ITEM 1. BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was formed in 1997 by the merger of UE and CIPSCO. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP.
Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and 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.
The following table presents our total employees at December 31, 2008:
(a) Total for Ameren includes Ameren registrant and nonregistrant subsidiaries.
As of January 1, 2009, the IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 58% of Ameren’s total employees. They represent 63% of the employees at UE, 82% at CIPS, 70% at Genco, 38% at CILCORP, 38% at CILCO, and 90% at IP. All collective bargaining agreements that expired in 2008 have been renegotiated and ratified. Most of the collective
bargaining agreements have four- or five-year terms, and expire in 2011 and 2012. The collective bargaining agreement between UE and IUOE Local 148, covering approximately 1,100 employees, expires on June 30, 2009.
For additional information about the development of our businesses, 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.
BUSINESS SEGMENTS
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 17 - Segment Information to our financial statements under Part II, Item 8, of this report for additional information on reporting segments.
RATES AND REGULATION
Rates
Rates that UE, CIPS, CILCO and IP are allowed to charge for their utility services are an important influence upon their and Ameren’s consolidated results of operations, financial position, and liquidity. The utility rates charged to UE, CIPS, CILCO and IP customers are determined by governmental entities. Decisions by these entities 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 governmental entities regarding rates, as well as the regulatory lag involved in filing and getting new rates approved, could have a material impact on the results of operations, financial position, or liquidity of UE, CIPS, CILCORP, CILCO, IP and Ameren.
The ICC regulates rates and other matters for CIPS, CILCO and IP. The MoPSC regulates rates and other matters for UE. The FERC regulates UE, CIPS, Genco, CILCO, and IP as to their ability to charge market-based rates for the sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.
About 35% of Ameren’s electric and 14% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2008. About 41% of Ameren’s electric and 86% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2008. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.
Missouri Regulated
Electric
About 81% of UE’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2008.
Following the expiration of a multiyear electric rate change moratorium, UE filed a request with the MoPSC in July 2006 for approval of an increase in its annual revenues for electric service. In May 2007, the MoPSC issued an order, that, as clarified, granted UE a $43 million increase in base rates for electric service, effective June 4, 2007.
On January 27, 2009, the MoPSC issued an order responding to UE’s April 2008 rate increase request, approving an increase for UE in annual revenues for electric service of approximately $162 million. The MoPSC also approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. Rate changes consistent with the MoPSC order, as well as the FAC and the vegetation management and infrastructure inspection cost tracking mechanism, were effective as of March 1, 2009. These cost recovery and tracking mechanisms help to mitigate the negative effect of regulatory lag.
The MoPSC initiated a proceeding in December 2008 to develop revised rules for an environmental cost recovery mechanism, which has been authorized under Missouri law. Rules for the environmental cost recovery mechanism are expected to be approved by the MoPSC during the second quarter of 2009 and will be effective once published in the Missouri Register. UE will not be able to implement an environmental cost recovery mechanism until authorized by the MoPSC as part of a rate case proceeding. UE has not requested approval of an environmental cost recovery mechanism.
Gas
All of UE’s gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2008.
If certain criteria are met, UE’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer. The ISRS also permits prudently incurred gas infrastructure replacement costs to be passed directly to the consumer.
As part of a 2007 stipulation and agreement approved by the MoPSC authorizing an increase in annual natural gas delivery revenues of $6 million effective April 1, 2007, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement did not prevent UE from filing to recover gas infrastructure replacement costs through an ISRS during this three-year rate moratorium. During 2008, the MoPSC approved two UE requests to establish an ISRS to recover annual revenues of $2 million in the aggregate, effective in March and November 2008.
For further information on Missouri rate matters, see Results of Operations and Outlook in Management’s Discussion 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 2 - Rate and Regulatory Matters, and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
Illinois Regulated
The following table presents the approximate percentage of electric and gas operating revenues subject to regulation by the ICC for each of the Illinois Regulated companies for the year ended December 31, 2008:
(a) AERG’s revenues are not subject to ICC regulation.
If certain criteria are met, CIPS’, CILCO’s and IP’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.
Environmental adjustment rate riders authorized by the ICC permit the recovery of prudently incurred MGP remediation and litigation costs from CIPS’, CILCO’s and IP’s Illinois electric and natural gas utility customers. In addition, IP has 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 is recoverable by IP from a trust fund established by IP. At December 31, 2008, the trust fund balance was $23 million, including accumulated interest. 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 recoverable through charges assessed to customers under the tariff rider.
A multiyear electric rate moratorium expired and new electric rates for CIPS, CILCO and IP went into effect on January 2, 2007. The new rates reflected delivery service tariffs approved by the ICC in November 2006 and a cost recovery mechanism for power purchased on behalf of the Ameren Illinois Utilities’ customers. In 2007, an agreement was reached among key stakeholders in Illinois to address the increase in electric rates and the future power procurement process. The Illinois electric settlement agreement provides $1 billion of funding from 2007 to 2010 for rate relief for certain electric customers in Illinois, including $488 million to customers of the Ameren Illinois Utilities. Ameren’s contributions over the four-year period under the Illinois electric settlement agreement aggregate $150 million.
In September 2008, responding to CIPS’, CILCO’s and IP’s November 2007 electric and natural gas rate adjustment requests, the ICC issued a consolidated order approving a net increase in annual revenues for electric service of $123 million in the aggregate (CIPS - $22 million increase, CILCO - $3 million decrease, and IP - $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million decrease, and IP - $40 million increase). Rate changes implementing these adjustments were effective on October 1, 2008. The ICC also approved an increase in the percentage of costs to be recovered through fixed monthly charges for natural gas customers, as well as an increase in the Supply Cost Adjustment factors for the customers who take their power supply from the Ameren Illinois Utilities. These two rate structure changes help to mitigate the negative effect of regulatory lag.
For further information on Illinois rate matters, including the pending court appeal of the September 2008 consolidated electric and gas rate order, see Results of Operations and Outlook in Management’s Discussion 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 2 - Rate and Regulatory Matters, and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
Non-rate-regulated Generation
Non-rate-regulated Generation revenues are determined by market conditions. We expect the Non-rate-regulated Generation fleet of assets to have 6,480 megawatts of capacity available for the 2009 peak demand. As discussed below, Genco, AERG, and EEI sell all of their power and capacity to Marketing Company via power supply agreements. Marketing Company attempts to optimize the value of those generation assets and mitigate risks utilizing a variety of hedging techniques including wholesale sales of capacity and energy, retail sales in the non-rate-regulated Illinois market, spot market sales primarily in MISO and PJM, and financial transactions. Marketing Company enters into long-term and short-term contracts. Marketing Company’s counterparties include cooperatives, municipalities, commercial and industrial customers, power marketers, MISO, and investor-owned utilities like the Ameren Illinois Utilities. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information, including Marketing Company sales to the Ameren Illinois Utilities.
General Regulatory Matters
UE, CIPS, CILCO and IP must receive FERC approval to issue short-term debt securities and to conduct certain acquisitions, mergers and consolidations involving electric utility holding companies having a value in excess of $10 million. In addition, these Ameren utilities must receive
authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities (with maturities of more than 12 months) and to conduct mergers, affiliate transactions, and various other activities. Genco, AERG and EEI are subject to FERC’s jurisdiction when they issue any securities.
Under PUHCA 2005, FERC and any state public utility regulatory agencies may access books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren, the ICC, or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.
Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on June 11, 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for UE’s Osage hydroelectric plant expires on March 30, 2047, and the license for UE’s Taum Sauk plant expires on June 30, 2010. In June 2008, UE filed an application with FERC to relicense its Taum Sauk plant for another 40 years. The Taum Sauk plant is currently out of service. It is being rebuilt due to a major breach of the upper reservoir in December 2005. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.
For additional information on regulatory matters, see Note 2 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, which include a discussion about the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.
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. These matters include identification, generation, storage, handling, transportation, disposal, recordkeeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards 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. We could be subject to criminal or civil penalties by regulatory agencies. We could be ordered to make payment to private parties by the courts. Except as indicated in this report, we believe that we
are in material compliance with existing statutes and regulations.
For additional discussion of environmental matters, including NOx, SO2, and mercury emission reduction requirements and the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
SUPPLY FOR ELECTRIC POWER
Ameren operates an integrated transmission system that comprises the transmission assets of UE, CIPS, CILCO, IP and AITC. AITC placed its first transmission assets, jointly owned with IP, in service during the fourth quarter of 2008. Any transmission assets of AITC would be eligible for rate recovery upon making the necessary filings with and acceptance by FERC. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes CIPS, CILCO, IP, AITC, Genco and AERG). During 2008, the peak demand in AMMO was 8,644 MW and in AMIL was 8,794 MW. The Ameren transmission system directly connects with 17 other balancing authority areas for the exchange of electric energy.
UE, CIPS, CILCO and IP are transmission-owning members of MISO, and they have transferred functional control of their systems to MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems is provided pursuant to the terms of the MISO OATT on file with FERC. EEI operates its own balancing authority area and its own transmission facilities in southern Illinois. The EEI transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.
The Ameren Companies and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in much of the southeastern United States, including all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP.
See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.
Missouri Regulated
UE’s electric supply is obtained primarily from its own generation. Factors that could cause UE to purchase power include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it.
In March 2006, UE completed the purchase of three CT facilities, totaling 1,490 megawatts of capacity, at a price of $292 million. These purchases were designed to help meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining when to add future baseload generating capacity. UE expects these CT facilities to satisfy demand growth until 2018 or 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In 2008, UE filed an integrated resource plan with the MoPSC. The plan included proposals to pursue energy efficiency programs, expand the role of renewable energy sources in UE’s overall generation mix, increase operational efficiency at existing power plants, and possibly retire some generating units that are older and less efficient.
In July 2008, UE filed a COLA with the NRC for a potential new nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. In addition, in 2008, UE filed an application with the DOE for loan guarantees associated with the potential construction of a new nuclear unit. UE has also signed contracts for certain long lead-time nuclear plant related equipment. The filing of the COLA and the DOE loan guarantee application and entering into these contracts does not mean a decision has been made to build another nuclear unit. These are only the first steps in the regulatory licensing and procurement process and are necessary actions to preserve the option to develop a new nuclear unit.
See also Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 2 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
Illinois Regulated
As of January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who did not purchase electric supply from third-party suppliers. The power procurement costs incurred by CIPS, CILCO and IP are passed directly to their customers through a cost recovery mechanism.
In September 2006, a reverse power procurement auction was held, as a result of which CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including Marketing Company. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve the electric load needs of fixed price residential and small commercial customers (with less than one MW of demand) at an all-inclusive fixed price. These contracts commenced on January 1, 2007, with one-third of the supply contracts expiring in each of May 2008, 2009 and 2010.
As part of the Illinois electric settlement agreement reached in 2007, the reverse power procurement auction process in Illinois was discontinued. It was replaced with a new power procurement process led by the IPA beginning in 2009. Under the new plan, the IPA will procure separate wholesale products (capacity, energy swaps and renewable energy credits) on behalf of the Ameren Illinois Utilities for the period of June 1, 2009, through May 30, 2014. The products will be procured through a RFP process, which is expected to begin during the first half of 2009. In 2008, utilities contracted for necessary power and energy requirements not already supplied through the September 2006 auction contracts, primarily through a RFP process that was subject to ICC review and approval.
A portion of the electric power supply required for the Ameren Illinois Utilities to satisfy their distribution customers’ requirements is purchased from Marketing Company on behalf of Genco, AERG and EEI. Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices at that time. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy.
See Note 2 - Rate and Regulatory Matters and Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information on power procurement in Illinois.
Non-rate-regulated Generation
In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and the associated energy commencing on January 1, 2007. These power supply agreements continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement by providing the other party with no less than six months advance written notice. In December 2005, EEI and Marketing Company entered into a power supply agreement whereby EEI sells all of its capacity and energy to Marketing Company commencing January 1, 2006. This agreement expires on December 31, 2015. All of Genco’s, AERG’s and EEI’s generating capacity competes for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information.
Factors that could cause Marketing Company to purchase power for the Non-rate-regulated Generation business segment include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, and extreme weather conditions.
FUEL FOR POWER GENERATION
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Less than 1% of total fuel supply.
The following table presents the cost of fuels for electric generation for the years ended December 31, 2008, 2007 and 2006:
(a) The fuel cost for coal represents the cost of coal, costs for transportation, which includes diesel fuel adders, and cost of emission allowances.
(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 in the calculation of fuel cost for the generating facilities.
(c) Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal.
(d) Excludes impact of the Genco coal supply contract settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See Note 1 - Summary of Significant Accounting Policies under Part II, Item 8, of this report.
Coal
UE, Genco, AERG and EEI have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2012. UE, Genco, AERG and EEI expect to enter into additional contracts to purchase coal. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. Ameren burned 40.3 million (UE - 22.0 million, Genco - 9.6 million, AERG - 3.7 million, EEI - 5.0 million) tons of coal in 2008. See Part II, Item 7A - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.
About 96% of Ameren’s coal (UE - 97%, Genco - 98%, AERG - 77%, EEI - 100%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. UE, Genco, AERG and EEI have a policy to maintain coal inventory consistent with their projected usage. Inventory may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries,
equipment breakdowns, and other factors. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather and derailments. As of December 31, 2008, coal inventories for UE, Genco, AERG and EEI were adequate and at targeted levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
Nuclear
Developing nuclear generating fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and then the fabrication of the enriched uranium hexafluoride gas into usable fuel assemblies. UE has entered into uranium, uranium conversion, enrichment, and fabrication contracts to procure the fuel supply for its Callaway nuclear plant.
Fuel assemblies for the 2010 spring refueling at UE’s Callaway nuclear plant will begin manufacture during the fourth quarter of 2009. Enriched uranium for such assemblies is in inventory. UE also has agreements or inventories to price-hedge approximately 95% of Callaway’s 2010 and 55% of Callaway’s 2011 refueling requirements. UE has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium and conversion requirements through at least 2014. UE has enriched uranium inventories and enrichment supply contracts sufficient to satisfy enrichment requirements through 2012. Fuel fabrication services are under contract through 2010. UE expects to enter into additional contracts to purchase nuclear fuel. As a member of Fuelco, UE can join with other member companies to increase its purchasing power and opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in November 2008. There is no refueling scheduled in 2009 or 2012. The nuclear fuel markets are competitive, and prices can be volatile; however, we do not anticipate any significant problems in meeting our future supply requirements.
Natural Gas Supply
To maintain gas deliveries to gas-fired generating units throughout the year, especially during the summer peak demand, Ameren’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. UE, Genco and EEI primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to generating units. In addition to physical transactions, Ameren uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
UE, Genco and EEI’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. UE, Genco and EEI do this in two ways. They optimize transportation and storage options and minimize cost and price risk through various supply and price hedging agreements that allow them to maintain access to multiple gas pools, supply basins, and storage. As of December 31, 2008, UE had price-hedged about 22% and Genco had price-hedged about 30% of their required gas supply for generation in 2009. As of December 31, 2008, EEI did not have any of its required gas supply for generation hedged for price risk.
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. These include 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 customers throughout the year and especially during peak demand. UE, CIPS, CILCO and IP primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, and the Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to physical transactions, financial instruments, including those entered into in the NYMEX futures market and in the OTC financial markets, are used to hedge the price paid for natural gas. See Part II, Item 7A - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about natural gas supply contracts. Prudently incurred natural gas purchase costs are passed on to customers of UE, CIPS, CILCO and IP in Illinois and Missouri under PGA clauses, subject to prudency 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 in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. Also see Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report, Note 1 - Summary of Significant Accounting Policies, Note 7 - 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.
INDUSTRY ISSUES
We are facing issues common to the electric and gas utility industry and the non-rate-regulated electric generation industry. These issues include:

political and regulatory resistance to higher rates, especially in a recessionary economic environment;

the potential for changes in laws, regulation, and policies at the state and federal level, including those resulting from election cycles;

access to and uncertainty in the capital and credit markets;

the potential for more intense competition in generation and supply;

pressure on customer growth and usage in light of current economic conditions;

the potential for reregulation in some states, including Illinois, which could cause electric distribution companies to build or acquire generation facilities and to purchase less power from electric generating companies like Genco, AERG and EEI;

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 RTOs;

increases or decreases in power prices due to the balance of supply and demand;

the availability of fuel and increases or decreases in fuel prices;

the availability of labor and material and rising costs;

regulatory lag;

negative free cash flows due to rising investments and the regulatory framework;

continually developing and complex environmental laws, regulations and issues, including air-quality standards, mercury regulations, and increasingly likely greenhouse gas limitations;

public concern about the siting of new facilities;

construction of power generation and transmission facilities;

proposals for programs to encourage or mandate energy efficiency and renewable sources of power;

public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste; and

consolidation of electric and gas companies.
We are monitoring these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 - Rate and Regulatory Matters, and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
(a) Includes impact of the Genco coal settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See Note 1 - Summary of Significant Account Policies to our financial statements under Part II, Item 8, of this report.
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren’s Internet Web site (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 possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through an Internet Web site maintained by the SEC (www.sec.gov).
The Ameren Companies also make available free of charge through Ameren’s Web site (www.ameren.com) the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, finance committee, nuclear oversight committee, and public policy committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies 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. The public may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
ITEM 1A.
ITEM 1A. RISK FACTORS
Investors should review carefully the following risk factors and the other information contained in this report. The risks that the Ameren Companies face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect the financial position, results of operations and liquidity of the Ameren Companies. See Forward-looking Statements and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.
The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions, which are largely outside of their control. Any such events that prevent UE, CIPS, CILCO or IP from recovering their respective costs or from earning appropriate returns on their investments could have a material adverse effect on future results of operations, financial position, or liquidity.
The rates that UE, CIPS, CILCO and IP are allowed to charge for their services are an important item influencing the results of operations, financial position, and liquidity of these companies and Ameren. The electric and gas utility industry is highly regulated. The regulation of the rates that utility customers are charged is determined, in large part, by governmental entities, including the MoPSC, the ICC, and FERC. Decisions by these entities 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 and are largely outside of our control. Decisions made by these entities could have a material adverse effect on results of operations, financial position, or liquidity.
UE, CIPS, CILCO and IP electric and gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Rates established in those proceedings are primarily based on historical costs, and they include an allowed return on investments by the regulator.
Our company, and the industry as a whole, is going through a period of rising costs and investments. The fact that rates at UE, CIPS, CILCO and IP are primarily based on historical costs means that these companies may not be able to earn the allowed return established by their regulators (often referred to as regulatory lag). As a result, UE, CIPS, CILCO and IP expect to file more frequent rate cases. A period of increasing rates to our customers, especially during weak economic times, could result in additional regulatory and legislative actions, as well as competitive and political pressures, that could have a material adverse effect on our results of operations, financial position, or liquidity.
We are subject to various environmental laws and regulations that require significant capital expenditures, can increase our operating costs, and may adversely influence or limit our results of operations, financial position or liquidity or expose us to environmental fines and liabilities.
We are subject to various environmental laws and regulations enforced 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, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise,
emissions, impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to 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 release prevention plans and emergency response procedures.
Compliance with environmental laws and regulations can require significant capital expenditures and operating costs. Actions required to ensure that our facilities are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, we could be required to close or alter the operation of our facilities, which could have an adverse effect on our results of operations, financial position, and liquidity.
Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures affecting operating assets. We are also subject to liability under environmental laws for remediating environmental contamination of property now or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such sites include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws and regulations against us and could allege injury from exposure to hazardous materials.
About 85% of Ameren’s (UE - 77%, Genco - 99%, CILCO (through AERG) - 99%, EEI - 100%) generating capacity is coal-fired. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. Federal and state laws require significant reductions in SO2, NOx and mercury emissions from coal-fired plants.
Ameren’s estimated capital costs through 2018, based on current technology, to comply with the federal Clean Air Interstate Rule and related state implementation plans and the MPS as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility Rule range from $4.5 billion to $5.5 billion (UE - $2.2 billion to $2.6 billion; Genco - $1.2 billion to $1.4 billion, CILCO (through AERG) - $480 million to $590 million, EEI - $665 million to $830 million). In addition, the Ameren Companies could incur additional capital costs with respect to a MACT standard for mercury emissions. The EPA is expected to move forward with a MACT standard for mercury emissions as the U.S. Supreme Court denied in February 2009 a petition to review a U.S. Court of Appeals decision that vacated the federal Clean Air Mercury Rule. Further, with respect to the EPA’s enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to the New Source Review requirements or New Source Performance Standards under the Clean Air Act, Ameren, UE, Genco, AERG and EEI could incur increased capital expenditures for
the installation of control technology, increased operations and maintenance expenses, as well as fines or penalties.
New environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties, or closure of power plants for UE, Genco, AERG and EEI. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs for Genco, AERG or EEI. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.
Future limits on greenhouse gas emissions would likely require UE, Genco, CILCO (through AERG) and EEI to incur significant increases in capital expenditures and operating costs, which, if excessive, could result in the closures of coal-fired generating plants or otherwise materially adversely affect our results of operations, financial position or liquidity.
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In October 2008, the U.S. House of Representatives, Energy and Commerce Committee, Subcommittee on Energy and Air Quality issued a “discussion draft” of climate legislation, which proposed establishing an economy-wide cap-and-trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to 6% below 2005 levels by 2020 and to 80% below 2005 levels by 2050. In addition, new leadership in the Energy and Commerce Committee is considering aggressive climate legislation. Finally, President Obama supports an economy-wide cap-and-trade greenhouse gas reduction program that would reduce emissions to 1990 levels by 2020 and 80% below 1990 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. Although we cannot predict the date of enactment or the requirements of any global warming legislation or regulations, we believe it is likely that some form of federal greenhouse gas legislation or regulations will become law during President Obama’s administration.
As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in the U.S. Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of our region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO2 that coal emits when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation could affect the cost of heating for our utility customers and many industrial
processes. Ameren believes that under some policy scenarios being considered by Congress, wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for both electricity and natural gas.
Future initiatives regarding greenhouse gas emissions and global warming may also be subject to the activities pursuant to the Midwest Greenhouse Gas Reduction Accord, an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota to develop a strategy to achieve energy security and reduce greenhouse gas emissions through a cap-and-trade mechanism. It is expected that the advisory group to the Midwest governors will provide recommendations on the design of a greenhouse gas reduction program by the third quarter of 2009. However, it is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.
With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO2 and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In July 2008, the EPA issued an advance notice of public rulemaking (ANPR) in response to the U.S. Supreme Court’s directive. The ANPR solicited public comments on the benefits and ramifications of regulating greenhouse gases under the Clean Air Act, and that rulemaking has not been completed. On February 12, 2009, the EPA announced its intent to reconsider the decision under the Bush Administration denying the waiver to the state of California for regulating CO2 emissions from automobiles. On February 17, 2009, the EPA also granted a petition for reconsideration filed by the Sierra Club to reexamine a December 2008 Bush Administration ruling that CO2 should not be regulated under the Clean Air Act when issuing construction permits for power plants. These EPA actions will factor into the rulemaking process on the ANPR and could ultimately lead to regulation of CO2 from power plants.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI and other similarly situated electric power generators to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s (through AERG) and EEI’s results of operations, financial position, or liquidity.
The construction of, and capital improvements to, UE’s, CIPS’, CILCO’s and IP’s electric and gas utility infrastructure as well as to Genco’s, CILCO’s (through AERG) and EEI’s non-rate-regulated generation facilities involve substantial risks. These risks include escalating costs, performance of the projects when completed and the ability to complete projects as scheduled, which could result in the closure of facilities and higher costs.
Over the next five years, the Ameren Companies will incur significant capital expenditures for compliance with environmental regulations and to make significant investments in their electric and gas utility infrastructure and their non-rate-regulated generation facilities. The Ameren Companies estimate that they will incur up to $10.4 billion (UE - up to $5.3 billion; CIPS - up to $565 million; Genco - up to $1.8 billion; CILCO (Illinois Regulated) - up to $415 million; CILCO (AERG) - up to $640 million; IP - up to $1.2 billion; EEI - up to $385 million; Other - up to $160 million) of capital expenditures during the period 2009 through 2013. These expenses include construction expenditures, capitalized interest or allowance for funds used during construction, and compliance with EPA and state regulations regarding SO2 and NOx emissions and mercury emissions from coal-fired power plants. Costs for these types of projects have escalated in recent years and are expected to either stay at current levels or further escalate.
Investments in Ameren’s regulated operations are expected to be recoverable from ratepayers, but are subject to prudency reviews. The recoverability of amounts expended in non-rate-regulated generation operations will depend on whether market prices for power adjust to reflect increased costs for generators.
The ability of the Ameren Companies to complete facilities under construction successfully, and to complete future projects within established estimates, is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on favorable terms, or other events beyond our control may occur that may materially affect the schedule, cost and performance of these projects. With respect to capital spent for pollution control equipment, there is a risk that electric generating plants will not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such construction efforts be unsuccessful, the Ameren Companies could be subject to additional costs and the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase additional electricity or natural gas for their customers until the projects are completed. All of these risks may have a material adverse effect on the Ameren Companies’ results of operations, financial position, or liquidity.
Our counterparties may not meet their obligations to us.
We are exposed to the risk that counterparties to various arrangements who owe us money, energy, coal, or other commodities or services will not be able to perform their obligations or, with respect to our credit facilities, will fail to honor their commitments. Should the counterparties to commodity arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. Should the lenders under our current credit facilities fail to perform, the level of borrowing capacity under those arrangements would decrease unless we were able to find replacement lenders to assume the nonperforming lender’s commitment. In such an event, we might incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.
Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries because of transactions involving energy, coal, other commodities, services, and because of hedging transactions. If one Ameren entity failed to perform under any of these arrangements, other Ameren entities might incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting Ameren entity being unable to meet its obligations to unrelated third-parties. Our hedging activities are generally undertaken with a view to the Ameren-wide exposures. Some Ameren Companies may therefore be more or less hedged than if they were to engage in such hedging alone.
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, or liquidity.
We offer 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 matters have a significant impact on our earnings and funding requirements. Ameren expects to fund its pension plans at a level equal at least to the pension expense. Based on Ameren’s assumptions at December 31, 2008, and reflecting this pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 61%, 6%, 10%, 9%, and 14%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs of 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.
Our electric generating, transmission and distribution facilities are subject to operational risks that could adversely affect our results of operations, liquidity, and financial position.
The Ameren Companies’ financial performance depends on the successful operation of electric generating, transmission, and distribution facilities. Operation of electric generating, transmission, and distribution facilities involves many risks, including:

increased prices for fuel and fuel transportation;

facility shutdowns due to operator error or a failure of equipment or processes;

longer-than-anticipated maintenance outages;

disruptions in the delivery of fuel and lack of adequate inventories;

increased purchased power costs;

lack of water for cooling plant operations;

labor disputes;

inability to comply with regulatory or permit requirements, including environmental contamination;

disruptions in the delivery of electricity, including impacts on us or our customers;

increased capital expenditure requirements, including those due to environmental regulation;

handling and storage of fossil-fuel combustion waste products, such as coal ash;

unusual or adverse weather conditions, including severe storms, drought and floods;

a workplace accident that might result in injury or loss of life, extensive property damage or environmental damage;

information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored;

catastrophic events such as fires, explosions, or other similar occurrences; and

other unanticipated operations and maintenance expenses and liabilities.
Even though agreements have been reached with the state of Missouri and the FERC, the breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could continue to have an adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park.
UE has settled with the FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. Other parties have also claimed damages as a result of the incident. UE has begun rebuilding the upper reservoir at its Taum Sauk plant. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010.
If UE must purchase power because of the unavailability of the Taum Sauk facility during the rebuild of the upper reservoir, UE has committed to not seek recovery of these additional costs from ratepayers. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2009 pretax earnings by $15 million to $20 million, excluding any unreimbursed costs related to the incident or the rebuild, which are currently not expected. UE expects to realize higher-cost sources of power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs.
At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties and the Department of the Army, Corp of Engineers. Until all litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risks.
All of Genco’s, AERG’s, and EEI’s generating facilities compete for the sale of energy and capacity in the competitive energy markets.
To the extent that electricity generated by these facilities is not under a fixed-price contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries generally depend on the prices that can be obtained 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:

current and future delivered market prices for natural gas, fuel oil, and coal and related transportation costs;

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 regulatory and market structures developed for evolving Midwest energy markets;

changes enacted by the Illinois legislature, the ICC, the IPA or other government agencies with respect to power procurement procedures;

the potential for reregulation of generation in some states;

future pricing for, and availability of, services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit our ability to sell energy in our markets;

the growth rate in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs;

climate conditions in the Midwest market; and

environmental laws and regulations.
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 about 12% of UE’s generation capacity and produced 19% of UE’s 2008 generation. 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;

the lack of a permanent waste storage site;

limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE or other U.S. nuclear operations;

uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate;

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);

limited availability of fuel supply; and

costly and extended outages for scheduled or unscheduled maintenance and refueling.
The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear generation facilities. In the event of noncompliance, 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, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on 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 relicensing of any domestic nuclear unit.
Our energy risk management strategies may not be effective in managing fuel and electricity procurement and pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings and cash flows.
We are exposed to changes in market prices for natural gas, fuel, electricity, emission allowances, and transmission congestion. Prices for natural gas, fuel, electricity, and emission allowances may fluctuate substantially over relatively short periods of time and expose us to commodity
price risk. We use short-term and 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 ensure that these strategies will be successful in managing our pricing risk or that they will not result in net liabilities because of future volatility in these markets.
Although we routinely enter into contracts to hedge our exposure to the risks of demand and changes in commodity prices, we do not 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. To the extent that 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, or liquidity.
Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.
Like other electric and gas utilities and other non-rate-regulated electric generators, 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 for repair, which could have a material adverse effect on our results of operations, financial position, or 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.
The global capital and credit markets experienced extreme volatility and disruption in 2008, and we expect those conditions to continue throughout 2009. Several factors have driven this situation, including deteriorating global economic conditions and the weakened condition of major financial institutions. The extreme disruption in the financial markets has limited companies’, including the Ameren Companies’, ability to access the debt and equity capital markets as well as credit markets to support their operations and refinance debt, which has led to higher financing costs compared to recent years. At December 31, 2008, the Ameren Companies had in place revolving bank credit facilities aggregating $2.15 billion, the size of which would be reduced if any of the participating banks fail to honor their commitments. In total, 18 banks participated in these credit facilities.
We use short-term and long-term debt as a significant source of liquidity and funding for capital requirements not
satisfied by our operating cash flow, including requirements related to future environmental compliance. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with near-term regulatory lag, we expect to need more short-term and long-term debt financing. The inability to raise debt or equity capital on favorable terms, or at all, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control, such as the extreme volatility and disruption in global debt or equity capital and credit markets in 2008 and 2009, may create uncertainty that could increase our cost of capital or impair, or eliminate, our ability to access the debt, equity or credit markets, including the ability to draw on our bank credit facilities. Certain of the Ameren Companies rely, in part, on Ameren for access to capital. Circumstances that limit Ameren’s access to capital, including those relating to its other subsidiaries, could impair its ability to provide those Ameren Companies with needed capital.
The Ameren Companies have certain debt that matures, and credit facilities that expire, in 2009 and 2010. Although we are actively developing plans and strategies to refinance or otherwise repay this debt and to renew or replace these credit facilities, we are unable to predict capital market conditions, our access to the capital markets or the degree of success we will have in renewing or replacing any of the credit facilities and whether the size and terms of any new credit facilities will be comparable to the existing credit facilities.
Ameren’s and some of the Ameren Companies’ holding company structures could limit their ability to pay common stock dividends, to service their respective debt obligations and to pay dividends on their outstanding preferred stock, as applicable.
Ameren is a holding company, and therefore, its primary assets are the common stock of its subsidiaries. As
a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s and some of the Ameren Companies’ ability to service their respective debt obligations and to pay dividends on their respective preferred stock are also dependent upon the earnings of operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under intercompany indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations and cash flows and other items affecting retained earnings. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of intercompany borrowing arrangements) to Ameren. Certain of the Ameren Companies’ financing agreements and articles of incorporation, in addition to certain statutory and regulatory requirements, may impose certain restrictions on the ability of such Ameren Companies to transfer funds to Ameren in the form of cash dividends, loans or advances.
Failure to retain and attract key officers and other skilled professional and technical employees could have an adverse effect on our operations.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. A significant portion of our workforce is nearing retirement, including many employees with specialized skills such as maintaining and servicing our electric and natural gas infrastructure and operating our generating units. Our inability to retain and recruit qualified employees could adversely affect our results of operations.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.
ITEM 2. PROPERTIES.
For information on our principal properties, see the generating facilities table below. See also 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 for any planned additions, replacements or transfers. See also Note 5 - Long-term Debt and Equity Financings, and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2009 peak summer electrical demand:
(a) “Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.
(b) This facility is not operational because of a breach of its upper reservoir in December 2005. It is expected to be out of service through early 2010. Its 2005 peak summer electrical demand net kilowatt capability was 440,000. For additional information on the Taum Sauk incident, see Note 15 - Commitments and Contingencies under Part II, Item 8 of this report.
(c) This facility will be out of service in 2009.
(d) There are economic development lease arrangements applicable to these CTs.
(e) Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).
(f) Ameren owns an 80% interest in EEI. See Part I, Item 1, Business and Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report. This table reflects the full capability of EEI’s facilities.
(g) There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts). The agreement expires on May 31, 2009.
(h) 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 Columbia exercises the purchase options.
(i) In December 2008, CILCO entered into talks with a third party to sell the Sterling Avenue facility. CILCO expects to sell this facility in 2009.
(j) This facility exclusively serves one industrial customer, which announced in early 2009 a suspension of operations of its plant.
The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2008:
Our other properties include office buildings, warehouses, garages, and repair shops.
With only a few exceptions, 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 and credit facility indebtedness and to certain permitted liens and judgment liens). The exceptions are as follows:

A portion of UE’s Osage plant reservoir, certain facilities at UE’s Sioux plant, most of UE’s Peno Creek and Audrain CT facilities, Genco’s Columbia CT facility, AERG’s Indian Trails generating facility, Medina Valley’s generating 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.

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 July 2006 and February 2007, AERG recorded open-ended mortgages and security agreements with respect to its E.D. Edwards and Duck Creek power plants. These plants serve as collateral to secure its obligations under multiyear, senior secured credit facilities entered into on July 14, 2006, and February 9,
2007, along with other Ameren subsidiaries. See Note 4 - Short-term Borrowings and Liquidity under Part II, Item 8, of this report for details of the credit facilities.
UE has conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city through 2022. Under the terms of this capital lease, UE is responsible for all operation and maintenance responsibilities for the facility. Ownership of the facility will transfer to UE at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
In March 2006, UE purchased a CT facility located in Audrain County, Missouri, from NRG Audrain Holding, LLC, and NRG Audrain Generating LLC, both affiliates of NRG Energy, Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County and assumed NRG’s obligations under the lease. The lease term will expire on December 1, 2023. Under the terms of this capital lease, UE has all operation and maintenance responsibilities for the facility, and ownership of the facility will be transferred to UE at the expiration of the lease. When ownership of the Audrain County CT facility is transferred to UE by the county, the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for information on mechanics’ liens filed against CILCO’s Duck Creek plant.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial 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, and Item 1A, Risk Factors, above. See also 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, and Note 2 - 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 2008 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, 2008, 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:
SUBSIDIARIES:
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, with 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 Adam C. Heflin, all of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management 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. On April 30, 2008, Ameren submitted to the NYSE a certificate of its chief executive officer certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.
Ameren common shareholders of record totaled 72,475 on January 30, 2009. The following table presents the price ranges, closing prices, and dividends paid per Ameren common share for each quarter during 2008 and 2007.
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; Resources 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 during 2008 and 2007:
On February 13, 2009, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 38.5 cents per share. The common share dividend is payable March 31, 2009, to stockholders of record on March 11, 2009.
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.
None of the Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the period October 1 to December 31, 2008.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31, 2008. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI Index), which comprises most investor-owned electric utilities in the United States. The comparison assumes that $100 was invested on December 31, 2003, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
Ameren management cautions that the stock price performance shown in the graph above should not be considered indicative of potential future stock price performance.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
(a) Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) For the year ended December 31, 2005, net income included income (loss) from cumulative effect of change in accounting principle of $(22) million ($(0.11) per share) for Ameren, $(16) million for Genco, $(2) million for CILCORP, $(2) million for CILCO, and $- million for IP.
(c) Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Operations
In 2008 and early 2009, we were able to successfully execute on key aspects of our long-term strategic plan. Our strategic plan calls for generation excellence and improvement of customer service and satisfaction. UE’s Callaway nuclear plant completed its first-ever breaker-to-breaker run and completed a plant record 28-day refueling and maintenance outage in the fall of 2008. In addition, the equivalent availability for UE’s coal-fired generating units was a solid 88% as compared to 89% in 2007. Ameren’s Non-rate-regulated Generation business segment set new generation records, producing approximately 31 million total megawatthours, as equivalent availability for its coal-fired units was 85% compared to 81% in 2007.
Amidst the economic challenges facing us and our nation, we have remained focused on our customers and have made significant investments in our energy infrastructure to improve overall reliability and customer satisfaction. In Missouri, through UE’s Power On reliability program, we buried more than 100 miles of electric line, trimmed trees along more than 6,500 miles of overhead line, tested nearly 100,000 wood utility poles, and inspected more than 8,000 miles of electric line. In Illinois, we targeted the worst-performing circuits and aggressively trimmed trees in Illinois Regulated’s 40,000 square-mile territory and continued to automate its transmission system to elevate its reliability. We believe that high-quality customer service is essential to earning solid returns in our rate-regulated businesses.
In Missouri, UE received approval of an electric rate increase in January 2009 with new rates effective March 1, 2009. The authorized increase in annual electric revenues is approximately $162 million based on a 10.76% return on equity. The MoPSC rate order authorized a FAC, as well as a vegetation management and infrastructure inspection cost tracking mechanism. The FAC and tracking mechanisms improve UE’s ability to continue to invest in its infrastructure so that UE will be able to meet its customers’ expectations for safe and reliable service.
In Illinois, the ICC authorized in September 2008 new electric and gas rates for the Ameren Illinois Utilities effective October 1, 2008. These new rates provide approximately $161 million in additional annual revenue based on allowed returns on equity of nearly 10.7%. The ICC also approved an increase in the fixed non-volumetric monthly charge for natural gas residential and commercial customers such that the Ameren Illinois Utilities now recover 80% of delivery service costs through this charge versus the prior 53%. The remainder is recovered through volume-based charges. This will make our gas utility earnings less sensitive to volumetric swings.
Earnings
Ameren reported net income of $605 million, or $2.88 per share, for 2008 compared with net income of $618 million, or $2.98 per share, in 2007. The decline in earnings in 2008 versus 2007 was principally due to higher fuel and related transportation prices, increased spending on utility distribution system reliability, higher plant operations and maintenance costs, milder weather, and net unrealized mark-to-market losses on nonqualifying hedges, among other things.
Those items more than offset the positive items. The positive items included improved generating plant output and higher realized margins from Non-rate-regulated Generation operations, the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms and the amount of these costs that UE will recover as a result of an accounting order issued by the MoPSC, the reduced impact in 2008 of the Illinois electric settlement agreement, the absence in 2008 of the March 2007 FERC order that resettled costs among MISO market participants retroactive to 2005 that was recorded in 2007 and subsequent recovery of a portion of these costs in 2008 through a MoPSC order, net increases in electric and natural gas rates, and a 2008 lump-sum settlement payment from a coal supplier for expected higher fuel costs in 2009 as a result of a premature mine closure and contract termination, among other things.
Liquidity
Cash flows from operations of $1.5 billion in 2008 at Ameren, along with other funds, were used to pay dividends to common shareholders of $534 million and to partially fund capital expenditures of $1.9 billion. The remaining capital expenditures were primarily funded with debt.
We have taken actions to build on our financial strength and enhance our financial flexibility in light of the current difficult economic and capital and credit market conditions. These actions included the February 2009 decision of Ameren’s board of directors to reduce its common dividend and accessing the capital markets to increase our available liquidity, as well as making significant reductions in our 2008 and projected 2009 spending plans while still meeting our reliability, environmental, and safety objectives.
Outlook
The global capital and credit markets experienced extreme volatility and disruption in 2008, and we expect those conditions to continue throughout 2009. We believe that the disruption in the capital and credit markets will further weaken global economic conditions. These weak economic conditions will likely result in volatility in the power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth, particularly with respect to industrial sales, higher bad debt expense and possible impairment of goodwill and long-lived assets, among other things.
Over the next few years, we continue to expect to make significant investments in our electric and natural gas infrastructure to improve reliability of our distribution systems and to comply with environmental requirements. From 2009 through 2011, we expect our rate-regulated rate base to grow approximately 9% per year. Earnings growth in our rate-regulated businesses is expected to come from updating existing customer rates to reflect these investments and the current levels of costs UE and the Ameren Illinois Utilities are experiencing. We consider the 2008 and 2009 Illinois and Missouri rate orders to be constructive. However, the returns that UE and the Ameren Illinois Utilities expect to earn in 2009 are below levels allowed by the respective state utility commissions in their last rate orders. The new rates were based on historic test year data and 2009 costs are expected to be higher than the levels recovered in rates. This is especially true of financing costs in Illinois, where sharply higher debt financing costs, which were incurred after our rate cases were filed, are not being recovered in rates. UE and the Ameren Illinois Utilities will file more frequent rate cases requesting moderate rate increases, as well as continue to seek appropriate cost recovery and tracker mechanisms to mitigate regulatory lag.
In addition, we will continue to optimize Ameren’s Non-rate-regulated Generation’s assets, focusing on improving the output of these plants and related energy marketing. We believe Non-rate-regulated Generation’s plants will be well positioned for earnings growth in the future should energy prices improve.
We will incur significant costs in future years to comply with existing federal EPA and state regulations regarding SO2, NOx, and mercury emissions from coal-fired power plants. Between 2009 and 2018, Ameren expects that certain Ameren Companies will be required to invest between $4.5 billion and $5.5 billion to retrofit their coal-fired power plants with pollution control equipment. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers.
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. President Obama supports an economy-wide cap-and-trade greenhouse gas reduction program that would reduce emissions to 1990 levels by 2020 and to 80% below 1990 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. Although we cannot predict the date of enactment or the requirements of any global warming legislation or regulations, it is likely that some form of federal greenhouse gas legislation or regulations will become law during President Obama’s administration. Potential impacts from proposed legislation could vary depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of allocating allowances, and provisions for cost containment measures.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI and other similarly-situated electric power generators to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s (through AERG) and EEI’s results of operations, financial position, or liquidity.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock and the payment of other expenses by the Ameren and CILCORP holding companies 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 transmission and distribution business in Missouri.

CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

Genco operates a non-rate-regulated electric generation business in Illinois and Missouri.

CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG) in Illinois.

IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are expressed in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps 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.
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: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. As part of the electric rate order issued by the MoPSC on January 27, 2009, UE was granted permission to put in place a FAC, which was effective March 1, 2009. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, for a discussion of the January 27, 2009, MoPSC order in UE’s electric rate proceeding. Fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Ameren’s net income was $605 million ($2.88 per share) for 2008, $618 million ($2.98 per share) for 2007, and $547 million ($2.66 per share) for 2006.
Ameren’s net income decreased $13 million and earnings per share decreased 10 cents in 2008 compared with 2007. Net income increased in the Non-rate-regulated Generation segment by $71 million in 2008 compared to 2007, while net income in the Missouri Regulated and Illinois Regulated segments decreased by $47 million and $15 million, respectively. Other net income decreased $22 million in 2008 compared with 2007, primarily because of net unrealized mark-to-market losses on nonqualifying hedges mainly related to fuel-related transactions and reduced interest and dividend income.
Compared with 2007 earnings, 2008 earnings were negatively affected by:

higher fuel and related transportation prices, excluding net mark-to-market losses on fuel-related transactions (27 cents per share);

increased distribution system reliability expenditures (16 cents per share);

higher plant operations and maintenance expenses (16 cents per share);

unfavorable weather conditions (estimated at 16 cents per share);

net unrealized mark-to-market losses on nonqualifying hedges (11 cents per share);

higher financing costs (10 cents per share);

asset impairment charges recorded during 2008 to adjust the carrying value of CILCO’s (through AERG) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008 (6 cents per share);

increased depreciation and amortization expense (6 cents per share);

the absence in 2008 of the reversal, recorded in 2007, of the Illinois Customer Elect electric rate increase phase-in plan accrual (5 cents per share);

higher labor and employee benefit costs (5 cents per share); and

higher bad debt expenses (3 cents per share).
Compared with 2007 earnings, 2008 earnings were favorably affected by:

higher realized electric margins in the Non-rate-regulated Generation segment;

the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms and the amount of these costs that UE will recover as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset in 2008 (16 cents per share);

the reduced impact in 2008 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (13 cents per share);

the absence in 2008 of a March 2007 FERC order that resettled costs among MISO market participants retroactive to 2005 that was recorded in 2007 and the subsequent recovery of a portion of these costs in 2008, through a MoPSC order (10 cents per share);

higher electric and natural gas delivery service rates in the Illinois Regulated segment pursuant to the ICC consolidated rate order for CIPS, CILCO, and IP issued in September 2008 (9 cents per share);

a settlement agreement with a coal mine owner reached in June 2008 that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation that it expects to incur in 2009 due to the premature closure of an Illinois mine at the end of 2007 (8 cents per share);

higher electric rates, lower depreciation expense and decreased income tax expense in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (8 cents per share); and

the reduced impact of the Callaway nuclear plant refueling and maintenance outage in 2008, as
compared with the prior-year refueling and maintenance outage (4 cents per share).
The cents per share information presented above is based on average shares outstanding in 2007.
Ameren’s net income increased $71 million and earnings per share increased 32 cents in 2007 compared with 2006.
Compared with 2006 earnings, 2007 earnings were favorably affected by:

higher margins in the Non-rate-regulated Generation segment due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts;

higher electric rates, lower depreciation expense, decreased income tax expense and $5 million in SO2 emission allowance sales in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (21 cents per share);

decreased costs associated with outages caused by severe storms (17 cents per share);

the absence of costs in 2007 that were incurred in 2006 related to the reservoir breach at UE’s Taum Sauk plant (15 cents per share); and

favorable weather conditions (estimated at 14 cents per share).
Compared with 2006 earnings, 2007 earnings were negatively affected by:

the combined effect of the elimination of the Ameren Illinois Utilities’ bundled electric tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts;

higher fuel and related transportation prices (31 cents per share);

electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities’ electric customers under the Illinois electric settlement agreement (21 cents per share);

higher labor and employee benefit costs (18 cents per share);

higher financing costs (17 cents per share);

lower emission allowance sales (16 cents per share);

increases in distribution system reliability expenditures (15 cents per share);

reduced gains on the sale of noncore properties, including leveraged leases (15 cents per share);

increased depreciation and amortization expense (13 cents per share);

a planned refueling and maintenance outage at UE’s Callaway nuclear plant net of an unplanned outage at Callaway in 2006 (9 cents per share); and

higher bad debt expenses (8 cents per share).
The cents per share information presented above is based on average shares outstanding in 2006.
Because it is 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, 2008, 2007 and 2006:
(a) Includes earnings from a non-rate-regulated 40% interest in EEI through February 29, 2008.
(b) Includes earnings from EEI, other non-rate-regulated operations, as well as corporate general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI prior to February 29, 2008 and an 80% interest in EEI since that date.
Below is a table of income statement components by segment for the years ended December 31, 2008, 2007 and 2006:
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2008, 2007, and 2006. We consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
2008 versus 2007
Ameren
Ameren’s electric margin increased by $153 million, or 4%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s electric margin:

Net mark-to-market gains on energy transactions of $81 million, primarily related to nonqualifying hedges of changes in market prices for electricity.

Improved Non-rate-regulated Generation plant availability due to the lack of an extended plant outage in 2008. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 76% and 85%, respectively, in 2008 compared with 74% and 81%, respectively, in 2007.

The effect of rate increases. The Ameren Illinois Utilities’ net electric rate increase, effective October 1, 2008, increased electric margin by $27 million. UE’s electric rate increase, effective June 4, 2007, increased electric margin by $16 million.

The reduced impact of the Illinois electric settlement agreement increased electric margin by $35 million.

The absence in 2008 of a March 2007 FERC order that resettled costs among MISO participants retroactive to 2005 that was recorded in 2007 and the subsequent recovery of a portion of these costs in 2008 through a MoPSC order. The net benefit to electric margin in 2008 of these items was $30 million.

A settlement agreement with a coal mine owner reached in June 2008, which reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation that it expects to incur in 2009 due to the premature closure of an Illinois mine at the end of 2007, increased electric margin by $27 million.

Other MISO net purchased power costs decreased by $23 million.

Lower Non-rate-regulated Generation emission allowance costs of $8 million.

Increased Non-rate-regulated Generation capacity sales of $6 million.
The following items had an unfavorable impact on Ameren’s electric margin for 2008 as compared with 2007:

Net mark-to-market losses on fuel-related transactions of $75 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, which decreased electric margin by an estimated $65 million. Compared to normal weather, cooling degree-days in 2008 were 5% lower.

Fuel prices increased by 6%.

Lower interchange margin due to reduced UE plant availability, partially offset by an 8% increase in realized prices and a 10% increase in hydroelectric generation. Nuclear plant availability was unfavorably affected by unplanned plant outages, which offset the shorter planned refueling and maintenance outage. UE’s coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 88%, respectively, in 2008 compared with 80% and 89%, respectively, in 2007.
Ameren’s gas margin increased by $36 million, or 9%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s gas margin:

Favorable weather conditions, as evidenced by a 13% increase in heating degree-days, which increased gas margin by an estimated $12 million. Compared to normal weather, heating degree-days in 2008 were 7% higher.

The effect of rate increases. The Ameren Illinois Utilities’ net gas rate increase, effective October 1, 2008, increased gas margin by $4 million. The UE gas rate increase, effective April 2007, increased gas margin by $3 million.

A September 2008 ICC rate order that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased gas margin by $9 million.

A 2% increase in weather normalized sales volumes and favorable customer sales mix, which increased gas margin by $5 million.

Increased transportation revenues of $4 million.
Missouri Regulated
UE
UE’s electric margin decreased $62 million, or 3%, in 2008 compared with 2007. The following items had an unfavorable impact on UE’s electric margin:

Unfavorable weather conditions, as evidenced by a 29% reduction in cooling degree-days, which decreased electric margin by an estimated $42 million.

Net mark-to-market losses on fuel-related transactions of $39 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Fuel prices increased by 5%.

Lower replacement power insurance recoveries of $12 million due to the lack of an extended plant outage and an increase in insurance recovery deductible limits.

Lower interchange margin due to reduced plant availability, partially offset by an 8% increase in realized prices and a 10% increase in hydroelectric generation. Nuclear plant availability was unfavorably affected by unplanned plant outages, which offset the shorter planned refueling and maintenance outage. UE’s coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 88%, respectively, in 2008, compared with 80% and 89%, respectively in 2007.
The following items that had a favorable impact on electric margin in 2008 as compared with 2007:

The absence in 2008 of a March 2007 FERC order that resettled costs among MISO participants retroactive to 2005 that was recorded in 2007 and the subsequent recovery of a portion of these costs in 2008 through a MoPSC order. The net benefit to UE’s electric margin in 2008 of these items was $23 million.

Other MISO net purchased power costs decreased by $15 million.

UE’s electric rate increase, effective June 4, 2007, which increased electric margin by $16 million.

Net mark-to-market gains of $8 million, primarily related to nonqualifying hedges of changes in market prices for electricity.
UE’s gas margin increased by $8 million, or 11%, in 2008 compared with 2007. The following items had a favorable impact on gas margin:

The UE gas rate increase, effective April 2007, which increased gas margin by $3 million.

Favorable customer sales mix, which increased gas margin by $3 million.

Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, which increased gas margin by an estimated $2 million.
Illinois Regulated
Illinois Regulated’s electric margin increased by $58 million, or 8%, and gas margin increased by $25 million, or 8%, in 2008 compared with 2007. The Ameren Illinois Utilities have a cost recovery mechanism for power purchased on behalf of their customers. These pass-through power costs do not impact margin; however, the electric revenues and offsetting purchased power costs fluctuate due primarily to customer switching and usage. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margin increased by $14 million, or 6%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Reduced MISO purchased power costs of $8 million due to the absence of the March 2007 FERC order.

Other MISO net purchased power costs decreased by $5 million.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $6 million.

The CIPS electric rate increase, effective October 1, 2008, increased electric margin by $5 million.
These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, which decreased electric margin by an estimated $6 million.
CIPS’ gas margin increased by $7 million, or 10%, in 2008 compared with 2007. The following items had a favorable impact on gas margin:

Favorable customer sales mix, which increased gas margin by $3 million.

Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, which increased gas margin by an estimated $2 million.

The CIPS gas rate increase, effective in October 2008, which increased gas margin by $1 million.

A September 2008 ICC rate order, that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased gas margin by $1 million.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2008 compared with 2007:
CILCO’s (Illinois Regulated) electric margin increased by $17 million, or 14%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Increased delivery and generation service margins of $14 million due to increased sales volume and favorable customer sales mix, and the reduced impact of monthly MISO settlements that occurred in the prior year.

Reduced MISO purchased power costs of $4 million due to the absence of the March 2007 FERC order.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $3 million.
These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 28% reduction in cooling degree-days, which decreased electric margin by an estimated $4 million.
See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) electric margin in 2008 compared with 2007.
CILCO’s (Illinois Regulated) gas margin was comparable in 2008 and 2007. Favorable weather conditions, as evidenced by an 11% increase in heating degree-days, and improved customer sales mix, increased gas margins by an estimated $4 million. These favorable variances were offset by CILCO’s gas rate decrease, effective in October 2008.
IP
IP’s electric margin increased by $27 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

The IP electric rate increase, effective October 1, 2008, which increased electric margin by $22 million.

Reduced MISO purchased power costs of $12 million due to the absence of the March 2007 FERC order.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $7 million.
These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 34% reduction in cooling degree-days, which decreased electric margin by an estimated $13 million.
IP’s gas margin increased by $18 million, or 12%, in 2008 compared with 2007. The following items had a favorable impact on gas margin:

The IP gas rate increase, effective in October 2008, which increased gas margin by $8 million.

A September 2008 ICC rate order, that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased gas margin by $7 million.

Favorable weather conditions, as evidenced by a 15% increase in heating degree-days, which increased gas margin by an estimated $6 million.
These favorable variances were partially offset by a 4% decrease in normalized sales volumes, which decreased gas margin $3 million.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $151 million, or 15%, in 2008 compared with 2007. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 76% and 85%, respectively, in 2008 compared with 74% and 81%, respectively, in 2007. See below for explanations of electric margin variances for the Non-rate regulated Generation segment.
Genco
Genco’s electric margin increased by $82 million, or 16%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

A settlement agreement with a coal mine owner reached in June 2008, which reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation that it expects to incur in 2009 due to the premature closure of an Illinois mine at the end of 2007, increased electric margin by $27 million.

Increased revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. Revenues from the Genco PSA, which increased by 7% due primarily to the repricing of wholesale and retail electric power supply agreements, and an increase in reimbursable expenses in accordance with the Genco PSA.

Reduced purchased power costs of $17 million due to the absence of MISO resettlement costs experienced in early 2007.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $13 million.

Gains on the sales of excess oil and off-system natural gas, which increased electric margin by $12 million.

Higher replacement power insurance recoveries of $9 million due to extended plant outages in 2008.

Lower emission allowance costs of $5 million due primarily to an increase in low-sulfur coal consumption in 2008.
The following items had an unfavorable impact on electric margin in 2008 compared with 2007:

Fuel prices increased by 2%.

Net mark-to-market losses on fuel-related transactions of $18 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Reduced MISO-related revenues of $12 million due to the absence of the March 2007 FERC order.

Decreased power plant utilization due to system congestion. Genco’s baseload coal-fired generating plants’ equivalent availability factors were comparable year over year. However, the average capacity factor was approximately 73% in 2008 compared with 75% in 2007.

Decreased revenues of $9 million due to the termination of an operating lease in February 2008 under which Genco leased certain CTs at a Joppa, Illinois site to its former parent, Development Company. See Note 14 - Related Parties to our financial statements under Part II, Item 8, of this report, for additional information.
CILCO (AERG)
AERG’s electric margin increased by $12 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Increased revenue allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company. Revenues from the AERG PSA increased 24% due primarily to stronger generation performance as a result of the lack of an extended plant outage in 2008, the repricing of wholesale and retail electric power supply agreements, and an increase in reimbursable expenses in accordance with the AERG PSA. AERG’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 70% and 77%, respectively, in 2008 compared with 55% and 61%, respectively, in 2007.

The reduced impact of the Illinois electric settlement agreement increased electric margin by $6 million.
The following items had an unfavorable impact on electric margin in 2008 compared with 2007:

Fuel prices increased by 30%, primarily due to a greater percentage of higher-cost Illinois coal burned in 2008 and an increased amount of oil consumed during plant start-ups.

Reduced MISO-related revenues of $4 million due to the absence of the March 2007 FERC order.

Net mark-to-market losses on fuel-related transactions of $3 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.
EEI
EEI’s electric margin increased by $10 million, or 4%, in 2008 compared with 2007, primarily because of an 8% increase in the average sales price for wholesale power.
The following items had an unfavorable impact on electric margin:

Fuel prices increased by 9%.

Net mark-to-market losses on fuel-related transactions of $8 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.
Marketing Company
Market price fluctuations during 2008 resulted in nonaffiliated mark-to-market gains on energy transactions of $73 million, primarily related to nonqualifying hedges of changes in market prices for electricity.
2007 versus 2006
Ameren
Ameren’s electric margin increased by $297 million, or 9%, in 2007 compared with 2006. The following items had a favorable impact on Ameren’s electric margin:

More power sold by Non-rate-regulated Generation at market-based prices in 2007. These 2007 sales compared favorably with 2006 sales at below-market prices, pursuant to cost-based power supply agreements that expired on December 31, 2006.

Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, which increased electric margin by an estimated $35 million. Compared to normal weather, cooling degree-days in 2007 were 37% higher.

The UE electric rate increase, effective June 4, 2007, which increased electric margin by $29 million.

An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, which was originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased power costs of $12 million associated with an agreement with Entergy Arkansas, Inc. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc.

A 67% increase in hydroelectric generation because of improved water levels, which allowed additional generation to be used for interchange sales and reduced use of higher-priced energy sources, thereby increasing Ameren’s electric margin by $27 million.

Increased Non-rate-regulated Generation capacity sales of $11 million.

Reduced severe storm-related outages in 2007 compared with 2006, which negatively affected electric sales and resulted in a net reduction in overall electric margin of $9 million in 2006.

Insurance recoveries of $8 million related to power purchased to replace Taum Sauk generation. See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for additional information.
The following items had an unfavorable impact on Ameren’s electric margin in 2007 as compared with 2006:

The combined effect on the Ameren Illinois Utilities of the elimination of bundled tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts.

A 14% increase in fuel prices.

Rate relief and customer assistance programs under the Illinois electric settlement agreement, which reduced electric margin by $73 million.

The loss of wholesale margins at Genco from power acquired through the JDA, which terminated in 2006.

Decreased emission allowance sales of $53 million, offset by lower emission allowance costs of $15 million.

Net purchased power costs that were $18 million higher in 2007 because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005.

Reduced plant availability. Ameren’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 86%, respectively, in 2007 compared with 80% and 88%, respectively, in 2006.
Ameren’s gas margin increased by $15 million, or 4%, in 2007. The following items had a favorable impact on Ameren’s gas margin:

Favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by an estimated $10 million. Compared to normal weather, heating degree-days in 2007 were 10% lower.

The UE gas rate increase that went into effect in April 2007, which increased gas margin by $4 million.
Missouri Regulated
UE
UE’s electric margin increased $76 million, or 4%, in 2007 compared with 2006. The following items had a favorable impact on UE’s electric margin:

An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. The termination of the JDA allowed UE to sell its excess power, which was originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased
power costs of $12 million associated with an agreement with Entergy Arkansas, Inc.

The electric rate increase that went into effect June 4, 2007, which increased electric margin by $29 million.

A 67% increase in hydroelectric generation because of improved water levels. This allowed additional generation to be used for interchange sales and reduced UE’s use of higher priced energy sources, thereby increasing UE’s electric margin by $27 million.

Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, which increased electric margin by an estimated $22 million.

Replacement power insurance recoveries of $20 million, including $8 million associated with Taum Sauk. See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for additional information.

Increased transmission service revenues of $18 million due to the ancillary service agreement with CIPS, CILCO, and IP. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report, for additional information.

Decreased fuel costs due to the lack of $4 million in fees levied by FERC in 2006 upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years.

Reduced severe storm-related outages in 2007 compared with 2006, which negatively affected electric sales that year and resulted in a net reduction in overall electric margin of $7 million in 2006.
The following items had an unfavorable impact on electric margin in 2007 as compared with 2006:

Fuel prices increased by 21%.

A $29 million reduction in emission allowance revenues.

MISO purchased power costs that were $11 million higher due to the March 2007 FERC order.

Other MISO purchased power costs that were $20 million higher.

Reduced power plant availability because of planned maintenance activities. UE’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 81% and 89%, respectively, in 2007 compared with 84% and 90%, respectively, in 2006.
UE’s gas margin increased by $10 million, or 17%, in 2007 compared with 2006. The following items had a favorable impact on gas margin:

The UE gas rate increase effective in April 2007, which increased gas margin by $4 million.

Unrecoverable purchased gas costs totaling $4 million in 2006 that did not recur in 2007.

Favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by an estimated $2 million.
Illinois Regulated
Illinois Regulated’s electric margin decreased by $65 million, or 8%, and gas margin increased by $10 million, or 3%, in 2007 compared with 2006. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margin decreased by $12 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.

The Illinois electric settlement agreement, which reduced electric margin by $11 million.

MISO purchased power costs that increased by $8 million because of the March 2007 FERC order.
The following items had a favorable impact on electric margin in 2007 as compared with 2006:

Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $19 million lower, partly because of customers switching to third-party suppliers and the termination of the JDA agreement at the end of 2006.

Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively affected electric sales and resulted in a net reduction in overall electric margin of $3 million in 2006.

Favorable weather conditions, as evidenced by a 20% increase in cooling degree-days, which increased electric margin by an estimated $6 million.
CIPS’ gas margin was comparable in 2007 and 2006.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2007 compared with 2006:
CILCO’s (Illinois Regulated) electric margin decreased by $32 million, or 20%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.

The Illinois electric settlement agreement, which reduced electric margin by $7 million.

MISO purchased power costs that increased by $4 million, because of the March 2007 FERC order.
The following items had a favorable impact on electric margin in 2007 compared with 2006:

Other MISO purchased power costs, that were $4 million lower, partly because of customers switching to third-party suppliers.

Favorable weather conditions, as evidenced by an 18% increase in cooling degree-days, which increased electric margin by an estimated $2 million.
See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) electric margin in 2007 compared with 2006.
CILCO’s (Illinois Regulated) gas margin increased by $7 million, or 8%, in 2007 compared with 2006, primarily because of favorable weather conditions, as evidenced by a 7% increase in heating degree-days, increased industrial sales, and higher transportation volumes.
IP
IP’s electric margin decreased by $21 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.

The Illinois electric settlement agreement, which reduced electric margin by $14 million.

MISO purchased power costs that increased by $12 million, because of the March 2007 FERC order.
The following items had a favorable impact on electric margin in 2007 compared with 2006:

Other MISO purchased power costs, that were $13 million lower, partly because of customers switching to third-party suppliers.

Favorable weather conditions, as evidenced by a 21% increase in cooling degree-days, which increased electric margin by an estimated $5 million.

Reduced severe storm-related outages in 2007 compared with those that occurred in 2006, which negatively affected electric sales and resulted in an estimated net reduction in overall electric margin of $2 million in 2006.
IP’s gas margin was comparable in 2007 and 2006.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin increased by $281 million, or 37%, in 2007 compared with 2006. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 74% and 81%, respectively, in 2007 compared with 74% and 84%, respectively, in 2006. See below for explanations of electric margin variances for the Non-rate-regulated Generation segment.
Genco
Genco’s electric margin increased by $135 million, or 36%, in 2007 compared with 2006. The following items had a favorable impact on electric margin:

Selling power at market-based prices in 2007, compared with selling power at below-market prices in 2006, pursuant to a cost-based power supply agreement that expired on December 31, 2006.

Reduced purchased power costs due to the termination of the JDA.

Increased power plant availability, due to fewer planned outages in 2007, that reduced purchased power costs. Genco’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 75% and 86%, respectively, in 2007, compared with 66% and 82%, respectively, in 2006.

MISO-related revenues that were $12 million higher as a result of the March 2007 FERC order.

Other MISO purchased power costs that were $16 million lower.

A reduction of mark-to-market losses on fuel contracts of $6 million.
The following items had an unfavorable impact on electric margin in 2007 compared with 2006:

The loss of wholesale margins on sales of power acquired through the JDA, which terminated in 2006.

Costs of $30 million pursuant to the Illinois electric settlement agreement.

Fuel prices increased by 4%.
CILCO (AERG)
AERG’s electric margin increased by $97 million, or 87%, in 2007 compared with 2006. The following items had a favorable impact on electric margin:

Increased revenues due to selling power at market-based prices in 2007 compared with below-market prices in 2006, pursuant to a cost-based power supply agreement that expired on December 31, 2006.

Lower emission allowance costs of $11 million due to an increase in low sulfur coal consumption in 2007.

MISO-related revenues that were $4 million higher as a result of the March 2007 FERC order.

Other MISO purchased power costs that were $7 million lower.

Replacement power insurance recoveries of $7 million due to an extended plant outage.
The following items had an unfavorable impact on electric margin in 2007 compared with 2006:

Costs of $13 million pursuant to the Illinois electric settlement agreement.

Reduced plant availability because of an extended plant outage. AERG’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 55% and 61%, respectively, in 2007, compared with 69% and 81%, respectively, in 2006.

Fuel prices increased by 5%.
EEI
EEI’s electric margin decreased by $8 million, or 3%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The lack of emissions allowance sales in 2007, which increased 2006 electric margin by $30 million.

Fuel prices increased by 5%.

Reduced plant availability related to increased unit outages. EEI’s baseload coal-fired generating plant’s average capacity and equivalent availability factors were each approximately 92% in 2007, compared with 95% in 2006.
The decrease in margin was offset by a 12% increase in market prices at EEI in 2007.
Other Operations and Maintenance Expenses
2008 versus 2007
Ameren
Ameren’s other operations and maintenance expenses increased $170 million in 2008 compared with 2007, primarily because of higher distribution system reliability expenditures of $30 million, increased plant maintenance expenditures at coal-fired plants of $43 million due to outages, higher labor costs of $52 million, increased information technology costs of $10 million, and unrealized net mark-to-market adjustments of $22 million resulting from the lower market value of investments used to support Ameren’s deferred compensation plans. Bad debt expense also increased $10 million, primarily because of the continued transition to higher market-based rates at the Ameren Illinois Utilities. Additionally, in the first quarter of 2007, a $15 million accrual established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan was reversed because the plan was terminated, with no similar item in 2008.
In addition, other operations and maintenance expenses increased in 2008 by $14 million because of asset impairment charges recorded during the fourth quarter of 2008 to adjust the carrying value of CILCO’s (through AERG) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails cogeneration facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT based on the expected net proceeds to be generated from the sale of the facility in 2009. Because most of the Sterling Avenue asset carrying value is recorded at CILCORP, as a result of adjustments made during purchase accounting, the write-down of the carrying value of the Sterling Avenue CT did not result in an impairment loss at CILCO (AERG).
Reducing the unfavorable effect of these items were lower employee benefit costs of $10 million due to changes
in actuarial estimates and reduced storm expenditures of $18 million, primarily in UE’s service territory, in 2008 compared with 2007. Additionally, costs associated with the Callaway nuclear plant refueling and maintenance outage in 2008 were $5 million lower than those for the refueling in 2007. Other operations and maintenance expenses were further reduced in the current year by a MoPSC accounting order received in the second quarter of 2008, which resulted in UE recording a regulatory asset for $25 million of costs related to 2007 storms that had previously been expensed.
Variations in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated
UE
UE’s other operations and maintenance expenses increased $22 million in 2008, as compared with 2007, primarily because of increased distribution system reliability expenditures of $16 million, higher labor costs of $37 million, increased plant maintenance expenditures at coal-fired plants of $29 million, and unrealized net mark-to-market adjustments resulting from the lower market value of investments used to support deferred compensation plans. Reducing the impact of these items was the effect of the MoPSC accounting order discussed above, a decrease in injuries and damages expenses between years, and the reduced impact of the Callaway refueling and maintenance outage in 2008 compared with the refueling in 2007. Storm repair expenditures also decreased by $31 million in 2008 compared with 2007, further reducing other operations and maintenance expenses.
Illinois Regulated
Other operations and maintenance expenses increased $77 million in the Illinois Regulated segment in 2008, compared with 2007.
CIPS
Other operations and maintenance expenses increased $24 million in 2008 compared with 2007. The increase was primarily because of higher distribution system reliability expenditures of $11 million, including storm costs, along with increased labor costs and bad debt expense. Additionally, the reversal in the first quarter of 2007 of an accrual of $4 million, established in 2006, for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan, with no similar item in 2008, resulted in higher other operations and maintenance expenses in 2008 compared with 2007.
CILCO (Illinois Regulated)
Other operations and maintenance expenses increased $8 million in 2008, as compared with 2007, primarily
because of increased storm costs of $5 million in 2008. Additionally, in the first quarter of 2007, CILCO (Illinois Regulated) reversed a $3 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in 2008. Lower employee benefit costs reduced the effect of these unfavorable items.
IP
Other operations and maintenance expenses increased $47 million in 2008, as compared with 2007, primarily because of higher distribution system reliability expenditures of $17 million, including storm costs. Labor costs and bad debt expense increased by $6 million each, and unrealized net mark-to-market adjustments resulting from the lower market value of investments used to support deferred compensation plans also increased other operations and maintenance expenses between years. Additionally, in the first quarter of 2007, IP reversed an $8 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in 2008. Reducing the unfavorable effect of these items was a reduction in employee benefit costs.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $43 million in the Non-rate-regulated Generation segment in 2008 compared with 2007.
Genco
Other operations and maintenance expenses increased $12 million at Genco in 2008, as compared with 2007, primarily because of higher plant maintenance costs of $9 million, due to scheduled outages, and increased labor costs of $5 million. Genco paid $3 million to the IPA in the prior year as part of the Illinois electric settlement agreement, with no similar item in 2008, reducing other operations and maintenance expenses between 2008 and 2007.
CILCO (AERG)
Other operations and maintenance expenses increased $25 million at CILCO (AERG) in 2008, as compared with 2007, primarily because of a $12 million impairment charge recorded in 2008 related to the Indian Trails cogeneration plant as discussed above, higher plant maintenance costs of $7 million due to scheduled outages, and increased labor costs of $3 million. CILCO (AERG) paid $1.5 million to the IPA in 2007 as part of the Illinois electric settlement agreement, with no similar item in 2008, reducing other operations and maintenance expenses between 2008 and 2007.
CILCORP (parent company only)
Other operations and maintenance expenses increased $3 million in 2008, as compared with 2007, primarily because of an asset impairment charge recorded in 2008 related to the Sterling Avenue CT discussed above.
EEI
Other operations and maintenance expenses were comparable in 2008 and 2007.
2007 versus 2006
Ameren
Ameren’s other operations and maintenance expenses increased $131 million in 2007 compared with 2006. Maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007 added $35 million. Distribution system reliability expenditures increased $49 million and employee benefits and non-Callaway labor costs were higher by $55 million in 2007 compared with 2006. Bad debt expenses increased $25 million in 2007, primarily as a result of the transition to higher electric rates in Illinois. Increases in maintenance at coal-fired power plants and injuries and damages reserves also contributed to higher other operations and maintenance expenses in 2007. We recognized reduced gains on sales of noncore property in 2007 of $4 million, compared with gains of $16 million in 2006. Additionally, other operations and maintenance expenses in 2007 included a payment of $4.5 million made to the IPA as part of the Illinois electric settlement agreement.
Reducing the effect of these items was the reversal in 2007 of an accrual of $15 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. In 2006, we also recognized costs of $25 million related to the December 2005 Taum Sauk plant reservoir breach. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 exceeded the costs associated with an ice storm in January 2007 by $42 million, thereby reducing other operations and maintenance expenses in 2007 compared with 2006.
Variations in other operations and maintenance expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Other operations and maintenance expenses increased in 2007 compared with 2006. Maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in 2007 added $35 million to other operations and maintenance expenses compared with 2006. Higher distribution system reliability expenditures of $34 million, increased non-Callaway-related labor costs of $22 million, and insurance premiums of $19 million for replacement power coverage paid to a risk insurance affiliate also increased other operations and maintenance expenses in 2007 compared with 2006. Reducing the effect of these items was the absence in 2007 of costs recorded in 2006 related to the Taum Sauk plant reservoir breach
discussed above. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 exceeded the costs associated with an ice storm in January 2007 by $13 million, thereby reducing other operations and maintenance expenses in 2007 compared with 2006.
Illinois Regulated
Other operations and maintenance expenses increased $15 million in the Illinois Regulated segment in 2007 compared with 2006.
CIPS
Other operations and maintenance expenses increased $11 million in 2007 compared with 2006, primarily because of increased bad debt expenses, higher distribution system reliability expenditures, and increased injuries and damages reserves. The reversal in 2007 of the Illinois Customer Elect electric rate increase phase-in plan accrual of $4 million established in 2006 reduced the effect of these increases. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 were comparable with the costs associated with an ice storm in January 2007.
CILCO (Illinois Regulated)
Other operations and maintenance expenses were comparable between 2007 and 2006, as an increase in bad debt expenses was offset by the reversal of the Illinois Customer Elect electric rate increase phase-in plan accrual of $3 million established in 2006. Costs associated with storms had a minimal impact on CILCO (Illinois Regulated) other operations and maintenance expenses each year.
IP
IP’s other operations and maintenance expenses were comparable between 2007 and 2006. Higher employee benefit costs increased other operations and maintenance expenses in 2007. Bad debt expenses increased $10 million in 2007, primarily as a result of the transition to higher electric rates in Illinois. Offsetting the effect of these items was the reversal in 2007 of the Illinois Customer Elect electric rate increase phase-in plan accrual of $8 million established in 2006 and a reduction of $24 million in storm repair costs between years.
Non-rate-regulated Generation
Other operations and maintenance expenses increased $30 million in the Non-rate-regulated Generation segment in 2007 compared with 2006.
Genco
Genco’s other operations and maintenance expenses increased $10 million in 2007 compared with 2006, primarily because of higher labor costs, the IPA payment of $3 million, and insurance premiums for replacement power coverage paid to a risk insurance affiliate.
CILCORP (parent company only)
Other operations and maintenance expenses were comparable between 2007 and 2006. Increased employee benefit costs in 2007 were offset by the absence in 2007 of a write-off in 2006, of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.
CILCO (AERG)
Other operations and maintenance expenses increased $11 million in 2007 compared with 2006, primarily because of higher power plant maintenance costs due to plant outages and the IPA payment of $1.5 million.
EEI
Other operations and maintenance expenses increased $3 million in 2007 compared with 2006, primarily because of higher power plant maintenance costs.
Depreciation and Amortization
2008 versus 2007
Ameren
Ameren’s depreciation and amortization expenses were comparable between periods. Increases in depreciation expense resulting from capital additions during the past year were mitigated by a reduction in expense because of changes in the useful lives of plant assets resulting from rate orders in 2007 in Missouri and 2008 in Illinois, as discussed below.
Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated
UE
Depreciation and amortization expenses decreased $4 million in 2008, compared with 2007, primarily because of the extension of UE’s nuclear and coal-fired plants’ useful lives for purposes of calculating depreciation expense in conjunction with a MoPSC electric rate order effective June 2007. Reducing the benefit of this item was an increase in capital additions over the past year.
Illinois Regulated
Depreciation and amortization expenses were comparable in 2008 and 2007 in the Illinois Regulated segment. As part of the consolidated electric and natural gas rate order issued by the ICC in September 2008, the ICC changed plant asset useful lives, effective October 1, 2008, which resulted in an increase in depreciation expense at IP and reductions in depreciation expense at CIPS and CILCO (Illinois Regulated). The effects of these changes in useful lives were partially offset by capital additions at CIPS and CILCO (Illinois Regulated). IP’s depreciation and
amortization expenses increased due to the effect of the rate order and capital additions.
Non-rate-regulated Generation
Depreciation and amortization expenses increased $4 million in the Non-rate-regulated Generation segment in 2008 compared with 2007. Depreciation and amortization expenses increased $8 million at CILCO (AERG) because of capital additions over the past year. Depreciation and amortization expenses decreased $4 million at Genco, primarily as a result of a depreciation study completed in September 2007, which was mitigated by capital additions.
2007 versus 2006
Ameren
Ameren’s depreciation and amortization expenses increased $20 million in 2007 over 2006. The increases were primarily because of amortization of a regulatory asset in 2007 at IP, as discussed below, and capital additions in 2006 and 2007. A decrease in depreciation expense as a result of the MoPSC electric rate order effective in June 2007, discussed above, somewhat mitigated that effect.
Variations in depreciation and amortization expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Depreciation and amortization expenses in 2007 were comparable with 2006. Increased expenses associated with capital additions in 2006 and 2007 were offset by a reduction in depreciation as a result of the MoPSC electric rate order, effective June 2007, discussed above.
Illinois Regulated
Depreciation and amortization expenses increased $25 million in the Illinois Regulated segment in 2007 compared with 2006.
CIPS & CILCO (Illinois Regulated)
Depreciation and amortization expenses were comparable between 2007 and 2006.
IP
Depreciation and amortization expenses, including amortization of regulatory assets on IP’s statement of income, increased $19 million in 2007 compared with 2006, primarily because of the start of amortization in 2007 of a regulatory asset associated with acquisition integration costs, as required by an ICC order, and capital additions.
Non-rate-regulated Generation
Depreciation and amortization expenses were comparable between 2007 and 2006 in the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG) and EEI.
Taxes Other Than Income Taxes
2008 versus 2007
Ameren
Ameren’s taxes other than income taxes increased $12 million in 2008 compared with 2007, primarily because of higher property taxes and higher gross receipts taxes. Increases in property taxes were reduced by invested capital electricity distribution tax credits in the Illinois Regulated segment. These credits were related to payments made in a previous year.
Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated
UE
UE’s taxes other than income taxes increased $6 million in 2008 compared with 2007, primarily because of higher property taxes.
Illinois Regulated
Taxes other than income taxes increased $5 million in 2008 compared with 2007 in the Illinois Regulated segment, primarily because of higher excise taxes at CIPS, CILCO (Illinois Regulated), and IP. Property taxes were comparable between years as increases in 2008 were mitigated by the favorable impact of the invested capital electricity distribution tax credits discussed above.
Non-rate-regulated Generation
Taxes other than income taxes were comparable between 2008 and 2007 in the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG) and EEI.
2007 versus 2006
Ameren
Ameren’s taxes other than income taxes decreased $10 million in 2007 compared with 2006, primarily because of lower gross receipts and property taxes.
Variations in taxes other than income taxes for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Taxes other than income taxes increased $4 million in 2007 over 2006, primarily because of increased gross receipts taxes.
Illinois Regulated
Taxes other than income taxes decreased $16 million in 2007 compared with 2006 in the Illinois Regulated segment. Taxes other than income taxes decreased $7 million at CIPS, $2 million at CILCO (Illinois Regulated), and $7 million at IP in 2007 compared with 2006, primarily as a result of reduced property taxes and excise taxes.
Non-rate-regulated Generation
Taxes other than income taxes were comparable between 2007 and 2006 for the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG), and EEI.
Other Income and Expenses
2008 versus 2007
Ameren
Miscellaneous income increased $5 million in 2008 compared with 2007, primarily because of an increase at UE in allowance for funds used during construction, reduced by lower interest income. Miscellaneous expense increased $6 million in 2008 compared with 2007, primarily because of increased expenses associated with contributions to social programs.
Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated
UE
Miscellaneous income increased $24 million in 2008 compared with 2007, primarily because of an increase in allowance for funds used during construction. The increase in allowance for funds used during construction resulted from higher rates and increased construction-in-progress balances. Miscellaneous expenses were comparable in 2008 and 2007.
Illinois Regulated
Other income and expenses decreased $9 million in 2008 in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, compared with 2007, primarily because of lower interest income.
Non-rate-regulated Generation
Other income and expenses in the Non-rate-regulated Generation segment and at Genco, CILCORP (parent company only), CILCO (AERG) and EEI were comparable between 2008 and 2007.
2007 versus 2006
Ameren
Miscellaneous income increased $25 million in 2007 compared with 2006, primarily because of increased interest and investment income. Cash balances were higher because of uncertainty regarding the ultimate resolution of legislative and regulatory issues in Illinois. Miscellaneous expense increased $6 million in 2007 compared with 2006, primarily because we made contributions to our charitable trust and because Illinois Regulated made contributions of $5 million for energy efficiency and customer assistance programs as part of the Illinois electric settlement agreement. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.
Variations in other income and expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Other income and expenses were comparable in 2007 and 2006.
Illinois Regulated
Other income and expenses increased $7 million in the Illinois Regulated segment in 2007 compared with 2006, primarily because of increased interest income at IP. Other income and expenses were comparable between years at CIPS and CILCO (Illinois Regulated).
Non-rate-regulated Generation
Other income and expenses were comparable between 2007 and 2006 in the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG), and EEI.
Interest
2008 versus 2007
Ameren
Interest expense increased $17 million in 2008 compared with 2007. Long-term debt issuances, net of maturities and redemptions, and the cost of refinancing auction-rate environmental improvement and pollution control revenue refunding bonds resulted in increased interest expense in 2008. See Insured Auction-Rate Tax-exempt Bonds under Part II, Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. 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 part of the following discussion.
Our risk management objective is to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of 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 have within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.
The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at December 31, 2008:
(a) Calculations are based on an effective tax rate of 38%.
(b) Includes intercompany eliminations.
(c) Less than $1 million.
The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in
interest rates, management would probably act 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, this sensitivity analysis assumes no change in our financial structure.
Insured Tax-exempt Auction-Rate Bonds
Certain auction-rate tax-exempt environmental improvement and pollution control revenue bonds previously issued for the benefit of UE, CIPS, CILCO and IP through governmental authorities were insured by “monoline” bond insurers. See Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of this indebtedness. As a result of developments in the capital markets with respect to residential mortgage-backed securities and collateralized debt obligations, the credit rating agencies have downgraded the credit ratings of the monoline bond insurers that insured such securities. As a result, our insured auction-rate bonds were similarly downgraded. In 2008, we experienced higher interest expense and/or “failed auctions,” in which there were not sufficient clearing bids in an auction to set the interest rate for a portion of our auction-rate bonds. According to press reports, many other series of auction-rate securities similarly experienced “failed auctions.”
To mitigate the effect of these credit ratings downgrades and the resulting impact on the interest rates of our auction-rate tax-exempt environmental improvement and pollution control revenue bonds, we redeemed all of UE’s, CIPS’, CILCO’s and IP’s outstanding auction-rate bonds, except for UE’s 1992 Series and 1998 Series A, B and C bonds, which had an aggregate balance of $207 million at December 31, 2008, and interest rates ranging from 1.313% to 9.975% during the year ended December 31, 2008. In April 2008, UE and IP issued senior secured notes in the principal amount of $250 million and $337 million, respectively, to refinance their auction-rate indebtedness. See Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description of these redemptions and refinancings.
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. In 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 and executory contracts with market risk exposures. 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.
The 2007 increase in electric rates in Illinois, and a related increase in extended payment plan arrangements, resulted in an increase in the Ameren Illinois Utilities’ past-due accounts receivable balances during 2007 and the first quarter of 2008. Such past-due balances have improved during the last nine months of 2008, primarily as a result of enhanced collection efforts and an increase in the volume of write-offs of past-due balances deemed uncollectible. The Ameren Illinois Utilities will continue to monitor the impact of increased electric rates on customer collections and to make adjustments to their allowances for doubtful accounts, as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.
At December 31, 2008, no single nonaffiliated customer represented more 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, CIPS, Genco, AERG, IP, AFS, and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At December 31, 2008, UE’s, CIPS’, Genco’s, CILCO’s, IP’s, AFS’, and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties related to interchange or wholesale purchases and sales was less than $1 million, net of collateral (2007 - less than $1 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. It 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 before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $46 million at December 31, 2008 (2007 - $63 million).
The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois electric settlement agreement. The agreement provides to certain electric customers of the Ameren Illinois Utilities $488 million in rate relief over a four-year period that commenced in 2007. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 - Rate and Regulatory Matters to our financial statements under Part II, of this report for additional information.
Equity Price Risk
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in 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 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, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets.
In future years, the costs of such plans reflected in net income, OCI, or regulatory assets, and cash contributions to the plans could increase materially, without pension asset portfolio investment returns equal to or in excess of our assumed return on plan assets of 8%. See Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report for discussion of the impact of 2008 investment returns.
UE also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2008, this fund was invested primarily in domestic equity securities (55%) and debt securities (45%). It totaled $239 million (in 2007 - $307 million). By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be used 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. 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 trust to various investment options. UE’s exposure to equity price market risk is in large part mitigated, because UE is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Foreign Currency Risk
Ameren and UE are exposed to foreign currency exchange risk from UE’s procurement agreement related to construction of a potential new nuclear unit. This agreement provides a fixed price for heavy forgings as well as consulting services to aid with design certification. The agreement requires UE to pay for goods and services in euros. UE uses foreign currency forward contracts for the purchase of euros to mitigate the impact of changes in foreign currency exchange rates, which could affect the amount of U.S. dollars required to satisfy the obligation denominated in euros. To the extent the value of the U.S. dollar versus the euro declines, the effect would be reflected in construction work in process within property and plant, net, and would be subject to routine depreciation and impairment considerations.
Commodity Price Risk
We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.
The following table shows how our earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for 2009 through 2012:
(a) Calculations are based on an effective tax rate of 38%.
(b) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any negative material financial impact.
On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. At that time, UE, CIPS, Genco, IP, Marketing Company and AFS were counterparties with Lehman Brothers Commodity Services Inc. (Lehman Commodity Services), a subsidiary of Lehman, in energy commodity transactions that support their utility and generation businesses. The obligations of Lehman Commodity Services were guaranteed by Lehman, and the Lehman bankruptcy filing gives UE, CIPS, Genco, IP, Marketing Company and AFS the right to terminate any open transactions. On October 21, 2008, Ameren sent notice to Lehman Commodity Services terminating all transactions between UE, Genco, and Marketing Company and Lehman Commodity Services. As of December 31, 2008, Ameren’s and its subsidiaries’ direct exposure to Lehman Commodity Services, based on existing transactions and current market prices, was estimated to be less than $1 million before taxes, collectively.
We manage risks associated with changing prices of fuel for generation using similar techniques as those used to manage risks associated with changing market prices for electricity. Most UE, Genco and AERG fuel supply contracts are physical forward contracts. Genco, AERG and EEI do not have the ability to pass through higher fuel costs to their customers for electric operations. Prior to March 2009, UE did not have this ability either except through a general rate proceeding. As a part of the January 2009 MoPSC electric rate order, UE was granted permission to put a FAC in place which was effective March 1, 2009. The FAC allows UE to recover directly from its electric customers 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. Thus, UE remains exposed to 5% of changes in its fuel and purchased power costs, net of off-system revenues. UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a 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 is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. UE, Genco, AERG and EEI generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.
Transportation costs for coal and natural gas can be a significant portion of fuel costs. UE, Genco, AERG and EEI typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of UE, Genco, AERG and EEI are regulated by FERC through approved tariffs governing the rates,
terms and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the contracts prior to the termination of the
primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.
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, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the five-year period 2009 through 2013, as of December 31, 2008. The projected required supply of these commodities could be significantly affected by changes in our assumptions for such matters as customer demand of our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
(a) Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2009 represents January 2009 through March 2009. The year 2010 represents November 2009 through March 2010. This continues each successive year through March 2013.
(b) Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. Larger customers are purchasing power from the competitive markets. See Note 2 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a discussion of the Illinois power procurement process and for additional information on the Ameren Illinois Utilities’ purchased power commitments.
The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the five-year period 2009 through 2013.
(a) Calculations are based on an effective tax rate of 38%.
(b) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. If diesel fuel costs were to increase or decrease by $0.25/gallon, Ameren’s fuel expense could increase or decrease by $13 million annually (UE - $7 million, Genco - $3 million, AERG - $1 million and EEI - $2 million). As of December 31, 2008, Ameren had price-hedged approximately 100% of expected fuel surcharges in 2009.
In the event of a significant change in coal prices, UE, Genco, AERG and EEI 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, this 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, or it uses inventories that provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services. There is no fuel reloading scheduled for 2009 or 2012. UE has price hedges for 87% of the 2010 to 2013 nuclear fuel requirements.
Although nuclear fuel market prices declined in 2008, pricing remains subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some market-price-related component. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices which cannot now be accurately
predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.
With regard to the electric generating operations for UE, Genco and AERG that are exposed to changes in market prices for natural gas used to run CTs, the natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas while minimizing costs. We optimize 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 MISO Day Two Energy Market. In addition, Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois market. The FTRs are intended to mitigate expected electric transmission congestion charges related to the physical electricity business. Depending on the congestion and prices at various points on the electric transmission grid, FTRs could result in either charges or credits. Complex grid modeling tools are used to determine which FTRs to nominate in the FTR allocation process. There is a risk of incorrectly modeling the amount of FTRs needed, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.
With regard to UE’s natural gas distribution business and, commencing March 1, 2009, its electric distribution business, and to CIPS’, CILCO’s and IP’s electric and natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow UE, CIPS, CILCO and IP to pass on to retail customers prudently incurred fuel, purchased power and gas supply costs. UE’s, CIPS’, CILCO’s and IP’s strategy is designed to reduce the effect of market fluctuations for our regulated customers. The effects of price volatility cannot be eliminated. However, procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.
With regard to our exposure for commodity price risk for construction and maintenance activities, Ameren is exposed to changes in market prices for metal commodities and labor availability.
See Supply for Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear power, natural gas, hydroelectric power, 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, FTRs and emission allowances.
Price fluctuations in natural gas, fuel, electricity, FTRs and emission allowances may cause any of these conditions:

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sales prices under the commitments are compared with current commodity prices;

market values of fuel and natural gas inventories or purchased power that differ from the cost of those commodities in inventory under contracted commitment; or

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for 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 that sufficient volumes are available to meet our requirements. See Note 7 - 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, 2008. We use various methods to determine the fair value of our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents maturities of derivative contracts as of December 31, 2008, based on the hierarchy levels used to determine the fair value of the contracts:
(a) Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed price vs. floating over-the-counter natural gas swaps.
(b)
Principally coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes interruptible power forward and option contract values based on our estimates.
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:
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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
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 and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 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 13 to the financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
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 and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present 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 schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
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 and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present 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 schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
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 and its subsidiary at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CILCORP INC.
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes as they relate to IP 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, 2008
NOTE 1- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by the Ameren and CILCORP holding companies depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.

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 transmission and distribution business in Missouri. 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. It supplies electric and gas service to a 24,000-square-mile area located in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 126,000 customers.

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, west central and southern Illinois having an estimated population of 1.1 million in an area of 20,500 square miles. CIPS supplies electric service to 393,000 customers and natural gas service to 185,000 customers.

Genco, or Ameren Energy Generating Company, operates a non-rate-regulated electric generation business in Illinois and Missouri. Genco was incorporated in Illinois in March 2000. Genco owns
2,557 megawatts of coal-fired electric generating capacity and 1,663 megawatts of natural gas and oil-fired electric generating capacity.

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business, and a rate-regulated natural gas transmission and 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 0.6 million. CILCO supplies electric service to 214,000 customers and natural gas service to 216,000 customers. AERG, a non-rate-regulated wholly-owned subsidiary of CILCO, owns 1,125 megawatts of coal-fired electric generating capacity and 15 megawatts of oil-fired electric generating capacity. 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. IP was incorporated in 1923 in Illinois. It supplies electric and gas utility service to portions of central, east central and southern Illinois, serving a population of 1.5 million in an area of 15,000 square miles, contiguous to our other service territories. IP supplies electric service to 627,000 customers and natural gas service to 421,000 customers, including most of the Illinois portion of the Greater St. Louis area.
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, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. See Note 14 - Related Party Transactions for additional information.
The following table presents summarized financial information of EEI (in millions):
The financial statements of Ameren, Genco, CILCORP and CILCO are prepared on a consolidated basis. CIPS has no subsidiaries and therefore is not consolidated. UE had a subsidiary in 2007 and 2006 (Union Electric Development Corporation), but in January 2008 this subsidiary was transferred to Ameren in the form of a stock dividend. In March 2008 it was merged into an Ameren nonregistrant subsidiary. Accordingly, UE’s financial statements were prepared on a consolidated basis for 2007 and 2006 only. IP had a subsidiary in 2007 and 2006 (Illinois Gas Supply Company) that was dissolved at December 31, 2007. Accordingly, IP’s financial statements were prepared on a consolidated basis for 2007 and 2006 only. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are 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.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, the NRC, and 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 2 - 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 represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Consists of coal, oil, paint, 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,
including nuclear refueling and maintenance outages, 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 that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 - 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 2008, 2007 and 2006 generally ranged from 3% to 4% of the average depreciable cost. Due to the ICC consolidated electric and gas rate order that became effective on October 1, 2008, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS - $4 million reduction, CILCO - $26 million reduction, and IP - $17 million increase).
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, as is the 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 and 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 rates that were utilized during 2008, 2007 and 2006:
Goodwill and Intangible Assets
Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of December 31, 2008, Ameren, CILCORP, and IP had goodwill of $831 million, $542 million, and $214 million, respectively. Ameren’s and IP’s goodwill relates to the acquisition of IP in 2004. Ameren’s and CILCORP’s goodwill relates to the acquisition of CILCORP in 2003. Ameren’s goodwill also includes an additional 20% ownership interest in EEI acquired in 2004 as well as the acquisition of Medina Valley in 2003.
In accordance with the specific provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” we test goodwill for impairment at the reporting unit level. Ameren has identified three reporting units, which also represent Ameren’s reportable segments and operating segments under SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information.” The Ameren reporting units include Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. Ameren’s reporting units have been defined and goodwill is evaluated at the operating
segment level because we believe the components within each operating segment have similar economic characteristics. The following table details how goodwill has been assigned to the reporting units:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Impairment testing of goodwill is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, the second step is performed to measure the amount of impairment, if any. The second step requires a calculation of the implied fair value of goodwill.
The goodwill impairment test performed in the fourth quarter of 2008 did not require a second step assessment; it indicated no impairment of Ameren’s, CILCORP’s or IP’s goodwill. The fair value of Ameren’s, CILCORP’s and IP’s reporting units was estimated based on a probability-weighted discounted cash flow model that considered multiple operating scenarios. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year future cash flows, and an exit value based on observable market multiples. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, the regulatory environment, and operating costs. The failure to achieve projected future operating results and cash flows, or adjustments to other valuation assumptions, could change our estimate of reporting unit fair value, in which case we might be required, at a later date, to record an impairment charge related to goodwill.
At Ameren and IP, either (1) a decrease in the forecasted cash flows of ten percent, (2) an increase in the discount rate of one percentage point, or (3) a decrease of the market multiple by one would not have resulted in the carrying value of any of the reporting units exceeding their fair values.
The estimated fair values of CILCORP’s Illinois Regulated reporting unit and Non-rate-regulated Generation reporting unit exceeded carrying values by a nominal amount as of October 31, 2008. As a result, the failure in the future of either of these reporting units to achieve forecasted operating results and cash flows may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. CILCORP will continue to monitor the actual and forecasted operating results and cash flows and observable market multiples of these reporting units for signs of
possible declines in estimated fair value and potential goodwill impairment. Ameren would not necessarily expect any future goodwill impairment charge recorded at the CILCORP reporting unit level to also result in a goodwill impairment charge at the consolidated Ameren level because of the aggregation of reporting units.
Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets at December 31, 2008 and 2007, consisted of emission allowances. See also Note 15 - Commitments and Contingencies for additional information on emission allowances.
The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were carried as intangible assets as of December 31, 2008. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.
(a) Vintages are from 2008 to 2018. Each company possesses additional allowances for use in periods beyond 2018.
(b) Vintage is 2008.
(c)
The book value at December 31, 2008, represents SO2 and NOx emission allowances for use in periods through 2031. The book value at December 31, 2007, for Ameren, UE, Genco, CILCORP, CILCO (AERG), and EEI was $198 million, $56 million, $63 million, $41 million, $1 million, and $9 million, respectively.
(d) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(e) Includes $26 million of fair-market value adjustments recorded in connection with Ameren’s acquisition of an additional 20% ownership interest in EEI.
(f) Includes fair-market value adjustments recorded in connection with Ameren’s acquisition of CILCORP.
The following table presents the amortization expense based on usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco, CILCORP, and CILCO (AERG) during the years ended December 31, 2008, 2007, and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes allowances consumed that were recorded through purchase accounting.
(c) Less than $1 million.
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. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize the amount of the impairment by estimating the fair value of the assets and recording a provision for loss. During the fourth quarter of 2008, asset impairment charges were recorded to adjust the carrying value of CILCO’s (AERG’s) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails cogeneration facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT based on the expected net proceeds to be generated from the sale of the facility in 2009. These charges were recorded in Operating Expenses - Other Operations and Maintenance Expense in the applicable statements of income and were included with Non-rate-regulated Generation segment results.
Investments
Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which we believe would be recovered in electric rates paid by UE’s customers. Accordingly, Ameren and UE recognize a regulatory asset on their balance sheets for losses on investments held in the nuclear decommissioning trust fund. See Note 9 - Nuclear Decommissioning Trust Fund Investments for additional information.
Environmental Costs
Environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and that the amount of the liability can be reasonably estimated. Estimated environmental expenditures 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
Operating Revenues
UE, CIPS, Genco, CILCO and IP record operating revenue for electric or gas service when it is delivered to customers. We accrue an estimate of electric and gas revenues for service rendered but unbilled at the end of each accounting period.
Trading Activities
We present the revenues and costs associated with certain energy derivative contracts designated as trading on a net basis in Operating Revenues - Electric and Other.
Nuclear Fuel and Purchased Gas Costs
UE’s cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and that cost is charged to expense.
In UE’s, CIPS’, CILCO’s, and IP’s retail natural gas utility jurisdictions, changes in gas costs are generally reflected in billings to their natural gas utility customers through PGA clauses. The difference between actual natural gas costs and costs billed to customers in a given period are deferred and included in Other Current Assets or Other Current Liabilities in the balance sheets of UE, CIPS, CILCO and IP. The deferred amounts are either billed or refunded to their natural gas utility customers prospectively in a subsequent period.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, UE, CIPS, CILCO and IP using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in Operating Expenses - Purchased Power and net sales in a single hour in Operating Revenues - Electric in our statements of income. On occasion, prior period transactions will be resettled outside the routine settlement process due to a change in MISO’s tariff or a material interpretation thereof. In these cases, Ameren, UE, CIPS, CILCO and IP recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated. Ameren, UE, CIPS, CILCO and IP recognize revenues associated with resettlements in accordance with SEC Staff Accounting Bulletin No. 101, “Revenue Recognition in Financial Statements.”
Stock-based Compensation
In accounting for stock-based compensation, Ameren measures the cost of employee services received in exchange for an award of equity instruments by the grant-date fair value of the award over the requisite service period.
See Note 12 - Stock-based Compensation for further information.
Excise Taxes
Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Operating Expenses - Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the years ended 2008, 2007 and 2006:
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 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, that is, equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of SFAS No. 109.
Investment tax credits used on tax returns for 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. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 - Income Taxes.
UE, CIPS, Genco, CILCORP, CILCO, and IP are parties to a tax sharing agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax sharing
agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.
Minority Interest and Preferred Dividends of Subsidiaries
For the years ended December 31, 2008, 2007, and 2006, Ameren had minority interest expense related to EEI of $29 million, $27 million, and $27 million, respectively, and preferred dividends of subsidiaries of $10 million, $11 million, and $11 million, respectively.
Earnings per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2008, 2007, and 2006. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 16,841 shares in 2008, 35,545 shares in 2007, and 38,438 shares in 2006.
Accounting Changes and Other Matters
SFAS No. 157, Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. SFAS No. 157 clarifies that fair value is a market-based measurement that should be based on the assumptions that market participants would use in pricing an asset or liability. See Note 8 - Fair Value Measurements for additional information on our adoption of SFAS No. 157.
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of SFAS No. 115
In February 2007, the FASB issued SFAS No. 159, which permits companies to choose to measure at fair value many financial instruments and certain assets and liabilities that are not currently required to be measured at fair value on an instrument-by-instrument basis. Entities electing the fair value option will be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. SFAS No. 159 was effective as of the beginning of our 2008 fiscal year. We did not elect the fair value option for any of our eligible financial instruments or other items.
FSP FIN 39-1, Amendment of FASB Interpretation No. 39
In April 2007, the FASB issued FSP FIN 39-1, effective for us as of the beginning of our 2008 fiscal year. FSP FIN 39-1 permits companies to offset fair value amounts
recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. We did not elect to adopt FSP FIN 39-1 for any of our eligible financial instruments or other items.
SFAS No. 141 (Revised 2007), Business Combinations
In December 2007, the FASB issued SFAS No. 141(R), which replaces SFAS No. 141. SFAS No. 141(R) applies to all transactions in which an entity obtains control of one or more businesses and combinations without the transfer of consideration. SFAS No. 141(R) requires the acquiring entity in a business combination to recognize assets acquired and liabilities assumed in the transaction at fair value; it requires certain contingent assets and liabilities acquired be recognized at their fair values on the acquisition date; and it requires expensing of acquisition-related costs as incurred, among other provisions. SFAS No. 141(R) was effective as of January 1, 2009. It applies prospectively to business combinations completed on or after that date.
SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51
In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for minority interests, which will be recharacterized as noncontrolling interests. Under the provisions of SFAS No. 160, noncontrolling interests will be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control will be accounted for as equity transactions; net income attributable to the noncontrolling interest will be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, will be recorded at fair value, with any gain or loss recognized in earnings. SFAS No. 160 was effective for us as of the beginning of our 2009 fiscal year. It applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This standard is applicable to the minority interest in EEI, as EEI is 80% owned by Ameren.
SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities - an amendment of SFAS No. 133
In March 2008, the FASB issued SFAS No. 161, which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures
about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 was effective in the first quarter of 2009. The adoption of SFAS No. 161 did not have a material impact on our results of operations, financial position, or liquidity, because it provides enhanced disclosure requirements only.
FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active
In October 2008, the FASB issued FSP SFAS No. 157-3, which clarifies the application of SFAS No. 157 in a market that is not active. FSP SFAS No. 157-3 provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP SFAS No. 157-3 was effective upon issuance, and it applied retroactively to periods for which financial statements had not yet been issued. The adoption of FSP SFAS No. 157-3 did not have a material impact on our results of operations, financial condition, or liquidity.
FSP SFAS No. 140-4 and FIN 46(R), Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities
In December 2008, FASB issued FSP SFAS No. 140-4 and FIN 46(R), effective for us as of December 31, 2008.
FSP SFAS No. 140-4 and FIN 46(R) require enhanced qualitative and quantitative information about an enterprise’s involvement with a variable-interest entity (VIE) and its continuing involvement with transferred financial assets. For VIEs, enhanced qualitative and quantitative information about an enterprise’s involvement with a VIE, financial or other support provided by the enterprise to the VIE, and the methodology applied in determining whether an enterprise is the primary beneficiary should be disclosed. See Variable-interest Entities below for further information.
FSP SFAS No. 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets
In December 2008, FASB issued FSP SFAS No. 132(R)-1, which will be effective for us as of December 31, 2009. FSP SFAS No. 132(R)-1 requires additional disclosures related to pension and other postretirement benefit plan assets. Additional disclosures include the investment allocation decision-making process, the fair value of each major category of plan assets as well as the inputs and valuation techniques used to measure fair value and significant concentrations of risk within the plan assets. The adoption of FSP SFAS No. 132(R)-1 will not have a material impact on our results of operations, financial position or liquidity, because it provides enhanced disclosure requirements only.
Asset Retirement Obligations
SFAS No. 143, “Accounting for Asset Retirement Obligations,” and FIN 47, “Accounting for Conditional Asset Retirement Obligations” - an Interpretation of FASB Statement No. 143, require 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 AROs 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 AROs affect our estimates of fair value. Ameren, UE, Genco, CILCORP, and CILCO have recorded AROs for retirement costs associated with UE’s Callaway nuclear plant decommissioning costs, asbestos removal, ash ponds, and river structures. In addition, Ameren, UE, CIPS, and IP have recorded AROs for the disposal of certain transformers.
Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 - Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2008 and 2007:
(a) Ameren amounts do not equal total due to AROs at EEI.
(b) The nuclear decommissioning trust fund assets of $239 million and $307 million as of December 31, 2008 and 2007, respectively, are restricted for decommissioning of the Callaway nuclear plant.
(c) Less than $1 million.
(d) Substantially all accretion expense was recorded as an increase to regulatory assets.
(e) UE, Genco and CILCO changed estimates related to retirement costs for their ash ponds. Additionally, UE changed estimates related to its Callaway nuclear plant decommissioning costs.
(f) UE changed estimates related to its Callaway nuclear plant decommissioning costs based on a cost study performed in 2008, a change in assumptions related to plant life, and a decline in the cost escalation factor assumptions.
Variable-interest Entities
According to FIN 46R, “Variable-interest Entities,” an entity is considered a variable-interest entity (VIE) if it does not have sufficient equity to finance its activities without assistance from variable-interest holders, or if its equity investors lack any of the following characteristics of a controlling financial interest: control through voting rights, the obligation to absorb expected losses, or the right to receive expected residual returns. Ameren and its subsidiaries review its equity interests, debt obligations, leases, contracts, and other agreements to determine its relationship to a VIE. We have determined that the following significant VIEs were held by the Ameren Companies at December 31, 2008:

Leveraged lease and affordable housing partnership investments. Ameren has investments in affordable housing and low-income real estate development partnership arrangements that are variable interests. Ameren also has an investment in a leveraged lease. We have concluded that Ameren is not the primary beneficiary of any of the VIEs related to these investments because Ameren would not absorb a majority of the entity’s losses. These investments are classified as Other Assets on Ameren’s consolidated balance sheet. The maximum exposure to loss as a result of these variable interests is limited to the investments in these arrangements. At December 31, 2008, and December 31, 2007, Ameren had investments in affordable housing and low-income real estate development partnerships of $82 million and $100 million, respectively. At December 31, 2008, and December 31, 2007, Ameren had a net investment in a leveraged lease of $9 million. For these variable interests, Ameren is a limited partner. It owns less than
a 50 percent interest and receives the benefits and accepts the risks consistent with its limited partner interest. In 2008, a subsidiary of UE that owned affordable housing partnerships was eliminated in an internal reorganization. Those investments were transferred to a nonregistrant Ameren subsidiary.
IP’s variable interest in IP SPT was eliminated, as the TFNs for which the IP SPT was established were redeemed in September 2008. IP had indemnified IP SPT; IP was liable to IP SPT if IP did not bill the applicable charges to its customers on behalf of IP SPT or if it did not remit the collections to IP SPT. However, the note holders were considered the primary beneficiaries of this special-purpose trust. Accordingly, Ameren and IP did not consolidate IP SPT.
Coal Contract Settlement
In June 2008, Genco entered into an agreement with a coal mine owner. The owner provided Genco with a lump-sum payment of $60 million in July 2008 due to the coal supplier’s premature closing of a mine and the early termination of a coal supply contract. The settlement agreement compensates Genco, in total, for higher fuel costs it incurred in 2008 ($33 million) and expects to incur in 2009 ($27 million) as a result of the mine closure and contract termination.
NOTE 2 - RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.
Missouri
2007 Electric Rate Order
In May 2007, the MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service based on a return on equity of 10.2% and a capital structure of 52% common equity. New electric rates became effective June 4, 2007.
In July 2007, UE and other parties appealed certain aspects of the MoPSC decision, to the Circuit Court of Cole County in Jefferson City, Missouri and subsequently to the Court of Appeals for the Western District of Missouri. In January 2009, the Court of Appeals for the Western District of Missouri issued an order affirming, in all respects, the order issued by the MoPSC in May 2007, and the time to appeal this court decision has expired.
2009 Electric Rate Order
In April 2008, UE filed a request with the MoPSC to increase its annual revenues for electric service by $251 million. The electric rate increase request proposed an average increase in electric rates of 12.1%. It was based on a 10.9% return on equity, a capital structure composed of 52% common equity, a rate base of $5.9 billion, and a test year ended March 31, 2008, with updates for known and measurable changes through September 30, 2008.
As part of the proceeding, UE requested that the MoPSC also approve implementation of a FAC and a vegetation management and infrastructure inspection cost recovery mechanism.
On January 27, 2009, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $162 million based on a 10.76% return on equity, a capital structure composed of 52% common equity, and a rate base of $5.8 billion. The rate changes necessary to implement the provisions of the MoPSC’s order were effective March 1, 2009, with the MoPSC’s acceptance of conforming tariffs filed by UE. The MoPSC order also included the following significant provisions:

Approval of the implementation of a FAC. The mechanism provides for the adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review.

Approval of the implementation of a vegetation management and infrastructure inspection cost tracking mechanism. The mechanism provides for the tracking of expenditures that are more or less than amounts provided for in UE’s annual revenues for electric service in a particular year, subject to a 10% limitation on increases in any one year. The tracked amounts may be reflected in rates set in future rate cases.

Pursuant to an accounting order issued by the MoPSC in April 2008 that gave UE the ability to seek direct recovery of all or a portion of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of the severe ice storm should be amortized and recovered over a five-year period starting March 1, 2009. UE recorded these costs as a regulatory asset in 2008.

Allowance for recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously expensed. A regulatory asset was recorded at December 31, 2008, and will be amortized over a two-year period starting March 1, 2009.
UE provides power to Noranda’s smelter plant in New Madrid, Missouri. This plant has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer and constituting approximately 8% of UE’s total electric sales.
As a result of a major winter ice storm in Southeastern Missouri in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines delivering power to the substation serving the plant. Noranda stated that the outage affected approximately 75% of the smelter plant’s capacity. In addition, Noranda stated that based on preliminary information and management’s initial assessment, restoring full plant capacity may take up to 12 months, with partial capacity phased in during the 12 month period.
To the extent UE’s sales to Noranda are reduced, generation made available could be sold as off-system sales. However, the FAC approved in the January 2009 electric rate order would require UE to pass through substantially all of the off-system revenues to customers.
In order to adjust the FAC for this unanticipated event, UE sought rehearing by the MoPSC of its January 2009 electric rate order on February 5, 2009, to allow UE to first recover from the off-system sales any revenues it would lose as a result of the reduced tariff sales to Noranda with any excess revenues collected being provided to customers through the FAC. Also in February 2009, other parties to the rate case filed for rehearing of certain aspects of the MoPSC order. In February 2009, the MoPSC denied all rate order rehearing requests filed by UE and other parties. UE continues to consider other alternatives to recover any lost revenues resulting from the Noranda power outage. UE cannot predict whether court appeals will be filed by other parties to the rate case.
Environmental Cost Recovery Mechanism
A Missouri law enacted in July 2005 enables the MoPSC to put in place an environmental cost recovery mechanism for Missouri’s utilities. The law also includes
rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. The MoPSC initiated a proceeding in December 2008 to develop revised rules for the cost recovery mechanism. Rules for the environmental cost recovery mechanism are expected to be approved by the MoPSC during the second quarter of 2009 and will be effective once published in the Missouri Register. UE will not be able to implement an environmental cost recovery mechanism until so authorized by the MoPSC as part of a rate case proceeding.
Renewable Energy Portfolio Requirement
A ballot initiative passed by Missouri voters in November 2008 that created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Compliance with the renewable energy portfolio requirement can be achieved through the procurement of renewable energy or renewable energy credits. Rules are required to be issued by the MoPSC to implement the law. UE expects that any related costs or investments would ultimately be recovered in rates.
Illinois
2008 Electric and Natural Gas Delivery Service Rate Order
On September 24, 2008, the ICC issued a consolidated order approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS - $22 million increase, CILCO - $3 million decrease, and IP - $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million decrease, and IP - $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes to less than 10% for each utility during the first year, IP will not be able to recover approximately $10 million in revenue in the first year electric delivery service rates are in effect. Thereafter, residential electric delivery service rates will be adjusted to recover the full increase.
In addition, the ICC in its order changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS - $4 million reduction, CILCO - $26 million reduction, and IP - $17 million increase).
The ICC rejected the Ameren Illinois Utilities’ requested rate adjustment mechanisms for electric infrastructure investments. As an alternative to the Ameren Illinois Utilities’ requested decoupling of natural gas revenues from sales volumes, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial customer charges, to 80% from 53%. This increase will impact 2009 quarterly results of operations and cash flows, but is not expected to have any impact on annual margins. The ICC also approved an increase in the Supply Cost Adjustment (SCA) factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS - $2.6 million, CILCO - $1.6 million, and IP - $5.3 million), which is expected to cover the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities.
In October 2008, CIPS, CILCO and IP and other parties requested that the ICC rehear certain aspects of its September 2008 consolidated order. In November 2008, the ICC denied all rate order rehearing requests filed by the Ameren Illinois Utilities and other parties. In December 2008, the Illinois attorney general appealed to the Appellate Court of Illinois, Fourth District, the ICC’s denial of the rehearing request. The Ameren Illinois Utilities cannot predict the outcome of the court appeal.
Illinois Electric Settlement Agreement
In 2007, key stakeholders in Illinois agreed to avoid rate rollback and freeze legislation that would impose a tax on electric generation. These stakeholders wanted to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement included a comprehensive rate relief and customer assistance program. The Illinois electric settlement agreement provided approximately $1 billion of funding from 2007 to 2010 for rate relief for certain electric customers in Illinois, including approximately $488 million for customers of the Ameren Illinois Utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco, and CILCO (AERG) agreed to make aggregate contributions of $150 million over the four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco, and $28 million from CILCO (AERG). See Note 15 - Commitments and Contingencies for information on the remaining contributions to be made as of December 31, 2008.
The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues,
during the year ended December 31, 2008, of $42 million, $6 million, $3 million, $8 million, $17 million, and $8 million, respectively (year ended December 31, 2007 -$82 million, $12 million, $7 million, $15 million, $33 million, and $15 million, respectively) under the terms of the Illinois electric settlement agreement.
Other electric generators and utilities in Illinois agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities send a bill, due in 30 days, to the generators and utilities for their proportionate share of that month’s rate relief and assistance. If any escrow funds have been provided by the generators, these funds will be drawn upon first prior to seeking reimbursement from the generators. At December 31, 2008, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $15 million, $5 million, $3 million, and $7 million, respectively. See Note 14 - Related Party Transactions for information on the impact of intercompany settlements.
The Illinois electric settlement agreement provides that if legislation is enacted in Illinois before August 1, 2011, freezing or reducing retail electric rates, or imposing or authorizing a new tax, special assessment, or fee on the generation of electricity, then the remaining commitments under the Illinois electric settlement agreement would expire, and any funds set aside in support of the commitments would be refunded to the utilities and Generators.
Power Procurement Plan
As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It was replaced with a new power procurement process led by the IPA, which was established as a part of the Illinois electric settlement agreement, beginning in 2009. In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products (capacity, energy swaps and renewable energy credits) that the IPA will procure on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 30, 2014. The products are expected to be procured through a RFP process during the first half of 2009.
Except for those that expired in May 2008, existing supply contracts from the September 2006 reverse power procurement auction remain in place. In the September 2006 auction, the Ameren Illinois Utilities procured power to serve the electric load needs of fixed-price residential and small commercial customers, with one-third of the supply contracts expiring in each of May 2008, 2009, and 2010. The Ameren Illinois Utilities used RFP processes in early
2008 to replace the supply contracts that expired in May 2008. See Note 15 - Commitments and Contingencies for information on the Ameren Illinois Utilities’ purchased power agreements.
Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. See Note 14 - Related Party Transactions for information on these financial contracts.
Natural Gas Energy Efficiency Plans
In February 2008, the Ameren Illinois Utilities filed a consolidated natural gas energy efficiency plan with the ICC. In October 2008, the ICC issued an order approving the Ameren Illinois Utilities’ natural gas energy efficiency plan as well as the cost recovery mechanism by which the program costs will be recovered from natural gas customers. The natural gas energy efficiency plan includes annual reduction targets in natural gas usage as well as spending limits for the 2009, 2010, and 2011 program years of $2 million, $4 million, and $6 million, respectively.
ICC Reliability Audit
In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. The Ameren Illinois Utilities are currently in discussions with the ICC and Liberty Consulting Group about this matter. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. At this time, we are unable to determine the impact such implementation will have on our results of operations, financial position, or liquidity.
Federal
Regional Transmission Organization
UE, CIPS, CILCO and IP are transmission-owning members of MISO, which is a FERC-regulated RTO that provides transmission tariff administration services for electric transmission systems. In early 2004, UE received authorization from the MoPSC to participate in MISO for a five-year period, with further participation subject to approval by the MoPSC. The MoPSC required UE to file a
study evaluating the costs and benefits of its participation in MISO prior to the end of the five-year period. The MoPSC also directed UE to enter into a service agreement with MISO to provide transmission service to UE’s bundled retail customers. The service agreement’s primary function was to ensure that the MoPSC continued to set the transmission component of UE’s rates to serve its bundled retail load. Among other things, the service agreement provided that UE would not pay MISO for transmission service to UE’s bundled retail customers. FERC approved the service agreement in the form that was acceptable to the MoPSC.
Due to changes to MISO’s allocation of transmission revenues to transmission owners, UE believed it should receive incremental annual transmission revenues of $60 million as of February 2008 in accordance with its service agreement with MISO. Numerous transmission owners in MISO, along with MISO itself as the tariff administrator, filed with FERC in December 2007 requesting changes to the MISO tariff to prevent UE from collecting these additional transmission revenues. In December 2007, UE filed a protest to these proposed MISO tariff changes, calling them unauthorized and improper in light of the MoPSC’s requirement for the service agreement between UE and MISO discussed above. In February 2008, FERC issued an order accepting the tariff changes proposed by MISO and by certain transmission owners in MISO. In March 2008, UE filed a request with FERC for a rehearing of its order. In April 2008, FERC suspended UE’s request for rehearing to permit time for further consideration by FERC. UE is unable to predict if or when FERC may issue a further order in this proceeding.
As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s filing noted a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement and MISO revenue allocation, as discussed above. In June 2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other parties to the proceeding was filed with the MoPSC, which provides for UE’s continued, conditional MISO participation through April 30, 2012. The stipulation and agreement gives UE the right to seek permission from the MoPSC for early withdrawal from MISO if UE determines that sufficient progress toward mitigating some of the continuing uncertainties respecting its MISO participation is not being made. The MoPSC issued an order, effective September 19, 2008, approving the stipulation and agreement.
Seams Elimination Cost Adjustment
Pursuant to a series of FERC orders, FERC put Seams Elimination Cost Adjustment (SECA) charges into effect on December 1, 2004, subject to refund and hearing procedures. The SECA charges were a transition mechanism in place for 16 months, from December 1, 2004, to March 31, 2006, to compensate transmission owners in the MISO and PJM for revenues lost when FERC
eliminated the regional through-and-out rates previously applicable to transactions crossing the border between the MISO and PJM. The SECA charge was a nonbypassable surcharge payable by load-serving entities in proportion to the benefit they realized from the elimination of the regional through-and-out rates as of December 1, 2004. The MISO transmission owners (including UE, CIPS, CILCO and IP) and the PJM transmission owners filed their proposed SECA charges in November 2004, as compliance filings pursuant to FERC order. A FERC administrative law judge issued an initial decision in August 2006, recommending that FERC reject both of the SECA compliance filings (the filing for SECA charges made by the transmission owners in the MISO and the filing for SECA charges made by the transmission owners in PJM). There is no date scheduled for FERC to act on the initial decision. Both before and after the initial decision, various parties (including UE, CIPS, CILCO and IP as part of the group of MISO transmission owners) filed numerous bilateral or multiparty settlements. To date, FERC has approved many of the settlements, and has rejected none of the settlements. Neither the MISO transmission owners, including UE, CIPS, CILCO and IP, nor the PJM transmission owners have been able to settle with all parties. During the transition period of December 1, 2004, to March 31, 2006, Ameren, UE, CIPS, and IP received net revenues from the SECA charge of $10 million, $3 million, $1 million, and $6 million, respectively. CILCO’s net SECA charges were less than $1 million. Until FERC acts on the pending settlements and issues a final order on the initial decision, we cannot predict the ultimate impact of the SECA proceedings on UE’s, CIPS’, CILCO’s and IP’s costs and revenues.
FERC Order - MISO Charges
In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO, and IP retroactive to April 2006. On November 7, 2008, FERC granted the request for clarification and directed MISO to
reallocate certain costs and provide refunds as requested. On November 10, 2008, FERC granted relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding these same MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward.
Several parties to these proceedings have protested MISO’s proposed implementation of these refunds, have requested rehearing of FERC’s orders and, in some cases, have appealed FERC’s orders to the courts. Additional amounts may be receivable or due depending on the final outcome of these proceedings.
UE Power Purchase Agreement with Entergy Arkansas, Inc.
In July 2007, FERC issued a series of orders addressing a complaint filed by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing UE for additional charges under a 165-megawatt power purchase agreement. Additional charges are expected to continue during the remainder of the term of the power purchase agreement, which expires August 25, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE has intervened in related FERC proceedings. UE filed a complaint with FERC against Entergy and Entergy Services, Inc. in April 2008 to challenge the additional charges. In September 2008, the presiding FERC administrative law judge issued an initial decision finding that Entergy’s allocation of such additional charges to UE is just and reasonable. FERC is expected to issue an order with respect to the administrative law judge’s initial decision in 2009. UE is unable to predict whether FERC will grant it any relief.
Additionally, LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy to the U.S. Court of Appeals for the District of Columbia. In April 2008, that court ordered further FERC proceedings regarding the LPSC complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the
retroactive impact of these issues could have a financial impact on UE. UE is unable to predict how FERC will respond to the court’s decision. UE estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. However, UE would contest such an order vigorously. Based on existing facts and circumstances, UE believes that the likelihood of incurring this $25 million expense is not probable. Thus no liability has been recorded as of December 31, 2008. UE plans to participate in any proceeding that FERC initiates to address the court’s decision.
Nuclear Combined Construction and Operating License Application
In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600 megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. This COLA filing is not a commitment to build another nuclear unit, but it is a necessary step to preserve the option to develop a new nuclear unit in the future. The regulatory process for a COLA involves a comprehensive review, estimated by the NRC to require up to 42 months for completion.
As authorized by the Energy Policy Act of 2005, the DOE may make available up to $18.5 billion in loan guarantees in connection with debt financing of certain new nuclear unit projects. Pursuant to DOE’s procedures, in 2008 UE filed with the DOE Part I and Part II of its application for a loan guarantee to support the potential construction and operation of a new nuclear unit. UE’s loan guarantee application is not a commitment to build another nuclear unit, and there is no assurance that the DOE will provide any such guarantee to UE.
Pumped-storage Hydroelectric Facility Relicensing
In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The current FERC license expires on June 30, 2010. Approval and relicensure are expected in 2012. Operations are permitted to continue under the current license while the renewal is pending.
Regulatory Assets and Liabilities
In accordance with SFAS No. 71, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. UE, CIPS, CILCO and IP also defer certain amounts pursuant to actions of regulators or based on the expectation that such amounts will be returned to customers in future rates. The following table presents our regulatory assets and regulatory liabilities at December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. Ameren believes it is probable that these costs will be recovered through rates in future periods. See Note 11 - Retirement Benefits for additional information.
(c) These assets do not earn a return.
(d) Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period.
(e) Recoverable costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.
(f) 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.
(g) Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
(h) The recoverable portion of accrued environmental site liabilities, primarily collected from electric and gas customers through ICC-approved cost recovery riders in Illinois. The period of recovery will depend on the timing of actual expenditures.
(i) Reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. Pursuant to the ICC order approving Ameren’s acquisition of IP, these costs are recoverable in rates through 2010.
(j) A portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP at September 30, 2004. This portion is being amortized over the remaining life of the related debt beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007.
(k) Financial contracts entered into by the Ameren Illinois Utilities with Marketing Company, as part of the Illinois electric settlement agreement. See Illinois - Power Procurement Plan discussion above for additional information.
(l) Deferral of SFAS No. 133 natural gas-related derivative mark-to-market gains and losses.
(m)
A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order.
(n) Costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously charged to expense but were recorded as a regulatory asset and will be amortized over a two-year period beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
(o) UE’s vegetation management and infrastructure inspection costs incurred from January 1, 2008, through December 31, 2008, relating to compliance with the MoPSC vegetation management and infrastructure rules. The costs incurred between January 1, 2008, through September 30, 2008, will be amortized over three years beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order. The amortization period for the costs incurred between October 1, 2008 through December 31, 2008, will be determined in the next UE rate case.
(p) Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. The 2006 storm costs are being amortized over a five-year period which began June 4, 2007. The 2008 storm costs are being amortized over a five-year period beginning March 1, 2009. In addition, the balance includes January 2007 ice storm costs that UE will recover as a result of a MoPSC accounting order issued in April 2008. These costs will be amortized over five years beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
(q) Demand-side costs including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. These costs are being amortized over a ten-year period beginning March 1, 2009, as approved by the January 2009 MoPSC rate order.
(r) Reserve for workers’ compensation liabilities. Ameren believes it is probable that these costs will be recovered through electric and gas rates in future periods.
(s) Includes costs related to the Ameren Illinois Utilities November 2007 electric and natural gas delivery service rate cases. The costs associated with the Ameren Illinois Utilities electric delivery service rate cases are being amortized over a three-year period; the costs associated with the Ameren Illinois Utilities natural gas delivery service rate cases are being amortized over a five-year period, as approved in the 2008 ICC rate order. In addition, the balance includes funding for the low-income weatherization and energy efficiency programs.
(t) Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.
(u) Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations. See discussion in Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.
(v) The deferral of gains on emission allowance vintage swaps UE entered into during 2005.
(w) A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level of such costs built into electric rates effective June 4, 2007, as approved in a MoPSC order.
(x) A portion of UE’s expected refund relating to MISO resettlements associated with the November 2008 FERC orders. See Federal - FERC Order - MISO Charges discussion above for additional information.
(y) 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 that was amortized over 14 years through 2007.
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.
NOTE 3 - PROPERTY AND PLANT, NET
The following table presents property and plant, net for each of the Ameren Companies at December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(b) Includes CILCO (Illinois Regulated) and CILCO (AERG) with adjustments due to purchase accounting.
In March 2006, following the receipt of all required regulatory approvals, UE completed the purchase of a 640-megawatt CT facility located in Audrain County, Missouri, at a price of $115 million from NRG Audrain Holding LLC, and NRG Audrain Generating LLC, both affiliates of NRG Energy Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County, and UE assumed NRG’s obligations under the lease. The lease will expire on December 1, 2023.
Also in March 2006, following the receipt of all required regulatory approvals, UE completed the purchase from subsidiaries of Aquila Inc., of the 510-megawatt Goose Creek CT facility in Piatt County, Illinois, at a price of $106 million, and the 340-megawatt Raccoon Creek CT facility located in Clay County, Illinois, at a price of $71 million.
The following table provides accrued capital expenditures at December 31, 2008, 2007 and 2006, which represent noncash investing activity excluded from the statements of cash flows:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash and drawings under committed bank credit facilities.
The following table summarizes the borrowing activity and relevant interest rates under the $1.15 billion credit facility described below for the years ended December 31, 2008 and 2007, respectively, and excludes letters of credit issued under this credit facility:
(a) Includes issuances under commercial paper programs of $80 million at Ameren and UE supported by this facility as of December 31, 2007.
The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit facility described below for the years ended December 31, 2008 and 2007:
The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit facility described below for the years ended December 31, 2008 and 2007, respectively:
At December 31, 2008, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of the three facilities shown above, in the amounts of $1.15 billion, $500 million, and $500 million, maturing in July 2010, January 2010, and January 2010, respectively.
Ameren can directly borrow under the $1.15 billion facility, as amended, up to the entire amount of the facility. UE can directly borrow under this facility up to $500 million on a 364-day basis. Genco can directly borrow under this facility up to $150 million on a 364-day basis. The amended facility will terminate on July 14, 2010, with respect to all
borrowers. The termination date for UE and Genco is July 9, 2009, subject to the annual 364-day renewal provisions of the facility.
Under the $1.15 billion credit facility, the principal amount of each revolving loan will be due and payable no later than the final maturity of the facility in the case of Ameren and the last day of the then-applicable 364-day period in the case of UE and Genco. Swingline loans will be made on same-day notice and will mature five business days after they are made.
Ameren, UE and Genco will use the proceeds of any borrowings under the facility for general corporate purposes. These purposes include working capital and funding loans under the Ameren money pool arrangements.
The $1.15 billion credit facility may be used to support the commercial paper programs of Ameren and UE. However, Ameren and UE are currently limited in their access to the commercial paper market as a result of downgrades in their short-term credit ratings. Access to the $1.15 billion credit facility, the 2006 $500 million credit facility, and the 2007 $500 million credit facility for the Ameren Companies is subject to reduction as borrowings are made by affiliates.
CIPS, CILCORP, CILCO, IP and AERG are parties to the 2007 $500 million credit facility and to the 2006 $500 million credit facility.
The obligations of each borrower under the 2006 $500 million credit facility and the 2007 $500 million credit facility are several and not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower under the 2006 $500 million credit facility, including for issuance of letters of credit on its behalf, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $75 million, IP - $150 million and AERG - $200 million. Each of the companies has drawn various loans under this credit facility. Under the 2007 $500 million credit facility, the maximum amount available to each borrower, including for issuance of letters of credit on its behalf, is limited as follows: CILCORP - $125 million, CILCO - $75 million, IP - $200 million and AERG - $100 million. CIPS and CILCO have the option of permanently reducing their borrowing authority under the 2006 $500 million credit facility and shifting, in one or more transactions, such capacity to the 2007 $500 million credit facility up to the same limits. The total borrowing authority of CIPS and CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility cannot at any time exceed $135 million and $150 million, respectively, in the aggregate. Until either CIPS or CILCO elects to increase its borrowing capacity under the 2007 $500 million credit facility and issue first mortgage bonds as security for its obligations thereunder, as described below, it will not be considered a borrower under the 2007 $500 million credit facility and will not be subject to the covenants thereof (except as a subsidiary of a borrower). The borrowing companies will use the proceeds
of any borrowings for working capital and other general corporate purposes. However, a portion of the borrowings by AERG may be limited to financing or refinancing the development, management and operation of any of its projects or assets. The 2006 and 2007 $500 million credit facilities will terminate on January 14, 2010.
The obligations of CIPS, CILCO and IP under the 2006 $500 million facility are secured by the issuance of first mortgage bonds by each such utility under its respective mortgage indenture in the amounts of $135 million, $75 million, and $150 million, respectively. The obligations of CILCO and IP under the 2007 $500 million credit facility are secured by the issuance of first mortgage bonds in the amounts of $75 million and $200 million, respectively. If either CIPS or CILCO elects to transfer borrowing authority from the 2006 $500 million credit facility to the 2007 $500 million credit facility, it must retire an appropriate amount of first mortgage bonds issued with respect to the 2006 $500 million credit facility and issue new bonds in an equal amount to secure its obligations under the 2007 $500 million credit facility. In July 2007, CILCO permanently reduced its $150 million of borrowing authority under the 2006 $500 million credit facility by $75 million and shifted that amount of capacity to the 2007 $500 million credit facility. CILCO is now considered a borrower under both credit facilities and is subject to the covenants of both. The obligations of CILCORP under both the 2006 $500 million credit facility and the 2007 $500 million credit facility are secured by a pledge of the common stock of CILCO. The obligations of AERG under both the 2006 $500 million credit facility and the 2007 $500 million credit facility are secured by a mortgage and security interest in its E.D. Edwards and Duck Creek power plants and related licenses, permits, and similar rights.
On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. As of December 31, 2008, Lehman Brothers Bank, FSB, a subsidiary of Lehman, had lending commitments of $100 million and $21 million under the $1.15 billion credit facility and the 2006 $500 million credit facility, respectively. Assuming Lehman Brothers Bank, FSB does not fund its pro-rata share of funding or letter of credit issuance requests under these two facilities, and such participations are not assigned or otherwise transferred to other lenders, total amounts accessible by the Ameren Companies and AERG will be limited to amounts not less than $1.05 billion under the $1.15 billion credit facility and $479 million under the 2006 $500 million credit facility.
Based on outstanding borrowings under the $1.15 billion credit facility and the 2007 and 2006 $500 million credit facilities (including reductions for $9 million of letters of credit issued under the $1.15 billion credit facility and unfunded Lehman participations under the $1.15 billion credit facility and the 2006 $500 million credit facility), the available amounts under the facilities at December 31, 2008, were $540 million, $415 million, and $220 million, respectively.
On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. If Ameren issues capital stock or other equity interests (except for director or employee benefit or dividend reinvestment plan purposes), or certain equity-like hybrid securities, or certain additional indebtedness in amounts exceeding $25 million, Ameren is required under the term loan agreement to use the resulting net proceeds to prepay amounts borrowed under the agreement. The lenders under the term loan agreement have waived this prepayment requirement to the extent that the net proceeds from the issuance of certain funded indebtedness are applied to repurchase or to redeem indebtedness of CILCORP. Additionally, if Ameren replaces its $1.15 billion credit facility with one or more credit facilities having a total available commitment in excess of $1.15 billion, Ameren is required under the term loan agreement to prepay amounts borrowed thereunder in an amount equal to the excess of the new commitments over $1.15 billion. Such mandatory prepayments are without premium or penalty (except for any funding indemnity due in respect of Eurodollar loans).
Borrowings under the $300 million term loan agreement will bear interest, at the election of Ameren, at (1) a Eurodollar rate plus a margin, which margin is subject to a floor of 0.90% per annum and a cap of 1.50% per annum, or (2) a rate equal to the higher of the prime rate or the federal funds effective rate plus 0.50% per year. Ameren used the proceeds borrowed under the term loan agreement to reduce amounts borrowed under the $1.15 billion credit facility, which thereby made additional amounts available for borrowing under that credit facility. The average annual interest rate for borrowing under the $300 million term loan agreement was 3.93% from its inception through December 31, 2008. The obligations of Ameren under the term loan agreement are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the term loan agreement.
On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. Borrowings under the $20 million term loan agreement will bear interest, at the election of Ameren, at (1) a rate equal to the applicable LIBOR rate plus 1.70% per annum, or (2) a rate equal to the highest of the prime rate, the federal funds effective rate plus 0.50% per annum and the applicable LIBOR rate plus 2.00% per annum. The obligations of Ameren under the $20 million term loan agreement are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the agreement.
Indebtedness Provisions and Other Covenants
The Ameren Companies’ bank credit facilities contain provisions that, among other things, place restrictions on their ability to incur liens, sell assets, and merge with other entities. The $1.15 billion credit facility contains provisions that limit total indebtedness of each of Ameren, UE and Genco to 65% of total consolidated capitalization pursuant
to a calculation defined in the facility. Exceeding these debt levels would result in a default under the $1.15 billion credit facility.
The $1.15 billion credit facility also contains provisions for default, including cross-defaults, with respect to a borrower. Defaults can result from an event of default under any other facility covering indebtedness of that borrower or certain of its subsidiaries in excess of $50 million in the aggregate. The obligations of Ameren, UE and Genco under the facility are several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS, CILCORP, CILCO, IP and AERG are not considered subsidiaries for purposes of the cross-default or other provisions.
Under the $1.15 billion credit facility, restrictions apply limiting investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries by Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries are excluded for purposes of determining compliance with the 65% total consolidated indebtedness to total consolidated capitalization financial covenant in the facility.
Both the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG limit the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. Events of default under these facilities apply separately to each borrower (and, except in the case of CILCORP, to their subsidiaries). An event of default under these facilities does not constitute an event of default under the $1.15 billion credit facility, or vice versa. In addition, if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, should receive a below-investment-grade credit rating from either Moody’s or S&P, then each such borrower will be limited to common and preferred stock dividend payments of $10 million per year while such below-investment-grade credit rating is in effect. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured long-term debt credit rating to below-investment-grade, causing it to be subject to this dividend payment limitation. No similar restriction applies to AERG, which is currently not rated by Moody’s or S&P, if its debt-to-operating- cash-flow ratio, as set forth in these facilities, is less than or equal to a 3.0 to 1.0 ratio. As of December 31, 2008, AERG failed to meet the debt-to-operating-cash-flow ratio test in the 2007 and 2006 $500 million credit facilities. AERG’s ability to pay dividends is therefore currently limited to a maximum of $10 million per fiscal year. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 $500 million or 2006 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG is currently limited by dividend restrictions at CILCORP.
The 2007 $500 million credit facility and the 2006 $500 million credit facility also limit the amount of other
secured indebtedness issuable by each borrower. For CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other debt secured by the pledge of CILCO common stock is limited (1) under the 2007 $500 million credit facility to $425 million (in addition to the principal amount of CILCORP’s outstanding senior notes and senior bonds and its obligations under the 2006 $500 million credit facility) and (2) under the 2006 $500 million credit facility to $500 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds and amounts drawn on the 2007 $500 million credit facility). For AERG, other debt secured on an equal basis with its obligations under the facilities is limited to $100 million by the 2007 $500 million credit facility (excluding amounts drawn by AERG under the 2006 $500 million credit facility) and $200 million by the 2006 $500 million credit facility. The limitations on other secured debt at CILCORP and AERG in the 2007 $500 million credit facility are subject to adjustment based on the borrowing sublimits of these entities under this facility or under the 2006 $500 million credit facility. In addition, the 2007 $500 million credit facility and the 2006 $500 million credit facility prohibit CILCO from issuing any preferred stock if, after such issuance, the aggregate liquidation value of all CILCO preferred stock issued after February 9, 2007, and July 14, 2006, respectively, would exceed $50 million.
Under the 2007 $500 million and 2006 $500 million credit facilities, each of CIPS, CILCO and IP was originally required to reserve future bonding capacity under its respective mortgage indentures (that is, it agreed to forgo the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture). On March 26, 2008, CIPS, CILCO and IP and other parties to the credit facilities entered into amendments to the credit facilities, that eliminated this requirement.
The $300 million term loan agreement entered into in June 2008 has terms similar to the $1.15 billion credit facility, except that amounts repaid under the term loan agreement may not be reborrowed. The term loan agreement also contains nonfinancial covenants, including restrictions on the ability to incur liens, dispose of assets, and merge with other entities. In addition, the term loan agreement has nonfinancial covenants to limit the ability of Ameren to invest in or transfer assets to other entities, including affiliates. The events of default under the term loan agreement, including a cross-default to the occurrence of an event of default under the $1.15 billion credit facility or any other agreement covering indebtedness of Ameren and its subsidiaries in excess of $25 million in the aggregate, are similar to those contained in the $1.15 billion credit facility. Each of CIPS, CILCORP, CILCO, IP, AERG and each of their subsidiaries is excluded from the definition of “subsidiary” under the term loan agreement and accordingly is not subject to certain of the covenants, representations, or warranties under the term loan agreement. The term loan agreement requires Ameren to maintain consolidated indebtedness of not more then 65%
of consolidated total capitalization pursuant to a calculation defined in the term loan agreement.
Under the $20 million term loan agreement entered into in January 2009, Ameren may elect, for up to three 30-day periods, to pay down and reduce to zero the outstanding principal balance. The term loan agreement also contains nonfinancial covenants, including restrictions on the ability to incur liens, dispose of assets, and merge with other entities. In addition, the term loan agreement has nonfinancial covenants to limit the ability of Ameren to invest in or transfer assets to other entities, including affiliates. The events of default under the term loan agreement, including a cross-default to the occurrence of an event of default under the $1.15 billion credit facility or any other agreement covering indebtedness of Ameren and its subsidiaries in excess of $50 million in the aggregate, are similar to those contained in the $1.15 billion credit facility. Each of CIPS, CILCORP, CILCO, IP, AERG and each of their subsidiaries is excluded from the definition of “subsidiary” under the term loan agreement and accordingly is not subject to certain of the covenants, representations, or warranties under the agreement. The term loan agreement requires Ameren to maintain a consolidated capitalization ratio of not more than 65% pursuant to a calculation defined in the agreement.
As of December 31, 2008, the ratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility for Ameren, UE and Genco were 54%, 51% and 53%, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2006 $500 million credit facility and the 2007 $500 million credit facility, were 51%, 60%, 48%, 53% and 45%, respectively. The ratio for Ameren calculated in accordance with the provisions of the $300 million term loan agreement was 54%.
None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At December 31, 2008, management believes that the Ameren Companies were in compliance with their credit facilities and term loan agreement provisions and covenants.
Money Pools
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 utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.
Utility
Through the utility money pool, the pool participants may access the committed credit facilities. CIPS, CILCO and IP borrow from each other through the utility money pool
agreement subject to applicable regulatory short-term borrowing authorizations. Ameren Services administers the utility money pool and tracks internal and external funds separately. 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 2006 $500 million and the 2007 $500 million credit facilities. 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 that the pool participants have surplus funds or contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. CIPS, CILCO and IP 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, 2008, was 2.85% (2007 - 5.80%).
Non-state-regulated Subsidiaries
Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any time is
reduced by borrowings from Ameren made 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 remit funds from other external sources. See the discussion above for the amount available under the $1.15 billion credit facility at December 31, 2008. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren’s non-state-regulated activities. 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. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2008 was 3.51% (2007 - 5.14%).
See Note 14 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the years ended December 31, 2008, 2007, and 2006.
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 pool agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million, pursuant to authorization from the ICC. IP is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for operation and administration of the agreement.
NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2008 and 2007:
(a) At December 31, 2008, most property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued. Substantially all of the long-term debt issued by UE, CIPS (excluding the tax-exempt debt), CILCO and IP is secured by a lien on substantially all of its property and franchises.
(b) These notes are collaterally secured by first mortgage bonds issued by UE, CIPS, CILCO, or IP, respectively, and will remain secured at each company until the following series are no longer outstanding with respect to that company: UE - 5.45% Series due 2028 (currently callable at 102% of par, declining to 101% of par in October 2009 and 100% of par in October 2010), 6.00% Series due 2018 and 6.70% Series due 2019; CIPS - 7.61% Series 1997-2 due 2017 (currently callable at 103.04% of par declining annually thereafter to 100% of par in June 2012) which, pursuant to a covenant contained in the 6.70% Series due 2036, may not be called in full prior to June 15, 2009; CILCO - 6.20% Series 1992B due 2012 (currently callable at 100% of par) 5.90% Series 1993 due 2023 (currently callable at 100% of par) and 8.875% Series due 2013; IP - 7.50% Series due 2009, 6.125% Series due 2017, 6.25% Series due 2018, 9.75% Series due 2018 and all IP pollution control revenue bonds.
(c) Environmental improvement or pollution control series secured by first mortgage bonds. In addition, all of the series except UE’s 5.45% Series, CILCO’s 6.20% Series 1992B, and 5.90% Series 1993 bonds are backed by an insurance guarantee policy.
(d) Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. Maximum interest rates could range up to 18% depending upon the series of bonds. The average interest rates for the years 2008 and 2007 were as follows:
(e) 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. UE has not elected to defer any interest payments.
(f) CILCORP’s long-term debt is secured by a pledge of the common stock of CILCO.
(g) These notes are subject to a revocable tender offer whereby holders may receive up to $1,057.50 and $1,230, respectively, for each $1,000 principal amount of 8.70% senior notes due 2009 and 9.375% senior bonds due 2029 tendered.
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2008:
(a) Includes $2 million of fair-market value adjustments related to CILCORP’s current maturities of long-term debt.
(b) Excludes unamortized discount and premium of $7 million, $1 million, $1 million, and $10 million at UE, CIPS, Genco, and IP, respectively.
(c) Excludes $47 million related to CILCORP’s long-term debt fair-market value adjustments.
(d) Excludes $10 million related to IP’s long-term debt fair-market value adjustments.
All of the Ameren Companies expect to fund maturities of long-term debt, short-term debt and contractual obligations through a combination of cash flow from operations and external financing. See Note 4 - Short-term Borrowings and Liquidity for a discussion of external financing availability.
The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of December 31, 2008:
(a) In November 2008, Ameren, as a well-known seasoned issuer, along with CIPS, Genco, CILCO and IP, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011.
(b) In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.
Ameren
Ameren’s acquisitions of CILCORP and IP resulted in fair value adjustments to long-term debt of $111 million and $195 million, respectively. The fair value adjustments are being amortized to interest expense over the remaining life or to the expected redemption date of each debt issuance. As of December 31, 2008, the remaining unamortized balance of the fair-market value adjustments for CILCORP and IP were $49 million and $10 million, respectively. At IP, the amortization of fair value adjustments is offset in interest expense by a related amortization of a regulatory asset. See Note 2 - Rate and Regulatory Matters for more information on the regulatory asset.
The following table presents the amortization of the CILCORP and IP fair value adjustments for the succeeding five years:
(a) Amount is less than $1 million.
In July 2008, Ameren filed a Form S-3 registration statement with the SEC authorizing the offering of six million additional shares of its common stock under the DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, 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 selling newly issued shares of common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including a subsidiary plan that has now been merged into the Ameren 401(k) plan), Ameren issued 4.0 million, 1.7 million, and 1.9 million shares of common stock in 2008, 2007, and 2006, respectively, which were valued at $154 million, $91 million, and $96 million for the respective years.
In February 2007, $100 million of Ameren’s 5.70% notes matured and were retired.
In May 2007, $250 million of Ameren’s senior notes matured and were retired.
UE
In June 2007, UE issued $425 million of 6.40% senior secured notes due June 15, 2017, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2007. These notes are secured by first mortgage bonds. UE received net proceeds of $421 million, which were used to repay short-term debt.
In connection with UE’s June 2007 issuance of $425 million of senior secured notes, UE agreed, that so long as those senior secured notes are outstanding, it will not, prior to June 15, 2012, optionally redeem, purchase or otherwise retire in full its outstanding first mortgage bonds not subject to release provisions, thus causing a first mortgage bond release date to occur. Such release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness ranking equally with any other outstanding senior unsecured indebtedness of UE. UE further agreed that the interest rate for these $425 million of senior secured notes will be subject to an increase of up to
a maximum of 2.00% if such release date occurs between June 15, 2012, and June 15, 2017 (the maturity date of the $425 million senior secured notes), and if Moody’s or S&P downgrades the rating assigned to these senior secured notes below investment grade as a result of the release within 30 days of such release (subject to extension if and for so long as the rating for such senior secured notes is under consideration for possible downgrade).
In April 2008, UE issued $250 million of 6.00% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. These notes are secured by first mortgage bonds. UE received net proceeds of $248 million, which were used to redeem certain of UE’s outstanding auction-rate environmental improvement revenue refunding bonds discussed below and to repay short-term debt. In connection with this issuance of $250 million of senior secured notes, UE agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur.
In April 2008, $63 million of UE’s Series 2000B auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.
In May 2008, $43 million of UE’s Series 1991, $64 million of UE’s Series 2000A and $60 million of UE’s Series 2000C auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest. Also, in May 2008, $148 million of UE’s 6.75% Series first mortgage bonds matured and were retired.
In June 2008, UE issued $450 million of 6.70% senior secured notes due February 1, 2019, with interest payable semiannually on February 1 and August 1 of each year, beginning in February 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $446 million, which was used to repay short-term debt. A portion of that debt had been incurred so that UE could pay at maturity the 6.75% Series first mortgage bonds noted above. In connection with this issuance of $450 million of senior secured notes, UE agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur.
CIPS
In April 2008, $35 million of CIPS’ Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.
In December 2008, $15 million of CIPS’ 5.375% senior secured notes matured and were retired.
Genco
In April 2008, Genco issued and sold, with registration rights in a private placement, $300 million of 7.00% senior unsecured notes due April 15, 2018, with interest payable semiannually on April 15 and October 15 of each year, beginning in October 2008. Genco received net proceeds of
$298 million, which is used to fund capital expenditures, to repay short-term debt, and for general corporate purposes. Genco exchanged the outstanding unregistered unsecured notes for registered unsecured notes in July 2008.
CILCORP
As discussed above, in conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was increased to fair value by $111 million. Amortization related to fair-value adjustments was $6 million, $6 million, and $6 million for the years ended December 31, 2008, 2007, and 2006, respectively, and costs related to repayments were $- million, $- million, and $2 million for the years ended December 31, 2008, 2007, and 2006, respectively. These amounts were included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.
See Note 4 - Short-term Borrowings and Liquidity regarding CILCORP’s pledge of the common stock of CILCO as security for its obligations under the 2006 $500 million credit facility and the 2007 $500 million credit facility.
In September 2008, CILCORP commenced a cash tender offer for any and all of its outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal amount) and its 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount), collectively, the “notes.” Concurrent with the tender offer, CILCORP solicited consents from the holders of the notes to certain proposed amendments to the indenture governing these securities. Any holder tendering securities as part of this offer is deemed to consent to the proposed amendments. No consents will be accepted separate from a tender of such holder’s securities. The amendments would eliminate certain restrictive covenants in the indenture and the notes. The total consideration for each $1,000 principal amount of 2009 notes validly tendered on or prior to the current consent and expiration date, which has been extended to April 30, 2009, is $1,057.50. The total consideration includes a consent payment of $40 per $1,000 principal amount of such 2009 notes tendered on or prior to such date. The total consideration for each $1,000 principal amount of 2029 bonds validly tendered on or prior to the current April 30, 2009, consent and expiration date is $1,230, which includes a consent payment of $50 per $1,000 principal amount of such 2029 bonds tendered on or prior to such date. Holders validly tendering and not withdrawing notes on or before the extended consent and expiration date are eligible to receive the applicable total consideration. In addition, tenders of notes, including previously tendered notes, may be withdrawn (and related consents may be rescinded) at any time prior to April 30, 2009. As of January 28, 2009, CILCORP had received consents, net of those rescinded, from the holders of $121.3 million, or 98.0%, of its outstanding 2009 8.70% senior notes and $206.6 million, or 98.1%, of its outstanding 2029 bonds. Consummation of the tender offer and the consent solicitation is subject to a number of conditions, including the absence of certain adverse legal
and market developments, as described in the offer to purchase. CILCORP has reserved the right to amend, further extend, terminate, or waive any conditions to the tender offer and the consent solicitation at any time. The impact on CILCORP’s net income of the tender offer is expected to be approximately $3 million, if consummated.
CILCO
In July 2007, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2007.
In April 2008, $19 million of CILCO’s Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.
In July 2008, CILCO redeemed the remaining 165,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption completed CILCO’s mandatory redemption obligations for this series of preferred stock.
In December 2008, CILCO issued $150 million of 8.875% senior secured notes due December 15, 2013, with interest payable semiannually on June 15 and December 15 of each year, beginning in June 2009. These notes are secured by first mortgage bonds. CILCO received net proceeds of $149 million, which were used to repay short-term debt. In connection with this issuance of $150 million of senior secured notes, CILCO agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under CILCO’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.
IP
As discussed above, 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 $13 million for the year ended December 31, 2006, and was included in interest expense in the consolidated statements of income of Ameren and IP. Beginning in 2007, the amortization related to fair value adjustments was recoverable in rates and a regulatory asset was established. See Note 2 - Rate and Regulatory Matters for more information.
In November 2007, IP issued and sold, with registration rights in a private placement, $250 million of 6.125% senior secured notes due November 15, 2017, with interest payable semiannually on May 15 and November 15 of each year, beginning in May 2008. These notes are
secured by mortgage bonds, which are subject to fallaway provisions as defined in the related financing agreements. IP received net proceeds of $248 million, which were used to repay short-term debt. IP exchanged the outstanding unregistered secured notes for registered secured notes in April 2008.
In April 2008, IP issued and sold, with registration rights in a private placement, $337 million of 6.25% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. IP received net proceeds of $334 million, which were used to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds during May and June 2008, as discussed below. In connection with IP’s April 2008 issuance of $337 million of senior secured notes, IP agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under IP’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness. IP exchanged the outstanding unregistered secured notes for registered secured notes in June 2008.
In May 2008, IP redeemed its $112 million Series 2001 Non-AMT, $75 million Series 2001 AMT, $70 million 1997
Series A, and $45 million 1997 Series B auction-rate pollution control revenue bonds at par value plus accrued interest. In June 2008, IP redeemed its $35 million 1997 Series C auction-rate pollution control revenue bonds at par value plus accrued interest.
In September 2008, IP redeemed the remaining portion of its $54 million principal amount 5.65% note payable to IP SPT. Previous redemptions occurred in the first and second quarters of 2008 for $19 million and $20 million, respectively. This was the remaining outstanding amount of $864 million of TFNs issued by the IP SPT in December 1998, as allowed under the Illinois Electric Utility Transition Funding Law.
In October 2008, IP issued and sold, with registration rights in a private placement, $400 million of 9.75% senior secured notes due November 15, 2018, with interest payable semiannually on November 15 and May 15 of each year, beginning in May 2009. IP received net proceeds of $391 million, which were used to repay short-term debt. In connection with IP’s October 2008 issuance of $400 million of senior secured notes, IP agreed that, so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur. In February 2009, IP commenced an offer to exchange the outstanding unregistered secured notes for registered secured notes.
Indenture Provisions and Other Covenants
UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain ratios to issue first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended December 31, 2008, at an assumed interest and dividend rate of 8%.
(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on meeting required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $161 million, $18 million, $44 million and $286 million, at UE, CIPS, CILCO and IP, respectively.
(c) Coverage required on the annual interest charges on all long-term debt (CIPS only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance.
(d) In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all mortgage bonds outstanding and to be issued. For the 12 months ended December 31, 2008, CILCO had earnings equivalent to at least 31% of the principal amount of all mortgage bonds outstanding.
(e) See Note 4 - Short-term Borrowings and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility.
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 $1.8 billion of free and unrestricted retained earnings at December 31, 2008.
CILCO’s articles of incorporation contain certain provisions that prohibit the payment of dividends on its common stock (1) from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock, or (2) if at the time of dividend declaration, there shall not remain to the credit of earned surplus account (after deducting the amount of such dividends) an amount at least equal to two times the annual dividend requirement on all outstanding shares of CILCO’s preferred stock.
Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and/or debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to or investments in affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended December 31, 2008:
(a) Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt-to-capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters.
(b) Ratio excludes amounts payable under Genco’s intercompany note to CIPS. The ratio must be met both for the prior four fiscal quarters and for the succeeding four six-month periods.
(c) CILCORP must maintain the required interest coverage ratio and debt-to-capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than direct or indirect subsidiaries.
Genco’s debt incurrence-related ratio restrictions and restricted payment limitations under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. Even if CILCORP is not in compliance with these restrictions, CILCORP may still make 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. At December 31, 2008, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, and BBB-, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.
In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2008, 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 6 - OTHER INCOME AND EXPENSES
The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended December 31, 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, and emission allowances. Price fluctuations in natural gas, fuel, and electricity may cause any of the following:

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

market values of fuel and natural gas inventories or purchased power that differ from the cost of those commodities in inventory; or

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for 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 that 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
these do not qualify for hedge accounting or the normal purchase and normal sales exceptions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.
Accordingly, such contracts are recorded at fair value. Changes in the fair value are charged or credited to the income statement in the period in which the change occurs. 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 the pretax net gain (loss) for the years ended December 31, 2008, 2007 and 2006, of power hedges included in Operating Revenues - Electric. This pretax net gain (loss) represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI for transactions that have since been delivered or settled:
(a) Includes amounts from Ameren registrants and non-registrant subsidiaries.
Other Derivatives
The following table represents the net change in market value for the years ended December 31, 2008, 2007 and 2006, of option and swap transactions used to manage
our positions in SO2 allowances, coal, heating oil, FTRs and power. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The net changes in the market value of nonhedge power and gas transactions are recorded in Operating Revenues - Electric, and Operating Revenues - Gas, while the net changes in the market value of coal, heating oil, and SO2 options and swaps is recorded as Operating Expenses - Fuel.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
During the third quarter ended September 30, 2008, UE entered into foreign currency forward contracts. These derivative instruments are intended to fix the amount of U.S. dollars UE will pay for future equipment deliveries denominated in euros as part of a firm commitment to purchase heavy forgings, which would be used in building a second nuclear unit. These forward contracts qualify as fair value hedges and, as a result, both the derivative positions and the foreign currency exposure on the firm commitment are recorded at fair value. Changes in the fair value of both the derivative instrument and the hedged item are recorded in earnings. For the year ended December 31, 2008, this hedging program was highly effective, resulting in no impact to net income.
The following table presents the carrying value of all derivative instruments and the amount of pretax net gains (losses) on derivative instruments in Accumulated OCI, regulatory assets, or regulatory liabilities, at December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes Ameren’s and UE’s carrying value of fair value foreign currency forward contracts.
(c) Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including $123 million and $39 million in 2009 at Ameren and UE, respectively.
(d) Includes 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. The carrying value at December 31, 2008 was $2 million.
(e) Includes a loss associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance. The cumulative gain and loss on the interest rate swaps will be amortized over a 10-year period that began in April 2008. The carrying value at December 31, 2008, was $13 million.
(f) Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through October 2012 at UE, through March 2013 at CIPS and IP, and through March 2012 at CILCORP and CILCO.
(g) Current losses deferred as regulatory assets of $14 million at CIPS, $7 million at CILCO, and $21 million at IP that were recorded in other current assets at December 31, 2008. Current gains deferred as regulatory liabilities include $2 million at CIPS, $1 million at CILCO, and $2 million at IP that were recorded in other current liabilities at December 31, 2007.
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments being accounted for as cash flow hedges at the Ameren Illinois Utilities and Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments are eliminated. See Note 2 - Rate and Regulatory Matters for additional information on these financial contracts.
Derivative instruments are subject to various credit- related losses in the event of nonperformance by
counterparties to the contracts. In order to mitigate these risks, collateral requirements are established. As of December 31, 2008, Ameren, UE, CIPS, CILCORP, CILCO and IP had collateral postings with external parties of $109 million, $15 million, $26 million, $16 million, $16 million, and $36 million, respectively. The amount of collateral external counterparties posted with Ameren was $7 million at December 31, 2008. The amounts of collateral external counterparties posted with UE, CIPS, CILCORP, CILCO, and IP were immaterial at December 31, 2008. See Note 14 - Related Party Transactions for information regarding collateral postings with affiliates.
On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. On October 21, 2008, Ameren sent notice to Lehman
Commodity Services terminating all transactions between Genco, UE, and Marketing Company and Lehman Commodity Services. As of December 31, 2008, Ameren’s and its subsidiaries’ direct exposure to Lehman Commodity Services, based on existing transactions and current market prices, was estimated to be less than $1 million before taxes, collectively.
NOTE 8 - FAIR VALUE MEASUREMENTS
SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. The Ameren Companies adopted SFAS No. 157 as of the beginning of their 2008 fiscal year for financial assets and liabilities and as of the beginning of their 2009 fiscal year for nonfinancial assets and liabilities, except those already reported at fair value on a recurring basis. The impact of the adoption of SFAS No. 157 for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities primarily include exchange-traded derivatives and assets including U.S. treasury securities and listed equity securities, such as those held in UE’s Nuclear Decommissioning Trust Fund.
Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in UE’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas swaps and financial power transactions. Derivative instruments classified as Level 2 are valued using corroborated observable inputs, such as pricing services or prices from similar instruments
that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.
Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between the Ameren Illinois Utilities and Marketing Company as part of the Illinois electric settlement agreement. We value Level 3 instruments using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, a review of all sources is performed to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to SFAS No. 157. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). SFAS No. 157 also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded $5 million in losses in the fourth quarter of 2008 related to valuation adjustments for counterparty default risk. At December 31, 2008, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $(1) million, $- million, $9 million, $6 million, and $16 million for Ameren, UE, CIPS, CILCORP/CILCO and IP, respectively.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes ($8) million of receivables, payables, and accrued income, net.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 31, 2008:
(a)
Net gains and losses on power options are recorded in Operating Revenues - Electric, while net gains and losses on coal, heating oil, and SO2 options and swaps are recorded as Operating Expenses - Fuel.
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable on electronic exchanges compared with previous periods for the year ended December 31, 2008. Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.
The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issues for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
NOTE 9 - NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
UE has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway nuclear plant. See Note 16 - Callaway Nuclear Plant for further information. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 2008, and 2007.
Investments by the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities with the balance invested in fixed-income securities. Due to recent market conditions, the equity securities weighting was below targeted levels at December 31, 2008. In January 2009, UE rebalanced its investments to align with its targeted equity securities weighting.
The following table presents proceeds from the sale of investments in UE’s nuclear decommissioning trust fund and the gross realized gains and losses on those sales for the years ended December 31, 2008, 2007 and 2006:
Net realized and unrealized gains and losses are reflected in regulatory assets or regulatory liabilities 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. See Note 2 - Rate and Regulatory Matters.
The following table presents the costs and fair values of investments in debt and equity securities in UE’s nuclear decommissioning trust fund at December 31, 2008 and 2007:
(a) Represents payables relating to pending security purchases, net of receivables related to pending securities sales and interest receivables.
The following table presents the costs and fair values of investments in debt securities in UE’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2008:
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund, recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for our nuclear facility expires. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in UE’s nuclear decommissioning trust fund. They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2008:
NOTE 10 - STOCKHOLDER RIGHTS PLAN AND PREFERRED STOCK
Stockholder Rights Plan
In 1998, Ameren’s board of directors adopted a share purchase rights plan designed to assure stockholders of fair and equal treatment in the event of a proposed takeover. The rights were exercisable only if a person or group acquired 15% or more of Ameren’s outstanding common stock or announced a tender offer that would result in ownership by a person or group of 15% or more of the Ameren common stock. Ameren’s stockholder rights plan expired on October 9, 2008, and Ameren’s Board of Directors decided not to renew it.
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 of $1 par value preference stock authorized and CILCO has 2 million shares of no par value preference stock authorized, with no such preference stock outstanding. IP has 5 million shares of no par value serial preferred stock authorized and 5 million shares of no par value preference stock authorized, 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. The preferred stock is entitled to cumulative dividends and is redeemable, at the option of the issuer, at the prices presented as of December 31, 2008 and 2007:
(a) In the event of voluntary liquidation, $105.50.
(b) Declining to $100 per share in 2012.
NOTE 11 - RETIREMENT BENEFITS
We offer 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.
We adopted the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R),” effective December 31, 2006. SFAS No. 158 requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, as an asset or liability in their balance sheets. Employers must also recognize as a component of OCI, net
of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. Upon adoption of this provision, Ameren recorded the unfunded obligation of its defined benefit and postretirement benefit plans. The unfunded obligation is the difference between plan assets and the projected benefit obligation for defined benefit plans or accumulated postretirement benefit obligation for postretirement benefit plans. Ameren’s adoption of SFAS No. 158 resulted in increases (decreases) to Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s, and IP’s accrued pension and other postretirement benefits of $406 million, $234 million, $95 million, $36 million, $(51) million, $55 million, and $(8) million, respectively. UE, CIPS, CILCO and IP recorded regulatory assets of $270 million, $108 million, $63 million, and $205 million, respectively, based on the expected recovery of these costs from ratepayers. The adoption of SFAS No. 158 had no
material impact on accumulated other comprehensive income at Ameren. CILCORP and IP recognized gains in accumulated other comprehensive income of $29 million and $5 million, respectively, net of taxes, as a result of SFAS No. 158 obligations being reduced from those previously recognized. Genco and CILCO recorded a charge to accumulated other comprehensive income of $25 million and $2 million, respectively, net of taxes.
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 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 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. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets.
Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Taking into consideration our assumptions at December 31, 2008, the investment performance in 2008, and our pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 61%, 6%, 10%, 9%, and 14%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the benefit liability recorded in the balance sheets of each of the Ameren Companies as of December 31, 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The following table presents the funded status of our pension and postretirement benefit plans for the years ended December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Not applicable.
Ameren’s current reconciliation of funded status shows certain amounts that will be recognized as a benefit cost in future years. The unrecognized loss in postretirement benefits is largely a result of declining discount rates over the past several years and market losses on plan assets.
No plan assets are expected to be returned to Ameren during 2009.
The market value of plan assets in 2008 declined by 7% and 26% for the pension and postretirement benefit plans, respectively. In 2008, investment losses in Ameren’s pension plan were partially offset by a gain on interest rate swaps, which had a notional value of $700 million at December 31, 2008. The swaps were intended to mitigate the impacts on the funded status of the plan resulting from decreases in the discount rate in the calculation of the pension liability. During 2008, U.S. Treasury yields declined significantly, resulting in Ameren’s pension plan recognizing a $336 million net gain from its interest rate swaps. Ameren closed its interest rate swap position in early 2009. Ameren’s postretirement benefit plan did not have a similar interest rate hedge.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2008 and 2007:
The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts and to our postretirement plans during 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Ameren determines the discount rate assumptions by using an interest rate yield curve to make judgments pursuant to EITF No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of Postretirement Benefit Plans Other Than Pensions.” The yield curve is based on the yields of more than 300 high-quality, noncallable corporate bonds with maturities between zero and 30 years. A theoretical spot-rate curve constructed from this yield curve is then used as a guide to develop a discount rate matching the plans’ payout structure.
In determining the current year market-related asset value, the prior-year market-related value of assets is adjusted by contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years.
The following table presents our target allocations for 2009 and our pension and postretirement plan asset categories as of December 31, 2008 and 2007. Ameren’s pension plan debt security weighting was at the high end of the target allocation range at the end of 2008. Due to current market conditions, Ameren expects the debt security weighting will remain near the high end of the target allocation range in 2009.
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans during 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2009 are as follows:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries
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 loss subject to amortization is amortized on a straight-line basis over 10 years.
UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, are as follows:
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2008, 2007 and 2006:
(a) The Ameren Companies will utilize an expected return on plan assets of 8% in 2009.
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren plan covered all eligible employees of the Ameren Companies at December 31, 2008. The plans allowed employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren matched a percentage of the employee contributions up to certain limits. Ameren’s matching contributions to the 401(k) plan totaled $23 million, $21 million, and $19 million in 2008,
2007, and 2006, respectively. Prior to February 1, 2008, CIPS employees represented by IBEW Local 702 were covered by a separate 401(k) plan. The CIPS-related 401(k) plan was merged into the Ameren plan effective February 1, 2008. CIPS’ matching contributions to the CIPS-related 401(k) plan were less than $1 million annually in 2008, 2007 and 2006.
The following table presents the portion of the 401(k) matching contribution to the Ameren plan for each of the Ameren Companies for the years ended December 31, 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 12 - STOCK-BASED COMPENSATION
Ameren’s long-term incentive plan for eligible employees, called the Long-term Incentive Plan of 1998 (1998 Plan), was replaced prospectively by the 2006 Omnibus Incentive Compensation Plan (2006 Plan) effective May 2, 2006. The 2006 Plan provides for a maximum of 4 million common shares to be available for grant to eligible employees and directors. No new awards may be granted under the 1998 Plan; however, previously granted awards continue to vest or to be exercisable in accordance with their original terms and conditions. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.
A summary of nonvested shares as of December 31, 2008, and changes during the year ended December 31, 2008, under the 1998 Plan and the 2006 Plan are presented below:
(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in February 2008 under the 2006 Plan.
(b) Includes share units granted in 2006 that were not earned based on performance provisions of the awarded grants.
(c) Includes share units granted in 2006 that vested as of December 31, 2008, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.
Ameren recorded compensation expense of $22 million, $18 million, and $11 million for the years ended December 31, 2008, 2007, and 2006, respectively, and a related tax benefit of $8 million, $7 million, and $4 million for the years ended December 31, 2008, 2007, and 2006, respectively. As of December 31, 2008, total compensation cost of $13 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 19 months.
Performance Share Units
Performance share unit awards were granted under the 1998 Plan and the 2006 Plan from 2006 to 2008. With these awards, a share unit will vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has achieved certain performance goals and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit will vary from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. When a share unit awarded from 2006 to 2008 vests, Ameren will issue the related shares to the
employee two years after vesting, but dividends on the shares will be paid to the employee at the same time they are paid to other shareholders.
The fair value of each share unit awarded in February 2008 under the 2006 Plan was determined to be $32.35, based on Ameren’s closing common share price of $44.30 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 2.264%, dividend yields of 2.3% to 5.4% for the peer group, volatility of 14.43% to 21.51% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.
The fair value of each share unit awarded in February 2007 under the 2006 Plan was determined to be $59.60. That figure was based on Ameren’s closing common share price of $53.99 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant
assumptions used to calculate fair value also included a three-year risk-free rate of 4.735%, dividend yields of 2.3% to 5.2% for the peer group, volatility of 12.91% to 18.33% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.
Restricted Stock
Restricted stock awards in Ameren common stock were granted under the 1998 Plan from 2001 to 2005. Restricted shares have the potential to vest over a seven-year period from the date of grant if the company achieves certain performance levels. An accelerated vesting provision included in this plan reduces the vesting period from seven years to three years if the earnings growth rate exceeds a prescribed level.
Stock Options
Ameren
Options in Ameren common stock were granted under the 1998 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 they permit accelerated exercising upon the occurrence of certain events, including retirement. There have not been any stock options granted since December 31, 2000. Outstanding options of 85,800 at December 31, 2008, expire on various dates through 2010. There is no expense from stock options for the years ended December 31, 2008, 2007 and 2006, as all options granted were fully vested.
NOTE 13 - INCOME TAXES
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, 2008, 2007 and 2006:
(a) Permanent items are treated differently for book and tax purposes and primarily include Internal Revenue Code Section 199 production activity deductions for Ameren, UE, Genco, CILCORP and CILCO, company-owned life insurance for Ameren, CILCORP and CILCO, SFAS No. 106-2 Medicare Part D for Ameren, UE, Genco, CILCORP and CILCO, employee stock ownership plan dividends for Ameren, and nondeductible expenses for IP.
(b) Primarily includes settlements with state taxing authorities for Ameren, state apportionment changes for Ameren, CIPS, Genco, CILCORP, and CILCO, research credits for Ameren, Genco, CILCORP, and CILCO and low-income housing tax credits for Ameren and CIPS.
(c) Primarily includes low-income housing tax credits for Ameren, UE, CIPS, Genco, CILCORP, and IP.
(d) The 2006 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from tax benefits from permanent effects of company-owned life insurance ($1 million), Internal Revenue Code Section 199 production activity deductions ($1 million), plant-related depreciation differences ($2 million), investment tax credit amortization ($1 million), adjustments to reserves for uncertain tax positions ($6 million), reconciliation of tax return to accrual ($2 million), leveraged leases ($1 million) and state tax impact of $1 million.
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes $3 million, $5 million, $24 million, $15 million, and $15 million as current assets recorded in the balance sheets for UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $4 million and $15 million as current liabilities recorded in the balance sheets for Ameren and Genco, respectively.
(c) Includes $61 million, $21 million, $8 million, $17 million, $7 million and $13 million as current assets recorded in the balance sheets for Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $7 million as current liabilities recorded in the balance sheet for Genco.
Ameren, CILCORP and IP have Illinois net operating loss carryforwards of $15 million, $11 million, and $4 million, respectively. These will begin to expire in 2019.
On February 20, 2009, the Illinois Supreme Court handed down its decision in Exelon Corporation v. The Department of Revenue, which concluded that an electric utility in Illinois qualifies for the Illinois investment tax credit. The decision in the case may have implications for the Ameren Companies’ income, sales, and use taxes. The Ameren Companies are assessing the impact the decision may have on their results of operations, financial position or liquidity.
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of SFAS No. 109 (FIN 48)
On January 1, 2007, the Ameren Companies adopted the provisions of FIN 48, which addresses the determination of whether tax benefits claimed or expected to be claimed on an income tax return should be recorded in the financial statements.
A reconciliation of the change in the unrecognized tax benefit balance from January 1, 2007, to December 31, 2008, is as follows:
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest expense (income) and penalties accrued on tax liabilities on a pretax basis as interest expense (income) or miscellaneous expense in the statements of income. Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis.
A reconciliation of the change in the liability (receivable) for interest on unrecognized tax benefits from January 1, 2007, to December 31, 2008, is as follows:
As of January 1, 2007, December 31, 2007, and December 31, 2008, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.
Ameren is currently under U.S. federal income tax examination by the Internal Revenue Service for years 2005, 2006, and 2007. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not now have material state income tax issues under examination, administrative appeals, or litigation.
It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their financial condition or results of operations.
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.
Illinois Electric Settlement Agreement
As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco, and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At December 31, 2008, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $1 million, less than $1 million, and $1 million, respectively. Also at December 31, 2008, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million, less than $1 million, and $1 million, respectively. During the year ended December 31, 2008, Genco incurred charges to earnings of $17 million for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $6 million, CILCO - $3 million, IP - $8 million), and AERG incurred charges to earnings of $8 million (CIPS - $3 million, CILCO - $1 million, and IP - $4 million). The Ameren Illinois Utilities recorded most of the reimbursements received from Genco and AERG as electric revenue with an immaterial amount recorded as miscellaneous revenue.
Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. These financial contracts are derivative instruments being accounted for as cash flow hedges at the Ameren Illinois Utilities and Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value
in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. Below are the contracted volumes and prices per megawatthour.
Electric Power Supply Agreements
The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the years ended December 31, 2008, 2007, and 2006:
(a) These agreements expired or terminated on December 31, 2006.
(b) In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and all the associated energy commencing on January 1, 2007.
(c) Marketing Company contracted with CIPS, CILCO, and IP to provide power based on the results of the Illinois reverse auction in September 2006. The values in this table reflect the physical sales volumes provided in that agreement.
In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco agreed to sell and Marketing Company agreed to purchase all of the capacity available from Genco’s generation fleet and all the associated energy. On March 28, 2008, Genco and Marketing Company entered into an amendment of the Genco PSA. Under the amendment, Genco is liable to Marketing Company in the event of an unplanned outage or derate (reduction in rated capacity) due to sudden, unanticipated failure or accident within the generating plant site of one or more of its generating units. Genco’s liability in such case will be for the positive difference, if any, between the market price of capacity and/or energy Genco does not deliver and the contract price under the Genco PSA for that capacity and/or energy. Genco has insurance with an affiliate company that covers many, but not all, of these situations, subject to deductibles and policy limits. An unplanned outage or derate that continues for one year or more is an event of
default under the Genco PSA. In the event of Marketing Company’s unexcused failure to receive energy under the Genco PSA, Marketing Company would be required to pay Genco the positive difference, if any, between the contract price and the price actually received by Genco, acting in a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.
Also in December 2006, AERG and Marketing Company entered into a power supply agreement (AERG PSA) whereby AERG agreed to sell and Marketing Company agreed to purchase all of the capacity available from AERG’s generation fleet and all the associated energy. On March 28, 2008, AERG and Marketing Company entered into an amendment of the AERG PSA that is substantially identical to the amendment to the Genco PSA described above. Under the amendment, AERG is liable to Marketing Company in the event of an unplanned outage or derate due to sudden, unanticipated failure or accident within the generating plant site of one or more of its generating units. AERG’s liability in such case will be for the positive difference, if any, between the market price of capacity and/or energy AERG does not deliver and the contract price under the AERG PSA for that capacity and/or energy. AERG has insurance with an affiliate company that covers many, but not all of these situations, subject to deductibles and policy limits. An unplanned outage or derate that continues for one year or more is an event of default under the AERG PSA. In the event of Marketing Company’s unexcused failure to receive energy under the AERG PSA, Marketing Company would be required to pay AERG the positive difference, if any, between the contract price and the price actually received by AERG, acting in a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.
Both the Genco PSA and the AERG PSA will continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement by providing the other party with no less than six months advance written notice.
In accordance with a January 2006 ICC order, an auction was held in September 2006 to procure power for CIPS, CILCO and IP beginning January 1, 2007. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for residential and small commercial customers (less than one megawatt of demand) as follows:
(a) Before impact to Ameren Illinois Utilities’ load due to customer switching.
One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers, and all of the
supply contracts that served large commercial and industrial customers, expired on May 31, 2008. To replace these expired supply contracts, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the Illinois electric settlement agreement, to contract for the necessary energy and capacity requirements for the period from June 1, 2008, through May 31, 2009. Marketing Company was one of the winning suppliers in the Ameren Illinois Utilities’ energy and capacity RFPs. Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities will pay for about two million megawatthours at approximately $60 per megawatthour. Marketing Company contracted to supply a portion of the Ameren Illinois Utilities’ capacity for $6 million. In addition, UE contracted to supply a portion of the Ameren Illinois Utilities’ capacity for $1 million.
Separately, the Ameren Illinois Utilities used an RFP process to procure ancillary services for 2007 and 2008 required to maintain reliable operation of their transmission systems. Both UE and Marketing Company were among the winning suppliers in both years’ ancillary services RFPs. In January 2009, the Ameren Illinois Utilities began procuring ancillary services from the MISO ancillary services market.
On June 1, 2008, FERC accepted an electric resource sharing agreement among the Ameren Illinois Utilities for various joint costs of the Ameren Illinois Utilities, including capacity, renewable energy credits, and rate swaps. The purpose of the agreement is to allocate these costs among the Ameren Illinois Utilities in an equitable manner, based on their respective retail loads.
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, and CILCO and CIPS, are parties to similar interconnection agreements. These agreements have no contractual expiration date, but may be terminated by any party with three years’ notice.
Generator Interconnection Agreement
In 2008, Genco and CIPS signed an agreement requiring Genco to fund the construction costs of upgrades to CIPS’ transmission system. The transmission upgrades are required to support the additional electric power upgrades being made at Genco’s Coffeen power plant. Under the agreement, Genco will pay CIPS for the costs of the transmission upgrades. When the transmission assets are placed in service, CIPS will be required to repay Genco, with interest, for the costs of the transmission upgrades. At December 31, 2008, CIPS had recorded $2 million in Other Deferred Credits and Liabilities and Genco had recorded $2 million in Accounts Receivable - Affiliates. These transactions were eliminated in consolidation on Ameren’s financial statements.
Joint Dispatch Agreement
Prior to December 31, 2006, UE and Genco dispatched electric generation under a joint dispatch agreement among UE, CIPS and Genco. UE and Genco had the option to serve their load requirements from their own generation first, and then each could give its affiliates access to any available generation at incremental cost. Any excess generation not used by UE or Genco to serve load requirements was sold to third parties on a short-term basis. To allocate power costs between UE and Genco, an intercompany sale was recorded by the company providing the power. By mutual consent of UE, CIPS, and Genco, the JDA was terminated on December 31, 2006.
The following table presents the amount of gigawatthour sales under the JDA during the year ended December 31, 2006:
The following table presents the short-term power sales margins under the JDA for UE and Genco during the year ended December 31, 2006:
Support Services Agreements
Costs of support services provided by Ameren Services, AFS, and Ameren Energy, Inc., until December 31, 2007, to their affiliates, including wages, employee benefits, professional services, and other expenses are based on, or are an allocation of, actual costs incurred. Ameren Energy, Inc. was dissolved on December 31, 2007.
Executory Tolling, Gas Sales, and Transportation Agreements
Under an executory tolling agreement, CILCO purchased steam, chilled water, and electricity from Medina Valley. In January 2009, CILCO transferred the tolling agreement to Marketing Company. In connection with the tolling agreement, Medina Valley purchases gas to fuel its generating facility from AFS under a fuel supply and services agreement.
Under a gas transportation agreement, Genco acquires gas transportation service from UE for its Columbia, Missouri, CTs. This agreement expires in February 2016.
Transitional Funding Securitization Financing Agreement
See Note 1 - Summary of Significant Accounting Policies for further information. In 2008, the TFNs were redeemed.
Money Pools
See Note 5 - Long-term Debt and Equity Financings for discussion of affiliate borrowing arrangements.
Intercompany Borrowings
Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. On May 1, 2005, Genco issued to CIPS an amended and restated subordinated promissory note in the principal amount of $249 million with an interest rate of 7.125% per year. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $7 million, $10 million, and $12 million for the years ended December 31, 2008, 2007, and 2006, respectively.
CILCORP had outstanding borrowings directly from Ameren of $152 million and $2 million, at December 31, 2008 and 2007, respectively. The average interest rate on these borrowings was 3.6% for the year ended December 31, 2008 (2007 - 5.14%). CILCORP recorded interest expense of $1 million, less than $1 million, and $7 million for Ameren borrowings for the years ended December 31, 2008, 2007, and 2006, respectively.
UE had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. The average interest rate on these borrowings was 3.6% for the year ended December 31, 2008. UE recorded interest expense of $1 million, $4 million, and $1 million for Ameren borrowings for the years ended December 31, 2008, 2007, and 2006, respectively.
At December 31, 2007, UE held a $30 million intercompany note receivable from its wholly owned subsidiary, Union Electric Development Corporation. This note was transferred to Ameren Development Company from Union Electric Development Corporation in connection with the merger discussed below under Intercompany Transfers. The note was paid off in November 2008. The average interest rate on this note while outstanding during 2008 was 5.17%. UE recorded interest revenue of $2 million for this note for the year ended December 31, 2008.
Collateral Postings
Under the terms of the power supply agreements between Marketing Company and the Ameren Illinois Utilities, which were entered into as part of the September 2006 Illinois power procurement auction, cash collateral must be posted by Marketing Company under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance by Marketing Company. The collateral postings are unilateral, meaning that Marketing Company as the supplier is the only counterparty required to post collateral. At December 31, 2008, there were no collateral postings by Marketing Company related to the 2006 auction power supply agreements, and at December 31, 2007, Marketing Company had posted $1 million, less than $1 million, and $1 million for the benefit of CIPS, CILCO, and IP, respectively.
In addition, under the terms of the 2008 Illinois power procurement RFPs, cash collateral must be posted by Marketing Company and the Ameren Illinois Utilities under certain market conditions. The collateral postings are bilateral, meaning that either counterparty may be required to post collateral. As of December 31, 2008, the Ameren Illinois Utilities had cash collateral postings as follows with Marketing Company: CIPS - $7 million, CILCO - $4 million, and IP - $11 million. These bilateral collateral postings were eliminated in consolidation on Ameren’s financial statements.
Operating Leases
Under an operating lease agreement, Genco leased certain CTs at a Joppa, Illinois, site to its former parent, Development Company, for an initial term of 15 years, expiring September 30, 2015. Genco recorded operating revenues from the lease agreement of $2 million, $11 million, and $11 million for the three years ended December 31, 2008, 2007, and 2006, respectively. Under an electric power supply agreement with Marketing Company, Development Company supplied the capacity and energy from these leased units to Marketing Company, which in turn supplied the energy to Genco. By mutual
agreement of the parties, this lease agreement and this power supply agreement were terminated in February 2008, when an internal reorganization merged Development Company into Resources Company.
Intercompany Transfers
On January 1, 2008, UE transferred its interest in Union Electric Development Corporation at book value to Ameren by means of a $3 million dividend-in-kind. On March 31, 2008, Union Electric Development Corporation was merged into Ameren Development Company, with Ameren Development Company surviving the merger.
On February 29, 2008, UE contributed its entire 40% ownership interest in EEI, book value of $39 million, to Resources Company, in exchange for a 50% interest in Resources Company, and then immediately transferred its interest in Resources Company to Ameren by means of a $39 million dividend-in-kind. Also on February 29, 2008, Development Company, which formerly held a 40% ownership interest in EEI, merged into Ameren Energy Resources Company, which then merged into Resources Company. As a result, Resources Company now has an 80% ownership interest in EEI and consolidates it accordingly.
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the years ended December 31, 2008, 2007 and 2006. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 - Short-term Borrowings and Liquidity.
(a) Amounts represent CILCORP and CILCO activity.
(b) Not applicable.
(c) Represents ancillary services to the Ameren Illinois Utilities in 2007 and 2008 and capacity to the Ameren Illinois Utilities beginning in June 2008.
(d) Represents power supply costs under agreements entered into as part of the Illinois September 2006 auction and the 2008 energy and capacity RFPs.
(e) Amount less than $1 million.
(f) Ameren Energy, Inc. was eliminated December 31, 2007, through an internal reorganization.
(g) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
NOTE 15 - COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, 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 a material adverse effect on our results of operations, financial position, or liquidity.
See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions and Note 16 - Callaway Nuclear Plant in this report.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2008. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.
(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under Price-Anderson. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. 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.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 - Related Party Transactions for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of 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.
After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
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 unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.
Leases
The following table presents our lease obligations at December 31, 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) See Properties under Part I, Item 2 of this report for further information.
(c) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. Ameren’s $2 million annual obligation for these items is 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 because that period is indefinite.
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. We also have capital leases relating to UE’s Peno Creek and Audrain County CT facilities. The following table presents total rental expense, included in other operations and maintenance expenses, for the years ended December 31, 2008, 2007 and 2006:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
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. We also have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. The following table presents the estimated fuel, electric capacity, and natural gas commitments at December 31, 2008. In addition, the following table presents in the Other column minimum purchase commitments for heavy forgings contracts related to a potential second nuclear unit, meter reading contracts, and an Ameren tax credit obligation. Ameren’s tax credit obligation is a $75 million note payable issued for an investment in a low-income real estate development partnership to acquire New Markets Tax Credits. This note payable was netted against the related investment in Other Assets at December 31, 2008, as Ameren has a legally enforceable right to offset it under FIN 39.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Commitments for natural gas and nuclear fuel are until 2021 and 2020, respectively.
(c) At December 31, 2008, less than $1 million of electric capacity contracts were executed for the Ameren Illinois Utilities for 2009 with approximately 33% of the capacity resources dedicated to CIPS, 17% to CILCO, and 50% to IP. For 2009, approximately one-third of the Ameren Illinois Utilities capacity was obtained through the Illinois power procurement auction. The IPA plans to go forward with RFPs to purchase capacity for the Ameren Illinois Utilities during the first half of 2009. See below for additional information.
Ameren Illinois Utilities’ Purchased Power Agreements
Commencing January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who do not purchase electric supply from third-party suppliers. The power procurement costs incurred by CIPS, CILCO and IP are passed directly to their customers. CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including their affiliate, Marketing Company, in the Illinois reverse power procurement auction held in September 2006. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve the electric load needs of residential and small commercial customers (with less than one megawatt of demand) at an all-inclusive fixed price. These contracts commenced on January 1, 2007, with one-third of the supply contracts expiring in each of May 2008, 2009 and 2010.
One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers, and all of the supply contracts that served large commercial and industrial customers, expired on May 31, 2008. The Ameren Illinois Utilities used RFP processes in early 2008 to replace these expired supply contracts, pursuant to the Illinois electric settlement agreement. Specifically, the Ameren Illinois Utilities used RFPs to procure energy swaps, capacity, and renewable energy credits for the period June 1, 2008, through May 31, 2009. The Ameren Illinois Utilities contracted to purchase approximately two million megawatthours of energy swaps at an average price of $60 per megawatthour. As a result of a capacity RFP, the Ameren Illinois Utilities contracted to purchase about 1,800 megawatts of capacity at an average price of $50 per MW-day. A renewable energy credits RFP resulted in the Ameren Illinois Utilities contracting to purchase 415,000 credits at an average price of $17 per credit.
Existing supply contracts from the September 2006 auction remain in place. Through the Illinois procurement auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads for residential and small commercial customers (less than one megawatt of demand) as follows:
(a) Represents peak forecast load for CIPS, CILCO and IP. Actual load could be different if customers elect not to purchase power pursuant to the power procurement auction but instead to receive power from a different supplier. Load could also be affected by weather, among other things.
Illinois Electric Settlement Agreement
The Illinois electric settlement agreement provides $1 billion of funding over a four-year period beginning in 2007 for rate relief for certain electric customers in Illinois. Funding for the settlement will come from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which the following contributions remain to be made at December 31, 2008:
(a) Estimated.
Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements from 2008 to 2012. See Note 14 - Related Party Transactions for additional information.
Environmental Matters
We are subject to various environmental laws and regulations enforced 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, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and 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 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 our operations. The more significant matters are discussed below.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In May 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, including Missouri and Illinois where our generating facilities are
located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2 emissions cap-and-trade program is scheduled to take effect in 2010.
In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method it used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The EPA and a group representing the electric utility industry filed petitions for rehearing; however, the court denied those petitions in May 2008. A group representing the electric utility industry and the EPA both filed petitions for review of the U.S. Court of Appeals decision with the U.S. Supreme Court in September 2008 and October 2008, respectively. In February 2009, the EPA withdrew its petition to the U.S. Supreme Court. In February 2009, the U.S. Supreme Court denied the petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions. The standard is expected to be available in draft form by mid to late 2009, and compliance is expected to be required in the 2013 to 2015 timeframe.
We are currently evaluating the impact that the court decision will have on our environmental compliance strategy. We are unable to predict the outcome of this legal proceeding, the actions the EPA or U.S. Congress may take in response to the court decision, or the timing of such actions. We also cannot predict at this time the ultimate impact the court decision and resulting regulatory actions will have on our estimated capital costs for compliance with environmental rules.
In July 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Interstate Rule. The court ruled that the regulation contained several fatal flaws, including a regional cap-and-trade program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008, the EPA, as well as several environmental groups, a group representing the electric utility industry, and the National Mining Association, all filed petitions for rehearing with the U.S. Court of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed its July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and remanded the rule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals’ July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA at which point the Illinois and Missouri rules may be subject to change.
The state of Missouri has adopted state rules to implement the federal Clean Air Interstate Rule for regulating SO2 and NOx emissions from electric generating units. The rules are a significant part of Missouri’s plan to attain existing ambient standards for ozone and fine particulates, as well as meeting the federal Clean Air Visibility Rule. The rules are expected to reduce NOx emissions 30% and SO2 emissions 75% by 2015. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. Missouri also adopted state rules to implement the federal Clean Air Mercury Rule. However, those state rules are not enforceable as a result of the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.
We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois. Under the MPS, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NOx and SO2 controls. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. This rule, when fully implemented, is expected to reduce mercury emissions 90%, NOx emissions 50%, and SO2 emissions 70% by 2015 in Illinois. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution control equipment. Current plans include installing scrubbers for SO2 reduction as well as optimizing operations of selective catalytic reduction (SCR) systems for NOx reduction at certain coal-fired plants in Illinois.
In October 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance from the MPS to the Illinois Pollution Control Board. In preparing this request, Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to the installation of more stringent SO2 and NOx controls at various stages between 2010 and 2020 in order to make the variance proposal “environmentally neutral.” In January 2009, the Illinois Pollution Control Board denied the variance request on procedural grounds. Genco, CILCO (AERG) and EEI filed a motion for reconsideration in February 2009. With the Illinois EPA’s concurrence, they now seek to amend the MPS within a pending rulemaking pertaining to technical amendments of the underlying mercury regulations. Revisions to the MPS within that rulemaking will require Illinois Pollution Control Board approval. If approved, this variance or rule amendment would allow Genco to defer approximately $375 million of environmental capital expenditures from the 2009-2012 timeframe to the 2013-2015 timeframe. This amount is reduced from the $500 million disclosed in Genco’s Quarterly Report on Form 10-Q for the period ended September 30, 2008, because of revisions to the size and timing of projected environmental capital expenditures if no variance is granted. A decision is expected in 2009.
In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. States must submit their nonattainment plans in March 2009. A final action by
the EPA to designate areas as nonattainment is expected in March 2010. State implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions for various requirement dates. Additional emission reductions may be required as a result of the future state implementation plans. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.
The table below presents estimated capital costs that are based on current technology, to comply with the federal Clean Air Interstate Rule and related state implementation plans through 2018, as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates described below could change depending upon additional federal or state requirements, the requirements under a mercury MACT standard, whether the variance or rule amendment request with respect to the Illinois MPS discussed above is granted, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment.
(a) UE’s expenditures are expected to be recoverable in rates over time.
Emission Allowances
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NOx Budget Trading Program, and the federal Clean Air Interstate Rule. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. NOx allowances allocated under the NOx Budget Trading Program can be used for the seasonal NOx program under the federal Clean Air Interstate Rule. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. In addition, the Illinois rules to implement the federal Clean Air Interstate Rule include an allowance set aside for new generating facilities. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. 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, rich-reagent injection, selective noncatalytic reduction, and selective catalytic reduction systems.
See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that were carried as intangible assets as of December 31, 2008.
UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and the level of operations, will have a significant impact on the number of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. Unless revised by the EPA as a result of the U.S. Court of Appeals remand, the Clean Air Interstate Rule program will require that SO2 allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO2 allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG, and EEI expect to install control technology designed to further reduce SO2 emissions, as discussed above.
The Clean Air Interstate Rule has both an ozone season program and an annual program for regulating NOx emissions, with separate allowances issued for each program. The Clean Air Interstate Rule ozone season program replaced the NOx Budget Trading Program beginning in 2009. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. Both sets of allowances for the years 2009 through 2011 were issued by the Illinois EPA in April 2008. Allocations for UE’s, Genco’s, AERG’s, and EEI’s Illinois generating facilities were 90, 3,442, 1,368, and 1,758 tons per ozone season, respectively, and 93, 8,300, 3,418, and 4,564 tons annually.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In October 2008, the U.S. House of Representatives, Energy and Commerce Committee, Subcommittee on Energy and Air Quality issued a “discussion draft” of climate legislation, which proposed
establishing an economy-wide cap-and-trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to a level that is 6% below 2005 levels by 2020 and 80% below 2005 levels by the year 2050. In addition, new leadership in the Energy and Commerce Committee is considering aggressive climate legislation.
President Obama supports an economy-wide cap-and- trade greenhouse gas reduction program that would reduce emissions to 1990 levels by 2020 and to 80% below 1990 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. Although we cannot predict the date of enactment or the requirements of any global warming legislation, it is likely that some form of federal greenhouse gas legislation will become law during President Obama’s administration.
Potential impacts from proposed legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of allocating allowances, and provisions for cost containment measures, such as a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in the U.S. Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO2 that coal emits when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also could affect the cost of heating for our utility customers and many industrial processes. Under some policy scenarios being considered by Congress, Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.
Future initiatives regarding greenhouse gas emissions and global warming may also be subject to the activities pursuant to the Midwest Greenhouse Gas Reduction Accord an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota to develop a strategy to achieve energy security and to reduce greenhouse gas emissions through a cap-and-trade mechanism. It is expected that the advisory group to the Midwest governors will provide recommendations on the design of a greenhouse gas reduction program by the third quarter of 2009. However, it is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.
With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO2 and
other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In July 2008, the EPA issued an advance notice of public rulemaking (ANPR) in response to the U.S. Supreme Court’s directive. The ANPR solicited public comments on the benefits and ramifications of regulating greenhouse gases under the Clean Air Act, and that rulemaking has not been completed. On February 12, 2009, the EPA announced its intent to reconsider the decision under the Bush Administration denying the waiver to the state of California for regulating CO2 emissions from automobiles. On February 17, 2009, the EPA also granted a petition for reconsideration filed by the Sierra Club to reexamine a December 2008 Bush Administration ruling that CO2 should not be regulated under the Clean Air Act when issuing construction permits for power plants. These EPA actions will factor into the rulemaking process on the ANPR and could ultimately lead to regulation of CO2 from power plants.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which in turn could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI as well as other similarly situated electric power generators to close some coal-fired facilities. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.
Ameren has taken actions to address the global climate issue. These include:

seeking partners to develop wind energy for our generation portfolio;

participating in DOE-sponsored research into the feasibility of sequestering CO2 underground in the Illinois basin, the Plains sequestration partnership, and a Missouri sequestration project to be conducted in Southwest Missouri;

increasing the operating efficiency and capacity of our nuclear and hydroelectric plants to provide more energy to offset fossil generation;

participating in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage in the lower Mississippi valley to sequester carbon;

using coal combustion byproducts as a direct replacement for cement, thereby reducing carbon emissions at cement kilns;

participating in a DOE and state of Missouri Department of Natural Resources project evaluating Missouri wind resources for the next generation of wind turbines;

funding a project investigating opportunities to reduce nitrous oxide (N2O), a potent greenhouse gas from agricultural usage, and tracking those reductions;

participating in the Illinois Clean Energy Community Foundation, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities;

establishing Pure Power, UE’s voluntary renewable energy program that allows UE’s electric customers to support development of wind farms and other renewable energy facilities in the Midwest;

purchasing Renewable Energy Credits, as when the Ameren Illinois Utilities purchased 415,000 renewable energy credits in April 2008; and

participating in funding the new Consortium for Clean Coal Utilization research center at Washington University, which will investigate clean coal technologies, such as oxy-fuel combustion and CO2 capture and storage.
The impact on us of future initiatives related to greenhouse gas emissions and global warming is unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state 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 cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts on aquatic species. These rules pertain to all 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. In January 2007, the U.S. Court of Appeals for the Second Circuit remanded many provisions of these rules to the EPA for revision. In April 2008, the U.S. Supreme Court agreed to hear an appeal of the lower court ruling. The U.S. Supreme Court heard the case in December 2008. The EPA is expected to reissue the rules early in 2009. Until a decision is issued by the Supreme Court and the new rules are adopted, and the studies on the power plants are completed, we are unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2012.
New Source Review
The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review (NSR) requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were performed.
In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. It sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s Illinois coal-fired power plants. We are in the process of responding to this request. We are also currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions.
In March 2008, Ameren received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to UE’s Labadie, Meramec, Rush Island, and Sioux facilities. All of these facilities are coal-fired power plants. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine UE’s compliance with state and federal regulatory requirements. UE is complying with this information request, but we are unable to predict the outcome of this matter.
Resolution of these matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, UE, Genco, AERG and EEI. A resolution could result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties.
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 their degree of fault, the legality of original disposal, or the 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 (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.
As of December 31, 2008, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 14, CILCO 4, and IP 25. 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 its former
MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of December 31, 2008, estimated obligations were: CIPS - $17 million to $29 million, CILCO - $8 million to $13 million, IP -$74 million to $143 million. CIPS, CILCO and IP recorded liabilities of $17 million, $8 million, and $74 million, respectively, to represent estimated minimum obligations, as no other amount within the range was a better estimate.
CIPS is also responsible for the cleanup of a former landfill in Coffeen, Illinois. As of December 31, 2008, CIPS estimated its obligation at $0.5 million to $6 million. CIPS recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of December 31, 2008, IP recorded a liability of $1 million to represent its best estimate of the obligation for these sites.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. See Note 2 - Rate and Regulatory Matters for information on a Missouri law enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of December 31, 2008, UE estimated its obligation at $3 million to $4 million. UE recorded a liability of $3 million to represent its estimated minimum obligation for its MGP sites, as no other amount within the range was a better estimate. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates.
In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.
Sauget Area 2 investigations overseen by the EPA are largely completed, and the results will be submitted to the EPA in June 2009. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical
waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of December 31, 2008, UE estimated its obligation at $1 million to $10 million. UE recorded a liability of $1 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In March 2008, the EPA issued an administrative order requesting that CIPS participate in a portion of an environmental cleanup of a site within Sauget Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a customer of Clayton Chemical Company, which before its dissolution was a recycler of waste solvents and oil. Other former customers of Clayton Chemical Company were issued similar orders by the EPA. Pursuant to that order, CIPS and three other PRPs agreed to install an engineered barrier on portions of the Clayton Chemical Company site. This work is expected to be concluded in the first quarter of 2009. As of December 31, 2008, CIPS recorded a liability of $0.25 million to represent its best estimate of its obligation for this site.
In July 2008, the EPA issued an administrative order to UE pertaining to a former coal tar distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site but did not conduct any of the manufacturing operations involving coal tar or its byproducts. UE is currently in negotiations with other PRPs concerning the scope of future site investigations. As of December 31, 2008, UE estimated its obligation at $2 million to $5 million. UE recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $1.9 million at December 31, 2008, on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.
In addition, our operations or those of our predecessor companies involve the use, disposal of, 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.
Ash Ponds
In December 2008, an ash pond dike failed at a non-Ameren owned utility company releasing approximately one billion gallons of coal ash slurry. The ash was deposited primarily over 300 acres, destroying three homes. As a result of this incident, there has been increased activity at both the state and federal level to examine the need for
additional regulation of utility ash pond facilities and coal-combustion wastes. It is anticipated that some form of additional regulation concerning the integrity of ash ponds and the handling and disposal of coal combustion waste may be forthcoming within the next two years. At this time, we are unable to predict the outcome any such regulations might have on our results of operations, financial position, or liquidity.
Polychlorinated Biphenyls Information Request
Polychlorinated biphenyls (PCBs) are a blend of chemical compounds that were historically used in a variety of industrial products because of their chemical and thermal stability. In natural gas systems, PCBs were used as a compressor lubricant and a valve sealant before their sale for these applications was banned by the EPA in 1979. During the third quarter of 2007, the Ameren Illinois Utilities received requests from the Illinois attorney general and from the EPA for information regarding their experiences with PCBs in their gas distribution systems. The Ameren Illinois Utilities responded to these information requests.
The Ameren Illinois Utilities have evaluated their gas distribution systems for the presence of PCBs. They believe that the presence of PCBs is limited to discrete areas and is not widespread throughout their service territories. We cannot predict whether any further actions will be required on the part of the Ameren Illinois Utilities regarding this matter or what the ultimate outcome will be.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park.
UE has settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and has begun rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010.
In December 2006, 11 business owners filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the Missouri Circuit Court of Reynolds County and remains pending, contains allegations of negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims. It seeks damages relating to business losses, lost profit, and unspecified punitive damages. UE has filed a motion to dismiss the lawsuit, arguing that Missouri law does not permit the plaintiffs to recover purely economic
losses under theories of negligence and strict liability. This motion is currently pending.
In December 2008, the Department of the Army, Corps of Engineers filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the U.S. District Court in Cape Girardeau, Missouri, and remains pending, claims that Clearwater Lake in southeast Missouri was damaged by
sediment from the Taum Sauk breach. This litigation is in its early stages, and we are evaluating the merits of the allegations. We are unable to predict the timing or outcome of this litigation, or its possible effect on UE’s results of operations, financial position, or liquidity.
At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the reservoir, will range from $200 million to $220 million. As of December 31, 2008, UE had paid $181 million, including costs resulting from the FERC-approved stipulation and consent agreement. UE accrued a $18 million liability while expensing $33 million and recording a $166 million receivable due from insurance companies. As of December 31, 2008, UE had received $85 million from insurance companies, which reduced the insurance receivable balance to $81 million.
As of December 31, 2008, UE had recorded a $332 million receivable due from insurance companies related to the rebuilding of the facility and the reimbursement of replacement power costs. As of December 31, 2008, UE had received $158 million from insurance companies, which reduced the insurance receivable balance as of December 31, 2008, to $174 million.
Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.
Until litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
Mechanics’ Liens
In November 2007, the primary subcontractor on a 2007 maintenance outage at AERG’s Duck Creek facility filed a complaint for foreclosure of its mechanic’s lien of $19 million plus interest against AERG. That action was filed in the Circuit Court of Fulton County, Illinois. Subsequently, various second-tier subcontractors of the primary subcontractor also filed for foreclosure of their mechanics’ lien claims against AERG in the Circuit Court of Fulton County, Illinois, in addition to filing their claims against the primary subcontractor. Approximately 13 mechanics’ liens claiming $23 million plus interest in the aggregate were filed as of December 31, 2008, against AERG for labor or material for the 2007 maintenance outage. These claims were primarily based on additional work outside of the original contract scope. Effective as of December 17, 2008, AERG entered into a Settlement and Release Agreement with the primary contractor. It provides that in exchange for AERG’s payment of $19 million to the
primary contractor, the primary contractor will, among other things, release Ameren from any existing or future claims they may have, pay off and obtain full releases of all mechanics’ liens filed against AERG and dismiss all mechanics’ lien claims against AERG in the Fulton County litigation made by the primary subcontractor and all second-tier subcontractors’, and indemnify, defend and hold AERG harmless from all such claims by these parties. The resolution of these liens and lawsuits did not have a material impact on CILCO’s results of operations, financial position, or liquidity.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 161 parties are named in some pending cases and as few as six in others. However, in the cases pending as of December 31, 2008, the average number of parties was 68.
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 former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a former parent subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 2008:
(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
As of December 31, 2008, six 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.
IP has 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 are recoverable by IP from a trust fund established by IP. At December 31, 2008, the trust fund balance was $23 million, including accumulated interest.
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.
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.
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 and sells 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 before 2020. UE has sufficient installed 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. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. See Note 1 - Summary of Significant Accounting Policies for additional information on asset retirement obligations. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2008, 2007 and 2006. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in September 2008. The 2008 study included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. 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 as 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 a regulatory asset or regulatory liability, as appropriate.
See Note 2 - Rate and Regulatory Matters for information on the COLA filed by UE with the NRC for a potential new nuclear unit and Note 9 - Nuclear Decommissioning Trust Fund Investments.
NOTE 17 - SEGMENT INFORMATION
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization) and other non-rate-regulated activities, which are in Other. The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company. CIPSCO Investment Company was eliminated on March 31, 2008, through an internal reorganization.
UE has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI and other non-rate-regulated activities, which are included in Other.
CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises leveraged lease investments, parent company activity, and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.
The following tables present information about the reported revenues and specified items included in net income of Ameren, UE, CILCORP, and CILCO for the years ended December 31, 2008, 2007 and 2006, and total assets as of December 31, 2008, 2007 and 2006.
Ameren
(a) Represents net income available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
(b) Total assets for Illinois Regulated included an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).
UE
(a) Included 40% interest in EEI through February 29, 2008.
(b) Represents net income available to the common stockholder (Ameren).
CILCORP
(a) Represents net income available to the common stockholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
(b) Total assets for Illinois Regulated and Non-rate-regulated Generation include an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).
CILCO
(a) Represents net income available to the common stockholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
(a) Genco and CILCORP had no preferred stock outstanding.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A
ITEM 9A and ITEM 9A(T). CONTROLS AND PROCEDURES.
Each of the Ameren Companies 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 2008 fiscal year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2008, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of 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 those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
(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 each of the Ameren Companies’ 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). After making that evaluation under the framework in Internal Control - Integrated Framework issued by the COSO, management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2008. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of UE’s, Genco’s, CIPS’, CILCO’s, CILCORP’s or IP’s (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over financial reporting. Management’s report for the Subsidiary Registrants was not subject to attestation by the independent registered public accounting firm because temporary rules of the SEC permit the company to provide only management’s report in this annual report.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into 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.
(c) Change in Internal Control
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.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 2008 that has not previously been reported on an SEC Form 8-K.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it 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 2009 annual meetings of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it 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 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.
UE, CIPS, Genco, CILCORP, CILCO and IP do not have separately designated standing audit committees, but instead use Ameren’s audit and risk committee to perform such committee functions for their boards of directors. These companies have no securities listed on the NYSE and therefore are not subject to the NYSE listing standards. Douglas R. Oberhelman serves as chairman of Ameren’s audit and risk committee, and Stephen F. Brauer and Susan S. Elliott serve as members. The board of directors of Ameren has determined that Douglas R. Oberhelman qualifies
as an audit committee financial expert and that he is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of UE, CIPS, Genco, CILCORP, CILCO and IP use the nominating and corporate governance committee of Ameren’s board of directors 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 Web site: www.ameren.com.
To encourage 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, the controllers, 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. It is referred to as the Corporate Compliance Policy. The Ameren Companies make available free of charge through Ameren’s Web site (www.ameren.com) the Code of Ethics and Corporate Compliance Policy. These documents are also available free 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 Web site within four business days following the date of the amendment or waiver.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2009 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C and is incorporated herein by reference. Information required by these SEC Regulation S-K items for IP is identical to the information that will be included in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC 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.
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, 2008, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans.
(a) Consists of the Ameren Corporation Long-term Incentive Plan of 1998, which was approved by shareholders in April 1998 and expired on April 1, 2008, and the Ameren Corporation 2006 Omnibus Incentive Compensation Plan, which was approved by shareholders in May 2006 and expires on May 2, 2016. Pursuant to grants of performance share units (PSUs) under the Long-term Incentive Plan of 1998 and the 2006 Omnibus Incentive Compensation Plan, 116,877 of the securities represent PSUs that vested at December 31, 2008, (including accrued and reinvested dividends) and 920,278 of the securities represent PSUs granted but not vested (including accrued and reinvested dividends). The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level based on the achievement of total shareholder return objectives established for such awards.
(b) PSUs are awarded when earned in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs have been excluded for purposes of calculating the weighted-average exercise price.
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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it 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 about 73%, of IP’s preferred stock are owned by 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, 2009. 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, 2009, 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.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Information required by Item 404 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it 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.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of UE, CIPS and CILCO for their 2009 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
CILCORP (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2008
NOTE 1 - BASIS OF PRESENTATION
CILCORP (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes to our financial statements under Part II, Item 8, of this report.
NOTE 2 - LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of long-term obligations of CILCORP (parent company only).
NOTE 3 - COMMITMENTS AND CONTINGENCIES
See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of CILCORP (parent company only).
CENTRAL ILLINOIS LIGHT COMPANY (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2008
NOTE 1 - BASIS OF PRESENTATION
Central Illinois Light Company (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes to our financial statements under Part II, Item 8, of this report.
NOTE 2 - LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of long-term obligations of Central Illinois Light Company (parent company only).
NOTE 3 - COMMITMENTS AND CONTINGENCIES
See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of Central Illinois Light Company (parent company only).
(a) Uncollectible accounts charged off, less recoveries.
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.
AMEREN CORPORATION (registrant)
Date: March 2, 2009
By
/s/ Gary L. Rainwater
Gary L. Rainwater
Chairman, President and Chief Executive Officer
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.
UNION ELECTRIC COMPANY (registrant)
Date: March 2, 2009
By
/s/ Thomas R. Voss
Thomas R. Voss
Chairman, President and Chief Executive Officer
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.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (registrant)
Date: March 2, 2009
By
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
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.
AMEREN ENERGY GENERATING COMPANY (registrant)
Date: March 2, 2009
By
/s/ Charles D. Naslund
Charles D. Naslund
Chairman and President
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.
CILCORP INC. (registrant)
Date: March 2, 2009
By
/s/ Gary L. Rainwater
Gary L. Rainwater
Chairman, President and Chief Executive Officer
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.
CENTRAL ILLINOIS LIGHT COMPANY (registrant)
Date: March 2, 2009
By
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
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.
ILLINOIS POWER COMPANY (registrant)
Date: March 2, 2009
By
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
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.
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies 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:
4.17
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004C (1998C) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967
4.18
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004D (2000B) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.4, File No. 1-2967
4.19
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004E (2000A) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.5, File No. 1-2967
4.20
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004F (2000C) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.6, File No. 1-2967
4.21
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004G (1991) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.7, File No. 1-2967
4.22
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004H (1992) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967
4.23
Ameren
UE
Supplemental Indenture to the UE Mortgage dated May 1, 2004
May 18, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967
4.24
Ameren
UE
Supplemental Indenture to the UE Mortgage dated September 1, 2004
September 23, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967
4.25
Ameren
UE
Supplemental Indenture to the UE Mortgage dated January 1, 2005
January 27, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967
4.26
Ameren
UE
Supplemental Indenture to the UE Mortgage dated July 1, 2005
July 21, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967
4.27
Ameren
UE
Supplemental Indenture to the UE Mortgage dated December 1, 2005
December 9, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967
4.28
Ameren
UE
Supplemental Indenture to the UE Mortgage dated June 1, 2007
June 15, 2007 Form 8-K, Exhibit 4.5, File No. 1-2967
4.29
Ameren
UE
Supplemental Indenture to the UE Mortgage dated April 11, 2008
April 18, 2008 Form 8-K, Exhibit 4.7, File No. 1-2967
4.30
Ameren
UE
Supplemental Indenture to the UE Mortgage dated June 1, 2008
June 19, 2008 Form 8-K, Exhibit 4.5, File No. 1-2967
4.31
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.
1992 Form 10-K, Exhibit 4.37, File No. 1-2967
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.32
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, Exhibit 4.9, File No. 1-2967
4.33
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.
1992 Form 10-K, Exhibit 4.38, File No. 1-2967
4.34
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, Exhibit 4.10, File No. 1-2967
4.35
Ameren
UE
Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967
4.36
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, Exhibit 4.11, File No. 1-2967
4.37
Ameren
UE
Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967
4.38
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, Exhibit 4.12, File No. 1-2967
4.39
Ameren
UE
Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE
September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967
4.40
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, Exhibit 4.13, File No. 1-2967
4.41
Ameren
UE
Indenture dated as of August 15, 2002, from UE to The Bank of New York Mellon Trust Company, N.A., as successor trustee (relating to senior secured debt securities)
August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.42
Ameren
UE
UE Company Order dated August 22, 2002, establishing the 5.25% Senior Secured Notes due 2012 (including the global note)
August 23, 2002 Form 8-K, Exhibit 4.2, File No. 1-2967
4.43
Ameren
UE
UE Company Order dated March 10, 2003, establishing the 5.50% Senior Secured Notes due 2034 (including the global note)
March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.44
Ameren
UE
UE Company Order dated April 9, 2003, establishing the 4.75% Senior Secured Notes due 2015 (including the global note)
April 10, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.45
Ameren
UE
UE Company Order dated July 28, 2003, establishing the 5.10% Senior Secured Notes due 2018 (including the global note)
August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.46
Ameren
UE
UE Company Order dated October 7, 2003, establishing the 4.65% Senior Secured Notes due 2013 (including the global note)
October 8, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.47
Ameren
UE
UE Company Order dated May 13, 2004, establishing the 5.50% Senior Secured Notes due 2014 (including the global note)
May 18, 2004 Form 8-K, Exhibits 4.2 and 4.3, No. 1-2967
4.48
Ameren
UE
UE Company Order dated September 1, 2004, establishing the 5.10% Senior Secured Notes due 2019 (including the global note)
September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, No. 1-2967
4.49
Ameren
UE
UE Company Order dated January 27, 2005, establishing the 5.00% Senior Secured Notes due 2020 (including the global note)
January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.50
Ameren
UE
UE Company Order dated July 21, 2005, establishing the 5.30% Senior Secured Notes due 2037 (including the global note)
July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.51
Ameren
UE
UE Company Order dated December 8, 2005, establishing the 5.40% Senior Secured Notes due 2016 (including the global note)
December 9, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.52
Ameren
UE
UE Company Order dated June 15, 2007, establishing the 6.40% Senior Secured Notes due 2017 (including the global note)
June 15, 2007 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.53
Ameren
UE
UE Company Order dated April 8, 2008, establishing the 6.00% Senior Secured Notes due 2018 (including the global note)
April 18, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967
4.54
Ameren
UE
UE Company Order dated June 19, 2008, establishing the 6.70% Senior Secured Notes due 2019 (including the global note)
June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.55
Ameren
CIPS
Indenture of Mortgage and Deed of Trust dated October 1, 1941, from CIPS to U.S. Bank National Association and Richard Prokosch, as successor trustees (CIPS Mortgage)
Exhibit 2.01, File No. 2-60232
4.56
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated September 1, 1947
Amended Exhibit 7(b), File No. 2-7341
4.57
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated January 1, 1949
Second Amended Exhibit 7.03, File No. 2-7795
4.58
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1965
Amended Exhibit 2.02, File No. 2-23569
4.59
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated April 1, 1971
Amended Exhibit 2.02, File No. 2-39587
4.60
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated December 1, 1973
Exhibit 2.03, File No. 2-60232
4.61
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated February 1, 1980
Exhibit 2.02(a), File No. 2-66380
4.62
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated May 15, 1992
May 15, 1992 Form 8-K, Exhibit 4.02, File No. 1-3672
4.63
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1997
June 6, 1997 Form 8-K, Exhibit 4.03, File No. 1-3672
4.64
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated December 1, 1998
Exhibit 4.2, File No. 333-59438
4.65
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 2001
June 30, 2001 Form 10-Q, Exhibit 4.1, File No. 1-3672
4.66
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated October 1, 2004
2004 Form 10-K, Exhibit 4.91, File No. 1-3672
4.67
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 2006
June 19, 2006 Form 8-K, Exhibit 4.9, File No. 1-3672
4.68
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated August 1, 2006
September 8, 2006 Form 8-K, Exhibit 4.4, File No. 1-3672
4.69
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated March 1, 2007
March 14, 2007 Form 8-K, Exhibit 4.2, File No. 1-3672
4.70
Ameren
CIPS
Indenture dated as of December 1, 1998, from CIPS to The Bank of New York Mellon Trust Company, N.A., as successor trustee (CIPS Indenture)
Exhibit 4.4, File No. 333-59438
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.71
Ameren
CIPS
CIPS Global Note, dated December 22, 1998, representing Senior Secured Notes, 5.375% due 2008
Exhibit 4.5, File No. 333-59438
4.72
Ameren
CIPS
CIPS Global Note, dated December 22, 1998, representing Senior Secured Notes, 6.125% due 2028
Exhibit 4.6, File No. 333-59438
4.73
Ameren
CIPS
First Supplemental Indenture to the CIPS Indenture, dated as of June 14, 2006
June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672
4.74
Ameren
CIPS
CIPS Company Order, dated June 14, 2006, establishing 6.70% Series Secured Notes due 2036
June 19, 2006 Form 8-K, Exhibit 4.5, File No. 1-3672
4.75
Ameren
Genco
Indenture dated as of November 1, 2000, from Genco to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Genco Indenture)
Exhibit 4.1, File No. 333-56594
4.76
Ameren
Genco
First Supplemental Indenture dated as of November 1, 2000, to Genco Indenture, relating to Genco’s 8.35% Senior Notes, Series B due 2010
Exhibit 4.2, File No. 333-56594
4.77
Ameren
Genco
Second Supplemental Indenture dated as of June 12, 2001, to Genco Indenture, relating to Genco’s 8.35% Senior Note, Series D due
Exhibit 4.3, File No. 333-56594
4.78
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
June 30, 2002 Form 10-Q, Exhibit 4.1, File No. 333-56594
4.79
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
2002 Form 10-K, Exhibit 4.5, File No. 333-56594
4.80
Ameren
Genco
Fifth Supplemental Indenture dated as of April 1, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series G due 2018
April 9, 2008 Form 8-K, Exhibit 4.2, File No. 333-56594
4.81
Ameren
Genco
Sixth Supplemental Indenture, dated as of July 7, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series H due 2018
Exhibit No. 4.55, File No. 333-155416
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.82
Ameren
CILCORP
Indenture, dated as of October 18, 1999, between Midwest Energy, Inc., and The Bank of New York Mellon Trust Company, N.A., as successor trustee, and First Supplemental Indenture, dated as of October 18, 1999, between CILCORP and The Bank of New York Mellon Trust Company, N.A., as successor trustee
Exhibits 4.1 and 4.2, File No. 333-90373
4.83
Ameren
CILCO
Indenture of Mortgage and Deed of Trust between Illinois Power Company (predecessor in interest to CILCO) and Deutsche Bank Trust Company Americas (formerly known as 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 the trustee, dated as of July 1, 1933, Supplemental Indenture between the same parties dated as of January 1, 1935, and Supplemental Indenture between the same parties dated as of April 1, 1940
Exhibit B-1, Registration No. 2-1937; Exhibit B-1(a), Registration No. 2-2093; and Exhibit A, April 1940 Form 8-K, File No. 1-2732
4.84
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949
December 1949 Form 8-K, Exhibit A, File No. 1-2732
4.85
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957
July 1957 Form 8-K, Exhibit A, File No. 1-2732
4.86
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966
February 1966 Form 8-K, Exhibit A, File No. 1-2732
4.87
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992
January 30, 1992 Form 8-K, Exhibit 4(b), File No. 1-2732
4.88
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated October 1, 2004
2004 Form 10-K, Exhibit 4.121, File No. 1-2732
4.89
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated June 1, 2006
June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732
4.90
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated August 1, 2006
September 8, 2006 Form 8-K, Exhibit 4.2, File No. 1-2732
4.91
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated March 1, 2007
March 14, 2007 Form 8-K, Exhibit 4.4, File No. 1-2732
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.92
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated December 1, 2008
December 9, 2008 Form 8-K, Exhibit 4.5, File No. 1-2732
4.93
Ameren
CILCO
Indenture dated as of June 1, 2006, from CILCO to The Bank of New York Mellon Trust Company, N.A., as successor trustee
June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732
4.94
Ameren
CILCO
CILCO Company Order, dated June 14, 2006, establishing the 6.20% Senior Secured Notes due 2016 (including the global note) and the 6.70% Senior Secured Notes due 2036 (including the global note)
June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732
4.95
Ameren
CILCO
CILCO Company Order, dated December 9, 2008, establishing the 8.875% Senior Secured Notes due 2013 (including the global note)
December 9, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2732
4.96
Ameren
IP
General Mortgage Indenture and Deed of Trust dated as of November 1, 1992 between IP and The Bank of New York Mellon Trust Company, N.A., as successor trustee (IP Mortgage)
1992 Form 10-K, Exhibit 4(cc), File No. 1-3004
4.97
Ameren
IP
Supplemental Indenture dated as of April 1, 1997, to IP Mortgage for the series P, Q and R bonds
March 31, 1997 Form 10-Q, Exhibit 4(b), File No. 1-3004
4.98
Ameren
IP
Supplemental Indenture dated as of March 1, 1998, to IP Mortgage for the series S bonds
Exhibit 4.41, File No. 333-71061
4.99
Ameren
IP
Supplemental Indenture dated as of March 1, 1998, to IP Mortgage for the series T bonds
Exhibit 4.42, File No. 333-71061
4.100
Ameren
IP
Supplemental Indenture dated as of June 15, 1999, to IP Mortgage for the 7.50% bonds due 2009
June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004
4.101
Ameren
IP
Supplemental Indenture dated as of July 15, 1999, to IP Mortgage for the series U bonds
June 30, 1999 Form 10-Q, Exhibit 4.4, File No. 1-3004
4.102
Ameren
IP
Supplemental Indenture dated as of May 1, 2001 to IP Mortgage for the series W bonds
2001 Form 10-K, Exhibit 4.19, File No. 1-3004
4.103
Ameren
IP
Supplemental Indenture dated as of May 1, 2001, to IP Mortgage for the series X bonds
2001 Form 10-K, Exhibit 4.20, File No. 1-3004
4.104
Ameren
IP
Supplemental Indenture dated as of December 15, 2002, to IP Mortgage for the 11.50% bonds due 2010
December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004
4.105
Ameren
IP
Supplemental Indenture dated as of June 1, 2006, to IP Mortgage for the series AA bonds
June 19, 2006 Form 8-K, Exhibit 4.13, File No. 1-3004
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.3
Ameren Companies
Third Amended Ameren Corporation System Utility Money Pool Agreement, as amended September 30, 2004
October 1, 2004 Form 8-K, Exhibit 10.2, File No. 1-14756
10.4
Ameren
Genco
CILCORP
Ameren Corporation System Amended and Restated Non- Regulated Subsidiary Money Pool Agreement, dated March 1, 2008
March 31, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.5
Ameren
UE
Genco
Amended and Restated Five-Year Revolving Credit Agreement, dated as of July 14, 2006, currently among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as administrative agent
July 18, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.6
Ameren
CILCORP
CILCO
Collateral Agency Agreement, dated as of July 14, 2006, between AERG and The Bank of New York Mellon Trust Company, N.A., as collateral agent
July 18, 2006 Form 8-K, Exhibit 10.6, File No. 2-95569
10.7
Ameren
CILCORP
CILCO
Collateral Agency Agreement Supplement, dated as of February 9, 2007, between AERG and The Bank of New York Mellon Trust Company, N.A., as collateral agent
February 13, 2007 Form 8-K, Exhibit 10.3, File No. 1-14756
10.8
Ameren
CIPS
CILCORP
CILCO
IP
Credit Agreement - Illinois Facility, dated as of July 14, 2006, among CIPS, CILCO, IP, AERG, CILCORP and JPMorgan Chase Bank, N.A., as administrative agent
(2006 Illinois Credit Agreement)
July 18, 2006 Form 8-K, Exhibit 10.2, File No. 1-14756
10.9
Ameren
CIPS
CILCORP
CILCO
IP
Amendment dated as of March 26, 2008 to 2006 Illinois Credit Agreement
March 28, 2008 Form 8-K, Exhibit 10.1, File No. 1-14756
10.10
Ameren
CIPS
CILCORP
CILCO
IP
Credit Agreement - Illinois Facility, dated as of February 9, 2007, among CIPS, CILCO, IP, AERG, CILCORP and JPMorgan Chase Bank, N.A., as administrative agent (2007 Illinois Credit Agreement)
February 13, 2007 Form 8-K, Exhibit 10.1, File No. 1-14756
10.11
Ameren
CIPS
CILCORP
CILCO
IP
Amendment dated as of March 26, 2008 to 2007 Illinois Credit Agreement
March 28, 2008 Form 8-K, Exhibit 10.2, File No. 1-14756
10.12
Ameren
Credit Agreement dated as of June 25, 2008, between Ameren and JPMorgan Chase Bank, N.A., as agent
June 27, 2008 Form 8-K, Exhibit 10.1, File No. 1-14756
10.13
Ameren
CILCORP
CILCO
Pledge Agreement dated as of October 18, 1999, between CILCORP and The Bank of New York Mellon, as collateral agent
October 29, 1999 Form 8-K, Exhibit 10.1, File No. 2-95569
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.14
Ameren
CILCORP
CILCO
Pledge Agreement Supplement, dated as of July 14, 2006, between CILCORP and The Bank of New York Mellon, as Collateral Agent
July 18, 2006 Form 8-K, Exhibit 10.3, File No. 2-95569
10.15
Ameren
CILCORP
CILCO
Pledge Agreement Supplement, dated as of February 9, 2007, between CILCORP and The Bank of New York Mellon, as Collateral Agent
February 13, 2007 Form 8-K, Exhibit 10.2, File No. 1-14756
10.16
Ameren
CILCORP
CILCO
Open-Ended Mortgage, Security Agreement, Assignment of Rents and Leases and Fixtures Filing (Illinois) - E.D. Edwards plant, dated as of July 14, 2006, by and from AERG to The Bank of New York Mellon Trust Company, N.A., as agent
July 18, 2006 Form 8-K, Exhibit 10.4, File No. 2-95569
10.17
Ameren
CILCORP
CILCO
Open-Ended Mortgage, Security Agreement, Assignment of Rents and Leases and Fixtures Filing (Illinois) - Duck Creek plant, dated as of July 14, 2006, by and from AERG to The Bank of New York Mellon Trust Company, N.A., as agent
July 18, 2006 Form 8-K, Exhibit 10.5, File No. 2-95569
10.18
Ameren
*Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on August 8, 2008
September 30, 2008 Form 10-Q, Form 8-K, Exhibit 10.1, File No. 1-14756
10.19
Ameren Companies
*Ameren’s Long-Term Incentive Plan of 1998
1998 Form 10-K, Exhibit 10.1, File No. 1-14756
10.20
Ameren Companies
*First Amendment to Ameren’s Long-Term Incentive Plan of 1998
February 16, 2006 Form 8-K, Exhibit 10.6, File No. 1-14756
10.21
Ameren Companies
*Form of Restricted Stock Award under Ameren’s Long-Term Incentive Plan of 1998
February 14, 2005 Form 8-K, Exhibit 10.1, File No. 1-14756
10.22
Ameren
*Ameren’s Deferred Compensation Plan for Members of the Board of Directors amended and restated effective January 1, 2009, dated June 13, 2008
June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756
10.23
Ameren Companies
*Ameren’s Deferred Compensation Plan for Members of the Ameren Leadership Team as amended and restated effective January 1, 2001
2000 Form 10-K, Exhibit 10.1, File No. 1-14756
10.24
Ameren Companies
*Ameren’s Executive Incentive Compensation Program Elective Deferral Provisions for Members of the Ameren Leadership Team as amended and restated effective January 1, 2001
2000 Form 10-K, Exhibit 10.2, File No. 1-14756
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.25
Ameren Companies
*Ameren 2007 Deferred Compensation Plan
December 5, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.26
Ameren Companies
*Ameren 2008 Deferred Compensation Plan
June 30, 2008 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.27
Ameren Companies
*2004 Ameren Executive Incentive Plan
2003 Form 10-K, Exhibit 10.7, File No. 1-14756
10.28
Ameren Companies
*2005 Ameren Executive Incentive Plan
February 14, 2005 Form 8-K, Exhibit 10.2, File No. 1-14756
10.29
Ameren Companies
*2006 Ameren Executive Incentive Plan
February 16, 2006 Form 8-K, Exhibit 10.2, File No. 1-14756
10.30
Ameren Companies
*2007 Executive Incentive Compensation Plan
February 15, 2007 Form 8-K, Exhibit 99.3, File No. 1-14756
10.31
Ameren Companies
*2008 Executive Incentive Compensation Plan
December 18, 2007 Form 8-K, Exhibit 99.1, File No. 1-14756
10.32
Ameren Companies
*2009 Executive Incentive Compensation Plan
February 19, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.33
Ameren Companies
*2005 and 2006 Base Salary Table for Named Executive Officers and 2006 Executive Officer Bonus Targets
December 15, 2005 Form 8-K, Exhibit 10.1, File No. 1-14756
10.34
Ameren Companies
*2007 Base Salary Table for Named Executive Officers
March 31, 2007 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.35
Ameren Companies
*2008 Base Salary Table for Named Executive Officers
2008 Form 10-K, Exhibit 10.31, File No. 1-14756
10.36
Ameren Companies
*2009 Base Salary Table for Named Executive Officers
10.37
Ameren Companies
*Second Amended and Restated Ameren Corporation Change of Control Severance Plan
10.38
Ameren Companies
*Table of 2005 Cash Bonus Awards and 2006 Performance Share Unit Awards Issued to Named Executive Officers
February 16, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.39
Ameren Companies
*Table of Target 2007 Performance Share Unit Awards Issued to Named Executive Officers
February 15, 2007 Form 8-K, Exhibit 99.4, File No. 1-14756
10.40
Ameren Companies
*Table of Target 2008 Performance Share Unit Awards Issued to Named Executive Officers
February 14, 2008 Form 8-K, Exhibit 99.1, File No. 1-14756
10.41
Ameren Companies
*Ameren Corporation 2006 Omnibus Incentive Compensation Plan
February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756
10.42
Ameren Companies
*Form of Performance Share Unit Award Issued in 2006-2008 Pursuant to 2006 Omnibus Incentive Compensation Plan
February 16, 2006 Form 8-K, Exhibit 10.4, File No. 1-14756
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; UE, 1-2967; CIPS, 1-3672; Genco, 333-56594; CILCORP, 2-95569; CILCO, 1-2732; and IP, 1-3004.
*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 that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.