies to renew the license for its Osage hydroelectric plant for an additional 50-year term. The current FERC license expires on February 28, 2006. The license application proposes to continue operations at the Osage
plant as a peaking facility, to upgrade four turbine units, and to maximize the hydroelectric capacity of the plant.
New Market Power Analysis Screen Order
In an order issued in April 2004, the FERC replaced the Supply Margin Assessment Screen previously used to review the applications by sellers of electricity at wholesale for authorization to sell power at market-based rates. The new system uses two alternative measures of market power: (1) a pivotal supplier analysis and (2) a market share analysis, which is to be prepared on a seasonal basis. Applicants located in a RTO with sufficient market structure and a single energy market were permitted to base these measures of market power on the size of the market in the geographic region under the control of the RTO. Other applicants were required to base these measures of market power on the size of the market in the control area in which they operate. If the applicant passes both screens, a rebuttable presumption will exist that it lacks generation market power. If the applicant fails either screen, a rebuttable presumption will exist that it has market power. Under such circumstances, the applicant may either seek to rebut the presumption by preparing a delivered price test (identifying the amount of economic capacity from neighboring areas that can be delivered to the control area) or propose mitigation measures. Unless some other mitigation measure is adopted, the applicant’s authority to sell power at market-based rates in areas where it has market power will be revoked, and the applicant will be required to sell at cost-based rates in those areas.
UE, Genco, CIPS, CILCO, AERG, Development Company, Marketing Company, and Medina Valley currently have authorization from the FERC to sell power at market-based rates. As required, these Ameren companies filed an updated market power analysis with the FERC in December 2004. All of the Ameren companies pass both screen measures for the market consisting of the entire MISO footprint. In their December filing, they wrote that because MISO’s Day Two Markets, at such date, were scheduled to begin March 1, 2005, the MISO footprint was the only relevant market for measuring whether any of the Ameren companies possess market power as defined by the FERC. Also in their December filing, they offered to submit supplemental information that applies the new tests to smaller markets consisting of the control areas in which the Ameren companies sell power, if the MISO Day Two Markets did not begin on March 1, 2005, as originally scheduled. In January 2005, the effective date of the MISO Day Two was moved to April 1, 2005; however, with only a one-month delay, we still believe that applying the new screens on the basis of the entire MISO footprint is inappropriate. In January 2005, the Missouri Joint Municipal Electric Utility Commission (MJMEUC) filed a protest to our December filing. The MJMEUC is an association of Missouri municipal customers, that purchase transmission service from Ameren. In its protest, the MJMEUC contends that the Ameren companies have not shown they lack market power, that the MISO footprint is not the relevant market, and that the MISO's energy markets will not be sufficient to protect consumers from market power abuses, especially with respect to long-term markets. In February 2005, the Ameren companies filed a response to the MJMEUC’s protest, responding to each of these claims. We are unable to anticipate how or when the FERC will respond to our December filing and to any supplemental filing. Therefore, we are unable to predict the ultimate impact the new screens will have on our ability to sell power at market-based rates.
Regulatory Assets and Liabilities
In accordance with SFAS No. 71, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators and are currently recovering such costs in rates charged to customers.
The following table presents our regulatory assets and regulatory liabilities at December 31, 2004 and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
amounts represent predecessor information.
(d)
Amount represents SFAS No. 109 deferred tax asset. See Note 13 - Income Taxes for amortization period.
(e)
These assets do not earn a return.
(f)
Represents recoverable costs for asset retirement obligations at our rate-regulated operations. See SFAS No. 143 discussion in Note 1 - Summary of Significant Accounting Policies.
(g)
Represents UE’s Callaway nuclear plant operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant’s current operating license through 2024.
(h)
Represents losses related to repaid debt. These amounts are being amortized over the lives of the related new debt issues or the remaining lives of the old debt issues if no new debt was issued.
(i)
Represents the recoverable portion of accrued environmental site liabilities primarily collected from electric and gas customers through ICC approved revenue riders in Illinois.
(j)
Represents reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. Per the ICC order approving Ameren’s acquisition of IP, these costs are recoverable over four years after 2006 through rates.
(k)
Represents a portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP at September 30, 2004. This portion will be amortized over the remaining life of the related debt upon expiration of the electric rate freeze in Illinois in 2006.
(l)
Represents Y2K expenses being amortized over six years starting in 2002, in conjunction with the 2002 settlement of UE’s Missouri electric rate case and a DOE decommissioning assessment being amortized over 14 years through 2007. In addition, this amount includes the portion of merger-related expenses applicable to the Missouri retail jurisdiction, which are being amortized through 2007 based on a MoPSC order.
(m)
Represents unamortized portion of investment tax credit and federal excess taxes. See Note 13 - Income Taxes for amortization period.
(n)
Represents estimated funds collected for the eventual dismantling and removing plant from service, net of salvage value, upon retirement related to our rate-regulated operations. See SFAS No. 143 discussion in Note 1 - Summary of Significant Accounting Policies.
(o)
Represents potentially noncompetitive investment costs (stranded costs) that IP was allowed to recover from retail customers during the transition period (until December 31, 2006) through frozen bundled rates and transition charges from customers who select other electric suppliers.
(p)
Represents ICC-allowed decommissioning costs associated with IP’s former nuclear plant. The regulatory asset for the probable future collections from rate payers of decommissioning costs was amortized as the decommissioning costs are collected. See Note 15 - Commitments and Contingencies for further discussion.
UE, CIPS, CILCO and IP continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered through future revenues. Electric industry restructuring legislation may affect the recoverability of electric regulatory assets in the future.
IP’s predecessor financial statements included a cost-recovery asset related to the recovery of certain stranded costs during the Illinois Customer Choice Law transition period, which extends until December 31, 2006. IP had recorded a regulatory asset of $341 million in 1998 for the portion of its stranded costs it expected to recover during the transition period. The transition-period cost-recovery asset amortization reflected in IP’s predecessor statement of income was $29 million during the nine months ended September 30, 2004, $39 million in 2003, and $71 million in 2002. No value was assigned to the transition-period cost-recovery asset in the allocation of the purchase price for IP upon the acquisition by Ameren on September 30, 2004. See Note 2 - Acquisitions for more information regarding the purchase price allocation.
NOTE 4 - PROPERTY AND PLANT, NET
The following table presents property and plant, net for each of the Ameren Companies at December 31, 2004 and 2003:
(a) amounts exclude amounts for IP; includes amounts for non-Registrant Ameren subsidiaries as well as intercompany eliminations.
(b) amounts represent predecessor information.
NOTE 5 - SHORT-TERM BORROWINGS AND LIQUIDITY
Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities generally within 1 to 45 days.
The following table summarizes the short-term borrowing activity and relevant interest rates for the years ended December 31, 2004 and 2003, respectively:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
represents predecessor information.
At December 31, 2004, certain of the Ameren Companies had committed bank credit facilities totaling $1,164 million, $789 million of which was available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP, and Ameren Services through a utility money pool arrangement. At December 31, 2004, UE had $375 million of commercial paper borrowings outstanding, which reduced the available amounts under these facilities. All of the $789 million was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, by CILCORP through direct short-term borrowings from Ameren, and by most of the non-rate-regulated subsidiaries including, but not limited to, Resources Company, Genco, Marketing Company, AFS,
AERG, and Ameren Energy, through a non-state-regulated subsidiary money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between rate-regulated and non-rate-regulated entities. In addition, a unilateral borrowing agreement exists between Ameren, IP and Ameren Services, which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreements. See Note 14 - Related Party Transactions for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement. The committed bank credit facilities are used to support our commercial paper programs under which $375 million was outstanding for Ameren on a consolidated basis at December 31, 2004 (2003 - $150 million). Access to our credit facilities for all Ameren Companies is subject to reduction based on use by affiliates.
In April 2004, UE renewed, for an additional one-year term, its $75 million 364-day committed credit facility, which is to be used for general corporate purposes, including support of its commercial paper program. This facility makes borrowings available at various interest rates based on London Interbank Offered Rate (LIBOR), agreed rates, and other options. CIPS, CILCO and IP can access this facility through the utility money pool agreement.
In July 2004, Ameren entered into two new revolving credit facilities totaling $700 million to be used for general corporate purposes, including support of Ameren and UE commercial paper programs. The $700 million in new facilities includes a $350 million three-year revolving credit facility and a $350 million five-year revolving credit facility. These new credit facilities replaced Ameren’s existing $235 million 364-day revolving credit facility, which matured in July 2004, and a $130 million multiyear revolving credit facility, which would have matured in July 2005. In September 2004, an existing Ameren $235 million multiyear revolving facility, which matures in July 2006, was amended and restated to accommodate Ameren’s acquisition of IP and to conform with the two credit facilities entered into in July 2004.
EEI has two bank credit agreements totaling $45 million with maturities through June 2005. At December 31, 2004, $7 million was available under these committed credit facilities.
Borrowings under Ameren’s non-state-regulated subsidiary money pool agreement by Genco, Development Company, and Medina Valley, each an “exempt wholesale generator,” are considered investments for purposes of the 50% SEC aggregate investment limitation. Based on Ameren’s aggregate investment in these “exempt wholesale generators” as of December 31, 2004, the maximum permissible borrowings under Ameren’s non-state-regulated subsidiary money pool pursuant to this limitation for these entities totaled $507 million.
Indebtedness Provisions and Other Covenants
Certain of the Ameren Companies’ bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. Certain of these credit agreements also contain a provision that limits Ameren’s, UE’s, CIPS’ and CILCO’s total indebtedness to 60% of total capitalization pursuant to a calculation defined in the agreement. Exceeding these debt levels would result in a default under the credit arrangements. As of December 31, 2004, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS and CILCO was 50%, 44%, 53% and 43%, respectively (2003 - 52%, 44%, 54%, 53%). From and after March 31, 2005, IP’s total indebtedness will also be limited by this provision. In addition, certain of these credit agreements contain indebtedness cross-default provisions and material adverse change clauses that could trigger a default under these facilities in the event that any of Ameren’s subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. The credit agreements also require us to meet minimum ERISA funding rules.
None of the Ameren Companies’ credit agreements or financing arrangements contain credit rating triggers. One of EEI’s credit agreements contains a credit rating trigger under which a default can occur in the event any of the sponsor’s (as defined in the credit agreements) credit rating falls below Baa3 or BBB- by Moody’s and S&P and the sponsor does not cover a payment default. A $100 million CILCO bank term loan containing a credit rating trigger was repaid in February 2004. At December 31, 2004, the Ameren Companies and EEI were in compliance with their credit agreement provisions and covenants.
NOTE 6 - LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding for the Ameren Companies and EEI as of December 31, 2004 and 2003:
(a) At December 31, 2004, a majority of property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued.
Substantially all of long-term debt issued by UE, CIPS, CILCO and IP is secured by a lien on substantially all of its property and franchises.
(b) Environmental Improvement or Pollution Control Series secured by first mortgage bonds. In addition, UE’s 1991, 1992, 1998 and 2000 series; CIPS’ 2004 series and CILCO’s
2004 series bonds are backed by an insurance guarantee policy.
(c) Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. The average interest rates for the years 2004
and 2003 were as follows:
UE 1991 Series
1.39%
1.60%
CIPS Series 2004
1.56%
-
UE 1992 Series
1.43%
1.64%
CILCO Series 2004
1.55%
-
UE 1998 Series A
1.30%
1.75%
IP 1997 Series A
1.68%
1.85%
UE 1998 Series B
1.28%
1.75%
IP 1997 Series B
1.55%
1.75%
UE 1998 Series C
1.26%
1.77%
IP 1997 Series C
1.535%
1.55%
UE 2000 Series A
1.19%
1.80%
IP Series 2001 (amortizing)
1.56%
1.85%
UE 2000 Series B
1.24%
1.77%
IP Series 2001
1.58%
1.75%
UE 2000 Series C
1.23%
1.75%
(d) Under the terms of the subordinated debentures, UE may, under certain circumstances, defer the payment of interest for up to five years. Upon the election to defer
interest payments, UE dividend payments to Ameren are prohibited.
(e) Variable-rate tax-exempt pollution control indebtedness that was converted to long-term fixed rates.
(f) CILCORP’s long-term debt is secured by a pledge of all of the common stock of CILCO.
(g) IP’s long-term debt payable to IP SPT was reduced by $12 million of overfunding at both December 31, 2004 and 2003.
The following table presents the aggregate maturities of long-term debt for the Ameren Companies at December 31, 2004:
(a)
Excludes $83 million related to CILCORP’s long-term debt fair market value adjustments.
(b)
Excludes $61 million related to IP’s long-term debt fair market value adjustments.
(c)
Total maturities of $423 million include $15 million of EEI current maturities of long-term debt.
All of the Ameren Companies expect to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing. See Note 5 - Short-term Borrowings and Liquidity for a discussion of external financing availability.
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain of the Ameren Companies as of January 31, 2005:
(a)
Ameren issued securities totaling $875 million under the August 2002 shelf registration statement and $459 million under the September 2003 shelf registration statement.
(b)
UE issued securities totaling $200 million in 2003, $404 million in 2004 and $85 million in January 2005.
Ameren
In February 2004, Ameren issued, pursuant to an August 2002 SEC Form S-3 shelf registration statement, 19.1 million shares of its common stock at $45.90 per share, for net proceeds of $853 million. This issuance substantially depleted all of the capacity under the August 2002 shelf registration statement. In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren and its subsidiary trusts covering the offering from time to time of up to $2 billion of various types of securities, including long-term debt, trust preferred securities, and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share, for net proceeds of $445 million. The proceeds from both of these offerings were used to pay the cash portion of the purchase price for our acquisition of IP and Dynegy's 20% interest in EEI and, as described below under IP, to reduce IP debt assumed as part of the acquisition and to pay related premiums.
The purchase of IP on September 30, 2004, included the assumption of IP debt and preferred stock at closing of $1.8 billion. The assumed debt and preferred stock included $936 million of mortgage bonds, $509 million of pollution control indebtedness supported by mortgage bonds, $352 million of TFNs issued by IP SPT, and $13 million of preferred stock not acquired and owned by Ameren. Upon acquisition, total IP debt was increased to fair value by $191 million. The adjustment to the fair value of each debt series is being amortized over its remaining life, or to the expected redemption date, to interest expense.
In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. In December 2001, Ameren began issuing new shares of common stock in connection with certain of our 401(k) plans pursuant to effective Form S-8 registration statement. Under DRPlus and our 401(k) plans, Ameren issued a total of 2.3 million shares of common stock in 2004 valued at $107 million. Under the DRPlus and our 401(k) plans, Ameren issued 2.5 million and 2.3 million shares of common stock in 2003 and 2002, respectively, which were valued at $105 million and $93 million for the respective years.
In March 2002, Ameren issued $345 million of adjustable conversion-rate equity security units and $227 million (gross proceeds) of common stock (5 million shares at $39.50 per share and 750,000 shares, pursuant to the exercise of an option granted to the underwriters, at $38.865 per share). The $25 adjustable conversion-rate equity security units each consisted of an Ameren senior unsecured note with a principal amount of $25 and a contract to purchase, for $25, a fraction of a share of Ameren common stock on May 15, 2005. The senior unsecured notes were recorded at their fair value of $345 million and will mature on May 15, 2007. Total distributions on the equity security units were originally made at an annual rate of 9.75%, consisting of quarterly interest payments on the senior unsecured notes at the initial annual rate of 5.20% and contract adjustment payments under the stock purchase contracts at the annual rate of 4.55%. In February 2005, the annual interest rate on $375 million principal amount of Ameren’s senior unsecured notes due May 15, 2007, was reset from 5.20% to 4.263%. The stock purchase contracts require holders to purchase 8.7 million to 7.4 million shares of Ameren common stock on May 15, 2005, at the market price at that time, subject to a minimum share purchase price of $39.50 and a maximum of $46.61. The stock purchase contracts included a pledge of the related senior unsecured notes as collateral for the stock purchase obligation. As a result of the February 2005 remarketing of the senior unsecured notes, treasury securities were substituted for the senior unsecured notes and are currently pledged as collateral for the stock purchase obligation and the senior unsecured notes were released from the pledge. In 2002, we recorded the net present value of the stock purchase contract adjustment payments of $46 million as an increase in Other Deferred Credits and Liabilities to reflect our obligation and a decrease in Other Paid-in Capital to reflect the fair value of the stock purchase contract. The liability for the stock purchase contract adjustment payments (December 31, 2004 - $6 million; December 31, 2003 - $21 million) will be reduced as such payments are made through May 15, 2005.
As discussed above, in February 2005, the annual interest rate on the $345 million principal amount of Ameren’s senior unsecured notes due May 15, 2007 was reset from 5.20% to 4.263%. These senior unsecured notes were originally issued in March 2002 as a component of Ameren’s publicly traded adjustable conversion-rate equity security units. As required by the original terms of the agreement, the interest rate was reset because Ameren remarketed these senior unsecured notes. The proceeds from the remarketing of the senior unsecured notes were used by the former holders of the adjustable conversion-rate equity security units to purchase treasury securities to secure their obligations to purchase Ameren common stock pursuant to the stock purchase contracts in May 2005. As part of this remarketing, Ameren also repurchased $95 million in principal amount of the senior unsecured notes; it has subsequently retired these notes.
UE
In 2004, UE received a capital contribution from Ameren totaling $16 million, as a result of an allocation of income tax benefit in 2004 and 2003, pursuant to the tax-allocation agreement among the Ameren Companies.
UE had a lease agreement, scheduled to expire on August 31, 2031, that provided for the financing of a portion of its nuclear fuel that was processed for use or was consumed at UE’s Callaway nuclear plant. In February 2004, UE terminated this lease with a final payment of $67 million made in January 2004.
In February and March 2004, in connection with the delivery of bond insurance policies to secure the environmental improvement and pollution control revenue bonds (Series 1991, 1992, 1998A, 1998B, 1998C, 2000A, 2000B and 2000C) previously issued by the Missouri Environmental Authority, UE delivered separate series of its first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those included in its first mortgage bonds that secure UE’s senior secured notes) to secure its respective obligations under the existing loan agreements with the Missouri Environmental Authority relating to such environmental improvement and pollution control revenue bonds. As a result, the environmental improvement and pollution control revenue bonds were rated Aaa, AAA, and AAA by Moody’s, S&P, and Fitch, respectively.
In May 2004, UE issued, pursuant to its September 2003 SEC Form S-3 shelf registration statement, $104 million of 5.50% senior secured notes due May 15, 2014, with interest payable semi-annually on May 15 and November 15 of each year beginning in November 2004. UE received net proceeds of $103 million, which were used to redeem its $100 million 7.00% first mortgage bonds due 2024.
In September 2004, UE issued, pursuant to its September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.10% senior secured notes due October 1, 2019, with interest payable semi-annually on April 1 and October 1 of each year beginning in April 2005. UE received net proceeds of $298 million, which were used to repay short-term debt temporarily incurred to fund the maturity of UE’s $188 million 6.875% first mortgage bonds on August 1, 2004, and to repay other short-term debt, which consisted of borrowings under the utility money pool arrangement.
In January 2005, UE issued, pursuant to its September 2003 SEC Form S-3 shelf registration statement, $85 million of 5.00% senior secured notes due February 1, 2020, with interest payable semi-annually on February 1 and August 1 of each year beginning in August 2005. UE received net proceeds of $83 million, which were used to repay short-term debt temporarily incurred to fund the maturity of UE’s $85 million 7.375% 2004 first mortgage bonds.
In December 2002, upon receipt of all necessary federal and state regulatory approvals, UE, pursuant to Missouri economic development statutes, conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri in exchange for the issuance by the city of a taxable industrial development revenue bond in the amount of $103 million. Concurrently, the city leased back the facility to UE for a term of 20 years. The lease term is the same as the final maturity of the bond purchased by UE. Although the lease is a capital lease, no capital was raised in the transaction. UE is responsible for making rental payments under the lease in an amount sufficient to pay the debt service of the bond. The city's ownership of the facility during the term of the bond and the lease will result in property tax savings to UE. Under the terms of the lease, UE retains all operation and maintenance responsibilities for the facility and ownership of the facility is returned to UE at the expiration of the lease.
CIPS
In November 2004, CIPS issued, through the Illinois Finance Authority, $35 million of Series 2004 environmental improvement revenue refunding bonds due in 2025, currently in a variable-rate Dutch auction interest rate mode. These bonds are insured by a bond insurance policy and secured by first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those which secure CIPS’ senior secured notes). As a result, the environmental improvement revenue refunding bonds were rated Aaa, AAA, and AAA by Moody’s, S&P, and Fitch, respectively. The proceeds received from the issuance of the $35 million Series 2004 bonds were used to redeem, at par, CIPS’ $35 million 6.375% 1993 Series A due 2028 pollution-control revenue bonds.
In December 2004, CIPS redeemed prior to maturity, $18 million of its 5.90% 1993 Series B-2 pollution control bonds due 2028 and $17 million of its $25 million 5.70% 1993 Series C-2 pollution control bonds due 2026. These redemptions were made with available cash and borrowings from the utility money pool agreement.
Ameren, UE and CIPS may sell all, or a portion of, the remaining securities registered under their open SEC registration statements if market conditions and capital requirements warrant. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and its rules and regulations.
CILCORP
In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. This resulted in recognition of fair-value adjustment increases of $71 million related to CILCORP’s 9.375% senior bonds due 2029 and $40 million related to its 8.70% senior notes due 2009. Amortization related to these fair value adjustments was $8 million for the year ended December 31, 2004 (2003 - $7 million), and was included in interest expense in the
Consolidated Statements of Income of Ameren and CILCORP.
In May 2004, CILCORP repurchased $15 million in principal amount of its 9.375% senior bonds. In July 2004, it repurchased an additional $2 million in principal amount of these bonds. In conjunction with these debt repurchases, the fair-value adjustment on these bonds was reduced by $5 million for the year ended December 31, 2004.
CILCO
In February 2004, CILCO repaid its secured bank term loan totaling $100 million with borrowings from the utility money pool agreement.
In November 2004, CILCO issued, through the Illinois Finance Authority, $19 million of Series 2004 environmental improvement revenue refunding bonds due in 2039, currently in a variable-rate Dutch auction interest rate mode. These bonds are insured by a bond insurance policy and are secured by first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those included in the first mortgage bonds which secure UE’s and CIPS' senior secured notes). As a result, the environmental improvement revenue refunding bonds were rated Aaa, AAA, and AAA by Moody’s, S&P, and Fitch, respectively. The Series 2004 bonds are subject to a mandatory sinking fund redemption totaling $5 million at par on October 1, 2026, with the remainder of $14 million in principal amount due October 1, 2039. The proceeds received from the issuance were used to redeem CILCO’s $14 million 6.50% Series 1992 A due 2018 and $5 million 6.50% Series 1992 C due 2010 pollution control revenue bonds.
IP
In conjunction with Ameren’s acquisition of IP, IP’s long-term debt was increased to fair value by $195 million. Amortization related to fair-value adjustments was $14 million for the year ended December 31, 2004 (2003 - $1 million) and was included in interest expense in the Consolidated Statements of Income of Ameren and IP.
In November 2004, pursuant to an equity clawback provision in the related bond indenture, IP redeemed
$192.5 million principal amount of its 11.50% Series mortgage bonds due 2010. The redemption price was equal to $1,115 per $1,000 principal amount, plus accrued and unpaid interest to the redemption date. Also in November 2004, IP completed a cash tender offer for $351 million of these bonds. The tender offer consideration paid was $1,214 per $1,000 principal amount plus accrued and unpaid interest to the settlement date. This tender offer satisfied IP’s indenture obligation to offer to purchase the bonds resulting from the change of control of IP upon its acquisition by Ameren. In December 2004, IP repurchased an additional $6.5 million principal amount of these bonds at a redemption price of $1,207 per $1000 principal amount plus accrued unpaid interest. At December 31, 2004, only $33,000 principal amount of these bonds remained outstanding.
In December 2004, IP redeemed $66 million principal amount of its 7.50% Series mortgage bonds due 2025 at a redemption price of 103.105% of the principal amount plus accrued interest and $84 million in principal amount of its 7.40% Series 1994 B pollution control bonds due 2024 at a redemption price of 102% of the principal amount plus accrued and unpaid interest. This indebtedness, along with the redemption and repurchase of the 11.50% Series mortgage bonds due 2010 described above, were funded by IP through equity contributions made by Ameren in the fourth quarter of 2004 totaling $871 million. In conjunction with these debt repurchases, the fair value adjustment on IP’s long-term debt was reduced by $103 million for the year ended December 31, 2004.
In December 1998, the IP SPT issued $864 million of TFNs as allowed under the Illinois Electric Utility Transition Funding Law. In accordance with the Transitional Funding Securitization Financing Agreement, IP must designate a portion of the cash received from customer billings to fund payment of the TFNs. The amounts received are remitted to the IP SPT and are restricted for the sole purpose of paying down the TFNs. Due to the adoption of FIN No. 46R and resulting deconsolidation of IP SPT, certain amounts of restricted cash are netted against the current portion of IP’s long-term debt payable to IP SPT on IP’s December 31, 2004 and 2003, consolidated balance sheets.
In September 1999, IP entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. IP sublet the turbines to a predecessor of DMG in October 1999. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, IP terminated its lease with the original lessor. DMG then executed a transfer agreement under which the original lessor sold the turbine assets to DMG for the full contract price of $81 million. Additionally, IP assigned its associated land lease on the Tilton site to a predecessor of DMG. For additional information relating to the Tilton capital lease and related asset retirement obligation liability and remeasurement, see Note 1 - Summary of Significant Accounting Policies.
EEI
In June 2004, EEI repaid its $40 million bank term loan at maturity with proceeds received from EEI’s credit facilities.
In December 2004, EEI repaid $6 million of its 8.60% medium-term notes and $8 million of its 6.61% medium-term notes with proceeds received from EEI’s credit facilities.
Indenture Provisions and Other Covenants
UE
UE’s indenture agreements and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. For the 12 months ended December 31, 2004, UE had a coverage ratio of 8.2 times the annual interest charges on the first mortgage bonds outstanding, which would permit UE to issue an additional $3.7 billion of first mortgage bonds at an assumed interest rate of 7%. For the issuance of additional preferred stock, earnings coverage of at least 2.5 times the annual dividend on preferred stock outstanding and to be issued is required under UE’s articles of incorporation. For the 12 months ended December 31, 2004, UE had a coverage ratio of 63 times the annual dividend requirement on preferred stock outstanding, which would permit UE to issue an additional $2 billion in preferred stock at an assumed dividend rate of 7%. The ability to issue such securities in the future will depend on such tests at that time.
In addition, UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.7 billion of free and unrestricted retained earnings at December 31, 2004.
CIPS
CIPS’ indenture agreements and articles of incorporation include covenants that must be complied with before first mortgage bonds and preferred stock are issued. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required, except in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. For the 12 months ended December 31, 2004, CIPS had a coverage ratio of 3.1 times the annual interest charges for one year on the aggregate amount of bonds outstanding. Consequently, the most restrictive test under the indenture agreements would allow CIPS to issue an additional $134 million of first mortgage bonds, assuming an interest rate of 7%. For the issuance of additional preferred stock, earnings coverage of 1.5 times annual interest charges on all long-term debt and the annual preferred stock dividends is required under CIPS’ articles of incorporation. For the 12 months ended December 31, 2004, CIPS had a coverage ratio of 2.1 times the sum of the annual interest charges and dividend requirements on all long-term debt and preferred stock outstanding as of December 31, 2004, and consequently had the availability to issue an additional $182 million of preferred stock, assuming a dividend rate of 7%. The ability to issue such securities in the future will depend on such coverage ratios at that time.
Genco
Genco’s senior note indenture includes provisions that require it to maintain a senior debt service coverage ratio of at least 1.75 to 1 (for both the prior four fiscal quarters and for the succeeding four six-month periods) in order to pay dividends or to make payments of principal or interest under certain subordinated indebtedness, excluding amounts payable under its intercompany note payable to CIPS. For the 12 months ended December 31, 2004, this ratio was 5.0 to 1. In addition, the indenture also restricts Genco from incurring any additional indebtedness, with the exception of certain permitted indebtedness defined in the indenture, unless its senior debt service coverage ratio equals at least 2.5 to 1 for the most recently ended four fiscal quarters and its senior debt to total capital ratio would not exceed 60% - both after giving effect to the additional indebtedness on a pro-forma basis. This debt incurrence restriction is to be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of debt incurrence after considering the additional indebtedness. As of December 31, 2004, Genco’s senior debt to total capital ratio was 53%.
CILCORP
Covenants in CILCORP's indenture governing its $475 million (original issuance amount) senior notes and bonds require CILCORP to maintain a debt-to-capital ratio no greater than 0.67 to 1 and an interest coverage ratio of at least 2.2 to 1 in order to make any payment of dividends or intercompany loans to affiliates other than to its direct and indirect subsidiaries, including CILCO. However, in the event CILCORP is not in compliance with these tests, CILCORP may make such payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. For the 12 months ended December 31, 2004, CILCORP's debt-to-capital ratio was 0.58 to 1 and its interest coverage ratio was 2.3 to 1, calculated in accordance with applicable provisions of this indenture. At December 31, 2004, CILCORP’s senior long-term debt ratings from S&P, Moody’s, and Fitch were BBB+, Baa2, and BBB+, respectively. The common stock of CILCO is pledged as security to the holders of these senior notes and bonds.
CILCO
CILCO’s indenture agreement and articles of incorporation include covenants that must be compiled with before CILCO may issue first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds, an
earnings coverage of twice the annual interest requirements on first mortgage bonds outstanding and to be issued, or earnings of at least 12% of the principal amount of all bonds
outstanding and to be issued is required, except in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. For the 12 months ended December 31, 2004, CILCO had an earnings coverage ratio of 7.5 times the annual interest charges for one year on the aggregate amount of bonds outstanding or at least 53% of the principal amount of all mortgage bonds outstanding under the mortgage. Accordingly, the most restrictive test under the indenture agreement would allow CILCO to issue an additional $47 million of first mortgage bonds. For the issuance of additional shares of preferred stock, the articles of incorporation would allow CILCO to issue an additional $47 million of first mortgage bonds. For the issuance of additional shares of preferred stock, the articles of incorporation provide that no class of shares with rights superior to the currently issued preferred stock as to payment of dividends or as to assets shall be issued, unless the net income available for the payment of the dividends for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance shall be at least 2 ½ times the annual dividend requirements of all then-outstanding shares of preferred stock. Consequently, the most restrictive test under which CILCO could issue additional shares of preferred stock would allow CILCO to issue additional preferred stock in the amount of $155 million.
IP
IP’s indenture agreements and articles of incorporation include covenants and provisions related to the issuance of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds based on property additions, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. For the 12 months ended December 31, 2004, IP had a coverage ratio of 1.88 times the annual interest charges on the first mortgage bonds outstanding, which would not permit IP to issue any additional first mortgage bonds based on property additions. However, as of December 31, 2004, IP had the ability to issue $1.3 billion of bonds based upon retired bond capacity, for which no earnings coverage test is required. For the issuance of additional preferred stock, earnings coverage of at least 1.5 times the annual dividend on preferred stock outstanding and to be issued is required under IP’s articles of incorporation. For the 12 months ended December 31, 2004, IP had a coverage ratio of 1.37 times the annual dividend requirement on preferred stock outstanding, which would not permit IP to issue any additional preferred stock. The ability to issue such securities in the future will depend on such tests at that time.
The IP SPT TFNs contain restrictions that prohibit IP LLC from making any loan or advance to, or certain investments in, any other person. Also, as long as the TFNs are outstanding, the IP SPT shall not, directly or indirectly, pay any dividend or make any distribution (by reduction of capital or otherwise) to any owner of a beneficial interest in the IP SPT.
See Note 3 - Rate and Regulatory Matters for restrictions on IP’s ability to declare and pay common stock dividends imposed by the ICC order approving Ameren’s acquisition of IP.
Off-Balance Sheet Arrangements
At December 31, 2004, none of the Ameren Companies had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance sheet financing arrangements in the near future.
NOTE 7 - RESTRUCTURING CHARGES AND OTHER SPECIAL ITEMS
Ameren and UE recorded a pretax coal contract settlement gain of $51 million in 2003. This gain represented a return of coal costs plus accrued interest accumulated by a coal supplier for reclamation of a coal mine that supplied a UE power plant. UE entered into a settlement agreement with the coal supplier to return the accumulated reclamation funds, which were paid to UE ratably through December 2004.
CILCO recorded $2 million and $21 million in acquisition integration costs in 2004 and 2003, respectively. The 2004 costs primarily represented severance and relocation amounts. The 2003 costs represented write-offs of software without future benefit as of the acquisition date ($13 million), severance and relocation costs ($5 million), and an increase in the bad debt reserve related to one customer for which there was significant collection concern at the acquisition date ($3 million). These amounts were offset against goodwill at CILCORP through purchase accounting and, therefore, there was no impact to Ameren’s Consolidated Statement of Income.
Ameren recorded voluntary employee retirement and other restructuring charges of $92 million in 2002. These charges included a voluntary retirement program charge of $75 million based on voluntary retirements of approximately 550 employees. Of the $75 million charge, UE recorded $51 million, CIPS recorded $14 million, Genco recorded $8 million, and other Ameren companies recorded $2 million. These charges related primarily to special termination benefits associated with our pension and postretirement benefit plans. Most of the employees who voluntarily retired accepted retirement in 2002 and left Ameren in early 2003.
In addition, in 2002, Ameren recorded a charge of $17 million primarily associated with the retirement of 343 megawatts of rate-regulated generating capacity at UE’s Venice, Illinois plant and temporary suspension of operations of two coal-fired generating units (126 megawatts) at Genco’s Meredosia, Illinois plant.
NOTE 8 - OTHER INCOME AND DEDUCTIONS
The following table presents Other Income and Deductions for each of the Ameren Companies for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
amounts represent predecessor information. January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
and 2002 amounts represent predecessor information. January through September 2004 predecessor miscellaneous income and expense amounts were $144 million and $1 million, respectively.
NOTE 9 - DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel, and electricity cause:
·
an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sale prices under the firm commitment are compared with current commodity prices;
·
market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory under firm commitment; and
·
actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are approved by risk management policies that control the use of forward contracts, futures, options and swaps. Our net positions are continually assessed within our structured hedging programs to determine if new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring sufficient volumes are available to meet our requirements.
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and sale exceptions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Accordingly, these contracts are recorded at fair value with changes in the fair value charged or credited to the income statement in the period in which the change occurred. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty.
Cash Flow Hedges
Our risk management processes identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The mark-to-market value of cash flow hedges will continue to fluctuate with changes in market prices up to contract expiration.
We monitor and value derivative positions daily as part of our risk management processes. We use published sources for pricing when possible to mark positions to market. We rely on modeled valuations only when no other method exists.
The following table presents balances in certain accounts for cash flow hedges as of December 31, 2004 and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
Represents the mark-to-market value for the hedged portion of electricity price exposure for periods generally less than one year. Certain contracts designated as hedges of electricity price exposure have terms up to three years.
(c)
Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002.
(d)
Represents a gain associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2008.
(e)
Represents the mark-to-market gain of two call options to purchase coal that are accounted for as cash flow hedges. One of these options to purchase coal expired in October 2003 and the other option expires in July 2005.
The pretax net gain or loss on power forward derivative instruments included in Other Income and (Deductions) at Ameren, UE and Genco, which represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, was less than $1 million loss for Ameren, UE and Genco for the year ended December 31, 2004 (2003 - less than a $1 million loss for Ameren, UE, and Genco).
Other Derivatives
The following table represents the net change in market value of option transactions, which are used to manage our positions in SO2 allowances, coal, heating oil, and electricity or power. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133. The net change in the market value of SO2 options is recorded in Operating Revenues - Electric, while the net change in the market value of coal, heating oil and electricity or power options is recorded as Operating Expenses - Fuel and Purchased Power.
(a)
Heating oil option gains and losses were less than $1 million for all periods shown above.
(b)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(c)
amounts represent predecessor information. January 2003 predecessor amounts were zero.
Through the market allocation process, UE, CIPS, Genco, CILCO and IP have been granted FTRs associated with the advent of the MISO Day Two Market. Marketing Company has been granted FTRs for its participation in the PJM-Com Ed market. We sought and received FTRs with the intent to hedge (offset) congestion charges related to our physical electricity business. Depending on the congestion on the transmission grid and prices at various points on the grid, FTRs could result in either charges or credits. We use complex grid modeling tools to determine which FTRs we wish to nominate in the FTR allocation process. There is risk that we may incorrectly model the amount of FTRs we need, and there is the potential that some of the FTR hedges could be ineffective.
NOTE 10 - STOCKHOLDER RIGHTS PLAN AND PREFERRED STOCK
Stockholder Rights Plan
Ameren’s board of directors has adopted a share purchase rights plan designed to assure stockholders of fair and equal treatment in the event of a proposed takeover. The rights are exercisable only if a person or group acquires 15% or more of Ameren’s outstanding common stock or announces a tender offer, which would result in ownership by a person or group of 15% or more of the Ameren common stock. Each right will entitle the holder to purchase one one-hundredth of a newly issued preferred stock at an exercise price of $180. If a person or group acquires 15% or more of Ameren’s outstanding common stock, each right will entitle its holder (other than such person or members of such group) to purchase, at the right’s then-current exercise price, a number of Ameren’s common shares having a market value of twice such price. In addition, if Ameren is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of Ameren’s outstanding common stock, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price. The acquiring person or group will not be entitled to exercise these rights. These rights expire in 2008. One right will accompany each new share of Ameren common stock prior to such expiration date.
Preferred Stock
All classes of UE’s, CIPS’, CILCO’s and IP’s preferred stock are entitled to cumulative dividends and have voting rights. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding. CIPS has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding. UE has 7.5 million shares authorized of $1 par value preference stock and CILCO has 2 million shares authorized of no par value preference stock, with no such preference stock outstanding. IP has 5 million shares authorized of no par value serial preferred stock and 5 million shares authorized of no par value preference stock, with no such serial preferred stock and preference stock outstanding. No shares of preference stock have been issued by any of the Ameren Companies.
The following table presents the outstanding preferred stock of UE, CIPS, CILCO and IP that is not subject to mandatory redemption and is entitled to cumulative dividends and is redeemable, at the option of the issuer, at the prices presented as of December 31, 2004 and 2003:
(a)
In the event of voluntary liquidation, $105.50.
(b)
Beginning February 15, 2003, declining to $100 per share in 2012.
(c)
amounts represent predecessor information.
(d)
Ameren purchased 662,924 shares of IP’s preferred stock on September 30, 2004. See Note 2 - Acquisitions for additional information.
The following table presents the outstanding preferred stock of CILCO that is subject to mandatory redemption, is entitled to cumulative dividends and is redeemable, at a determinable price on a fixed date or dates, at the prices presented as of December 31, 2004 and 2003, respectively:
(a)
Beginning July 1, 2003, this preferred stock became redeemable, at the option of CILCO, at $100 per share. A mandatory redemption fund was established on July 1, 2003. The fund provides for the redemption of 11,000 shares for $1.1 million on July 1 of each year through July 1, 2007. On July 1, 2008, the remaining shares outstanding will be retired for $16.5 million.
(b)
In the event of voluntary or involuntary liquidation, the stockholder receives $100 per share plus accrued dividends.
NOTE 11 - RETIREMENT BENEFITS
We have defined benefit and postretirement benefit plans covering substantially all employees of UE, CIPS, CILCORP, CILCO, IP, EEI and Ameren Services and certain employees of Resources Company and its subsidiaries, including Genco. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans.
IP merged into the Ameren pension and postretirement plans during the fourth quarter of 2004. Previously, IP had been part of the Dynegy benefit plans, so the IP predecessor amounts below represent the components of IP’s participation in the Dynegy plans prior to Ameren’s acquisition of IP. Plan participants included not only employees of IP, but certain Illinova and DMG employees. IP was reimbursed by participating Dynegy subsidiaries for their respective shares of the expenses of these benefit plans. Effective with Ameren’s acquisition of IP, employees of the other Dynegy subsidiaries were not transferred into the Ameren plans and, therefore, are not included in successor information presented.
Investment Strategy and Return on Asset Assumption
The primary objective of the Ameren Retirement Plan and postretirement benefit plans is to provide eligible employees with pension and postretirement health care benefits. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in the ERISA. Ameren’s goal is to earn the highest possible return on plan assets consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. Where appropriate, Ameren provides the investment manager with specific guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after an analysis of historical experience and future expectations of the returns and the volatility of the various asset classes. Depending on the target asset allocation for each asset class, the overall expected rate of return for the portfolio was adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
Pension
Pension benefits are based on the employees’ years of service and compensation. Our plans are funded in compliance with income tax regulations and federal funding requirements.
The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts during 2004 and 2003. The current-year contribution provided cost savings to us by eliminating the need to pay a portion of insurance premiums to the Pension Benefit Guarantee Corporation.
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
A minimum pension liability was recorded at December 31, 2002, which resulted in an after-tax charge to OCI and a reduction in stockholders’ equity of $102 million. In 2003, the minimum pension liability was reduced, resulting in OCI of $46 million and an increase in stockholders’ equity. In 2004, the minimum pension liability was increased, resulting in a charge to OCI of $6 million and a decrease in stockholders’ equity.
The following table presents the minimum pension liability amounts, after taxes, as of December 31, 2004 and 2003:
(a) Excludes amounts for IP prior to the acquisition date of September 30, 2004; and includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c) Represents predecessor information in 2003.
The following tables present the funded status of our pension plans for the years ended December 31, 2004 and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b)
Represents predecessor information.
(c)
Excludes amounts paid from company funds.
(d)
Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
The following table presents the assumptions used to determine benefit obligations at December 31, 2004 and 2003:
(a) amounts do not include IP.
(b) Included in Ameren’s plan at December 31, 2004. 2003 amounts represent predecessor information.
Based on our assumptions at December 31, 2004, we expect to be required under ERISA to fund an aggregate of $400 million for the period of 2005 to 2009, in order to maintain minimum funding levels for our pension plan with no minimum contribution required until 2008, assuming continuation of the current interest rate relief beyond 2005. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be approximately 50%, 9%, 9%, 11%, and 21%, respectively. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any prior voluntary contributions.
The following tables present the amounts recorded in the Consolidated Balance Sheets as of December 31, 2004 and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004.
(b)
Represents predecessor information.
The following table presents our pension plan asset categories as of December 31, 2004 and 2003 and our target allocations for 2005:
(a) amounts do not include IP.
(b) Included in Ameren’s plan at December 31, 2004; 2003 amounts represent predecessor information.
The following table presents the projected benefit obligation, the accumulated benefit obligation and the fair value of plan assets for plans that have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2004 and 2003:
(a) 2003 amounts do not include IP.
(b) Included in Ameren’s plan at December 31, 2004; 2003 amounts represent predecessor information.
The following table presents the components of the net periodic pension benefit cost during 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b)
Represents predecessor information for the first nine months of 2004.
(c)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(d)
Represents predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(e)
Special termination benefits are deferred as a regulatory asset. See Note 3 - Rate and Regulatory Matters.
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan. The net actuarial (gain) loss subject to amortization is amortized on a straight-line basis over 10 years.
UE, CIPS, Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are responsible for their proportional share of the costs. The following table presents the pension costs (benefits) incurred for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b)
Includes predecessor information for periods prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
Includes predecessor information for periods prior to the acquisition date of September 30, 2004. Predecessor amount in 2004 is $7 million.
The expected pension benefit payments from qualified trust and company funds, which reflect expected future service, are as follows:
The following table presents the assumptions used to determine net periodic benefit cost for the years ended December 31, 2004, 2003, and 2002:
(a)
amounts do not include IP. 2002 amounts do not include CILCORP or CILCO.
(b)
Included in Ameren’s plan for 2003 and 2004. Represents predecessor information for 2002.
(c)
Included in Ameren’s plan for 2004. Represents predecessor information for 2003 and 2002.
Postretirement
Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association trusts (VEBA) to match the annual postretirement expense.
The following table presents the cash contributions made to our postretirement plan during 2004. We made cash contributions of $70 million in 2003, excluding predecessor IP. IP contributions in 2003 were $6 million. We expect to make contributions of $75 million during 2005.
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant Ameren subsidiaries.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
There were no contributions made by predecessor IP during the first nine months of 2004.
The following tables present the funded status of Ameren’s postretirement benefit plans at December 31, 2004, and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b)
Represents predecessor information.
(c)
Excludes amounts paid from company funds.
(d)
Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(e)
Ameren’s transition obligation at December 31, 2004, is being amortized over the next years.
The following table presents the assumptions used to determine the benefit obligations at December 31, 2004, and 2003:
(a)
amounts do not include IP.
(b)
Included in Ameren’s plan at December 31, 2004; 2003 amounts represent predecessor information.
The following tables present the components of Ameren’s net periodic postretirement benefit cost as of December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b)
Represents predecessor information for the first nine months of 2004.
(c)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(d)
Represents predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
Prior service cost is amortized on a straight-line basis over the average future service of active plan participants benefiting under the postretirement plans. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
Ameren adopted FSP SFAS 106-2 during the second quarter of 2004, retroactive to January 1, 2004, which resulted in the recognition of a federal subsidy for postretirement benefit costs related to prescription drug benefits. See Note 1 - Summary of Significant Accounting Policies. The effect of this subsidy was a reduction of various components of Ameren’s and principally UE’s net periodic postretirement benefit costs. Interest costs were reduced by $4 million and amortization of losses were reduced by $7 million. The impact of the subsidy on the expected return on plan assets was minimal.
UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their proportional share of the postretirement benefit costs. The following table presents the postretirement benefit costs for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; includes amounts for Ameren Registrant and non-Registrant subsidiaries.
(b)
Includes predecessor information for periods prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
Includes predecessor information for periods prior to the acquisition date of September 30, 2004. Predecessor amount in 2004 is $12 million.
The following expected postretirement benefit payments, which reflect expected future service, are as follows:
The following table presents our postretirement plan asset categories as of December 31, 2004 and 2003, and our target allocations for 2005:
(a) amounts do not include IP.
(b) Included in Ameren’s plan at December 31, 2004. 2003 amounts represent predecessor information.
The following table presents the assumptions used to determine net periodic benefit cost for the years ended December 31, 2004, 2003 and 2002:
(a)
amounts do not include IP. 2002 amounts do not include CILCORP or CILCO.
(b)
Included in Ameren’s plan in 2003 and 2004. Represents predecessor information for 2002.
(c)
Included in Ameren’s plan in 2004. Represents predecessor information for 2003 and 2002.
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. In addition, we have plan limits on the amount Ameren will contribute to future postretirement benefits. The following table presents the effects of a 1% change in assumed health care cost trend rates:
Other
Ameren and CIPS sponsor 401(k) plans for eligible employees. An IP plan was merged into the Ameren plan during the fourth quarter of 2004. The CILCO plan was merged into the Ameren plan at the beginning of 2004. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren, CIPS and IP (predecessor) match a percentage of the employee contributions up to certain limits. Ameren’s and IP’s matching contributions to the 401(k) plans totaled $15 million and $2 million (predecessor), respectively, in 2004. Matching contributions to the Ameren, previous IP, and previous CILCO plans were $14 million, $2 million, and $1 million, respectively, in each of the years 2003 and 2002. CIPS’ matching contributions to its 401(k) plan were less than $1 million annually in 2004, 2003 and 2002.
NOTE 12 - STOCK-BASED COMPENSATION
Ameren has a long-term incentive plan for eligible employees called the Long-term Incentive Plan of 1998, which provides for the grant of options, performance awards, restricted stock, dividend equivalents, and stock appreciation rights. Restricted stock awards were granted in 2004, 2003 and 2002 as a component of our compensation programs. We applied APB Opinion No. 25 in accounting for our stock-based compensation for years prior to 2003. There have not been any stock options granted since December 31, 2000. Effective January 1, 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of SFAS No. 123. See Note 1 - Summary of Significant Accounting Policies for further information.
Restricted Stock
Restricted stock awards in Ameren common stock may be granted under our long-term incentive plan. Upon the achievement of certain performance levels, the restricted
stock award vests over a period of seven years, beginning at the date of grant, and includes provisions requiring certain stock ownership levels based on position and salary. An accelerated vesting provision included in this plan reduces the vesting period from seven years to three years. During 2004, 2003, and 2002, respectively, 135,340, 152,956, and 154,678 restricted stock awards were granted. The weighted-average fair value for restricted stock awards granted in 2004, 2003, and 2002 was $46.34, $39.74, and $42.50 per share, respectively. We record unearned compensation (as a component of stockholders’ equity) equal to the market value of the restricted stock on the date of grant and charge the unearned compensation to expense over the vesting period.
Stock Options
Ameren
Options in Ameren common stock may be granted under our long-term incentive plan at a price not less than the fair-market value of the common shares at the date of grant. Granted options vest over a period of five years, beginning at the date of grant, and provide for accelerated exercising upon the occurrence of certain events, including retirement. Outstanding options expire on various dates through 2010. Subject to adjustment, 4 million shares have been authorized to be issued or delivered under our long-term incentive plan. In accordance with APB Opinion No. 25, no compensation expense was recognized related to our stock options for 2004, 2003 and 2002.
The following table presents Ameren stock option activity during 2004, 2003 and 2002:
The following table presents additional information about Ameren stock options outstanding at December 31, 2004:
The fair values of stock options were estimated using a binomial option-pricing model with the following assumptions:
CILCORP
Prior to Ameren’s acquisition of CILCORP, employees of CILCORP and CILCO participated in the AES Stock Option Plan that provided for grants of AES common stock options to eligible participants. Under the terms of the plan, options were issued to purchase shares of AES common stock at a price equal to 100% of the market price at the date the option was granted. The
options became eligible for exercise under various schedules. The following table presents CILCORP stock option activity during 2002:
Provisions of CILCORP bonus programs allowed for the cash-out of certain AES stock options in the event of an acquisition of CILCORP. CILCORP paid $3 million during 2003 for the cash-out of the entire 73,502 shares that were eligible under these provisions. All other outstanding options under the AES Stock Option Plan remain the sole obligation of AES.
The following table presents the assumptions that were used in the Black-Scholes valuation method for shares of AES common stock granted:
IP
Prior to Ameren’s acquisition of IP, certain IP employees participated in the equity compensation plans of Dynegy. On October 1, 2004, as a result of the acquisition, all unvested stock options granted to IP employees became null and void. The following table presents IP stock option activity:
(a)
The 22,594 exercisable options as of September 30, 2004, are an obligation of Dynegy; therefore, additional successor information is not presented.
The following table presents the assumptions that were used in the Black-Scholes valuation method for shares of Dynegy common stock granted:
(a) Assumptions for the 2004 grant are not presented as the expense associated with the options was negligible and the options were either cancelled or assumed by Dynegy.
NOTE 13 - INCOME TAXES
The following table presents the effective tax rates on income before income taxes as a result of total income tax expense for each of the Ameren Companies for 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003.
(b)
Represents predecessor information for 2002.
(c)
Represents predecessor information for January - September 2004, 2003 and 2002.
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003.
(b)
Represents predecessor information for 2002.
(c)
Represents predecessor information for January - September 2004, 2003 and 2002.
(d)
Permanent items primarily include FAS 106-2 Medicare Part D for Ameren, UE, CIPS, CILCORP and CILCO and a litigation settlement at CILCORP and CILCO.
(e)
CILCORP Other primarily includes low-income housing tax credits and company-owned life insurance.
The following table presents the components of income tax expense for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003.
(b)
Represents predecessor information for 2002.
(c)
Represents predecessor information for January - September 2004, 2003 and 2002.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2004 and 2003:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
CILCORP consolidates CILCO and therefore includes CILCO in its balances.
(c)
Represents predecessor information for 2003.
Upon Ameren’s acquisition of IP, IP’s net accumulated deferred income tax liabilities and unamortized accumulated investment tax credits were eliminated. Subsequent to the acquisition, IP began recording new accumulated deferred tax assets and liabilities and had recorded net deferred income tax assets of $65 million as of December 31, 2004.
NOTE 14 - RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. Below are the material related-party agreements.
Electric Power Supply Agreements
Under two electric power supply agreements, Genco is obliged to supply to Marketing Company, and Marketing Company, in turn, is obliged to supply to CIPS with all of the energy and capacity CIPS needs to offer service for resale to
its native load customers at ICC-related rates and to fulfill its other obligations under all applicable federal and state tariffs or contracts. Any power not used by CIPS is sold by Marketing Company under various long-term wholesale and retail contracts. For native load, CIPS pays an annual capacity charge per megawatt (the greater of its forecasted peak demand or actual demand), plus an energy charge per megawatthour to Marketing Company. For fixed-price retail customers outside of the tariff, CIPS pays Marketing Company the price it receives under these contracts. The fees paid by CIPS to Marketing Company for native load and fixed-price retail customers and any other sales by Marketing Company under various long-term wholesale and retail contracts are passed through to Genco. In addition, under the power supply agreement between Genco and Marketing Company, Genco bears all generation-related operating risks, including plant performance, operations, maintenance, efficiency, employee retention, and other matters. There are no guarantees, bargain purchase options, or other terms that may convey to CIPS the right to use the property and plant of Genco. The expiration date for the agreement between CIPS and Marketing Company has been extended to December 31, 2006. The agreement between Genco and Marketing Company can be terminated by either party upon one year’s notice. This extension was required by the ICC in its order approving Ameren’s acquisition of CILCORP and CILCO.
In October 2003, in conjunction with CILCO’s transfer to AERG of substantially all of its generating assets, AERG entered into an electric power supply agreement to supply CILCO with sufficient power to meet its native load requirements. CILCO pays a monthly capacity charge per megawatt based on its system capacity requirements, plus an energy charge per megawatthour. The expiration date for this agreement has been extended to December 31, 2006. The ICC required this extension in its order approving Ameren’s acquisition of CILCORP and CILCO. Also in conjunction with CILCO’s generating asset transfer, a bilateral power supply agreement was entered into between AERG and Marketing Company. This agreement provides for AERG to sell excess power to Marketing Company for sales outside the CILCO control area, and it also allows Marketing Company to sell power to AERG to fulfill CILCO’s native load requirements.
CILCO had an agreement with CIPS for the purchase of 100 megawatts of capacity and firm energy for the months of January and June through September under a contract that commenced in January 2000 and expired in September 2003. This power was supplied by Genco through the Marketing Company, CIPS, and Genco electric power supply agreements discussed above.
UE, CIPS, IP and a nonaffiliated company are parties to a power supply agreement with EEI to purchase and sell capacity and energy. This agreement expires on December 31, 2005. Under a separate agreement that expires on December 31, 2005, CIPS resold its entitlements under the power supply agreement with EEI to Marketing Company. Marketing Company and certain nonaffiliated companies are parties to a power supply agreement with Midwest Electric Power, Inc., a subsidiary of EEI, to purchase capacity and energy. This agreement’s term is year to year on a calendar basis unless the purchasing parties unanimously agree to terminate their participation.
UE has a 150-megawatt power supply agreement with Marketing Company that expires December 31, 2005. UE also had a one-year 450-megawatt power supply agreement with Marketing Company that expired in May 2002 and another one-year 200 megawatt power supply agreement with Marketing Company that expired in May 2003. Power supplied by Marketing Company to UE through these agreements is being obtained from Genco.
In December 2003, the SEC approved an agency agreement between AERG and Marketing Company that authorizes Marketing Company, on behalf of AERG, to sell AERG’s excess generation or to purchase power needed to supply AERG customers.
In December 2004, Marketing Company and IP entered into an agency agreement that authorizes Marketing Company, on behalf of IP, to sell or purchase, as necessary, electric energy and capacity in the wholesale market for 2005 and 2006.
IP had a contract with a former affiliate, DMG, to supply power via purchase agreements that expired at the end of 2004. The purchased power agreement with DMG obliged DMG to provide power to IP up to the reservation amount, and at the same prices, even if DMG had individual units unavailable at various times.
IP is party to several commercial and industrial electric and gas sales agreements with DMG, which were entered into prior to Ameren’s acquisition of IP. These are typically yearly contracts that renew automatically unless cancelled by either party pursuant to a 30-day written notice.
Also prior to Ameren’s acquisition, IP purchased natural gas from Dynegy to serve its gas distribution business under a Gas Industry Standards Board master base contract that terminated October 1, 2004. Under this agreement, IP executed multiple transactions in 2002 and 2003 that covered deliveries for the yearly winter peak season from November through March. One transaction was executed in 2004 to provide deliveries from January to March 2004.
Interconnection and Transmission Agreements
UE, CIPS and IP are parties to an interconnection agreement for the use of their respective transmission lines and other facilities for the distribution of power. In addition, CILCO and IP are parties to a similar interconnection agreement. These agreements have no contractual expiration
date but may be terminated by either party with three years notice.
IP is party to transmission and interconnection sales agreements with DYPM, a former affiliate, for the use of IP’s transmission lines and other facilities. The transmission sale agreements expire in April and June 2005. The interconnection sales agreements expire January 1, 2006. On October 1, 2004, pursuant to the sale of IP to Ameren, all continuing contracts with Dynegy and its affiliates became third-party agreements.
Joint Dispatch Agreement
UE and Genco jointly dispatch electric generation under a joint dispatch agreement among UE, Genco and CIPS. Under the agreement, each affiliate is permitted to use the cheapest generation available first, whether it be from UE or Genco. Each affiliate has the option to serve its load requirements from its own generation first, and then to allow access to any available generation to its affiliate. The joint dispatch agreement can be terminated by either party upon one year’s notice. In an order approving the transfer of UE’s Illinois-based utility businesses to CIPS (see Note 3 - Rate and Regulatory Matters), the MoPSC ordered UE to amend the joint dispatch agreement so that margins on short-term power sales will be determined by generation output as opposed to load. This will provide UE with a larger share of the margins on short-term sales of power from the combined generation of UE and Genco. Such an amendment is expected to provide to UE with additional annual margins ranging from $7 million to $24 million for UE’s share of short-term power sales. Such an amendment is expected to result in a corresponding reduction in Genco’s margins from its share of short-term power sales. However, this reduction is expected to be mitigated by margins received from additional power sales by Genco (through Marketing Company) to CIPS to serve the transferred UE Illinois-based electric utility business through the end of 2006 under the current power supply contracts.
The termination of the joint dispatch agreement, or modifications to it, could have a material effect on Ameren, UE or Genco. Modifications to or termination of the agreement would not have an immediate impact on Ameren because of UE’s Missouri electric rate moratorium, which ends June 30, 2006.
Any excess generation not used by UE or Genco through the joint dispatch agreement is sold to third parties through Ameren Energy, serving as each affiliate’s agent. Ameren Energy also acts as agent on behalf of UE and Genco to purchase power when they require it.
Support Services Agreements
Costs of support services provided by Ameren Services, Ameren Energy, and AFS to their affiliates, including wages, employee benefits, professional services, and other expenses are based on, or are an allocation of, actual costs incurred. Effective September 30, 2004, IP was added to the support services agreements with Ameren Services and AFS. Prior to this, IP operated under Dynegy’s consolidated group’s Services and Facilities Agreement, whereby other Dynegy affiliates exchanged with IP services such as financial, legal, information technology, and human resources, as well as shared facility space. IP services were exchanged at fully distributed costs and revenues were not recorded under this agreement. This agreement was terminated in conjunction with IP’s sale to Ameren.
Executory Tolling, Gas Sales, and Transportation Agreements
Under an executory tolling agreement, CILCO purchases steam, chilled water, and electricity from Medina Valley. In connection with this agreement, Medina Valley purchases gas to fuel its generating facility from AFS under a fuel supply and services agreement. Prior to September 2003, Medina Valley purchased gas from CILCORP Energy Services, Inc., a subsidiary of CILCORP that operated gas management services including commodity procurement and redelivery to retail customers, and gas transportation from CILCO.
Under a gas transportation agreement, Genco acquires gas transportation service from UE for its Columbia, Missouri CTs. This agreement expires in February 2016.
Notes Receivable from Former Affiliate
At December 31, 2004, there was no principal outstanding under IP’s $2.3 billion Note Receivable from Former Affiliate, as it was eliminated in connection with the sale of all of IP’s common stock and approximately 73% of its preferred stock to Ameren. Due to the prepayments described below, IP had no accrued interest at December 31, 2004 or 2003. In July, September, October and December 2003, Dynegy made interest payments totaling $256 million on its $2.3 billion intercompany note payable to Illinova, which in turn made interest payments totaling $256 million to IP under the Note Receivable from Former Affiliate. These interest payments represented accrued interest on the notes for the months of April through December 2003 and prepaid interest for the months of January 2004 through September 2004. In January 2004, IP received an additional interest prepayment of $43 million. These notes contained payment provisions pursuant to which semi-annual interest payments of $86 million were due on April 1 and October 1 of each year. See Note 2 - Acquisitions for further information.
Transitional Funding Securitization Financing Agreement
IP's financial statements include related-party transactions with the IP SPT, its wholly owned unconsolidated subsidiary, which was deconsolidated in accordance with the adoption of FIN No. 46R effective on December 31, 2003. In accordance with the Transitional Funding Securitization Financing Agreement, IP must designate a portion of the cash received from customer billings to fund payment of the TFNs. The amounts received are remitted to the IP SPT and are restricted for the sole purpose of paying down the TFNs. Due to the adoption of FIN No. 46R and resulting deconsolidation of IP SPT, these amounts are netted against the current portion of IP’s long-term debt payable to IP SPT on IP’s December 31, 2004 consolidated balance sheet. See Note 1 - Summary of Significant Accounting Policies for further information.
Money Pools
Utility
UE, CIPS, CILCO and IP have the ability to borrow from Ameren and from each other through a utility money pool agreement. Ameren Services administers the utility money pool and tracks internal and external funds separately. Ameren Services also participates in the utility money pool. Ameren and AERG may participate in the utility money pool only as lenders. Internal funds are surplus funds contributed to the utility money pool from participants. The primary source of external funds for the utility money pool is the UE commercial paper program. Through the utility money pool, the pool participants can access committed credit facilities at Ameren that totaled $935 million at December 31, 2004. These facilities are in addition to UE’s $154 million, CIPS’ $15 million, and CILCO’s $60 million in committed credit facilities, which are also available to the utility money pool participants. Based on outstanding UE commercial paper borrowings at December 31, 2004, $789 million was available for borrowing under Ameren credit facilities through the utility money pool agreement. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The availability of funds is also determined by funding requirement limits established by the SEC under the PUHCA. UE, CIPS, CILCO, IP and Ameren Services rely on the utility money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2004 was 1.38% (2003 - 1.14%).
On September 30, 2004, in conjunction with the completion on that date of Ameren’s acquisition of IP, a unilateral borrowing agreement was entered into between Ameren, IP, and Ameren Services that enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement, together with any short-term borrowings by IP, may not exceed $500 million, pursuant to authorization from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreement. At December 31, 2004, IP had loaned $140 million to the utility money pool.
Non-state-regulated subsidiaries
Genco and other non-state-regulated Ameren subsidiaries have the ability to borrow up to $935 million in total from Ameren through a non-state-regulated subsidiary money pool agreement. However, the total amount available to the pool participants at any time is reduced by the amount of borrowings from Ameren by its subsidiaries and is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or external sources are used to increase the available amounts. At December 31, 2004, $789 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The non-state-regulated subsidiary money pool was established to coordinate and provide for short-term cash and working capital requirements of Ameren’s non-state-regulated activities. It is administered by Ameren Services. Borrowers receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. These rates are based on the cost of funds used for money pool advances. Ameren and CILCORP are authorized to act only as lenders to the non-state-regulated subsidiary money pool. In October 2003, AERG received the required regulatory approval necessary to participate in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for year ended December 31, 2004 was 8.84% (2003 - 8.84%).
CILCORP has been granted authority by the SEC under the PUHCA to borrow up to $250 million directly from Ameren in a separate arrangement unrelated to the money pools. At December 31, 2004, CILCORP had notes payable under this agreement of $72 million (2003 - $46 million) at an average interest rate of 8.84% for the year ended December 31, 2004.
Intercompany Promissory Notes
As of December 31, 2004, Genco has affiliate notes payable of $249 million and $34 million to CIPS and Ameren, respectively, which, by their current terms, have final payments of principal and interest due on May 1, 2005. These notes bear interest at 7%. In November 2004, Genco made a $75 million principal prepayment under its note payable to CIPS. The note payable to CIPS was issued in conjunction with the transfer of its electric generating assets and related liabilities to Genco. Genco and CIPS plan to renew or modify the CIPS note to extend the principal maturity to May 1, 2010, which is expected to include continued amortization of the principal amount. Genco and Ameren are currently evaluating various alternatives with respect to the note payable to Ameren. In the event the maturities of these notes are not extended or restructured, Genco may need to access other financing sources to meet the maturity obligation to the extent it does not have cash available from its operating cash flows. Such sources of financing could include borrowings under the non-state-regulated subsidiary money pool, or infusion of equity capital or new direct borrowings from Ameren, all subject to applicable regulatory financing authorizations and provisions in Genco’s senior note indenture.
Operating Leases
Under an operating lease agreement, Genco is leasing certain CTs at a Joppa, Illinois site to its parent, Development Company for a minimum term of 15 years, expiring September 30, 2015. Under an electric power supply agreement with Marketing Company, Development Company supplies the capacity and energy from these leased units to Marketing Company, which in turn supplies the energy to Genco.
In September 1999, IP entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. IP sublet the turbines to its former affiliate, DMG, in October 1999. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, IP terminated its lease with the original lessor. DMG then executed a transfer agreement under which the original lessor sold the turbine assets to DMG for the full contract price of $81 million. Additionally, IP assigned its associated land lease on the Tilton site to DMG. For IP, the Tilton lease was a complete pass-through, with no revenue or expense to IP, as DMG made all of the payments on IP's behalf. The receivable from DMG was offset by a corresponding payable to the lessor. For additional information relating to the Tilton capital lease and related asset retirement obligation liability and remeasurement, see Note 1 - Summary of Significant Accounting Policies.
UE
The following tables present the impact of related party transactions on UE’s Consolidated Statement of Income for the years ended December 31, 2004, 2003 and 2002, and on the Consolidated Balance Sheet as of December 31, 2004 and 2003, based primarily on the agreements discussed above:
CIPS
The following tables present the impact of related party transactions on CIPS’ Statement of Income for the years ended December 31, 2004, 2003 and 2002, and on the Balance Sheet as of December 31, 2004, and 2003, based primarily on the agreements discussed above:
(a)
Amount includes current portion of $249 million as of December 31, 2004 (December 31, 2003 - $49 million).
(b)
Amount includes current portion of $11 million as of December 31, 2004 (December 31, 2003 - $12 million).
Genco
The following tables present the impact of related party transactions on Genco’s Statement of Income for the years ended December 31, 2004, 2003 and 2002, and on the Balance Sheet as of December 31, 2004 and 2003, based primarily on the agreements discussed above:
(a)
Amount includes current portion of $249 million as of December 31, 2004 (December 31, 2003 - $49 million).
(b)
Amount includes current portion of $34 million as of December 31, 2004 (December 31, 2003 - $4 million).
(c)
Amount includes current portion of $11 million as of December 31, 2004 (December 31, 2003 - $12 million).
CILCORP
The following tables present the impact of related party transactions on CILCORP’s Consolidated Statement of Income for the years ended December 31, 2004, 2003 and 2002, and on the Consolidated Balance Sheet as of December 31, 2004 and 2003, based primarily on the agreements discussed above:
(a)
amounts represent predecessor information. 2003 amounts include January 2003 predecessor information, which included $2 million in operating revenues and $3 million in purchased power associated with the executory tolling agreement with Medina Valley.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
CIPS was not a related party of CILCORP prior to January 31, 2003.
(a)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
CILCO
The following tables present the impact of related party transactions on CILCO’s Consolidated Statement of Income for the years ended December 31, 2004, 2003 and 2002, and on the Consolidated Balance Sheet as of December 31, 2004, and 2003, based primarily on the various agreements discussed above:
IP
The following tables present the impact of related party transactions on IP’s Consolidated Statement of Income for the years ended December 31, 2004, 2003 and 2002, and on the Consolidated Balance Sheet as of December 31, 2004 and 2003, based primarily on the various agreements discussed above:
(a)
Represents predecessor information.
(a)
Represents predecessor information.
(b)
Amount includes current portion of $74 million as of December 31, 2004 (December 31, 2003 - $74 million) and includes a purchase accounting fair value adjustment of $18 million as of December 31, 2004.
NOTE 15 - COMMITMENTS AND CONTINGENCIES
As a result of issues generated in the course of daily business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have an adverse material effect on our results of operations, financial position or liquidity.
Capital Expenditures
See Note 3 - Rate and Regulatory Matters for information regarding Ameren’s capital expenditure commitment with respect to IP, which was included in the ICC order approving Ameren’s acquisition of IP, as well as for information regarding Ameren’s and UE’s capital expenditure commitments, which were agreed upon in relation to UE’s 2002 Missouri electric rate case settlement and UE’s 2003 Missouri gas rate case settlement. Additionally, UE’s future estimated capital expenditures include the addition of new CTs with approximately 330 megawatts of capacity at its Venice, Illinois plant site by the end of 2005. Total costs expected to be incurred for these units are $125 million, of which $82 million was committed as of December 31, 2004.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2004:
(a)
Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended (Price-Anderson). This is subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expired in August 2002 and the temporary extension expired December 31, 2003. Until Price-Anderson is renewed, its provisions continue to apply to existing nuclear plants.
(b)
Limit of liability for each incident under Price-Anderson.
(c)
Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation.
(d)
Includes premature decommissioning costs.
(e)
Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.
Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years to reflect changes in the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.
If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is not available, we self-insure the risk. Although we have no reason to anticipate a serious nuclear incident, if one did occur, it could have a material but indeterminable adverse effect on our results of operations, financial position, or liquidity.
Leases
The following table presents our lease obligations at December 31, 2004:
(a)
Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
See Note 6 - Long-term Debt and Equity Financings for further discussion.
(c)
Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The amounts for these items are included in the Less than 1 Year, 1 - 3 Years and 3 - 5 Years columns. Amounts for After 5 Years are not included in the total amount due to the indefinite periods. Ameren’s estimated obligation for after five years is $1 million annually for both the real estate leases and the railroad licenses.
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. We also have a capital lease relating to UE’s Peno Creek CT facility. We also had a capital lease relating to nuclear fuel for UE’s Callaway nuclear plant, which was terminated early in February 2004. See Note 6 - Long-term Debt and Equity Financings for further information on this nuclear fuel lease. In September 1999, IP entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. IP sublet the turbines to a predecessor of DMG in October 1999. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, IP terminated the lease with the original lessor. DMG then executed a transfer agreement under which the original lessor sold the turbine assets to DMG for the full contract price of $81 million. Additionally, IP assigned its associated land lease on the Tilton site to DMG. The following table presents total rental expense, included in Other Operations and Maintenance expenses, as of December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
amounts represent predecessor information. January 2003 predecessor amount was less than $1 million.
(c)
and 2002 amounts represent predecessor information. January through September 2004 predecessor amount was $4 million.
Other Obligations
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. The following table presents the total estimated fuel, power purchase, and natural gas commitments at December 31, 2004:
(a)
Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
Commitments for coal, natural gas, nuclear fuel and the purchase of electricity are until 2010, 2012, 2009 and 2009, respectively.
(c)
Beginning in 2007, CIPS, CILCO and IP are expected to purchase all electric capacity and energy through a competitive procurement process approved by the ICC.
(d)
CILCORP consolidates CILCO and therefore includes CILCO in its amounts.
IP paid the $5 million in remaining decommissioning obligations associated with its former Clinton nuclear plant in December 2004. Other obligations also include decontamination and decommissioning charges associated with IP’s use of a DOE facility that enriched uranium for the Clinton nuclear plant. IP was assessed an amount to be paid over 15 years that would be used by the DOE for decontamination and decommissioning of its facility. The remaining obligation is $2 million and the final payment is due in 2006.
Environmental Matters
We are subject to various environmental regulations by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, and natural gas storage plant, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical and waste handling. Our activities often require complex and often lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operations, as required. The more significant matters are discussed below.
Clean Air Act
The EPA issued a rule in October 1998 that required 22 eastern states and the District of Columbia to reduce emissions of NOx in order to reduce ozone in the eastern United States. Among other things, the EPA’s rule establishes an ozone season, which runs from May through September, and a NOx emission budget for each state, including Illinois. The EPA rule required states to implement controls sufficient to meet their NOx budget by May 31, 2004. In the spring of 2004, the EPA issued similar rules for Missouri. The compliance date for the Missouri rules is May 1, 2007.
As a result of these requirements, affected Ameren Companies have installed a variety of NOx control technologies on power plant boilers over the past several years. Ameren’s and UE’s future estimated capital expenditures to comply with the final NOx regulations in Missouri between 2005 and 2008 are $15 million to $20 million.
In mid-December 2003, the EPA issued proposed regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions from coal-fired power plants. The new rules, if adopted, will require significant additional reductions in these emissions from UE, Genco and CILCO power plants in phases, beginning in 2010. The rules are currently under a public review and comment period; they may change before being issued as final. We do not expect regulations to be finalized until the first half of 2005. The following table presents preliminary estimated capital costs based on current available technology to comply with the Clean Air Interstate Rule and mercury rules, as proposed:
IP and DMG are the subject of a Notice of Violation (NOV) from the EPA and a complaint filed in 1999 by the United States in the U.S. District Court for the Southern District of Illinois (Court) alleging violations of the Clean Air Act and certain related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements, and maintenance activities at the three Baldwin Power Station generating units, currently owned by DMG and formerly owned by IP, constituted “major modifications” under the Prevention of Significant Deterioration (PSD) regulations, the New Source Performance Standard (NSPS) regulations and the applicable Illinois regulations. It is further alleged that the defendants failed to obtain required operating permits under the applicable Illinois regulations. When activities meeting the definition of “major modifications” occur, the Clean Air Act and related regulations generally subject those activities to PSD review and permit requirements; the generating facilities where the activities occur must meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.
Pursuant to the terms of the stock purchase agreement covering Ameren’s acquisition of IP from Dynegy, Dynegy agreed to fully indemnify Ameren and IP in the event of an adverse ruling and in any settlement arising from or out of this litigation. To secure payment of the indemnification obligations
of Dynegy, Ameren, pursuant to the terms of the stock purchase agreement, has deposited $100 million of the cash portion of the purchase price into an escrow account with the funds to be released to Dynegy on the sooner of (1) December 31, 2010; (2) the date on which the senior unsecured debt of Dynegy Holdings Inc., a Dynegy subsidiary, achieves an investment grade rating from S&P or Moody’s; or (3) the occurrence of specified events relating to contingent environmental liabilities associated with IP’s former generating facilities, including the Baldwin Power Station.
DMG has entered into a comprehensive settlement with the EPA, the U.S. and other intervening parties that resolves this litigation. The settlement agreement is set forth in a consent decree and resolves all claims in the litigation as well as similar claims that may have been brought with respect to other generation facilities owned by DMG and formerly owed by IP. If approved by the Court, this consent decree will relieve IP of any civil liability under the Clear Air Act and related federal and Illinois regulations with respect to IP's former ownership of the Baldwin Power Station and other generation assets now owned by DMG. The consent decree, upon its approval by the Court, is also expected to satisfy the conditions for the release to Dynegy of the $100 million of the IP purchase price that is held in an escrow account as discussed above.
Multipollutant Legislation
The United States Congress has been working on legislation to consolidate the numerous air pollution regulations facing the utility industry. Continued deliberation on this “Clear Skies” legislation is expected in 2005. Our cost to comply with such legislation, if it is enacted, is expected to be covered by the modifications to our facilities required by combined mercury and Clean Air Interstate rules described above.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming are the subjects of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Coal-fired power plants, however, are significant sources of carbon dioxide emissions, a principal greenhouse gas. The related Kyoto Protocol was signed by the United States but has since been rejected by the president, who instead has asked for an 18% decrease in carbon intensity on a voluntary basis. In response to the administration’s request, six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the Tennessee Valley Authority signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% - 5% decrease in carbon intensity from the utility sector between 2002 and 2012 on a voluntary basis. Currently, Ameren is considering various initiatives to comply with the MOU, including enhanced generation at our nuclear and hydro power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.
Ameren has already taken actions to address the global climate issue. These include implementing efficiency improvements at our power plants; participating in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage in the lower Mississippi valley to sequester carbon; using coal combustion by-products as a direct replacement for cement, thereby reducing carbon emissions at cement kilns; participating in "Missouri Schools Going Solar," a project that will install photovoltaic solar arrays on school grounds; and partnering with other utilities, the Electric Power Research Institute, and the Illinois Geological Survey in the DOE Illinois Basin Initiative, which will examine methods and the feasibility of storing carbon dioxide within deep, uneconomic coal seams, mature oil fields, and saline reservoirs.
Future initiatives related to greenhouse gas emissions and global warming and the ultimate effects of the Kyoto Protocol on us are unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal greenhouse gas program could have a material impact on our future results of operations, financial position, or liquidity.
Clean Water Act
In July 2004, the EPA issued rules under the Clean Water Act that require that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. These rules pertain to existing generating facilities that currently employ a cooling water intake structure whose flow exceeds 50 million gallons per day. The rules may require us to install additional intake screens or other protective measures, and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our facilities. Our compliance costs associated with conducting field studies and installing fish collection systems to determine the aquatic impact of our intake structures will be in the range of a few million dollars over the next few years. These studies will determine what, if any, additional technology must be applied at nine of our existing power plants. At this time, we are unable to estimate the costs of complying with these rules. Such costs will not be incurred prior to 2008.
Remediation
We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of fault, legality of original disposal, or ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and were transferred by CILCO to AERG in October 2003. As part of each transfer, the transferor (CIPS or CILCO) has contractually agreed to indemnify the transferee (Genco or AERG) for remediation costs associated with preexisting environmental contamination at the transferred sites.
UE, CIPS, CILCO, and IP own or are otherwise responsible for one, 13, four, and 25 former MGP sites, respectively, in Illinois. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites located in Illinois from their Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred; costs are subject to annual reconciliation review by the ICC. The total costs deferred, net of recoveries from insurers and through environmental adjustment rate riders, at December 31, 2004, were $1 million, $25 million, $4 million, and $64 million for UE, CIPS, CILCO, and IP, respectively.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. Unlike Illinois, UE does not have in effect in Missouri a rate rider mechanism which permits remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site and the environmental risk), and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. UE has recorded a $16 million liability as of December 31, 2004, to represent its estimated minimum obligation. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.
In June 2000, the EPA notified UE and numerous other companies that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 1 and Sauget Area 2. From approximately 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2; UE currently owns and operates electric transmission and distribution facilities in or near Sauget Areas 1 and 2.
In September 2000, the DOJ was granted leave by the U.S. District Court of the Southern District of Illinois to add numerous additional parties, including UE, to a pre-existing lawsuit between the government and others. The government seeks recovery of response costs under CERCLA (Superfund), incurred in connection with the remediation of Sauget Area 1. In October 2003, the government dismissed UE as a party to the lawsuit. UE considers the Sauget Area 1 litigation closed.
In September 2001, the EPA proposed in the Federal Register that Sauget Area 1 and Sauget Area 2 be listed on the National Priorities List. The inclusion of a site on this list allows the EPA to access Superfund trust monies to fund site remediations. With respect to Sauget Area 2 and under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties to evaluate the extent of potential contamination. We are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity.
In October 2002, UE was included in a Unilateral Administrative Order list of potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Monsanto Chemical Company’s (now known as Solutia) former chemical waste landfill and the resulting impact area in the Mississippi River. UE is being asked to participate in response activities that involve the installation of a barrier wall around a chemical waste site with three recovery wells to divert groundwater flow. The projected cost for this remedy method is $26 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requested its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection; it is now seeking to discharge its environmental liabilities. In March 2004, Pharmacia Corporation, the former parent company of Solutia, confirmed its intent to comply with the EPA’s Unilateral Administrative Order. As the status of future remediation at Sauget Area 2 or compliance with the Unilateral Administrative Order is uncertain, we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity. In December 2004, the U.S. Supreme Court in the case Cooper Industries, Inc. vs. Availl Services Inc. limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders.
In October 2002, CILCO submitted a corrective action plan to the Illinois Environmental Protection Agency (Illinois EPA) in accordance with permit conditions to address groundwater issues associated with the recycle pond and ash ponds at the Duck Creek power plant facility. In January 2003, the Illinois EPA accepted portions of the plan but rejected other portions. Additional discussions with the Illinois EPA will be necessary to develop an acceptable plan. CILCORP and CILCO both have a liability of $5 million at December 31, 2004, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort to treat and discharge the recycle system water in order to address these groundwater issues. Future CILCO capital expenditures at Duck Creek will include construction of a dry fly ash collection system, a landfill, and a new pond. CILCO estimates that future capital expenditures for the indicated activities could be approximately $15 million by 2008.
In addition, our operations or those of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our results of operations, financial position, or liquidity.
Waste Disposal
On July 30, 2002, the Illinois Attorney General’s Office advised us that it would be commencing an enforcement action concerning an inactive waste disposal site near Coffeen, Illinois. This is the location of a disposal facility that is permitted by the Illinois EPA to receive fly ash from Genco’s Coffeen power plant. The Illinois Attorney General also notified the disposal facility’s current and former owners about the proposed enforcement action. The Attorney General’s Office advised us that it may initiate an action under CERCLA (Superfund) to recover past costs incurred at the site ($0.3 million) and to obtain a declaratory judgment as to liability for future costs. Neither Genco, the current owner of the Coffeen power plant, nor CIPS, the prior owner of the Coffeen power plant, owned or operated the disposal facility. We do not expect that this matter will have a material adverse effect on Ameren’s, CIPS' or Genco’s results of operations, financial position, or liquidity.
Emission Credits
Both federal and state laws require significant reductions in SO2 and NOx emissions from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program created marketable commodities called allowances. Each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances that are based on past production and the statutory emission reduction goals. UE, Genco, CILCO and EEI have recorded these allowances at no cost. If additional allowances are needed for new generating facilities, they can be purchased from facilities having excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, the use of low-sulfur fuels, or the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program applies to all electric generating units in Illinois beginning in 2004 and in the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low NOx burners, over-fire air systems, combustion optimization, and selective catalytic reduction systems.
As of December 31 2004, UE, Genco, CILCO, and EEI held 1.6 million, 0.4 million, 0.2 million, and 0.3 million tons, respectively, of SO2 emission allowances with vintages from 2004 to 2012. Each company possesses additional allowances for use in periods beyond 2012. As of December 31, 2004, UE, Genco, CILCO and EEI Illinois facilities held 290, 22,400, 6,300 and 8,600 tons, respectively, of NOX emission allowances with vintages from 2004 to 2007. The Illinois EPA is still determining some NOx emission allowance allocations for this period and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Allocations of NOx allowances for Missouri facilities are pending the finalization of rules by Missouri regulators. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and level of operations will have a significant impact on the amount of allowances actually required for ongoing operations.
Asbestos-Related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits that have been filed by certain plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The number of total defendants named in each case is significant; as many as 235 parties are named in some cases and as few as five in others. However, the average number of parties is 61 in the cases that were pending as of December 31, 2004.
The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and most former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, the transferor (CIPS or CILCO) has contractually agreed to
indemnify the transferee (Genco or AERG) for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants.
From September 30, 2004, through December 31, 2004, 24 additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois; three lawsuits were dismissed and one was settled. The following table presents the status as of December 31, 2004, of the asbestos-related lawsuits that have been filed against the Ameren Companies:
(a)
Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants.
In January 2005, UE filed suit in the Circuit Court of Madison County, Illinois, alleging that four of its historic liability insurers have failed to pay more than $2 million in fees and costs relating to the defense and investigation of more than 120 asbestos lawsuits filed against UE. The defendant insurers are American Automobile Insurance Co., Pacific Insurance Co., Royal Insurance Co. of America and Royal Indemnity Co. These insurers insured UE from the late 1940s through the early 1970s for liability arising out of the work of independent contractors working at UE’s facilities. We are unable to predict the outcome of this lawsuit.
As of December 31, 2004, five asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.
The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity. See Note 3 - Rate and Regulatory Matters - IP and EEI Acquisition for information on the ICC’s approval of a tariff rider through which asbestos-related litigation claims will be allowed to be recovered from IP’s electric customers, subject to certain terms, commencing in 2007.
Other Matters
Enron Litigation Settlement
In May 2001, CILCO and Enron Power Marketing, Inc. (EPMI), a subsidiary of Enron Corporation (Enron), entered into a master agreement for electric purchases and sales, which covered energy transactions scheduled for deliveries during the period of 2001 to 2003. In November 2001, EPMI demanded that CILCO post $28 million in collateral based on mark-to-market exposure of open transactions. Also in November 2001, CILCO notified EPMI that events of default had occurred under the master agreement. Therefore, pursuant to the termination provisions of the master agreement it declared the master agreement terminated effective December 20, 2001. Enron and EPMI filed Chapter 11 bankruptcy petitions in December 2001 in the U.S. Bankruptcy Court for the Southern District of New York. In December 2002, EPMI filed a complaint against AES, Constellation New Energy, Inc., formerly known as AES New Energy Inc., and CILCO in the U.S. Bankruptcy Court seeking $31 million. As a result of court-ordered mediation of this matter, a settlement agreement was reached among the parties and approved by the Bankruptcy Court on September 30, 2004. This settlement agreement and court order settled the outstanding claims by requiring CILCO to pay $20.9 million to an Enron subsidiary. This settlement payment was made during October 2004. The payment also settled an unrelated dispute between CILCO and another Enron subsidiary, Enron North America Corporation (ENA), over ENA’s failure to deliver natural gas to CILCO pursuant to transactions entered into in May and October 2001. AES, in conjunction with its sale of CILCORP to Ameren in 2003, agreed to indemnify Ameren against the after-tax cost of all liabilities, which includes the settlement payment, legal fees, and expenses incurred by CILCO relating to the Enron claim. Ameren assigned its indemnification rights to CILCO. The indemnification payment from AES to CILCO also took place in October 2004. As a result of the income tax treatment afforded the settlement and related indemnification, this settlement had no earnings impact on Ameren, CILCORP or CILCO.
Retiree Medical Plan Litigation
In June 2003, 20 retirees and surviving spouses of retirees of various Ameren companies (the plaintiffs) filed a complaint in the U.S. District Court, Southern District of Illinois, against Ameren, UE, CIPS, Genco and Ameren Services, and against our Retiree Medical Plan and by an amended complaint, our Group Medical Plan (the defendants). The retirees were members of various local labor unions of the IBEW and the IUOE. The complaint, referred to as Barnett et al. vs. Ameren Corporation, et al., alleged, among other things, that the defendants recent actions relating to requiring retirees to pay a portion of their own health care premiums or
increasing the premiums paid by dependents or surviving spouses of retirees violate the ERISA and Labor Management Relations Act of 1947 and constitute a breach of the defendants’ fiduciary duties.
In July 2004, the District Court denied the plaintiffs’ motion to certify this lawsuit as a class action and in September 2004, the U.S. Seventh Circuit Court of Appeals denied the plaintiffs’ application to appeal the District Court’s decision. In January 2005, the District Court granted the defendants’ motion for summary judgment, which dismisses the plaintiffs’ complaint against the defendants with prejudice. In February 2005, the plaintiffs filed a notice of appeal of the District Court’s ruling with the U.S. Seventh Circuit Court of Appeals. We do not believe the final resolution of this matter will have a material adverse effect on our results of operations, financial position, or liquidity.
IP Litigation
Kemerer vs. IP was brought against IP in the Circuit Court of Mercer County, Illinois, by the wife of a man who died in 2000 when he backed his aluminum ladder into overhead power lines and was electrocuted. In the lawsuit, the plaintiff sought to recover on allegations of wrongful death (including lost wages and pain and suffering), negligent infliction of emotional distress (to the decedent’s wife), and punitive damages. The case was tried before a jury in January 2004, and the jury awarded the plaintiff $1.6 million in actual damages and $3 million in punitive damages. In January 2005, IP entered into a settlement agreement with the plaintiff resolving all outstanding matters; the terms of the settlement are confidential. This settlement will not have a material adverse effect upon IP’s results of operations, financial position, or liquidity.
Another case involved plaintiffs Lucash and Johnson, who were killed in an automobile accident in February 2001 when their car struck an IP guy wire and utility pole and caught fire. The plaintiffs’ families filed lawsuits against IP in the Circuit Court of Madison County, Illinois, which asserted wrongful death and survivorship causes of action alleging that IP failed to properly maintain its electrical equipment and did not have authority for the location of the pole. The lawsuit sought unspecified damages in excess of $50,000. In February 2005, IP entered into settlement agreements with the plaintiffs that resolved all outstanding matters; the terms of those settlements are confidential. Those settlements will not have a material adverse effect upon IP’s results of operation, financial position, or liquidity.
Leveraged Leases
Ameren owns interests in assets that have been financed as leveraged leases. One of these leveraged leases is a $10 million investment at December 31, 2004, in an aircraft leased to Delta Air Lines. Delta Air Lines reported significant operating losses and disclosed in its Form 10-Q filing for the three months ended September 30, 2004, that these results are unsustainable and underscore the urgent need to reduce its cost structure. Ameren could lose all or a portion of its investment in the Delta Air Lines lease in the event of a bankruptcy or default by Delta Air Lines or any voluntary restructuring of the lease. As of December 31, 2004, Delta Air Lines was current on its payments on this lease.
Regulation
Regulatory changes enacted and being considered at the federal and state levels continue to change the structure of the utility industry and utility regulation, as well as to encourage increased competition. At this time, we are unable to predict the impact of these changes on our future results of operations, financial position, or liquidity. See Note 3 - Rate and Regulatory Matters for further information.
NOTE 16 - CALLAWAY NUCLEAR PLANT
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2010. UE has sufficient storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.
Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. The Callaway nuclear plant site is assumed to be decommissioned based on immediate dismantlement method and removal from service. Ameren and UE have recorded an asset retirement obligation for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. See the discussion of SFAS No.143, “Accounting for Asset Retirement Obligations” in Note 1 - Summary of Significant Accounting Policies. Decommissioning costs are charged to cost of services used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2004, 2003 and 2002. Every three years, the MoPSC and ICC
require UE to file updated cost studies for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 2002; updated cost studies are expected to be filed in September 2005. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to the regulatory asset recorded in connection with the adoption of SFAS No. 143. Upon the completion of UE’s transfer of its Illinois electric and gas utility businesses to CIPS, which is subject to the receipt of regulatory approvals, the assets and liabilities related to the Illinois portion of the decommissioning trust fund will be transferred to Missouri. See Note 3 - Rate and Regulatory Matters for further information.
NOTE 17 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash, Temporary Investments and Short-term Borrowings
The carrying amounts approximate fair value because of the short-term maturity of these instruments.
Marketable Securities
The fair value is based on quoted market prices obtained from dealers or investment managers.
Nuclear Decommissioning Trust Fund
The fair-value estimate is based on quoted market prices for securities.
Preferred Stock of UE, CIPS, CILCO and IP
The fair-value estimate is based on the quoted market prices for the same or similar issues.
Long-term Debt
The fair-value estimate is based on the quoted market prices for same or similar issues or on the current rates offered to the Ameren Companies for debt of comparable maturities.
Derivative Financial Instruments
Market prices used to determine fair value are primarily based on published indices and closing exchange prices. In addition, valuations must also rely on management’s estimates, which take into account time value of money and volatility factors.
The following table presents the carrying amounts and estimated fair values of our financial instruments at December 31, 2004 and 2003:
(a)
Excludes amounts for IP for 2003; and includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.
(b)
CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c)
amounts represent predecessor information.
UE has investments in debt and equity securities that are held in trust funds for the purpose of funding the nuclear decommissioning of its Callaway nuclear plant. See Note 16 - Callaway Nuclear Plant for further information. We have classified these investments in debt and equity securities as available for sale and have recorded all such investments at their fair market value at December 31, 2004 and 2003. Investments by the nuclear decommissioning trust fund are allocated 60% to 70% to equity securities, with the balance invested in fixed-income securities. Fixed-income investments are limited to U.S. government or agency securities, municipal bonds, or investment-grade corporate securities. The proceeds from the sale of investments were $131 million in 2004 (2003 - $123 million; 2002 - $141 million). Using the specific identification method to determine cost, the gross realized gains on those sales were $1 million for 2004 (2003 - $1 million; 2002 - less than $1 million). Net realized and unrealized gains and losses are reflected in regulatory assets on Ameren’s and UE’s Consolidated Balance Sheets. This reporting is consistent with the method we use to account for the decommissioning costs recovered in rates. Gains or losses on assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in electric rates paid by UE’s customers.
The following table presents the costs and fair values of investments in debt and equity securities in the nuclear decommissioning trust fund at December 31, 2004, and 2003:
The following table presents the costs and fair values of investments in debt securities according to their contractual maturities at December 31, 2004:
NOTE 18 - SEGMENT INFORMATION
Ameren’s reportable segment Utility Operations comprises its electric generation and electric and gas transmission and distribution operations. It includes the operations of UE, CIPS, Genco, CILCORP and CILCO. Ameren’s reportable segment Other consists of the parent holding company, Ameren Corporation. The operations of IP are included in Ameren’s Utility Operations segment from September 30, 2004.
The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data include intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which, in each case, is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as headcount, number of customers, and total assets.
The following table presents information about the reported revenues, net income, and total assets of Ameren for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004.
(b)
Excludes amounts for CILCORP prior to the acquisition date of January 31, 2003.
(c)
Elimination of intercompany revenues.
The following table presents specified items included in Ameren’s segment profit (loss) for the years ended December 31, 2004, 2003 and 2002:
(a)
Excludes amounts for IP prior to the acquisition date of September 30, 2004.
(b)
Excludes amounts for CILCORP prior to the acquisition date of January 31, 2003.
(c)
Elimination of intercompany interest charges.
(d)
Does not include income tax expense related to the cumulative effect gain recognized upon adoption of SFAS No. 143.
All construction expenditures for the years ended December 31, 2004, 2003 and 2002, were in the Utility Operations segment.
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
(a)
Includes amounts for CILCORP since the acquisition date of January 31, 2003 and for IP since the acquisition date of September 30, 2004.
(a)
Includes predecessor information for periods prior to January 31, 2003.
(a)
Includes predecessor information for periods prior to September 30, 2004.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
Only Ameren as an “accelerated filer”, with respect to the reporting requirements of the Exchange Act was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2004 fiscal year. UE, CIPS, Genco, CILCORP, CILCO and IP are not accelerated filers and were not required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2004 fiscal year.
(a)
Evaluation of Disclosure Controls and Procedures
As of December 31, 2004, the principal executive officer and principal financial officer of each of the Ameren Companies have evaluated the effectiveness of the design and operation of such Registrant’s disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Based upon that evaluation, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such Registrant that is required in such Registrant’s reports filed or submitted to the SEC under the Exchange Act.
(b)
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a - 15(f) and 15d - 15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of Ameren’s 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 (COSO). Based on that evaluation under the framework in Internal Control - Integrated Framework issued by the COSO, management concluded that Ameren’s internal control over financial reporting was effective as of December 31, 2004. Management’s assessment of the effectiveness of Ameren’s internal control over financial reporting as of December 31, 2004, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report herein under Part II, Item 8.
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.
Management has excluded IP from its assessment of internal control over financial reporting as of December 31, 2004, because it was acquired by Ameren in a purchase business combination on September 30, 2004. PricewaterhouseCoopers LLP, Ameren’s independent registered public accounting firm, also excluded IP from its audit of internal control over financial reporting. IP is a wholly owned subsidiary of Ameren whose total assets and total revenues represented 18% and 7%, respectively, of Ameren’s consolidated financial statement amounts as of, and for the year ended, December 31, 2004.
(c)
Change in Internal Controls
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting, except for the modification of certain of the internal controls of IP to make them consistent with the internal controls of the other Ameren Companies, and the application of Ameren’s existing controls to include the operations of IP.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
The Ameren Companies have no information reportable under this item that is required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 2004, which has not previously been reported on an SEC Form 8-K.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS.
Information required by Items 401 and 405 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2005 annual meeting of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference. Information required by these SEC Regulation S-K items for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2005 annual meetings of shareholders filed pursuant to Regulation 14C and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K. Information required by SEC Regulation S-K Items 401 and 405 for IP is set forth at the conclusion of this Item 10.
Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Executive Officers of the Registrants” in Part I of this report.
As “controlled companies” of their ultimate parent, Ameren, as defined by the NYSE listing standards, UE, CIPS, Genco, CILCORP, CILCO and IP do not have separately designated standing audit committees of their own, but instead use Ameren’s Audit Committee to perform such committee functions for their boards of directors as permitted under exemptions provided in the NYSE listing standards. Harvey Saligman serves as chairman of Ameren’s Audit Committee and Richard A. Liddy, Richard A. Lumpkin, Paul L. Miller Jr., and Douglas R. Oberhelman serve as members. The board of directors of Ameren has determined that it has one Audit Committee financial expert serving on its Audit Committee. He is Douglas R. Oberhelman, and he has been determined by Ameren’s board of directors to be “independent” as that term is used in SEC Regulation 14A.
Also in accordance with exemptions provided under the NYSE listing standards, the boards of directors of UE, CIPS, Genco, CILCORP, CILCO and IP use the Nominating and Corporate Governance Committee of Ameren’s board to perform such committee functions. This committee is responsible for the nomination of directors and corporate governance practices. Ameren’s Nominating and Corporate Governance Committee will consider director nominations from shareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s Internet Web site (http://www.ameren.com). This policy became applicable to IP upon its acquisition by Ameren on September 30, 2004.
To provide for ethical conduct in its financial management and reporting, Ameren has adopted a Code of Ethics that applies to the principal executive officer, the principal financial officer, the principal accounting officer and controller, and the treasurer of the Ameren Companies. Ameren has also adopted a Code of Business Conduct that applies to the directors, officers and employees of the Ameren Companies, referred to as the Corporate Compliance Policy. The Ameren Companies make available free of charge through Ameren’s Internet site (http://www.ameren.com) the Code of Ethics and Corporate Compliance Policy. These documents are also available without charge in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. Any amendment to, or waiver of, the Code of Ethics and Corporate Compliance Policy will be posted on Ameren’s Internet site within five business dates following the date of the amendment or waiver.
Information Concerning IP’s Directors as Required by Item 401 of SEC Regulation S-K
The current members of IP’s board of directors are Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss, and David A. Whiteley, each of whom is an executive officer of IP or an affiliate. For each director’s age as of December 31, 2004, and business background for at least the last five years, refer to “Executive Officers of the Registrants” in Part I of this report. All of the directors were initially elected by directors upon Ameren’s acquisition of IP in September 2004, except for Cisel, who was elected by the directors to fill a vacancy on the board in October 2004. All of these directors have been nominated by Ameren’s Nominating and Corporate Governance Committee for re-election to IP’s Board at its annual meeting of shareholders to be held on April 26, 2005, to serve until the next annual meeting of shareholders and until their respective successors have been duly elected and qualified. Each nominee has consented to being nominated for director and has agreed to serve if elected. No arrangement or understanding exists between any nominee and IP or, to IP’s knowledge, any other person or persons pursuant to which any nominee was or is to be selected as a director or nominee. There are no family relationships among any directors, executive officers, or people nominated or chosen by IP to become directors or executive officers. See Item 13 under Part III of this report for certain reportable family relationships with nonexecutive officers. IP has been informed that Ameren intends to cast the votes of all of the outstanding shares of common stock of IP for the election of the nominees for directors named above. Accordingly, all the nominees are expected to be re-elected.
Section 16(a) Beneficial Ownership Reporting Compliance (for IP as Required by Item 405 of SEC Regulation S-K)
Section 16(a) of the Exchange Act, as amended, requires IP’s directors and executive officers and persons who own more than 10% of IP’s common stock to file with the SEC and the NYSE reports of their ownership in IP’s preferred stock, and, in some cases, of its ultimate parent’s common stock, and of changes in that ownership. SEC regulations also require IP to identify in this report any person subject to this requirement who failed to file any such report on a timely basis. Based solely on a review of the filed reports and written representations that no other reports are required, each of IP’s directors and executive officers complied with all such filing requirements during 2004.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information required by Item 402 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2005 annual meeting of shareholders filed pursuant to SEC Regulation 14A and is incor-porated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for their 2005 annual meetings of shareholders filed pursuant to Regulation 14C and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K. Information required by SEC Regulation S-K Item 402 for IP is as follows.
Compensation Tables for IP
The following tables set forth compensation information for the periods indicated for IP’s chairman and chief executive officer and the four other most highly compensated executive officers of IP who were serving at the end of 2004, named in the Summary Compensation Table below (the “IP Named Executive Officers”). No options were granted in fiscal year 2004 to any IP Named Executive officer. The Summary Compensation Table below also includes compensation information for Larry F. Altenbaumer and R. Blake Young, who each served as IP’s chief executive officer at different times during 2004 prior to Ameren’s acquisition of IP from Dynegy and its subsidiaries on September 30, 2004. The compensation of Altenbaumer and Young was set according to the policy of Dynegy prior to Ameren’s acquisition of IP.
Summary Compensation Table
(a) Includes compensation received as an officer of IP and its affiliates (except for Altenbaumer and Young, former chief executive officers of IP).
(b) Amounts for each fiscal year represent bonus compensation earned for that year payable in the subsequent year.
(c) Restricted stock awards relate to Ameren common stock. This column is based on the closing market price of Ameren common stock on the date the restricted stock was awarded
(for 2004, $46.34 per share on February 13, 2004; for 2003, $39.74 per share on February 14, 2003; and for 2002, $42.50 per share on February 8, 2002). The aggregate number
of restricted shares of Ameren common stock held at December 31, 2004 and the value of such holdings, based on the number of restricted shares for which restrictions have
not lapsed times the closing market price at December 31, 2004 ($50.14 per share), was 41,329 shares and $2,072,236 for Rainwater; 20,118 shares and $1,008,717 for Baxter;
13,245 shares and $664,104 for Voss; 13,343 shares and $669,018 for Cole; and 12,332 shares and $618,326 for Sullivan. Restricted shares have the potential to vest equally over a
seven-year period from date of grant (one-seventh on each anniversary date) based upon the achievement of certain Ameren performance levels and upon the achievement of
required stock ownership levels based on position and salary (ownership levels range from three to five times salary). The vesting period is reduced from seven years to three
years if Ameren’s ongoing earnings per share achieve a prescribed growth rate over the three-year period. Restricted stock that would otherwise vest remain restricted until
prescribed minimum stock ownership levels are satisfied by the IP Named Executive Officer. Upon the occurrence of a “change in control” as defined in Ameren's Long-Term
Incentive Plan of 1998, all restrictions and vesting requirements with respect to the restricted stock terminate. Dividends paid on restricted shares are reinvested in additional
shares of Ameren common stock, which vest concurrently with the restricted shares. The IP Named Executive Officers are entitled to voting privileges associated with the
restricted shares to the extent the restricted shares have not been forfeited.
(d) Options relate to Ameren common stock, except with respect to Altenbaumer, whose options were granted under a Dynegy plan in Dynegy common stock.
(e) For the IP Named Executive Officers, amounts include matching contributions to Ameren’s 401(k) plan, the dollar value of insurance premiums paid by Ameren with respect to term
life insurance, and above-market earnings on deferred compensation. See "Arrangements with IP Named Executive Officers - Deferred Compensation Plans" below. For fiscal year
2004, earnings on deferred compensation were not above market as defined by SEC rules. For fiscal year 2004, the amount includes (1) matching contributions to Ameren’s 401(k)
plan and (2) the dollar value of insurance premiums paid by Ameren with respect to term life insurance as follows:
(1) (2)
G.L. Rainwater $ 9,851 $ 11,122
W.L. Baxter 10,480 1,688
T.R. Voss 9,358 4,832
D.F. Cole 9,788 2,584
S.R. Sullivan 6,808 1,355
(f) Effective January 1, 2005, Voss was elected executive vice president and chief operating officer of Ameren in addition to his other named positions.
(g) Altenbaumer served as president of IP until his retirement effective April 1, 2004. All compensation presented for Altenbaumer in this table relates to compensation paid prior to
Ameren’s acquisition of IP based on Dynegy’s policy. His 2003 bonus amount and $350,000 of his 2004 “All Other Compensation” were paid pursuant to his severance agreement
and release entered into with Dynegy and IP in January 2004 in connection with his resignation from IP and Dynegy, which is described under “Employment Contracts and
Change-In-Control Arrangements” in Part III, Item 11. Executive Compensation, of IP’s 2003 Annual Report on Form 10-K. The balance of Altenbaumer’s 2004 “All Other
Compensation” consisted of $40,385 as payment for banked vacation earned in 2000 and $4,213 in matching contributions to IP’s 401(k) plan.
(h) Young is an executive officer of Dynegy who succeeded Altenbaumer as president of IP from April 1, 2004, until the completion of Ameren’s acquisition of IP on September 30,
2004. Young was not compensated by IP for serving as its president. He was compensated by Dynegy for services rendered in all capacities to Dynegy and its affiliates, including
IP. Information with respect to Young’s compensation for 2004 is expected to be reported in Dynegy’s definitive proxy statement for its 2005 annual meeting of shareholders,
and his compensation for 2003 and 2002 was reported in Dynegy’s definitive proxy statement for its 2004 annual meeting of shareholders, neither of which shall be deemed to be
incorporated by reference into this report and for which the Ameren Companies accept no responsibility.
Aggegated Option Exercises in 2004 and Year-End Values for the IP Named Executive Officers(a)
(a) No options were granted by Ameren in 2004.
(b) These columns represent the excess of the closing price of Ameren’s common stock of $50.14 per share, as of December 31, 2004, above the exercise price of the options. The
amounts under the Exercisable column report the “value” of options that are vested and therefore could be exercised. The Unexercisable column reports the “value” of options
that are not vested and therefore could not be exercised as of December 31, 2004. There is no guarantee that, if and when these options are exercised, they will have this value.
Upon the occurrence of a “change in control” as defined in Ameren's Long-Term Incentive Plan of 1998, all options become vested and immediately exercisable.
Ameren Retirement Plan (as it applies to the IP Named Executive Officers)
Most salaried employees of Ameren and its subsidiaries, including the IP Named Executive Officers, earn benefits under the Ameren Retirement Plan immediately upon employment. Benefits generally become vested after five years of service. On an annual basis a bookkeeping account in a participant’s name is credited with an amount equal to a percentage of the participant’s pensionable earnings for the year. Pensionable earnings include base pay, overtime and annual bonuses, which are equivalent to amounts shown as “Annual Compensation” in the Summary Compensation Table above. The applicable percentage is based on the participant’s age as of December 31 of that year. If the participant was an employee prior to July 1, 1998, an additional transition credit percentage is credited to the participant’s account through 2007 (or an earlier date if the participant had less than 10 years of service on December 31, 1998).
(a)
An additional regular credit of 3% is received for pensionable earnings above the Social Security wage base.
These accounts also receive interest credits based on the average yield for one-year U.S. Treasury Bills for the previous October, plus 1%. The minimum interest credit is 5%. In addition, certain annuity benefits earned by participants under prior plans as of December 31, 1997, were converted to additional credit balances under the Ameren Retirement Plan as of January 1, 1998. Effective January 1, 2001, an Enhancement Account was added that provides a $500 additional credit at the end of each year. When a participant terminates employment, the amount credited to the participant’s account is converted to an annuity or paid to the participant in a lump sum. The participant can also choose to defer distribution, in which case the account balance is credited with interest at the applicable rate until the future date of distribution. Benefits are not subject to any deduction for Social Security or other offset amounts.
In certain cases, pension benefits under the Retirement Plan are reduced to comply with maximum limitations imposed by the Internal Revenue Code. A Supplemental Retirement Plan is maintained by Ameren to provide for a supplemental benefit equal to the difference between the benefit that would have been paid if such Code limitations were not in effect and the reduced benefit payable as a result of such Code limitations. The plan is unfunded and is not a qualified plan under the Internal Revenue Code.
The following table shows the estimated annual retirement benefits, including supplemental benefits, payable to each IP Named Executive Officer listed if he were to retire at age 65. These estimates use total compensation through December 31, 2004, and project his 2005 base salary to retirement, excluding bonuses. The estimates show payments made in the form of a single life annuity.
Compensation of IP Directors
Directors who are employees or directors of Ameren or any of its subsidiaries receive no additional compensation for their services as IP directors. All directors of IP are executive officers of Ameren or its subsidiaries.
Arrangements with IP Named Executive Officers
Change of Control Severance Plan
Under the Ameren Corporation Change of Control Severance Plan, designated officers of Ameren and its subsidiaries, including the IP Named Executive Officers, are entitled to receive severance benefits if their employment is terminated under certain circumstances within three years after a “change of control.” A “change of control” occurs, in general, if (1) any individual, entity or group acquires 20% or more of the outstanding Common Stock of Ameren or of the combined voting power of the outstanding voting securities of Ameren; (2) individuals who, as of the effective date of the plan, constitute the board of directors of Ameren, or who have been approved by a majority of the board, cease for any reason to constitute a majority of the board; (3) Ameren enters into certain business combinations, unless certain requirements are met regarding continuing ownership of the outstanding common stock and voting securities of Ameren and the membership of its board of directors; or (4) approval by Ameren shareholders of a complete liquidation or dissolution of Ameren.
Severance benefits are based upon a severance period of two or three years, depending on the officer’s position. An officer entitled to severance will receive a cash lump sum equal to the following: (1) salary and unpaid vacation pay through the date of termination; (2) a pro rata bonus for the year of termination, and base salary and bonus for the severance period; (3) continued employee welfare benefits for the severance period; (4) a cash payment equal to the actuarial value of the additional benefits the officer would have received under Ameren’s qualified and supplemental retirement plans if employed for the severance period; (5) up to $30,000 for the cost of outplacement services; and (6) reimbursement for any excise tax imposed on such benefits as excess payments under the Internal Revenue Code.
Deferred Compensation Plans
Under the Ameren Deferred Compensation Plan and its Executive Incentive Compensation Program Elective Deferral Provisions, executive officers and certain key employees, including the IP Named Executive Officers, may choose to defer up to 30% of their salary and 25%, 50%, 75%, or 100% of their bonus. All of the IP Named Executive Officers have deferred amounts under one or both of the plans. The minimum amount of salary that can be deferred in any calendar year is $3,500 and the minimum amount of bonus that can be annually deferred is $2,000. Deferred amounts under both plans earn interest at 150% of the average Mergent's Seasoned AAA Corporate Bond Yield Index (“Mergent’s Index,” formerly called Moody’s Index) until the participant retires or attains 65 years of age. After the participant retires, attains 65 years of age, or dies, the deferred amounts under the plans earn the average Mergent's Index rate. For 2004, the average Mergent’s Index rate was 5.67%, 150% of that was 8.51%. A participant may choose to receive the deferred amounts at retirement in a lump sum payment or in installments over a set period, up to 15 years with respect to deferred salary and 10 years with respect to deferred bonus. If a participant revokes the deferral election under either plan, deferred amounts will be distributed in a lump sum with all interest credited to the deferral account forfeited. In the event a participant terminates employment with Ameren prior to attaining retirement age and after the occurrence of a change in control (as defined in such plans), the balance in such participant’s deferral account, including interest payable at 150% of the average Mergent’s Index is distributable in a lump sum to the participant within 30 days of the date the participant terminates employment.
Severance Agreement and Consulting Agreement with Former IP President
In January 2004, prior to Ameren’s acquisition of IP, Dynegy and IP entered into a severance agreement and release and a consulting agreement with Larry F. Altenbaumer, then president of IP. These agreements are described under “Employment Contracts and Change-In-Control Arrangements” in Part III, Item 11, Executive Compensation, of IP’s 2003 Annual Report on Form 10-K.
Compensation Committee Interlocks and Insider Participation
The members of the Human Resources Committee of the Ameren board of directors performed compensation-related committee functions for IP for the fourth quarter of the 2004 fiscal year after Ameren’s acquisition of IP. Its members during this period were Gordon R. Lohman, Thomas A. Hays, Richard A. Liddy, and John Peters MacCarthy. No member of this committee was at any time during this part of the 2004 fiscal year or at any other time an officer or employee of Ameren or IP, and no member had any relationship with Ameren or IP requiring disclosure under applicable SEC rules. No executive officer of Ameren or IP has served on the board of directors or compensation committee of any other entity that has or has had one or more executive officers who served as a member of Ameren’s or IP’s board of directors or Ameren’s Human Resources Committee during the 2004 fiscal year. Prior to Ameren’s acquisition of IP, the members of Dynegy’s compensation committee performed committee functions for IP. There are no matters relating to interlocks or insider participation during this period that IP is required to report.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Equity Compensation Plan Information
The following table presents information as of December 31, 2004, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plan.
(a) Consists of the Ameren Corporation Long-term Incentive Plan of 1998 which was approved by shareholders in April 1998, and expires on April 1, 2008.
(b) Excludes an aggregate of 738,848 restricted shares of Ameren common stock issued under the Ameren Corporation Long-term Incentive Plan of 1998 in 2001 through 2005.
UE, CIPS, Genco, CILCORP, CILCO and IP do not have separate equity compensation plans.
Security Ownership of Certain Beneficial Owners and Management
The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2005 annual meeting of shareholders filed pursuant to SEC Regulation 14A and is incor-porated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2005 annual meetings of shareholders filed pursuant to Regulation 14C and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K. Information required by SEC Regulation S-K Item 403 for IP is as follows.
Securities of IP
All 23 million outstanding shares of IP’s common stock and 662,924 shares, or approximately 73%, of IP’s preferred stock were acquired by Ameren from Dynegy and its subsidiaries on September 30, 2004, and are owned by Ameren as of the date of this report. This acquisition resulted in a change in control of IP. IP is now a subsidiary of Ameren.
None of IP’s outstanding shares of preferred stock were owned by directors, nominees for director, or executive officers of IP as of February 1, 2005. To our knowledge, other than Ameren, which as noted above owns 73% of IP’s outstanding preferred stock, there are no beneficial owners of 5% or more of IP’s outstanding shares of preferred stock as of February 1, 2005, but no independent inquiry has been made to determine whether any shareholder is the beneficial owner of shares not registered in the name of such shareholder or whether any shareholder is a member of a shareholder group.
Securities of Ameren (As Applicable to IP)
The following table sets forth certain information known to IP with respect to beneficial ownership of Ameren common stock as of February 1, 2005, for (1) each director and nominee for director of IP, (2) the IP Named Executive Officers, and (3) all executive officers, directors, and nominees for director as a group. The table below does not include information regarding Larry F. Altenbaumer and R. Blake Young, who each served as IP’s president at different times during 2004 prior to Ameren’s acquisition of IP.
* Less than 1%
(a) This column lists voting securities, including Ameren restricted stock held by executive officers over whom the officers have voting power but no investment power. It also
includes shares issuable within 60 days upon the exercise of Ameren stock options as follows: Baxter, 3,525; Cole, 46,650; Rainwater, 8,150; Sullivan, 3,525; Voss, 16,300;
and Whiteley, 7,880. Reported shares include those for which a director, nominee for director, or executive officer has voting or investment power because of joint or fiduciary
ownership of the shares or a relationship with the record owner, most commonly a spouse, even if such director, nominee for director, or executive officer does not claim beneficial
ownership.
(b) For each individual and group included in the table, percentage ownership is calculated by dividing the number of shares beneficially owned by such person or group as
described above by the sum of the 195,291,612 shares of Ameren common stock outstanding on February 1, 2005, and the number of shares of Ameren common stock that such
person or group had the right to acquire on or within 60 days of February 1, 2005, including, but not limited to, upon the exercise of options.
The address of all persons listed above is c/o Illinois Power Company, 500 South 27th Street, Decatur, Illinois 62521-2200.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information required by Item 404 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2005 annual meeting of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2005 annual meetings of shareholders filed pursuant to Regulation 14C and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K. Information required by SEC Regulation S-K Item 404 for IP is as follows.
During 2004, other than employment by IP or its affiliates, IP had no business relationships with directors and nominees for director required to be reported by SEC rules.
Certain of IP’s current directors and executive officers did have reportable family relationships in 2004. A sister of IP Chairman and Chief Executive Officer Gary L. Rainwater, Patricia A. Fuller, is employed by IP affiliate Ameren Services as a supervisor in its human resources function, for which she received an aggregate salary and bonus of $99,480 for 2004. Wendy C. Brumitt, a daughter of IP Senior Vice President Thomas R. Voss, is employed by IP affiliate UE as an engineer at its Callaway
nuclear plant, for which she received an aggregate salary and bonus of $71,047 for 2004. A brother of IP Vice President Dennis W. Weisenborn, Gary L. Weisenborn, is employed by UE as a superintendent at a power plant, for which he received an aggregate salary and bonus of $127,178 for 2004. Diana L. Weisenborn, the wife of Gary L. Weisenborn and sister-in-law of Dennis W. Weisenborn, is employed by Ameren Services as an executive secretary, for which she received aggregate salary and bonus of $60,422 for 2004.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies (including for IP only the period after its acquisition by Ameren) will be included in the definitive proxy statement of Ameren and the definitive information statements of UE, CIPS and CILCO for their 2005 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively, and is incorporated herein by reference. This information as it relates to IP prior to its acquisition by Ameren is expected to be reported in Dynegy’s definitive proxy statement for its 2005 annual meeting of shareholders, which shall not be deemed to be incorporated by reference into this report and for which the Ameren Companies accept no responsibility.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
The above schedule should be read in conjunction with the aforementioned financial statements. Schedules not included have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
(a)(3) Exhibits.
Reference is made to the Exhibit Index commencing on page 178.
(b) Exhibits are listed in the Exhibit Index commencing on page 178.
(a)
Uncollectible accounts charged off, less recoveries.
(b)
Amount includes $6 million related to IP balance at the date of acquisition on September 30, 2004.
(c)
Amount includes $2 million related to CILCO balance at the date of acquisition on January 31, 2003.
(d)
Ameren 2004 and 2003 amounts include financial activity of IP and CILCORP, subsequent to their respective acquisition dates. Amounts for IP and CILCORP include predecessor and successor financial information in the year of their respective acquisitions.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Gary L. Rainwater
Chairman, Chief Executive
March 9, 2005
Gary L. Rainwater
Officer, President and Director
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President and
March 9, 2005
Warner L. Baxter
Chief Financial Officer
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Susan S. Elliott
*
Director
March 9, 2005
Clifford L. Greenwalt
*
Director
March 9, 2005
Thomas A. Hays
*
Director
March 9, 2005
Richard A. Liddy
*
Director
March 9, 2005
Gordon R. Lohman
*
Director
March 9, 2005
Richard A. Lumpkin
*
Director
March 9, 2005
John Peters MacCarthy
*
Director
March 9, 2005
Paul L. Miller, Jr.
*
Director
March 9, 2005
Charles W. Mueller
*
Director
March 9, 2005
Douglas R. Oberhelman
*
Director
March 9, 2005
Harvey Saligman
*
Director
March 9, 2005
Patrick T. Stokes
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Gary L. Rainwater
Chairman, Chief Executive
March 9, 2005
Gary L. Rainwater
Officer, President and Director
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President, Chief
March 9, 2005
Warner L. Baxter
Financial Officer and Director
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Thomas R. Voss
*
Director
March 9, 2005
David A. Whiteley
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Gary L. Rainwater
Chairman, Chief Executive Officer
March 9, 2005
Gary L. Rainwater
and Director
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President, Chief
March 9, 2005
Warner L. Baxter
Financial Officer and Director
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Scott A. Cisel
*
Director
March 9, 2005
Daniel F. Cole
*
Director
March 9, 2005
Thomas R. Voss
*
Director
March 9, 2005
David A. Whiteley
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ R. Alan Kelley
President and Director
March 9, 2005
R. Alan Kelley
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President, Chief
March 9, 2005
Warner L. Baxter
Financial Officer and Director
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Daniel F. Cole
*
Director
March 9, 2005
Gary L. Rainwater
*
Director
March 9, 2005
Thomas R. Voss
*
Director
March 9, 2005
David A. Whiteley
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Gary L. Rainwater
Chairman, Chief Executive Officer,
March 9, 2005
Gary L. Rainwater
President and Director
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President, Chief
March 9, 2005
Warner L. Baxter
Financial Officer and Director
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Daniel F. Cole
*
Director
March 9, 2005
Richard A. Liddy
*
Director
March 9, 2005
Thomas R. Voss
*
Director
March 9, 2005
David A. Whiteley
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Gary L. Rainwater
Chairman, Chief Executive Officer
March 9, 2005
Gary L. Rainwater
and Director
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President, Chief
March 9, 2005
Warner L. Baxter
Financial Officer and Director
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Scott A. Cisel
*
Director
March 9, 2005
Daniel F. Cole
*
Director
March 9, 2005
Thomas R. Voss
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
/s/ Gary L. Rainwater
Chairman, Chief Executive Officer
March 9, 2005
Gary L. Rainwater
and Director
(Principal Executive Officer)
/s/ Warner L. Baxter
Executive Vice President, Chief
March 9, 2005
Warner L. Baxter
Financial Officer and Director
(Principal Financial Officer)
/s/ Martin J. Lyons
Vice President and Controller
March 9, 2005
Martin J. Lyons
(Principal Accounting Officer)
*
Director
March 9, 2005
Scott A. Cisel
*
Director
March 9, 2005
Daniel F. Cole
*
Director
March 9, 2005
Thomas R. Voss
*
Director
March 9, 2005
David A. Whiteley
*By /s/ Warner L. Baxter
March 9, 2005
Warner L. Baxter
Attorney-in-Fact
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of Ameren, UE, CIPS, Genco, CILCORP and CILCO (collectively the “Ameren Companies”) and IP and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.26
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of October 1, 2003
October 7, 2003, UE Form 8-K, Exhibit 4.4, File No. 1-2967
4.27
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of February 1, 2004
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.1*
4.28
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004B (1998B) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.2*
4.29
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004C (1998C) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.3*
4.30
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004D (2000B) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.4*
4.31
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004E (2000A) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.5*
4.32
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004F (2000C) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.6*
4.33
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004G (1991) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.7*
4.34
Ameren
UE
Supplemental Indenture dated as of February 1, 2004, to the UE Mortgage relative to Series 2004A (1992) Bonds
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.8*
4.35
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of May 1, 2004
May 18, 2004, Ameren Combined Companies Form 8-K, Exhibit 4.4*
4.36
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of September 1, 2004
September 23, 2004, Combined Ameren
Companies Form 8-K, Exhibit 4.4*
4.37
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of January 1, 2005
January 27, 2005, Ameren and UE Form 8-K, Exhibit 4.4, File No. 1-14756 and 1-2967
4.38
Ameren
UE
Loan Agreement dated as of December 1, 1991, between the Missouri Environmental Authority and UE, together with Indenture of Trust dated as of December 1, 1991, between the Missouri Environmental Authority and UMB Bank N.A. as successor trustee to Mercantile Bank of St. Louis, N. A.
UE 1992 Form 10-K, Exhibit 4.37, File No. 1-2967
4.39
Ameren
UE
First Amendment dated as of February 1, 2004, to Loan Agreement dated as of December 1, 1991, between the Missouri Environmental Authority and UE
March 31, 2004 Form 10-Q Combined Ameren Companies, Exhibit 4.9*
4.40
Ameren
UE
Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and UE, together with Indenture of Trust dated as of December 1, 1992 between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N. A.
UE 1992 Form 10-K, Exhibit 4.38, File No. 1-2967
4.41
Ameren
UE
First Amendment dated as of February 1, 2004, to Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and UE
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.10*
4.42
Ameren
UE
Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
September 30, 1998, UE Form 10-Q, Exhibit 4.28, File No. 1-2967
4.43
Ameren
UE
First Amendment dated as of February 1, 2004, to Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.11*
4.44
Ameren
UE
Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
September 30, 1998, UE Form 10-Q, Exhibit 4.29, File No. 1-2967
4.45
Ameren
UE
First Amendment dated as of February 1, 2004, to Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.12*
4.46
Ameren
UE
Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
September 30, 1998, UE Form 10-Q, Exhibit 4.30, File No. 1-2967
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.47
Ameren
UE
First Amendment dated as of February 1, 2004, to Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
March 31, 2004, Form 10-Q Combined Ameren Companies, Exhibit 4.13*
4.48
Ameren
UE
Indenture dated as of August 15, 2002, from UE to The Bank of New York, as Trustee, relating to senior secured debt securities (including the forms of senior secured debt securities as exhibits)
August 23, 2002, UE Form 8-K, Exhibit 4.1, File No. 1-2967
4.49
Ameren
UE
UE Company Order dated August 22, 2002, establishing the 5.25% Senior Secured Notes due 2012
August 22, 2002, UE Form 8-K, Exhibit 4.2, File No. 1-2967
4.50
Ameren
UE
UE Company Order dated March 10, 2003, establishing the 5.50% Senior Secured Notes due 2034
March 10, 2003, UE Form 8-K, Exhibit 4.2, File No. 1-2967
4.51
Ameren
UE
UE Company Order dated April 9, 2003, establishing the 4.75% Senior Secured Notes due 2015
April 9, 2003, UE Form 8-K, Exhibit 4.2, File No. 1-2967
4.52
Ameren
UE
UE Company Order dated July 28, 2003, establishing the 5.10% Senior Secured Notes due 2018
July 28, 2003, UE Form 8-K, Exhibit 4.2, File No. 1-2967
4.53
Ameren
UE
UE Company Order dated October 7, 2003, establishing the 4.65% Senior Secured Notes due 2013
October 7, 2003, UE Form 8-K, Exhibit 4.2, File No. 1-2967
4.54
Ameren
UE
UE Company Order dated May 13, 2004, establishing the 5.50% Senior Secured Notes due 2014
May 18, 2004, Combined Ameren Companies Form 8-K, Exhibit 4.2*
4.55
Ameren
UE
UE Company Order dated September 1, 2004, establishing the 5.10% Senior Secured Notes due 2019
September 23, 2004, Combined Ameren Companies Form 8-K, Exhibit 4.2*
4.56
Ameren
UE
UE Company Order dated January 27, 2005, establishing the 5.00 % Senior Secured Notes due 2020
January 27, 2005, Ameren and UE Form 8-K, Exhibit 4.2, File No. 1-14756 and 1-2967
4.57
Ameren
CIPS
Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS to Continental Illinois National Bank and Trust Company of Chicago and Edmond B. Stofft, as Trustees (U.S. Bank Trust National Association and Patrick J. Crowley are successor Trustees) (CIPS Mortgage)
Exhibit 2.01, File No. 2-60232
4.58
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated September 1, 1947
Amended Exhibit 7(b), File No. 2-7341
4.59
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated January 1, 1949
Second Amended Exhibit 7.03, File No. 2-7795
4.60
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated February 1, 1952
Second Amended Exhibit 4.07, File No. 2-9353
4.61
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated September 1, 1952
Amended Exhibit 4.05, File No. 2-9802
4.62
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1954
Amended Exhibit 4.02, File No. 2-10944
4.63
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated February 1, 1958
Amended Exhibit 2.02, File No. 2-13866
4.64
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated January 1, 1959
Amended Exhibit 2.02, File No. 2-14656
4.65
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated May 1, 1963
Amended Exhibit 2.02, File No. 2-21345
4.66
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated May 1, 1964
Amended Exhibit 2.02, File No. 2-22326
4.67
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1965
Amended Exhibit 2.02, File No. 2-23569
4.68
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated May 1, 1967
Amended Exhibit 2.02, File No. 2-26284
4.69
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated April 1, 1970
Amended Exhibit 2.02, File No. 2-36388
4.70
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated April 1, 1971
Amended Exhibit 2.02, File No. 2-39587
4.71
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated September 1, 1971
Amended Exhibit 2.02, File No. 2-41468
4.72
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated May 1, 1972
Amended Exhibit 2.02, File No. 2-43912
4.73
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated December 1, 1973
Exhibit 2.03, File No. 2-60232
4.74
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated March 1, 1974
Amended Exhibit 2.02, File No. 2-50146
4.75
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated April 1, 1975
Amended Exhibit 2.02, File No. 2-52886
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.76
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated October 1, 1976
Second Amended Exhibit 2.04, File No. 2-57141
4.77
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated November 1,1976
Amended Exhibit 2.04, File No. 2-57557
4.78
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated October 1, 1978
Amended Exhibit 2.06, File No. 2-62564
4.79
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated August 1, 1979
Exhibit 2.02(a), File No. 2-65914
4.80
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated February 1, 1980
Exhibit 2.02(a), File No. 2-66380
4.81
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated February 1, 1986
Amended Exhibit 4.02, File No. 33-3188
4.82
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated May 15, 1992
May 15, 1992, CIPS Form 8-K, Exhibit 4.02, File No. 1-3672
4.83
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated July 1, 1992
July 1, 1992, CIPS Form 8-K, Exhibit 4.02, File No. 1-3672
4.84
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated September 15, 1992
September 15, 1992, CIPS Form 8-K, Exhibit 4.02, File No. 1-3672
4.85
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated April 1, 1993
March 30, 1993, CIPS Form 8-K, Exhibit 4.02, File No. 1-3672
4.86
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1995
June 5, 1995, CIPS Form 8-K, Exhibit 4.03, File No. 1-3672
4.87
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated March 15, 1997
March 15, 1997, CIPS Form 8-K, Exhibit 4.03, File No. 1-3672
4.88
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1997
June 1, 1997, CIPS Form 8-K, Exhibit 4.03, File No. 1-3672
4.89
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated December 1, 1998
Exhibit 4.2, File No. 333-59438
4.90
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 2001
June 30, 2001, CIPS Form 10-Q, Exhibit 4.1, File No. 1-3672
4.91
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated October 1, 2004
4.92
Ameren
CIPS
Indenture dated as of December 1, 1998, from CIPS to The Bank of New York, as trustee, relating to CIPS’ Senior Notes, 5.375% due 2008 and 6.125% due
Exhibit 4.4, File No. 333-59438
4.93
Ameren
Genco
Indenture dated as of November 1, 2000, from Genco to The Bank of New York, as trustee, relating to the issuance of senior notes (Genco Indenture)
Exhibit 4.1, File No. 333-56594
4.94
Ameren
Genco
First Supplemental Indenture dated as of November 1, 2000, to Genco Indenture, relating to Genco’s 7.75% Senior Notes, Series A due 2005 and 8.35% Senior Notes, Series B due 2010
Exhibit 4.2, File No. 333-56594
4.95
Ameren
Genco
Form of Second Supplemental Indenture dated as of June 12, 2001, to Genco Indenture, relating to Genco’s 7.75% Senior Notes, Series C due 2005 and 8.35% Senior Note, Series D due 2010 (including as exhibit the form of Exchange Note)
Exhibit 4.3, File No. 333-56594
4.96
Ameren
Genco
Third Supplemental Indenture dated as of June 1, 2002, to Genco Indenture, relating to Genco’s 7.95% Senior Notes, Series E due 2032 (including as exhibit the form of Note)
June 30, 2002, Genco Form 10-Q, Exhibit 4.1, File No. 333-56594
4.97
Ameren
Genco
Fourth Supplemental Indenture dated as of January 15, 2003, to Genco Indenture, relating to Genco 7.95% Senior Notes, Series F due 2032 (including as exhibit the form of Exchange Note)
Genco 2002 Form 10-K, Exhibit 4.5, File No. 333-56594
4.98
Ameren
CILCORP
Indenture, dated as of October 18, 1999, between Midwest Energy, Inc. and The Bank of New York, as Trustee, and First Supplemental Indenture, dated as of October 18, 1999, between CILCORP and The Bank of New York
Exhibits 4.1 and 4.2, File No. 333-90373
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.99
Ameren
CILCO
Indenture of Mortgage and Deed of Trust between Illinois Power Company and Bankers Trust Company, as trustee, dated as of April 1, 1933 (CILCO Mortgage), Supplemental Indenture between the same parties dated as of June 30, 1933, Supplemental Indenture between CILCO and Bankers Trust Company, as trustee, dated as of July 1, 1933 and Supplemental Indenture between the same parties dated as of January 1, 1935, securing First Mortgage Bonds.
Designated in Registration No. 2-1937 as Exhibit B-1, in Registration No. 2-2093 as Exhibit B-1(a), in Form 8-K for April 1940.
4.100
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949
December 1949 CILCO 8-K, Exhibit A, File No. 1-2732
4.101
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated December 1, 1951
December 1951 CILCO 8-K, Exhibit A, File No. 1-2732
4.102
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957
July 1957 CILCO 8-K, Exhibit A, File No. 1-2732
4.103
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated July 1, 1958
July 1958 CILCO 8-K, Exhibit A, File No. 1-2732
4.104
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated March 1, 1960
March 1960 CILCO 8-K, Exhibit A, File No. 1-2732
4.105
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated September 20, 1961
September 1961 CILCO 8-K, Exhibit A, File No. 1-2732
4.106
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated March 1, 1963
March 1963 CILCO 8-K, Exhibit B, File No. 1-2732
4.107
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966
February 1966 CILCO 8-K, Exhibit A, File No. 1-2732
4.108
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated March 1, 1967
March 1967 CILCO 8-K, Exhibit A, File No. 1-2732
4.109
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated August 1, 1970
August 1970 CILCO 8-K, Exhibit A, File No. 1-2732
4.110
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated September 1, 1971
September 1971 CILCO 8-K, Exhibit A, File No. 1-2732
4.111
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated September 20, 1972
September 1972 CILCO 8-K, Exhibit A, File No. 1-2732
4.112
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated April 1, 1974
April 1974 CILCO 8-K, Exhibit A, File No. 1-2732
4.113
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated June 1, 1974
June 1974 CILCO 8-K, Exhibit 2(b), File No. 1-2732
4.114
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated March 1, 1975
March 1975 CILCO 8-K, Exhibit A, File No. 1-2732
4.115
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated May 1, 1976
May 1976 CILCO 8-K, Exhibit A, File No. 1-2732
4.116
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated May 16, 1978
June 30, 1978, CILCO 10-Q, Exhibit A, File No. 1-2732
4.117
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated September 1, 1982
CILCO 1982, Form 10-K, Exhibit 2, File No. 1-2732
4.118
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992
January 30, 1982, CILCO 8-K, Exhibit (4)(b), File No. 1-2732
4.119
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated January 1, 1993
January 29, 1993, CILCO 8-K, Exhibit (4), File No. 1-2732
4.120
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated November 1, 1994
December 2, 1994, CILCO 8-K, Exhibit 4, File No. 1-2732
4.121
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated October 1, 2004
4.122
Ameren
IP
General Mortgage Indenture and Deed of Trust dated as of November 1, 1992 (IP Mortgage)
IP 1992 Form 10-K, Exhibit 4(cc), File No. 1-3004
4.123
Ameren
IP
Supplemental Indenture No. 2 dated March 15, 1993, to IP Mortgage for the 6 ¾% bonds due 2005
IP 1992 Form 10-K Exhibit 4(ii), File No. 1-3004
4.124
Ameren
IP
Supplemental Indenture dated July 15, 1993, to IP Mortgage for the 7 ½% bonds due
June 30, 1993, IP Form 10-Q, Exhibit 4(kk), File No. 1-3004
4.125
Ameren
IP
Supplemental Indenture dated August 1, 1993, to IP Mortgage for the 6 ½ bonds due
June 30, 1993, IP Form 10-Q, Exhibit 4(mm), File No. 1-3004
4.126
Ameren
IP
Supplemental Indenture dated April 1, 1997, to IP Mortgage for the series P, Q and R bonds
March 31, 1997, IP Form 10-Q, Exhibit 4(b), File No. 1-3004
4.127
Ameren
IP
Supplemental Indenture dated as of March 1, 1998, to IP Mortgage for the series S bonds
January 22, 1999, IP Registration Statement Form S-3, Exhibit 4.41 Registration No. 333-71061
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.18
Ameren
UE
Trust Indenture dated as of December 1, 2002, between the city of Bowling Green, Missouri and Commerce Bank N.A. as trustee
UE 2002 Form 10-K, Exhibit 10.10, File No. 1-2967
10.19
Ameren
UE
Bond Purchase Agreement dated as of December 20, 2002, between the city of Bowling Green, Missouri and UE as purchaser
UE 2002 Form 10-K, Exhibit 10.11, File No. 1-2967
10.20
Ameren
UE
CIPS
Genco
Amended and Restated Appendix I ITC Agreement dated February 14, 2003, between the MISO and GridAmerica LLC (Grid America)
Ameren 2002 Form 10-K, Exhibit 10.17, File No. 1-14756
10.21
Ameren
UE
CIPS
Genco
Amended and Restated Limited Liability Company Agreement of GridAmerica dated February 14, 2003
Ameren 2002 Form 10-K, Exhibit 10-18, File No. 1-14756
10.22
Ameren
UE
CIPS
Genco
Amended and Restated Master Agreement by and among GridAmerica, GridAmerica Holdings, Inc., GridAmerica Companies and National Grid USA dated February 14, 2003
Ameren 2002 Form 10-K, Exhibit 10.19, File No. 1-14756
10.23
Ameren
UE
CIPS
Genco
Amended and Restated Operation Agreement by and among UE, CIPS, American Transmission Systems, Inc., Northern Indiana Public Service Company, and GridAmerica dated February 14, 2003
Ameren 2002 Form 10-K, Exhibit 10.20, File No. 1-14756
10.24
Ameren
CILCORP
CILCO
**CILCO Executive Deferral Plan as amended effective August 15,
CILCORP 1999 Form 10-K, Exhibit 10
10.25
Ameren
CILCORP
CILCO
**CILCO Executive Deferral Plan II as amended effective April 1,
CILCORP 1999 Form 10-K, Exhibit 10a
10.26
Ameren
CILCORP
CILCO
**CILCO Benefit Replacement Plan as amended effective August 15,
CILCORP 1999 Form 10-K, Exhibit 10b
10.27
Ameren
CILCORP
CILCO
**Retention Agreement between CILCO and Scott A. Cisel dated October 16,
CILCORP 2001 Form 10-K, Exhibit 10c
10.28
Ameren
CILCORP
CILCO
**CILCO Involuntary Severance Pay Plan effective July 16, 2001
CILCORP 2001 Form 10-K, Exhibit 10e
10.29
Ameren
CILCORP
CILCO
**CILCO Restructured Executive Deferral Plan (approved August 15, 1999)
CILCORP 1999 Form 10-K, Exhibit 10e
10.30
Ameren
CILCORP
CILCO
Contribution Agreement between CILCO and AERG
September 30, 2003, Combined Ameren Companies Form 10-Q, Exhibit 10.1*
10.31
Ameren
CILCORP
CILCO
Power Supply Agreement between AERG and CILCO
September 30, 2003, Combined Ameren Companies Form 10-Q, Exhibit 10.2*
10.32
Ameren Companies
Three-Year Revolving Credit Agreement, dated as of July 14, 2004
June 30, 2004, Combined Ameren Companies Form 10-Q, Exhibit 10.1*
10.33
Ameren Companies
Five-Year Revolving Credit Agreement, dated as of July 14, 2004
June 30, 2004, Combined Ameren Companies Form 10-Q, Exhibit 10.2*
10.34
Ameren
CILCORP
CILCO
Extension of Power Supply Agreement between AERG and CILCO
June 30, 2004, Combined Ameren Companies Form 10-Q, Exhibit 10.3*
10.35
Ameren Companies
IP
Amended and Restated Three-Year Revolving Credit Agreement, dated as of September 21, 2004
September 21, 2004, Combined Ameren Companies Form 8-K, Exhibit 10.1*
10.36
Ameren Companies
Separation and Release Agreement of Garry L. Randolph
September 24, 2004, Combined Ameren Companies Form 8-K, Exhibit 10.1*
10.37
Ameren Companies
IP
Third Amended Ameren Corporation System Utility Money Pool Agreement
October 1, 2004, Combined Ameren Companies and IP Form 8-K, Exhibit 10.2, File No. 1-3004*
10.38
Ameren
IP
Power Purchase Agreement by and between IP and Dynegy Power Marketing, dated as of September 30, 2004
October 1, 2004, Combined Ameren Companies and IP Form 8-K, Exhibit 10.1, File No. 1-3004*
*The file number references for the Combined Ameren Companies’ filings with the SEC are: Ameren, 1-14756; UE, 1-2967; CIPS, 1-3672; Genco, 333-56594; CILCORP, 2-95569, and CILCO, 1-2732.
**Management compensatory plan or arrangement.
Each Registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above.