AMEREN CORP
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, CILCO and IP. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries.
As part of an internal reorganization, Resources Company transferred its 80% ownership interest in EEI to Genco, through a capital contribution, on January 1, 2010.
The following table presents our total employees at December 31, 2009:
(a) Total for Ameren includes Ameren registrant and nonregistrant subsidiaries.
As of January 1, 2010, the IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represented about 59% of Ameren’s total employees. They represented 64% of the employees at UE, 83% at CIPS, 72% at Genco, 38% at CILCO, and 90% at IP. All collective bargaining agreements that expired in 2009 have been renegotiated and ratified. Most of the collective bargaining agreements have three- to five-year terms, and expire between 2011 and 2013.
In 2009, Ameren initiated a voluntary separation program that provided eligible management employees the opportunity to voluntarily terminate their employment and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management employees at Ameren’s subsidiaries, including UE, CIPS, Genco, CILCO and IP. Additionally, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. In the third quarter of 2009, Genco announced operational changes and staff reductions at three of its generating facilities. The affected three plants were the Meredosia, Grand Tower, and Hutsonville plants. In addition, Genco retired two of the four units at its Meredosia plant. The Grand Tower plant will be operated seasonally from May through September; a very limited staff will maintain the plant during the other months. The number of positions eliminated as a result of these separation programs and operational changes was approximately 300.
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 under Part II, Item 8, of this report.
BUSINESS SEGMENTS
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Merchant Generation. CILCO has two reportable segments: Illinois Regulated and Merchant Generation. See Note 18 - Segment Information under Part II, Item 8, of this report for additional information on reporting segments.
RATES AND REGULATION
Rates
The rates that UE, CIPS, CILCO and IP are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to UE, CIPS, CILCO and IP customers are 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 prudency of expenditures, 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 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, and liquidity of Ameren, UE, CIPS, CILCO and IP.
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 38% of Ameren’s electric and 14% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2009. About 39% of Ameren’s electric and 86% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2009. 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 83% of UE’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2009. Effective March 1, 2009, as a result of a MoPSC electric rate order issued in January 2009, UE’s retail electric rates include a FAC for billing adjustments for changes in prudently incurred fuel and purchased power costs.
FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files regional transmission tariff rates for approval by FERC. All members within that RTO are then subjected to those rates. As a member of MISO, UE’s transmission rate is calculated in accordance with MISO’s rate formula. The transmission rate is updated in June of each year based on FERC filings. This rate is charged directly to wholesale customers. This rate is not directly charged to Missouri retail customers because the MoPSC includes transmission-related costs in setting bundled retail rates in Missouri.
Natural Gas
All of UE’s natural gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2009.
If certain criteria are met, UE’s natural 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 natural gas infrastructure replacement costs to be passed directly to the consumer.
As part of a 2007 stipulation and agreement approved by the MoPSC that authorized 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. Since April 1, 2007, the MoPSC has approved three separate requests from UE for an ISRS to recover annual revenues of $3 million, in the aggregate. These surcharges remain in place until new rates go into effect.
For additional information on Missouri rate matters, including UE’s pending electric rate case and UE’s 2009 electric 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 under Part II, Item 8, of this report.
Illinois Regulated
The following table presents the approximate percentage of electric and natural gas operating revenues subject to regulation by the ICC for each of the Illinois Regulated companies for the year ended December 31, 2009:
(a) AERG’s revenues are not subject to ICC regulation.
Under the Illinois Customer Choice Law, all electric customers in Illinois may choose their own electric energy provider. However, the Ameren Illinois Utilities are required to serve as the provider of last resort (POLR) for electric customers within their territory who have not chosen an alternative retail electric supplier. The Ameren Illinois Utilities’ obligation to provide full requirements electric service, including power supply, as a POLR varies by customer size. The Ameren Illinois Utilities are not required to offer fixed priced electric service to many of their largest customers with electric demands of 400 kilowatts or greater, as this group of customers has been declared competitive. The power procurement costs incurred by the Ameren Illinois Utilities are passed directly to their customers through a cost recovery mechanism.
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: 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, 2009, 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.
In 2009, a new law became effective in Illinois that allows electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their base rates. In February 2010, the ICC approved the Ameren Illinois Utilities’ electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in base rates.
If certain criteria are met, CIPS’, CILCO’s and IP’s natural 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.
FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files regional transmission tariff rates for approval by FERC. All members within that RTO are then subjected to those rates. As members of MISO, the Ameren Illinois Utilities’ transmission rate is calculated in accordance with MISO’s rate formula. The transmission rate is updated in June of each year based on FERC filings. This rate is charged directly to wholesale customers and alternative retail electric suppliers. For retail customers who have not chosen an alternative retail electric supplier, the transmission rate is collected through a rider mechanism.
For additional information on Illinois rate matters, including the currently pending electric and natural gas rate cases, 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 under Part II, Item 8, of this report.
Merchant Generation
Merchant Generation revenues are determined by market conditions and contractual arrangements. We expect the Merchant Generation fleet of assets to have 6,370 megawatts of capacity available for the 2010 peak summer electrical demand. As discussed below, Genco, AERG and EEI sell all of their power and capacity to Marketing Company through power supply agreements. Marketing Company attempts to optimize the value of those assets and mitigate risks through 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 such as the Ameren Illinois Utilities. For additional information on Marketing Company’s hedging activities and Marketing Company’s sales to the Ameren Illinois Utilities, see Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 7 - Derivative Financial Instruments and Note 14 - Related Party Transactions under Part II, Item 8, of this report.
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 the 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. Approval and relicensure are expected in 2012. Operations are permitted to continue under the current license while the application for relicensing is pending. 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 expects the Taum Sauk plant to become operational in the second quarter of 2010. 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 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 environmental statutes and regulations include requirements for 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 and the management of waste and byproduct materials. 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, global climate change, remediation efforts and UE’s receipt in January 2010 of a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and New Source Performance Standards (NSPS) provisions, 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 under Part II, Item 8, of this report.
SUPPLY FOR ELECTRIC POWER
Ameren owns an integrated transmission system that comprises the transmission assets of UE, CIPS, CILCO, IP and AITC. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes CIPS, CILCO, IP, AITC, Genco and AERG). During 2009, the peak demand in AMMO was 8,081 MW and in AMIL was 8,607 MW. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
UE, CIPS, CILCO and IP are transmission-owning members of 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.
See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional 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 fulfillment of renewable energy requirements, 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.
UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s
integrated resource plan filed with the MoPSC in February 2008 included the expectation that new baseload generation capacity would be required in the 2018 to 2020 time frame. 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 energy efficiency programs that could help defer new plant construction. UE’s 2008 integrated resource 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. UE will file a new integrated resource plan with the MoPSC in 2011.
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 under Part II, Item 8, of this report.
Illinois Regulated
As of January 1, 2007, CIPS, CILCO and IP were required to obtain from market sources all electric supply requirements for customers, except those declared competitive, 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 May 2008, 2009 and 2010.
As part of the 2007 Illinois Electric Settlement Agreement, the reverse power procurement auction process was discontinued and a new competitive power procurement process led by the IPA beginning in 2009 was established. 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 that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy swaps, and renewable energy credits through an RFP process on behalf of the Ameren
Illinois Utilities in the second quarter of 2009. In August 2009, the IPA submitted its plan to the ICC for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The plan was modified and approved by the ICC in December 2009. The IPA will procure energy swaps, capacity and renewable energy credits, and long-term renewable supply.
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 2007 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, through 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, Note 14 - Related Party Transactions and Note 15 - Commitments and Contingencies under Part II, Item 8, of this report for additional information on power procurement in Illinois.
Merchant Generation
Genco and AERG have entered into power supply agreements with Marketing Company 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. 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. EEI and Marketing Company have entered into a power supply agreement for EEI to sell all of its capacity and energy to Marketing Company. This agreement expires on December 31, 2015. All of Genco’s, AERG’s and EEI’s generating facilities compete for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 14 - Related Party Transactions under Part II, Item 8, of this report for additional information.
Factors that could cause Marketing Company to purchase power for the Merchant Generation business segment include, among other things, absence of sufficient owned generation, plant outages, the fulfillment of renewable energy requirements, 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.
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, 2009, 2008 and 2007:
(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, 2009, 2008 and 2007:
(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) 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.
(c) The fuel cost for natural gas represents the cost of natural gas and firm 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.
(d) 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.
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 2019. UE, Genco, AERG and EEI expect to enter into additional contracts to purchase coal from time to time. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. Ameren burned 37.6 million tons (UE - 21.3 million, Genco - 7.9 million, AERG - 4.0 million, EEI - 4.4 million) of coal in 2009. 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 - 96%, Genco - 99%, AERG - 89%, 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 occasionally been restricted because of rail maintenance, weather, and derailments. As of December 31, 2009, coal inventories for UE, Genco, AERG and EEI were 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 fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, the enrichment of that gas, and 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 have been manufactured and delivered to the plant. UE also has agreements or inventories to price-hedge approximately 89% of Callaway’s 2011 and 79% of Callaway’s 2013 refueling requirements. UE has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium and conversion requirements at least through 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. 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, 2009, UE had price-hedged about 89% and Genco had price-hedged 100% of their expected natural gas supply requirements for generation in 2010. As of December 31, 2009, EEI did not have any of its required gas supply for generation hedged for price risk.
Renewable Energy
Illinois and Missouri have enacted laws requiring electric utilities to include renewable energy resources in their portfolios. Illinois requires renewable energy resources to equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers as of June 1, 2008, increasing to 10% by June 1, 2015, and to 25% by June 1, 2025. The Ameren Illinois Utilities have procured renewable energy credits under the ICC-approved RFP to meet this requirement through May 2010. See Note 2 - Rate
and Regulatory Matters under Part II, Item 8, for additional information about the Illinois power procurement process. In Missouri, 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 renewable energy portfolio requirement must be derived from solar energy. UE expects to satisfy the 2011 requirement with existing renewable generation in its current fleet along with a 15-year, 102-MW power purchase agreement with a wind farm operator in Iowa that began generation in 2009 and the 15-MW landfill gas project discussed below.
In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which would generate approximately 15-MW of electricity by burning methane gas collected from the landfill. Construction of the CTs is expected to begin in 2010, and the CTs are expected to begin generating power in 2011. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas.
Energy Efficiency
Ameren’s regulated utilities have implemented energy efficiency programs to educate and help their customers become more efficient users of energy. A new law in Missouri allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The new law could, among other things, allow UE to earn a return on its energy efficiency programs equivalent to the return UE could earn with supply-side capital investments, such as new power plants. UE introduced multiple energy efficiency programs in 2009. The goal of these recently announced and future UE energy efficiency programs is to reduce usage by 540-MW by 2025. UE has set up a website at www.uefficiency.com in order to provide more information to its customers regarding energy efficiency.
The Ameren Illinois Utilities are participating in the Illinois Clean Energy Community Foundation, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities. In June 2008, the ICC issued an order approving the Ameren Illinois Utilities’ electric energy efficiency plan as well as a cost recovery mechanism by which the program costs will be recovered from electric customers. In October 2008, the ICC issued an order approving the Ameren Illinois Utilities’ natural gas energy efficiency plan as well as a cost recovery mechanism by which the program costs will be recovered from natural gas customers. The Ameren Illinois Utilities have set up a website at www.actonenergy.com in order to provide more information to their customers regarding energy efficiency.
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 under Part II, Item 8.
INDUSTRY ISSUES
We are facing issues common to the electric and natural gas utility industry and the merchant 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, supply and distribution, including new technologies;

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 such as 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 merchant generating and independent transmission 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 qualified 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 and ash management requirements;

public concern about the siting of new facilities;

aging infrastructure and the need to construct new power generation, transmission and distribution 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 natural 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 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 under Part II, Item 8, of this report.
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren’s 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 Sections 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). Ameren also uses its Web site (www.ameren.com) as a channel of distribution of material information relating to the Ameren Companies. Financial and other material information regarding the Ameren Companies is routinely posted and accessible at Ameren’s Web site.
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. The information on Ameren’s Web site, or any other Web site referenced in this report, is not incorporated by reference into this report.
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 above 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, and liquidity.
The rates that UE, CIPS, CILCO and IP are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to UE, CIPS, CILCO and IP customers are 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 prudency of expenditures, 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 governmental entities regarding rates, as well as the regulatory lag involved in filing and getting new rates approved, could have a material adverse effect on results of operations, financial position, and 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 revenues, 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 and revenues means that these companies may not be able to earn the allowed return established by their regulators and could result in deferral or elimination of planned capital investments. As a result, UE, CIPS, CILCO and IP expect to file rate cases frequently. A period of increasing rates for 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, and liquidity.
We are subject to various environmental laws and regulations that require significant capital expenditures or could result in closure of facilities, could increase our operating costs, and could adversely influence or limit our results of operations, financial position, and 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 facilities, 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, land 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. Periodically, environmental statutes and regulations are amended and new statutes and regulations are adopted that
impose new or modified obligations on our facilities and operations. Actions required to ensure that our facilities and operations 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.
Ameren also may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative targeted at coal-fired power plants in the United States to determine whether those power plants failed to comply with the requirements of the NSR and New Source Performance Standards (NSPS) provisions under the Clean Air Act when the plants implemented modifications. Failure to comply with the NSR and NSPS provisions under the Clean Air Act can result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties. In January 2010, UE received a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V programs. An outcome in this matter, adverse to UE, could require substantial capital expenditures and the payment of substantial penalties, neither of which can be determined at this time. Such expenditures could affect unit retirement and replacement decisions and our results of operations, financial position, and liquidity if such costs are not recovered through regulated rates.
Ameren, UE, Genco, AERG and EEI have incurred and expect to incur significant costs related to environmental compliance and site remediation. 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 facilities 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 and 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, impairment of
assets, or otherwise materially adversely affect our results of operations, financial position, and liquidity.
Initiatives to limit greenhouse gas emissions and to address climate change are subject to active consideration in the U.S. Congress. In June 2009, the U.S. House of Representatives passed energy legislation entitled “The American Clean Energy and Security Act of 2009” that, if enacted, would establish an economy-wide cap-and-trade program. The overarching goal of this proposed cap-and-trade program is to reduce greenhouse gas emissions from capped sources, including coal-fired electric generation units, to 3% below 2005 levels by 2012, 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. In September 2009, climate change legislation entitled “The Clean Energy Jobs and American Power Act” was introduced in the U.S. Senate that was similar to that passed by the U.S. House of Representatives in June 2009, although it proposes a slightly greater reduction in greenhouse gas emissions in the year 2020 and grants fewer emission allowances to the electricity sector. Under both proposed pieces of legislation, large sources of CO2 emissions will be required to obtain and retire an allowance for each ton of CO2 emitted. The allowances may be allocated to the sources without cost, sold to the sources through auctions or other mechanisms, or traded among parties. “The Clean Energy Jobs and American Power Act” was voted out of committee in November 2009. In December 2009, Senators Kerry, Graham and Lieberman introduced a framework for Senate legislation in 2010. The framework lacks specifics, but it is consistent with the House-passed legislation except that it emphasizes the need for greater support for nuclear power and energy independence through support for clean energy and drilling for oil and natural gas. Senate leadership has stated that consideration of climate legislation will be postponed until spring 2010. In addition, the reduction of greenhouse gas emissions has been identified as a high priority by President Obama’s administration. Although we cannot predict the date of enactment or the requirements of any future climate change legislation or regulations, we believe it is possible that some form of federal legislation or regulations to control emissions of greenhouse gases will become law during the current administration.
Potential impacts from climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing allowances, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s analysis shows that if either “The American Clean Energy and Security Act of 2009” or “The Clean Energy Jobs and American Power Act” were enacted into law in its current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest
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 electricity generation also could affect the cost of heating for our utility customers and many industrial processes. 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.
Additional requirements to control greenhouse gas emissions and address global climate change may also arise 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. The advisory group to the Midwest governors provided draft final recommendations on the design of a greenhouse gas reduction program in June 2009. The recommendations have not been endorsed or approved by the state governors. It is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.
With regard to the control of greenhouse gas emissions under federal regulation, in 2007, the U.S. Supreme Court issued a decision finding 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 required the EPA to determine whether greenhouse gas emissions may reasonably be anticipated to endanger public health or welfare, or, in the alternative, to provide a reasonable explanation as to why greenhouse gas emissions should not be regulated. In December 2009, in response to the decision of the U.S. Supreme Court, the EPA issued its “endangerment finding” determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. It is expected that the EPA will issue a rule by the end of March 2010 to control greenhouse gas emissions from light-duty vehicles such as automobiles. Once this rule is effective, greenhouse gases will, for the first time, be a regulated air pollutant under the Clean Air Act. The EPA has taken the position that the regulation of greenhouse gas emissions from new motor vehicles under the Clean Air Act will trigger the applicability of other Clean Air Act programs, such as the Title V Operating Permit Program and the NSR program, which apply to greenhouse gas emissions from stationary sources. This would include fossil fuel-fired electricity generating plants.
Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA announced in September 2009 a proposed rule, known as the “tailoring rule,” that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule would require any source that emits at least 25,000 tons per year of greenhouse gases measured as CO2 equivalents (CO2e) to obtain an operating permit under Title V Operating Permit Program of
the Clean Air Act. Sources that already have an operating permit would have greenhouse gas-specific provisions added to their permits upon renewal. Currently, all Ameren power plants have operating permits that, depending on the final rule, may be modified when they are renewed to address greenhouse gas emissions. The proposed tailoring rule also would set a new applicability threshold for subjecting stationary sources to the requirements of the NSR program for greenhouse gas emissions and a new emissions threshold for determining when modifications at such stationary sources would require the source to obtain a permit and to implement control technology to address greenhouse gas emissions.
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. Moreover, to the extent we request recovery of these costs through rates, our regulators might deny some or all of, or defer timely recovery of, these 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 and could lead to possible impairment of assets and reduced revenues. 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, and 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 merchant generation facilities involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as scheduled, cost disallowances by regulators and the inability to earn a reasonable rate of return on invested capital at our rate-regulated utilities, any of which could result in higher costs and the closure of facilities.
Over the next five years, the Ameren Companies will incur significant capital expenditures to comply with environmental regulations and to make investments in their electric and gas utility infrastructure and their merchant generation facilities. The Ameren Companies estimate that they will incur up to $8.1 billion (UE - up to $4.2 billion; CIPS - up to $555 million; Genco - up to $1.0 billion; CILCO (Illinois Regulated) - up to $400 million; CILCO (AERG) - up to $180 million; IP - up to $1.1 billion; EEI - up to $460 million; Other - up to $220 million) of capital expenditures during the period 2010 through 2014. These expenses include construction expenditures, capitalized interest or allowance for funds used during construction, and compliance with environmental standards. Construction costs as well as the cost of capital have escalated in recent years and are expected to either stay at current levels or escalate further.
Investments in Ameren’s regulated operations are expected to be recoverable from ratepayers, but are subject to prudency reviews and regulatory lag. The recoverability of amounts expended in merchant 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 who do not perform 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 to the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase electricity 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, and 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 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, and liquidity could otherwise be adversely affected.
Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries as a result of transactions involving energy, coal, other commodities and services, and as a result 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, and liquidity could be adversely affected, resulting in the nondefaulting Ameren entity being unable to meet its obligations, including to unrelated third parties.
Increasing costs associated with our defined benefit and postretirement plans, health care plans, and other employee-related benefits could materially adversely affect our results of operations, financial position, and 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 to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2009, its investment performance in 2009, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $225 million in each of the next five years, with aggregate estimated contributions of $740 million. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 66%, 6%, 9%, 9%, and 10%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, 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 could increase our financing needs and otherwise materially adversely affect our results of operations, financial position, and liquidity.
Our electric generating, transmission and distribution facilities are subject to operational risks that could materially adversely affect our results of operations, financial position, and liquidity.
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:

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

longer-than-anticipated maintenance outages;

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

lack of water for cooling plant operations;

labor disputes;

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

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

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

unusual or adverse weather conditions, including severe storms, droughts, 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 systems where sensitive utility customer data and account information are stored;

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

other unanticipated operations and maintenance expenses and liabilities.
Our natural gas distribution and storage activities involve numerous risks that may result in accidents and other operating risks and costs that could materially adversely affect our results of operations, financial position, and liquidity.
Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, accidental explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in serious injury to employees and nonemployees, loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of distribution lines and storage facilities near populated areas, including residential areas, commercial business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could materially adversely affect our results of operations, financial position, and liquidity.
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 a material 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 settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident.
UE has property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance does 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 upper reservoir, will be approximately $205 million.
UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of testing the rebuilt facility. UE expects the Taum Sauk plant to become operational in the second quarter of 2010. The estimated cost to rebuild the upper reservoir is in the range of $490 million.
Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the Circuit Court of St. Louis County, Missouri, seeking a declaratory judgment that the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized. The three insurers allege that they, along with the other policy participants, presented a rebuild design that was consistent with their insurance coverage obligations and that the insurance policies do not require these insurers to pay their share of the costs of construction associated with the design being used. These insurers have estimated a cost of approximately $214 million for their rebuild design compared to the estimated $490 million cost of the design approved by FERC and implemented by Ameren. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri, against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. Ameren seeks payment of a sum to-be-determined for all amounts covered by these policies incurred in the facility rebuild, including power replacement costs, interest, and attorneys’ fees. The insurers that are parties to the litigation represent approximately 40%, on a weighted average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million.
Until Ameren’s remaining insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and UE’s results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren and UE expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 State of Missouri settlement agreement. In that settlement, UE agreed that it would not attempt to recover from rate payers costs incurred in the reconstruction expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that were not at that time reasonably foreseeable and costs that would have been incurred absent the Taum Sauk incident. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the in-service date of the rebuilt facility. As of December 31, 2009, UE had capitalized in property and plant qualifying Taum Sauk-related costs of $99 million that UE believes qualify for potential recovery in electric rates under the terms of the November 2007 State of Missouri Settlement. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC in a future rate case. Any amounts not recovered through insurance, in electric rates, or otherwise could result in charges to earnings, which could be material.
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 merchant subsidiaries generally depend on the prices that can be obtained for energy and capacity in Illinois and adjacent markets by Marketing Company.
Market prices for energy and capacity may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and fuel can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, at times legislators or regulators with jurisdiction over wholesale and retail energy commodity and transportation rates may impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.
For power products sold in advance, contract prices are influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Marketing Company’s contract portfolio may have average contract prices greater than or less than current market prices, including at the expiration of the contracts, which could significantly affect Ameren’s, Genco’s, AERG’s, and EEI’s results of operations, financial condition and liquidity.
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 energy-efficiency programs;

climate conditions in the Midwest market and major natural disasters; and

environmental laws and regulations.
UE’s ownership and operation of a nuclear generating facility creates business, financial, and waste disposal risks.
UE’s ownership of the Callaway nuclear plant subjects it 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 the Callaway nuclear plant 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 from time to time 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, and 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 at other times experience sustained increases or decreases, 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, and liquidity.
Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.
Like other electric and natural gas utilities and other merchant 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, and liquidity.
Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.
We use short-term and long-term 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 continue to rely on short-term and long-term debt financing. Ameren intends to replace or extend its credit facility agreements during 2010. 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 that occurred in 2008 and continued into 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. Any adverse
change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, which could have a material adverse effect on our results of operations, financial position, and liquidity. 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.
Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.
Ameren is a holding company; 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 ability to service its debt obligations is 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 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 work force 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. UNRESOLVED STAFF COMMENTS.
None.
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 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 2010 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 currently operational because of a breach of its upper reservoir in December 2005. It is expected to become operational in the second quarter of 2010 and therefore is expected to be available for the 2010 peak summer demand. 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 2010.
(d) There are economic development lease arrangements applicable to these CTs.
(e) These CTs have the capability to operate on either oil or natural gas (dual fuel).
(f) Ameren owns an 80% interest in EEI. This table reflects the full capability of EEI’s facilities. As part of an internal reorganization, Resources Company transferred its 80% ownership interest in EEI to Genco, through a capital contribution, on January 1, 2010. See Part I, Item 1, Business and Note 1 - Summary of Significant Accounting Policies under Part II, Item 8, of this report.
(g) Genco and the city of Columbia, Missouri currently are parties to a power purchase agreement pursuant to which Columbia is now purchasing up to 72 megawatts of capacity and energy generated by the facility. Genco has granted Columbia options to purchase an ownership interest in the facility, which would result in a sale of up to 72 megawatts (about 50%) of the facility. 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. The purchase power agreement will terminate if Columbia exercises the purchase options. In addition, in February 2010, the city of Columbia approved the purchase of approximately 36 megawatts, or 25%, of the facility, subject to regulatory approvals. As part of this transaction, the structure of the first purchase option described above will be amended. Instead of the ability to exercise the option to purchase 36 megawatts at the end of 2010 for a purchase price of $15.5 million, the option could be exercised at the end of 2011 for a purchase price of $14.9 million. All other provisions of the options described above will remain the same.
The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2009:
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 bonds 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, Medina Valley’s generating facility, certain substations, and most transmission and distribution lines and gas mains are situated on lands occupied 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 first liens of the indentures securing their mortgage bonds.
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 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.
UE operates a CT facility located in Audrain County, Missouri. UE has rights and obligations as lessee of the CT facility under a long-term lease with Audrain County. The lease term will expire on December 1, 2023. Under the terms of this capital lease, UE is responsible for all operation and maintenance 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.
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.
In July 2009, Caterpillar Inc., in conjunction with other industrial customers as a coalition, intervened in the 2009 rate cases filed by CILCO and IP with the ICC to modify its electric and natural gas delivery service rates. Douglas R. Oberhelman is an executive officer of Caterpillar Inc. and a member of the board of directors of Ameren.
Mr. Oberhelman did not participate in Ameren Corporation’s board and committee deliberations relating to these matters.
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 under Part II, Item 8, of this report.
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 2009 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, 2009, 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 Karen C. Foss and 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. 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 common shareholders of record totaled 69,881 on January 29, 2010. The following table presents the price ranges, closing prices, and dividends paid per Ameren common share for each quarter during 2009 and 2008.
There is no trading market for the common stock of UE, CIPS, Genco, CILCO or IP. Ameren holds all outstanding common stock of UE, CIPS 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 2009 and 2008:
On February 12, 2010, 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, 2010, to stockholders of record on March 10, 2010.
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.
Purchase of Equity Securities
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
(a) Included in December were 2,850 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities repurchase plans or programs.
None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 2009 to December 31, 2009.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 2009. 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, 2004, 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. SELECTED FINANCIAL DATA.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Included income (loss) from cumulative effect of change in accounting principle of $(22) million ($(0.11) per share) for Ameren, $(16) million for Genco, and $(2) million for CILCO.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Operations
At Ameren’s rate-regulated utilities, milder weather and the economic slowdown led to a 3% decrease in kilowatthour sales to residential and commercial customers in 2009, compared with 2008. However, this sales decline was smaller, an estimated 1%, on a weather-normalized basis. The weak economy also led to a decline in kilowatthour sales by Ameren’s rate-regulated utilities to their industrial customers. These sales declined 11% in 2009, compared with 2008, excluding the impact of reduced sales to Noranda’s smelter plant in New Madrid, Missouri. Noranda’s plant sustained damage because of a power interruption on non-Ameren-owned power lines during a severe ice storm in January 2009. As a result, the smelter’s load was sharply reduced but has been rising steadily as repairs have been made to the smelter plant’s production lines, with full production expected to be reached in the second quarter of 2010. Electric sales to industrial customers, including Noranda, declined 17% in 2009, compared with 2008.
For several years, Ameren’s rate-regulated utility businesses have been earning returns on investment that are well below their authorized levels, in part, due to regulatory lag. Ameren is focused on improving earnings to levels that represent fair returns on its rate-regulated investments. Ameren has rate cases pending in both its Illinois and Missouri jurisdictions. Ameren is seeking revenue levels that reflect the significant investments it has made in electric and gas utility infrastructure to improve reliability. Ameren is also seeking recovery of higher financing costs and, in Missouri, rising net fuel costs. The Ameren Illinois Utilities are currently requesting a $130 million aggregate annual increase in base electric and natural gas delivery rates. The staff of the ICC currently supports a $46 million annual revenue increase. The staff’s lower revenue amount reflects its lower recommended return on equity of 10.1% compared to the Ameren Illinois Utilities’ request of 11.5%, on a rate base weighted basis, and use of a lower pension and benefits expense level, among other things. In February 2010, administrative law judges issued a consolidated proposed order, which included a recommended revenue increase for electric delivery service for the Ameren Illinois Utilities of $66 million in the aggregate (CIPS - $26 million increase, CILCO - $6 million increase, and IP - $34 million increase) and a recommended revenue net decrease for natural gas delivery service of $10 million in the aggregate (CIPS - $1 million increase, CILCO - $6 million decrease, and IP - $5 million decrease). The ICC is not bound by the proposed order issued by the administrative law judges. New rates should be effective by early May 2010.
UE filed a request with the MoPSC in July 2009 for an annual electric service rate increase of $402 million. More than half of the request was for anticipated higher net fuel costs. These increased net fuel costs would have been eligible for recovery through the FAC absent this filing. The MoPSC staff, in its direct testimony in the rate case, recommended an annual electric service rate increase of $218 million to $251 million, with approximately $214 million of this related to higher net fuel costs. The staff’s lower revenue amount reflects its lower recommended return on equity range of 9.0% to 9.7%, which was lower than UE’s initial request of 11.5%. The staff’s revenue amount also incorporated lower depreciation, plant maintenance and financing cost levels, as well as other adjustments. The staff testimony reflects continuation of the FAC and the pension and postretirement benefit cost trackers and a modified environmental cost recovery mechanism. Other parties filed testimony in the rate case, including a group of large industrial customers and the Office of Public Counsel. The Missouri Office of Public Counsel recommended a return on equity of 10.2%. The large industrial customers recommended a rate increase of $139 million, which included a $181 million increase related to net fuel costs. Their lower revenue requirement reflects their lower recommended return on equity of 10%, the use of significantly lower depreciation rates and plant maintenance expenses, as well as lower financing costs, among other things. The large industrial customers’ testimony reflects continuation of the FAC, as well as a modified approach for the accounting and recovery of environmental costs. In February 2010, UE filed its rebuttal testimony in this rate case, which included, among other things, a modification of its recommended return on equity to 10.8%. It is anticipated that certain major changes to revenues, expenses, rate base, and capital structure will be trued-up through January 31, 2010, in a March 2010 UE update. A MoPSC order is expected by late May 2010 with new rates expected to be effective in late June 2010.
Current lower power prices are very much linked to weak economic conditions. Weak economic conditions have reduced the demand for power and other energy commodities. Ameren believes that when the economy recovers, these prices should rise. In the meantime, Ameren continues to look for opportunities to prudently reduce operating and capital spending in the Merchant Generation business, as well as protect and enhance margins. Ameren’s Merchant Generation business output is significantly hedged over the next few years. Such hedging protects credit quality and reduces earnings and cash flow volatility. In addition, Ameren continues to focus on providing value-added electricity products to the market.
Leveraging Ameren’s competitive merchant generating assets, Marketing Company has a track record of enhancing margins through sales to wholesale and retail customers. To strengthen Merchant Generation’s ability to successfully weather current lower power prices, Ameren has reduced planned operating and capital spending, improving the cash flow outlook for the Merchant Generation business. Ameren continues to evaluate Merchant Generation’s spending plans in light of changing technologies, power prices and delivered fuel costs in order to ensure that the lowest cost options are identified in terms of both capital and ongoing operating costs.
Earnings
Ameren reported net income of $612 million, or $2.78 per share, for 2009 compared with net income of $605 million, or $2.88 per share, in 2008. Factors contributing to the 10 cent decline in earnings per share in 2009 compared with 2008 included lower electricity and natural gas sales in Ameren’s rate-regulated businesses and lower margins in its Merchant Generation business, as a result of weak economic conditions, milder 2009 weather and, in the Missouri Regulated business, the impact of reduced sales to Noranda. Higher depreciation and interest expense, the absence in 2009 of the benefit of a lump-sum payment from a coal supplier for higher fuel costs in 2009 as a result of a premature mine closure and contract termination, and an increased average number of common shares outstanding also affected comparative results. Offsetting factors included new utility rates in Illinois and Missouri, favorable unrealized MTM activity on derivatives, and lower operations and maintenance expenses due, in part, to the absence of a refueling and maintenance outage at the Callaway nuclear plant in 2009.
Liquidity
As a result of turmoil in the capital and credit markets in 2008 and 2009, we sought to improve our liquidity position. We replaced and extended the expiration of our credit facilities and sought to reduce our reliance on borrowings from these credit facilities, increase cash balances and increase the equity content of our capitalization. We also sought to eliminate debt at CILCORP as a step in simplifying our organizational structure. In addition, Ameren also reduced planned spending, headcount and capital investment across the company to mitigate the negative impact on sales of a weak economy and related power prices. At December 31, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $1.9 billion, which was $0.6 billion more than it had at the end of 2008. Cash flows from operations of $2.0 billion in 2009 at Ameren, along with other funds, were used to pay dividends to common shareholders of $338 million and to fund capital expenditures of $1.7 billion.
Capital Spending
During 2009, Ameren was able to significantly defer or reduce planned capital spending, including spending for environmental compliance, compared with previous plans.
Between 2010 and 2017, Ameren expects that certain Ameren Companies will be required to make cumulative investments of between $1.6 billion and $1.9 billion to retrofit their coal-fired power plants with pollution control equipment in compliance with existing emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and higher ongoing operating expenses. Approximately 20% of this investment is expected to be in Ameren’s Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers, but subject to prudency reviews.
Initiatives to limit greenhouse gas emissions and to address global climate change are subject to active consideration in the U.S. Congress. Although we cannot predict the date of enactment or the requirements of any future climate change legislation or regulations, we believe it is possible that some form of federal legislation or regulations to control emissions of greenhouse gases will become law during President Obama’s administration. Potential impacts from the climate change legislation could vary depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing allowances, the degree to which offsets are allowed and available, 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. Moreover, to the extent Ameren requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these 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 it could lead to possible impairment of assets and reduced revenues. 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 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, as the case may be, rate-regulated electric generation, transmission, and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. See Note 1 - Summary of Significant Accounting Policies 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 merchant electric generation business in Illinois and Missouri.

CILCO operates a rate-regulated electric transmission and distribution business, a merchant electric generation business (through its subsidiary, AERG), and a rate-regulated natural gas transmission and distribution business, all 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. Merchant 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 have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery service businesses, purchased power cost recovery mechanisms for our Illinois electric delivery service businesses, and a FAC for our Missouri electric utility business. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, for a discussion of pending rate cases in Missouri and Illinois, including UE’s request for approval to implement an environmental cost recovery mechanism and to continue its FAC. 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 and 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.
Net income attributable to Ameren Corporation was $612 million, or $2.78 per share, for 2009, $605 million, or $2.88 per share for 2008, and $618 million, or $2.98 per share, for 2007.
Net income attributable to Ameren Corporation increased $7 million and its earnings per share decreased 10 cents in 2009 compared with 2008. Net income attributable to Ameren Corporation increased in the Illinois Regulated and Missouri Regulated segments by $92 million and $25 million, respectively, in 2009 compared with 2008, while net income attributable to Ameren Corporation in the Merchant Generation segment decreased by $105 million in 2009 compared with 2008.
Compared with 2008 earnings, 2009 earnings were negatively affected by:

higher dilution and financing costs (31 cents per share);

the impact on electric and natural gas margins in our rate-regulated businesses of higher net fuel costs at UE and lower demand (exclusive of weather impacts), among other things (30 cents per share);

the absence in 2009 of the benefit of a settlement agreement reached with a coal mine owner that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation incurred in 2008 and 2009 due to the premature closure of an Illinois mine and contract termination (18 cents per share);

the impact of milder weather conditions on energy demand (estimated at 15 cents per share);

increased depreciation and amortization expenses (12 cents per share);

reduced sales to Noranda because of an extended storm-related outage (11 cents per share);

the absence in 2009 of a MoPSC rate order establishing two separate regulatory assets for previously incurred storm and MISO related costs (11 cents per share);

increased expense related to work force reductions through voluntary and involuntary separation programs and asset impairment charges recorded primarily at Genco in 2009 (7 cents per share);

increased taxes other than income taxes, primarily because of higher property taxes (6 cents per share);

lower realized electric margins in the Merchant Generation segment largely due to lower sales volumes and higher fuel and related transportation costs (5 cents per share); and

increased distribution system reliability expenditures (5 cents per share).
Compared with 2008 earnings, 2009 earnings were favorably affected by:

higher electric and natural gas delivery service rates, effective October 1, 2008, in the Illinois Regulated segment pursuant to an ICC consolidated rate order for
CIPS, CILCO and IP (40 cents per share);

higher electric rates, effective March 1, 2009, in the Missouri Regulated segment pursuant to a MoPSC rate order (40 cents per share);

favorable net unrealized MTM activity on derivatives and from changes in the market value of investments used to support Ameren’s deferred compensation plans (21 cents per share);

decreased plant operations and maintenance expense (15 cents per share);

the absence in 2009 of a Callaway nuclear plant refueling and maintenance outage (9 cents per share);

the absence in 2009 of asset impairment charges recorded to adjust the carrying value of CILCO’s (through AERG) Indian Trails and Sterling Avenue generating facilities to their estimated fair values as of December 31, 2008 (6 cents per share); and

the reduced impact in 2009 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the 2007 Illinois Electric Settlement Agreement (5 cents per share).
The cents per share information presented above is based on average shares outstanding in 2008.
Net income attributable to Ameren Corporation decreased $13 million and its earnings per share decreased 10 cents in 2008 compared with 2007. Net income attributable to Ameren Corporation increased in the Merchant Generation segment by $71 million in 2008 compared with 2007, while net income attributable to Ameren Corporation 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 MTM 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 MTM 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);

the impact of unfavorable milder weather conditions on energy demand (estimated at 16 cents per share);

net unrealized MTM losses on nonqualifying hedges (11 cents per share);

higher dilution and financing costs (10 cents per share);

asset impairment charges recorded 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 expenses (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 Merchant Generation segment;

the absence in 2008 of costs 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 2007 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);

the benefit of 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 expected to incur in 2009 due to the premature closure of an Illinois mine and contract termination (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.
Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCO 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, 2009, 2008 and 2007:
(a) Includes earnings from a 40% interest in EEI through February 29, 2008.
(b) Includes earnings from other merchant generation, including CILCORP, as well as corporate, general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI through 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, 2009, 2008 and 2007:
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2009, 2008, and 2007. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural 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.
2009 versus 2008
Ameren
Ameren’s electric margins decreased by $23 million, or 1%, in 2009 compared with 2008. The following items had an unfavorable impact on Ameren’s electric margins:

Higher net fuel expense at UE of $20 million resulting from lower off-system revenues ($89 million), offset, in part, by lower fuel-generation and other ($21 million) and purchased power ($48 million).

Net unrealized MTM activity in the Merchant Generation segment of $110 million (Marketing Company net loss of $112 million and EEI net gain of $2 million) on energy transactions, primarily related to nonqualifying hedges of changes in market prices for electricity.

Higher fuel expense at Genco as a result of its June 2008 settlement agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a coal supply contract. This payment compensated Genco, in total, for higher fuel costs it incurred throughout 2008 ($33 million) and 2009 ($27 million). Because the entire settlement was recorded in earnings in 2008, Ameren’s earnings in
2009 were comparatively lower than they otherwise would have been.

Excluding the impact of the June 2008 settlement agreement, 5% higher fuel prices in the Merchant Generation segment.

Reduced sales by UE to Noranda, due to an extended severe storm-related outage, which lowered electric revenues by $50 million in 2009. See Outlook for additional information on the Noranda plant outage.

Unfavorable weather conditions, as evidenced by a 7% reduction in cooling degree-days, which decreased margins by $43 million.

Excluding the impact of UE’s reduced sales to Noranda, lower weather-normalized end-use retail sales volume of 4% in Ameren’s rate-regulated utilities, largely a result of the economic slowdown, which decreased margins by $23 million.

Decreased power plant utilization in the Merchant Generation segment, primarily because of lower market prices, which resulted in fewer opportunities for economic sales, and transmission congestion, which limited the period when power could be sold. Merchant Generation’s baseload, coal-fired generating plants’ equivalent availability factors were 81% in 2009,
compared with 85% in 2008, and the average capacity factor was 66% in 2009, compared with 76% in 2008.
The following items had a favorable impact on Ameren’s electric margins for 2009 compared with 2008:

Higher electric rates at UE, effective March 1, 2009, which increased margins by $141 million, and at the Ameren Illinois Utilities, effective October 1, 2008, which increased margins by $88 million.

Net unrealized MTM activity at UE of $58 million on energy and fuel-related transactions. During 2009 UE reversed and deferred as regulatory assets previously recorded net MTM losses of $42 million on energy and fuel-related transactions in the first quarter of 2009, when these costs became probable of recovery because of the FAC. See Note 7 - Derivative Financial Instruments under Part II, Item 8, of this report, for additional information.

Net unrealized MTM activity at the Merchant Generation segment of $55 million (Genco - $33 million, CILCO - $7 million, EEI - $15 million) on fuel-related transactions. These were primarily associated with financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts.

The repricing of wholesale and retail electric power supply agreements and financial swaps that settled at higher margins at Merchant Generation.

Higher wholesale sales margins at UE of $32 million because of additional customers and higher-priced wholesale sales contracts. Power was available for sale to wholesale customers as a result of reduced native load demand.

The recovery of power supply costs incurred by the Ameren Illinois Utilities of $7 million, including an increase in Supply Cost Adjustment (SCA) factors as approved in the 2008 ICC electric rate order.

A $15 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.

Higher Callaway nuclear plant availability due to the absence of a 30-day planned maintenance outage, which occurred in the fourth quarter of 2008.
Ameren’s natural gas margins increased by $17 million, or 4%, in 2009 compared with 2008. The following items had a favorable impact on Ameren’s natural gas margins:

The Ameren Illinois Utilities’ net gas delivery service rate increase, effective October 1, 2008, which increased margins by $34 million.

The absence of net unrealized MTM losses at CILCO of $12 million in 2009 on natural gas swaps.
The following items had an unfavorable impact on Ameren’s natural gas margins in 2009 compared with 2008:

Unfavorable weather conditions, as evidenced by an 8% reduction in heating degree-days, which decreased margins by $7 million.

7% lower weather-normalized sales volumes, largely a result of the economic slowdown, which decreased margins by $9 million.

The absence of the capitalization of nonrecoverable purchased gas costs in accordance with the September 2008 ICC gas rate order, which resulted in a one-time increase in margins of $5 million in 2008.
Missouri Regulated (UE)
UE’s electric margins increased $59 million, or 3%, in 2009 compared with 2008. The following items had a favorable impact on UE’s electric margins:

Higher electric rates, effective March 1, 2009, which increased margins by $141 million.

Net unrealized MTM activity of $58 million on energy and fuel-related transactions. During 2009 UE reversed and deferred as regulatory assets previously recorded net MTM losses of $42 million on energy and fuel-related transactions in the first quarter of 2009, when these costs became probable of recovery because of the FAC. See Note 7 - Derivative Financial Instruments under Part II, Item 8, of this report, for additional information.

Higher wholesale sales margins of $32 million due to additional customers and higher-priced wholesale sales contracts. Power was available for sale to wholesale customers as a result of reduced native load demand.

Higher Callaway nuclear plant availability due to the absence of a 30-day planned maintenance outage, which occurred in the fourth quarter of 2008.
The following items had an unfavorable impact on UE’s electric margins in 2009 compared with 2008:

Higher net fuel expense of $20 million resulting from lower off-system revenues ($89 million), offset, in part, by lower fuel-generation and other ($21 million) and purchased power ($48 million).

Reduced sales to Noranda, due to an extended severe storm-related outage, which lowered electric revenues by $50 million. See Outlook for additional information on the Noranda plant outage.

Unfavorable weather conditions, as indicated by a 13% reduction in cooling degree-days during the third quarter, which is UE’s peak cooling period, and a mild winter, which decreased margins by $29 million.

Excluding the impact of reduced sales to Noranda, 2% lower weather-normalized end-use retail sales volumes, largely a result of the economic slowdown, which decreased margins by $18 million.

The absence in 2009 of the benefits from a MoPSC order that directed the recording of a regulatory asset related to previously incurred costs for a 2007 FERC order, which decreased margins by $12 million.
UE’s natural gas margins decreased by $5 million, or 6%, in 2009 compared with 2008, primarily because of an 8% decrease in weather-normalized sales volumes in 2009.
Illinois Regulated
Illinois Regulated’s electric margins increased by $69 million, or 8%, in 2009 compared with 2008. Illinois Regulated’s natural gas margins increased by $17 million, or 5%, in 2009 compared with 2008. The Ameren Illinois
Utilities have a cost recovery mechanism for power purchased on behalf of their customers. These pass-through power costs do not affect margins; however, the electric revenues and offsetting purchased power costs fluctuate primarily because of customer switching and usage. See below for explanations of electric and natural gas margin variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margins increased by $11 million, or 4%, in 2009 compared with 2008. The following items had a favorable impact on electric margins:

Higher electric delivery service rates, effective October 1, 2008, which increased margins by $17 million in 2009.

The recovery of power supply costs incurred of $2 million, including an increase in the SCA factors, as approved in the 2008 ICC electric rate order.

A $2 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
The following items had an unfavorable impact on CIPS’ electric margins in 2009 compared with 2008:

Net transmission margins that were $4 million lower, primarily because of reduced transmission service rates that were based on lower transmission costs in the prior year.

Unfavorable weather conditions, as evidenced by a 7% reduction in cooling degree-days, which decreased margins by $3 million.
CIPS’ natural gas margins increased by $1 million, or 1%, in 2009 compared with 2008. This was primarily due to higher gas delivery service rates, effective October 1, 2008, which increased margins by $7 million.
The following items had an unfavorable impact on CIPS’ natural gas margins in 2009 compared with 2008:

Unfavorable weather conditions, as evidenced by an 8% reduction in heating degree-days, which decreased margins by $1 million.

3% lower weather-normalized sales volumes for 2009, largely a result of the economic slowdown, which decreased margins by $2 million.

The absence of the capitalization of nonrecoverable purchased gas costs in accordance with the September 2008 ICC gas rate order, which resulted in a one-time increase in margins of $1 million in 2008.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margins by segment to CILCO’s total change in electric margins for 2009 compared with 2008:
CILCO’s (Illinois Regulated) electric margins decreased by $8 million, or 5%, in 2009 compared with 2008. The following items had an unfavorable impact on electric margins:

Lower electric delivery service rates, effective October 1, 2008, which decreased margins by $2 million.

Unfavorable weather conditions, as evidenced by a 25% reduction in cooling degree-days, which decreased margins by $4 million.

10% lower weather-normalized sales volumes, primarily in the lower-margin industrial customer sector, largely a result of the economic slowdown, which decreased margins by $1 million.
CILCO’s (Illinois Regulated) electric margins were favorably affected in 2009 compared with 2008 by:

The recovery of power supply costs incurred of $1 million, including an increase in the SCA factors, as approved in the 2008 ICC electric rate order.

A $1 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
See Merchant Generation below for an explanation of CILCO’s (AERG) electric margins in 2009 compared with 2008.
CILCO’s (Illinois Regulated) natural gas margins decreased by $3 million, or 3%, in 2009 compared with 2008. CILCO’s natural gas margins were unfavorably affected by:

12% lower weather-normalized sales volumes and lower realized prices related to a contract with a large industrial customer for 2009, largely a result of the economic slowdown, which decreased margins by $8 million.

Lower gas delivery service rates, effective October 1, 2008, which decreased margins by $6 million.

Unfavorable weather conditions, as evidenced by a 5% reduction in heating degree-days, which decreased margins by $1 million.
CILCO’s natural gas margins were favorably affected in 2009 compared with 2008 by the absence of net unrealized MTM losses of $12 million in 2009 on natural gas swaps.
IP
IP’s electric margins increased by $66 million, or 16%, in 2009 compared with 2008. The following items had a favorable impact on electric margins:

Higher electric delivery service rates, effective October 1, 2008, which increased margins by $73 million.

The recovery of power supply costs incurred of $4 million, including an increase in the SCA factors, as approved in the 2008 ICC electric rate order.

A $2 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
IP’s electric margins were unfavorably affected in 2009 compared to 2008 by:

Unfavorable weather conditions, as evidenced by a 12% reduction in cooling degree-days, which decreased margins by $7 million.

4% lower weather-normalized sales volumes, primarily in the lower-margin industrial customer sector, largely as a result of the economic slowdown, which decreased margins by $6 million.
IP’s natural gas margins increased by $23 million, or 14%, in 2009 compared with 2008. This was primarily due to higher gas delivery service rates, effective October 1, 2008, which increased margins by $33 million.
The following items had an unfavorable impact on IP’s natural gas margins in 2009 compared with 2008:

Unfavorable weather conditions, as evidenced by an 8% reduction in heating degree-days, which decreased margins by $4 million.

The absence of the capitalization of nonrecoverable purchased gas costs in accordance with the September 2008 ICC gas rate order, which resulted in a one-time increase in margins of $4 million in 2008.

4% lower weather-normalized sales volumes, largely a result of the economic slowdown, which decreased margins by $3 million.
Merchant Generation
Merchant Generation’s electric margins decreased by $176 million, or 15%, in 2009 compared with 2008.
Genco
Genco’s electric margins decreased by $19 million, or 3%, in 2009 compared with 2008. The following items had an unfavorable impact on electric margins:

Decreased power plant utilization, primarily due to lower market prices, which resulted in fewer opportunities for economic sales, and transmission congestion, which limited the period when power could be sold. In addition, one of Genco’s coal-fired power plants experienced a transformer fire in September 2009, which put two units out of service for a period of time. This contributed to a reduction in Genco’s baseload coal-fired generating plants’ equivalent availability factor to 81% in 2009, compared with 86% in 2008. Genco’s average capacity factor also decreased to 60% in 2009, compared with 73% in 2008.

Lower revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company, which were because of lower reimbursable expenses and lower generation relative to AERG in accordance with the Genco PSA, partially offset by financial swaps settling at higher margins and new higher-priced wholesale and retail electric power supply agreements.

Higher fuel expense as a result of Genco’s June 2008 settlement agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a coal supply contract. This payment compensated Genco, in total, for higher fuel costs it incurred throughout 2008 ($33 million) and 2009 ($27 million). Because the entire settlement was recorded in earnings in the second quarter of 2008,
Genco’s earnings in 2009 were comparatively lower than they otherwise would have been.

Excluding the impact of the June 2008 settlement agreement, 3% higher fuel prices.
Genco’s electric margins were favorably affected in 2009 compared with 2008 by:

Net unrealized MTM activity of $33 million on fuel-related transactions. These were primarily associated with financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts.

Lower emission allowance costs because of lower prices and reduced generation increased margins by $11 million.

A $7 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
CILCO (AERG)
AERG’s electric margins increased by $94 million, or 43%, in 2009 compared with 2008. The following items had a favorable impact on electric margins:

Higher revenues allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company, which were because of higher reimbursable expenses and higher generation relative to Genco in accordance with the AERG PSA. AERG’s baseload coal-fired generating plants’ equivalent availability and average capacity factors were comparable to 2008. Financial swaps also settled at higher margins, and new higher-priced wholesale and retail electric power supply agreements increased revenues.

Net unrealized MTM activity of $7 million on fuel-related transactions. These were primarily associated with financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts.

Oil consumption was lower because of fewer plant startups and lower oil prices in 2009, reducing costs by $6 million.

A $3 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
Other Merchant Generation
Electric margins from Ameren’s other Merchant Generation operations, primarily EEI and Marketing Company, decreased by $251 million, or 66%, in 2009. Other Merchant Generation electric margins were unfavorably affected, compared with 2008, by:

Decreased power plant utilization, primarily because of lower market prices, which resulted in fewer opportunities for economic sales, and plant outages. The average realized sales price for power including hedging decreased by 27%. EEI’s baseload coal-fired generating plant’s equivalent availability and average capacity factors were 88% and 81%, respectively, in 2009, compared with 92% and 91%, respectively, in 2008.

27% higher fuel prices at EEI because of an increase in transportation costs.

Net unrealized MTM activity (mostly at Marketing Company) of $95 million on energy and fuel-related transactions. These were primarily associated with financial instruments that related to nonqualifying hedges of changes in market prices for electricity.
2008 versus 2007
Ameren
Ameren’s electric margins increased by $153 million, or 4%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s electric margins:

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

Increased Merchant Generation plant availability due to the lack of an extended plant outage in 2008. Merchant 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.

Higher electric rates at the Ameren Illinois Utilities, effective October 1, 2008, which increased margins by $27 million and higher electric rates at UE, effective June 4, 2007, increased margins by $16 million.

A $35 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.

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 margins in 2008 of these items was $30 million.

Lower fuel expense at Genco as a result of a settlement agreement with a coal mine owner reached in June 2008, which increased margins by $27 million. Genco received a lump-sum payment for increased costs for coal and transportation that it expected to incur in 2009 because of the premature closure of an Illinois mine and contract termination.

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

Merchant Generation emission allowance costs were reduced by $8 million.

Merchant Generation capacity sales increased by $6 million.
The following items had an unfavorable impact on Ameren’s electric margins in 2008 compared with 2007:

Net unrealized MTM losses of $75 million on fuel-related transactions. These were primarily associated with 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
margins by $65 million. Compared with normal weather, cooling degree-days in 2008 were 5% lower.

6% higher fuel prices.

Lower off-system margins due to reduced UE plant availability, partially offset by an 8% increase in realized prices and a 10% increase in hydroelectric generation. Reduced Callaway nuclear plant availability was due to 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 natural gas margins increased by $36 million, or 9%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s natural gas margins:

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

Higher net gas rates at the Ameren Illinois Utilities, effective October 1, 2008, which increased margins by $4 million, and higher net gas rates at UE, effective April 2007, which increased margins 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 margins by $9 million.

Increased weather-normalized sales volumes of 2% and favorable customer sales mix, which increased margins by $5 million.

Transportation revenues increased by $4 million.
Missouri Regulated (UE)
UE’s electric margins decreased $62 million, or 3%, in 2008 compared with 2007. The following items had an unfavorable impact on UE’s electric margins:

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

Net unrealized MTM losses of $39 million on fuel-related transactions. These were primarily associated with 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.

5% higher fuel prices.

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

Lower off-system margins because of reduced plant availability, partially offset by an 8% increase in realized prices and a 10% increase in hydroelectric generation. Callaway nuclear plant availability was reduced because of 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 had a favorable impact on electric margins in 2008 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 margins in 2008 of these items was $23 million.

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

Higher electric rates, effective June 4, 2007, which increased margins by $16 million.

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

Higher gas rates, effective April 2007, which increased margins by $3 million.

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

Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, which increased margins by $2 million.
Illinois Regulated
Illinois Regulated’s electric margins increased by $58 million, or 8%, and natural gas margins 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 affect margins; however, the electric revenues and offsetting purchased power costs fluctuate primarily because of customer switching and usage. See below for explanations of electric and natural gas margins variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margins increased by $14 million, or 6%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:

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

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

A $6 million reduced impact of the 2007 Illinois Electric Settlement Agreement.

Higher electric delivery service rates, effective October 1, 2008, which increased margins 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 margins by $6 million.
CIPS’ natural gas margins increased by $7 million, or 10%, in 2008 compared with 2007. The following items had a favorable impact on natural gas margins:

Favorable customer sales mix, which increased margins by $2 million.

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

A September 2008 ICC rate order, that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased margins by $2 million.

Higher gas delivery service rates, effective in October 2008, which increased margins by $1 million.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s change in electric margins by segment to CILCO’s total change in electric margins for 2008 compared with 2007:
CILCO’s (Illinois Regulated) electric margins increased by $17 million, or 14%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:

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.

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

A $3 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 28% reduction in cooling degree-days, which decreased margins by $4 million.
See Merchant Generation below for an explanation of CILCO’s (AERG) electric margins in 2008 compared with 2007.
CILCO’s (Illinois Regulated) natural gas margins decreased $1 million, or 1%, in 2008 compared with 2007. The following items had an unfavorable impact on gas margins:

Net unrealized MTM losses on natural gas swaps of $6 million in 2008.

Lower gas delivery service rates, effective in October 2008, which decreased margins by $5 million.
The following items had a favorable impact on gas margins in 2008 compared with 2007:

5% higher weather-normalized sales volumes and favorable customer mix, which increased margins by $8 million.

Favorable weather conditions, as evidenced by an 11% increase in heating degree-days, which increased margins by $2 million.
IP
IP’s electric margins increased by $27 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:

Higher electric delivery service rates, effective October 1, 2008, which increased margins by $22 million.

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

A $7 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 34% reduction in cooling degree-days, which decreased margins by $13 million.
IP’s natural gas margins increased by $18 million, or 12%, in 2008 compared with 2007. The following items had a favorable impact on natural gas margins:

Higher gas delivery service rates, effective in October 2008, which increased margins by $8 million.

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

Favorable weather conditions, as evidenced by a 15% increase in heating degree-days, which increased margins by $6 million.
These favorable variances were partially offset by a 4% decrease in weather-normalized sales volumes, which decreased margins by $3 million.
Merchant Generation
Merchant Generation’s electric margins increased by $151 million, or 15%, in 2008 compared with 2007. Merchant 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 margins variances for the Merchant Generation segment.
Genco
Genco’s electric margins increased by $82 million, or 16%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:

Lower fuel expense at Genco as a result of a settlement agreement with a coal mine owner reached in June 2008, which increased margin by $27 million. Genco received a lump-sum payment for increased costs for coal and transportation that it expected to incur in 2009 because of the premature closure of an Illinois mine and contract termination.

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

Purchased power costs were reduced by $17 million due to the absence of MISO resettlement costs experienced in early 2007.

A $13 million reduction in the 2007 Illinois Electric Settlement Agreement.

Gains on the sales of excess oil and off-system natural gas increased margins by $12 million.

Replacement power insurance recoveries were $9 million higher 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 margins in 2008 compared with 2007:

Excluding the impact of the June 2008 settlement agreement, 2% higher fuel prices.

Net unrealized MTM losses of $18 million on fuel-related transactions. These were primarily associated with 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.

MISO-related revenues were $12 million lower 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.

A $9 million decrease in revenues because of 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 Party Transactions to our financial statements under Part II, Item 8, of this report, for additional information.
CILCO (AERG)
AERG’s electric margins increased by $12 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margins:

Increased revenue allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company. Revenues from the AERG PSA increased 24% primarily because of 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.

A $6 million reduction in the impact of the 2007 Illinois Electric Settlement Agreement.
The following items had an unfavorable impact on electric margins in 2008 compared with 2007:

30% higher fuel prices, 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.

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

Net unrealized MTM losses of $3 million on fuel-related transactions. These were primarily associated with 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.
Other Merchant Generation
Electric margins from Ameren’s other Merchant Generation operations, primarily from EEI and Marketing Company, increased by $57 million, or 18%, in 2008. Other Merchant Generation electric margins were unfavorably affected compared with 2007 by:

9% higher fuel prices.

Net unrealized MTM losses of $8 million on fuel-related transactions. These were primarily associated with 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.
Other Merchant Generation electric margins were favorably affected by market price fluctuations during 2008, which resulted in nonaffiliated MTM gains on energy transactions of $73 million, primarily related to nonqualifying hedges of changes in market prices for electricity.
Other Operations and Maintenance Expenses
2009 versus 2008
Ameren
Other operations and maintenance expenses decreased $119 million in 2009 compared with 2008 because of several factors. Coal-fired plant maintenance costs were reduced by $48 million and bad debt expenses were lower by $44 million, because of elevated levels of bad debt expense in 2008 as a result of the transition to higher market-based rates at the Ameren Illinois Utilities and the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs) discussed in Note 2 - Rate and Regulatory Matters under Part II, Item 8 of this report. A favorable change of $37 million in unrealized net MTM adjustments between periods resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans and the absence of a Callaway
nuclear plant refueling and maintenance outage in 2009, as compared with costs of $30 million in 2008, also reduced operations and maintenance expenses. Additionally, asset impairment charges were lower by $7 million between years.
Reducing the benefit of these items was an increase of $24 million in labor costs and the recognition of $17 million for employee severance costs in 2009. In 2008, other operations and maintenance expenses were reduced by a MoPSC accounting order related to storm costs incurred in 2007, which resulted in UE recording a regulatory asset of $25 million; no similar item occurred in 2009.
Variations in other operations and maintenance expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Other operations and maintenance expenses decreased $42 million. This was primarily because of a $32 million reduction in coal-fired plant maintenance costs and the absence of a Callaway nuclear plant refueling and maintenance outage in 2009, as compared with costs of $30 million in 2008. A favorable change of $19 million in unrealized net MTM adjustments between periods, which resulted from changes in the market value of investments used to support Ameren’s deferred compensation plans, and a $14 million decline in employee benefit costs also resulted in decreased expenses between years.
Reducing the benefit of these items was a $21 million increase in labor costs, the recognition of $8 million in employee severance costs in 2009, and the absence of the MoPSC storm cost accounting order of $25 million that occurred in 2008, as described above. In addition to these items, storm repair expenditures were higher in 2009 as a result of a severe ice storm at the beginning of the year.
Illinois Regulated
Other operations and maintenance expenses decreased $77 million in the Illinois Regulated segment, as discussed below.
CIPS
Other operations and maintenance expenses decreased $15 million, primarily because of a $10 million reduction in bad debt expense, because of elevated levels of bad debt expense in 2008 and the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs), and a favorable change in unrealized net MTM adjustments between periods resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.
CILCO (Illinois Regulated)
Other operations and maintenance expenses increased $63 million, primarily because of higher labor and employee benefit costs. These increases were primarily a result of work performed on behalf of CIPS and IP as discussed below.
At the beginning of 2009, approximately 570 employees were transferred from Ameren Services to CILCO (Illinois Regulated), which resulted in an increase in other operations and maintenance expenses at CILCO (Illinois Regulated) in 2009. These CILCO (Illinois Regulated) employees also provide support services to CIPS and IP. CILCO (Illinois Regulated) records reimbursements from CIPS and IP for work performed by its employees on their behalf as Operating Revenues - Support Services - Affiliates on its statement of income, which increased $70 million in 2009 compared with 2008. Intercompany revenue and expenses associated with these transactions are eliminated in consolidation within the Illinois Regulated segment. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information on CILCO (Illinois Regulated) support services.
Reducing the unfavorable effect of the above items was a reduction in bad debt expense, because of elevated levels of bad debt expense in 2008 and the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs).
IP
IP’s other operations and maintenance expenses decreased $43 million, primarily because of a $25 million reduction in bad debt expense, because of elevated levels of bad debt expense in 2008 and the impact of the Illinois bad debt rate adjustment mechanism (net of a related donation for customer assistance programs), a $6 million decrease in distribution system reliability expenditures, including reduced storm costs, and a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans.
Merchant Generation
Other operations and maintenance expenses decreased $16 million in the Merchant Generation segment, as discussed below.
Genco
Genco’s other operations and maintenance expenses were comparable between years as employee severance costs and expenses recognized for the termination of a rail line extension project were reduced by lower plant maintenance costs.
CILCO (AERG)
Other operations and maintenance expenses decreased $22 million, primarily because of a $9 million reduction in plant maintenance costs and an $11 million reduction in asset impairment charges between years.
EEI
EEI’s other operations and maintenance expenses increased $10 million, primarily because of higher plant maintenance costs.
2008 versus 2007
Ameren
Ameren’s other operations and maintenance expenses increased $170 million in 2008 compared with 2007. Labor costs increased by $52 million and plant maintenance expenditures at coal-fired plants were higher by $43 million due to outages. A $30 million increase in distribution system reliability expenditures and a $10 million increase in information technology costs also resulted in higher expenses. An unfavorable change of $22 million in unrealized net MTM adjustments resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans reduced expenses between years. Bad debt expense increased by $10 million, primarily because of the 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. There was no similar item in 2008.
Other operations and maintenance expenses also 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 was 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 was a reduction of $10 million in employee benefit costs, due to changes in actuarial estimates, and an $18 million decrease in storm expenditures, primarily in UE’s service territory. 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 2008 by the MoPSC accounting order related to 2007 storms, as discussed above.
Variations in other operations and maintenance expenses in Ameren’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 were higher by $22 million, primarily because of a $37 million increase in labor costs and a $29 million increase in plant maintenance expenditures at coal-fired plants. An unfavorable
change in unrealized net MTM adjustments resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans and a $16 million increase in distribution system reliability expenditures also resulted in incremental expenses.
Reducing the impact of these items were 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 nuclear plant refueling and maintenance outage in 2008 compared with the refueling in 2007. Storm repair expenditures also decreased by $31 million, further reducing other operations and maintenance expenses.
Illinois Regulated
Other operations and maintenance expenses increased $77 million in the Illinois Regulated segment, as discussed below.
CIPS
Other operations and maintenance expenses increased $24 million. The increase was primarily because of an $11 million increase in distribution system reliability expenditures, including storm costs, along with increased labor costs and bad debt expense. Additionally, in the first quarter of 2007, CIPS reversed an accrual of $4 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. There was no similar item in 2008.
CILCO (Illinois Regulated)
Other operations and maintenance expenses were higher by $8 million, primarily because of a $5 million increase in storm costs in 2008. Additionally, in the first quarter of 2007, CILCO (Illinois Regulated) reversed an accrual of $3 million established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions. There was 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, due, in part, to a $17 million increase in distribution system reliability expenditures, including storm costs. Labor costs and bad debt expense increased by $6 million each, and unrealized net MTM adjustments resulting from changes in the market value of investments used to support Ameren’s 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. There was no similar item in 2008. Reducing the unfavorable effect of these items was a reduction in employee benefit costs.
Merchant Generation
Other operations and maintenance expenses increased $43 million in the Merchant Generation segment, as discussed below.
Genco
Other operations and maintenance expenses increased $12 million at Genco. Plant maintenance costs were higher by $9 million, due to scheduled outages, and labor costs increased by $5 million. Genco paid $3 million to the IPA in 2007 as part of the 2007 Illinois Electric Settlement Agreement. There was no similar item in 2008.
CILCO (AERG)
Other operations and maintenance expenses increased $25 million at CILCO (AERG), primarily because of a $12 million impairment charge recorded in 2008 related to the Indian Trails cogeneration plant discussed above. Plant maintenance costs increased by $7 million, due to scheduled outages, and labor costs increased by $3 million. CILCO (AERG) paid $1.5 million to the IPA in 2007 as part of the 2007 Illinois Electric Settlement Agreement. There was no similar item in 2008.
EEI
Other operations and maintenance expenses were comparable in 2008 and 2007.
Depreciation and Amortization
2009 versus 2008
Ameren
Ameren’s depreciation and amortization expenses increased $40 million in 2009, as compared with 2008, because of items noted below at the Ameren Companies.
Variations in depreciation and amortization expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Depreciation and amortization expenses increased $28 million, primarily because of capital additions and amortization of regulatory assets that resulted from UE’s electric rate case in 2009.
Illinois Regulated
Depreciation and amortization expenses were comparable between years 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. This resulted in reductions in depreciation expense at CIPS and CILCO (Illinois Regulated) and an increase in depreciation expense at IP. Capital additions partially offset the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further
increased depreciation and amortization expenses at IP. The net effect of the above items was an $18 million reduction in depreciation and amortization expenses at CILCO (Illinois Regulated) and a $14 million increase at IP. Depreciation and amortization expenses at CIPS were comparable between years.
Merchant Generation
Depreciation and amortization expenses increased $17 million in the Merchant Generation segment, primarily because of capital additions at CILCO (AERG) and $3 million of expense recorded by Genco in the third quarter of 2009 for the retirement of two generation units at its Meredosia power plant. Depreciation and amortization expenses were comparable at EEI between years.
2008 versus 2007
Ameren
Ameren’s depreciation and amortization expenses were comparable between periods. Increases in depreciation expense, resulting from capital additions in 2008, 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 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, 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 in 2008.
Illinois Regulated
Depreciation and amortization expenses were comparable in 2008 and 2007 in the Illinois Regulated segment. The effect of the consolidated electric and natural gas rate order issued by the ICC in 2008, as noted above, resulted in reductions in depreciation expense at CIPS and CILCO (Illinois Regulated) and an increase in depreciation expense at IP. Capital additions partially offset the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further increased depreciation and amortization expenses at IP.
Merchant Generation
Depreciation and amortization expenses increased $4 million in the Merchant Generation segment. Depreciation and amortization expenses increased $8 million at CILCO (AERG) because of capital additions in 2008. Genco’s depreciation and amortization expenses decreased $4 million, primarily because of extended useful lives resulting from a depreciation study completed in September 2007, partially
mitigated by capital additions. EEI’s depreciation and amortization expenses were comparable between years.
Taxes Other Than Income Taxes
2009 versus 2008
Ameren
Ameren’s taxes other than income taxes increased $19 million, primarily because of higher property and payroll taxes.
Variations in taxes other than income taxes in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Taxes other than income taxes increased $17 million, primarily because of higher property taxes.
Illinois Regulated
Taxes other than income taxes were comparable in 2009 and 2008 in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated), and IP.
Merchant Generation
Taxes other than income taxes were comparable between years in the Merchant Generation segment and at Genco, CILCO (AERG) and EEI.
2008 versus 2007
Ameren
Ameren’s taxes other than income taxes increased $12 million, 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 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, primarily because of higher property taxes.
Illinois Regulated
Taxes other than income taxes increased $5 million 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.
Merchant Generation
Taxes other than income taxes were comparable in 2008 and 2007 in the Merchant Generation segment and for Genco, CILCO (AERG) and EEI.
Other Income and Expenses
2009 versus 2008
Ameren
Other income and expenses were comparable in 2009 and 2008. Miscellaneous expenses decreased as expenses associated with energy efficiency and customer assistance programs under the 2007 Illinois Electric Settlement Agreement were lower in 2009. However, miscellaneous income declined because of reduced interest income, partially offset by increased allowance for funds used during construction.
Variations in other income and expenses in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Other income and expenses were comparable between periods.
Illinois Regulated
Other income and expenses decreased $9 million in the Illinois Regulated segment, and decreased at both CIPS and IP, primarily because of lower interest income. Decreased expenses associated with energy efficiency and customer assistance programs under the 2007 Illinois Electric Settlement Agreement mitigated this decrease. Other income and expenses at CILCO (Illinois Regulated) were comparable in 2009 and 2008.
Merchant Generation
Other income and expenses were comparable between years in the Merchant Generation segment and at Genco, CILCO (AERG) and EEI.
2008 versus 2007
Ameren
Other income and expenses were comparable in 2008 and 2007. Miscellaneous income increased $5 million, primarily because of an increase at UE in allowance for funds used during construction, reduced by lower interest income. Miscellaneous expense increased $6 million, primarily because of increased expenses associated with contributions to social programs.
Variations in other income and expenses in Ameren’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, primarily because of an increase in allowance for funds used during construction. This increase resulted from higher rates and increased construction work in progress balances. Miscellaneous expense was comparable between years.
Illinois Regulated
Other income and expenses decreased $9 million in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, primarily because of lower interest income.
Merchant Generation
Other income and expenses in the Merchant Generation segment and at Genco, CILCO (AERG) and EEI were comparable in 2008 and 2007.
Interest Charges
2009 versus 2008
Ameren
Ameren’s interest charges increased $68 million because of items noted below at the Ameren Companies and because of the issuance of $425 million of senior notes at Ameren in May 2009.
Variations in interest charges in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Interest charges increased $36 million, primarily because of the issuance of $350 million, $450 million, and $250 million of senior secured notes in March 2009, June 2008, and April 2008, respectively. The amortization of fees related to new credit facilities entered into in the second quarter of 2009 also increased interest charges. The majority of the fees related to the new credit facilities are being amortized over a two-year period. Additionally, a reversal in interest charges previously accrued on uncertain tax positions due to favorable income tax settlements in 2008, with no similar item in 2009, had a negative impact on 2009. The maturity of $148 million of first mortgage bonds in May 2008 and refinancing of auction-rate environmental improvement revenue bonds in 2008, along with a reduction of short-term borrowings, mitigated the impact of the above items.
Illinois Regulated
Interest charges increased $9 million in the Illinois Regulated segment because of the amortization of fees related to a new credit facility entered into in the second quarter of 2009 and as a result of matters as discussed below.
CIPS
Interest charges were comparable in 2009 and 2008.
CILCO (Illinois Regulated)
Interest charges increased $8 million, primarily because of the issuance of senior secured notes of $150 million in December 2008 at a higher rate than the short-term borrowings it refinanced.
IP
Interest charges were comparable between years. Increased interest charges resulting from the issuance of senior secured notes of $400 million and $337 million in October 2008 and April 2008, respectively, was mitigated as the proceeds of these issuances were used to refinance auction-rate pollution control revenue refunding bonds, which bore default rates ranging from 12% to 18%, and to reduce short-term borrowings.
Merchant Generation
Interest charges increased $20 million in the Merchant Generation segment, because of items discussed below. Additionally, CILCORP parent company recorded amortization of fees related to new credit facilities entered into in the second quarter of 2009 and had increased intercompany borrowings.
Genco
Interest charges increased $4 million, primarily because of the issuance of $300 million of senior unsecured notes in April 2008.
CILCO (AERG)
Interest charges increased $12 million, primarily because of increased intercompany borrowings.
EEI
Interest charges were comparable between years.
2008 versus 2007
Ameren
Interest charges increased $17 million. 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. These increases were reduced by income tax settlements in 2008.
Variations in interest charges in Ameren’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated (UE)
Interest charges were comparable between periods. Interest charges associated with the issuance of senior secured notes of $450 million, $250 million, and $425 million in June 2008, April 2008, and June 2007, respectively, was
mitigated by a reduction in short-term borrowings, which were reduced with proceeds from the senior secured notes financings. The proceeds from these senior secured notes financings were also used to refinance auction-rate environmental improvement revenue refunding bonds, and to fund the maturity of $148 million of first mortgage bonds, and to reduce short-term borrowings. Additionally, interest charges were reduced by $8 million because of a reversal of interest charges previously accrued on uncertain tax positions as a result of income tax settlements in 2008.
Illinois Regulated
Interest charges increased $12 million in the Illinois Regulated segment, as discussed below.
CIPS
Interest charges decreased $7 million, primarily because of reduced short-term borrowings and a $3 million reduction from a reversal of interest charges previously accrued on uncertain tax positions as a result of an income tax settlement.
CILCO (Illinois Regulated)
Interest charges were comparable in 2008 and 2007.
IP
Interest charges increased $22 million, primarily because of the issuance of $400 million, $337 million, and $250 million of senior secured notes at IP in October 2008, April 2008, and November 2007, respectively. The $337 million senior secured notes were issued to refinance auction-rate pollution control revenue refunding bonds, while proceeds from the other debt issuances were used to reduce short-term borrowings.
Merchant Generation
Interest charges decreased $8 million in the Merchant Generation segment, as discussed below.
Genco
Interest charges were comparable between periods. Increased interest charges resulting from the issuance of $300 million of senior unsecured notes in April 2008 was mitigated by a corresponding reduction in short-term borrowings. Additionally, interest charges were reduced by $3 million as a result of an income tax settlement.
CILCO (AERG)
Interest charges decreased $4 million at CILCO (AERG), primarily because of reduced short-term borrowings.
EEI
Interest charges were comparable in 2008 and 2007.
Income Taxes
The following table presents effective income tax rates by segment for the years ended December 31, 2009, 2008, and 2007:
2009 versus 2008
Ameren
Ameren’s effective tax rate in 2009 was higher than the effective tax rate in 2008 due to variations discussed below. Variations in effective tax rates for Ameren’s and CILCO’s business segments and for the Ameren Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
UE’s effective tax rate was lower, primarily because of higher favorable net amortization of property-related regulatory assets and liabilities, partially mitigated by changes to reserves for uncertain tax positions.
Illinois Regulated
The effective tax rate was higher in the Illinois Regulated segment because of items detailed below.
CIPS
The effective tax rate increased, primarily because of the decreased impact of net amortization of property-related regulatory assets and liabilities, investment tax credit amortization, and permanent items on higher pretax book income.
CILCO (Illinois Regulated)
The effective tax rate was higher, primarily because of the decreased impact of permanent benefits, net amortization of property-related regulatory assets and liabilities, and investment tax credit amortization on higher pretax book income.
IP
The effective tax rate decreased, primarily because of the impact of permanent items on higher pretax book income, along with changes to reserves for uncertain tax positions.
Merchant Generation
The effective tax rate was higher in the Merchant Generation segment because of items detailed below.
Genco
The effective tax rate increased, primarily because of the decreased impact of Internal Revenue Code Section 199
production activity deductions, along with changes to reserves for uncertain tax positions.
CILCO (AERG)
The effective tax rate was lower, primarily because of the increased impact of Internal Revenue Code Section 199 production activity deductions, along with changes to reserves for uncertain tax positions.
versus 2007
Ameren
Ameren’s effective tax rate was comparable in 2008 and 2007. Favorable impacts of state audit settlements and changes in state apportionment were offset by unfavorable permanent items related to company-owned life insurance as well as other variations discussed below at the Ameren Companies.
Variations in effective tax rates for Ameren’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.
Missouri Regulated (UE)
The effective tax rate increased, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities, along with decreased Internal Revenue Code Section 199 production activity deductions in 2008.
Illinois Regulated
The effective tax rate decreased in the Illinois Regulated segment because of items detailed below.
CIPS
The effective tax rate was lower, primarily because of the impact of net amortization of property-related regulatory assets and liabilities and permanent items on lower pretax income in 2008.
CILCO (Illinois Regulated)
The effective tax rate was higher, primarily because of lower tax credits, lower favorable net amortization of property-related regulatory assets and liabilities, and lower favorable permanent benefits related to company-owned life insurance.
IP
The effective tax rate increased, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities, lower tax credits, and the impact of other permanent items as well as increased reserves for uncertain tax positions on lower pretax book income in 2008.
Merchant Generation
The effective tax rate decreased in the Merchant Generation segment because of items detailed below.
Genco
The effective tax rate was lower, primarily because of the increased impact of Internal Revenue Code Section 199 production activity deductions and research tax credits.
CILCO (AERG)
The effective tax rate increased, primarily because of the impact of Internal Revenue Code Section 199 production activity deductions.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be a principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial, and industrial classes and a commodity mix of natural gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to Marketing Company, which sold power through financial contracts that were part of the 2007 Illinois Electric Settlement Agreement and various power procurement processes in the non-rate-regulated Illinois market. Marketing Company also sells power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool, or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. The use of operating cash flows and credit facility or short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at December 31, 2009, for Genco and CILCO. The Ameren Companies may reduce their credit facility or short-term borrowings with cash from operations or discretionarily with long-term borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and natural gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses, of approximately 50% to 55% equity. We plan to implement our long-term financing plans for debt, equity, or equity-linked securities in order to finance our operations appropriately, meet scheduled debt maturities, and maintain financial strength and flexibility.
In 2008 and 2009, the global capital and credit markets experienced extreme volatility. See Outlook for a discussion of the implications of this volatility for our industry as a whole, including the Ameren Companies, and how we addressed these issues.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2009, 2008 and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Cash Flows from Operating Activities
2009 versus 2008
Ameren’s cash from operating activities increased in 2009 compared with 2008. Operating activities associated with the December 2005 Taum Sauk incident resulted in a $256 million increase in cash during 2009, compared with 2008. The 2009 increase was a result of a $65 million increase in insurance recoveries received as well as a $191 million reduction in cash payments compared with 2008. See Note 15 - Commitments and Contingencies under Part II, Item 8, of this report for information about
the Taum Sauk property insurance settlement agreement with all but three of the property insurance carriers and the related settlement payment received during 2009. Other factors contributing to the increase in cash from operating activities during 2009, compared with 2008, included a $198 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $97 million decrease, net of refunds, in income tax payments primarily at UE as discussed below, and an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms. Additionally, as discussed in Results of Operations, less cash was used for operations and
maintenance activities because many plant-related projects were either reduced, deferred, or cancelled as well as the absence of a Callaway nuclear plant refueling and maintenance outage in 2009. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included a $68 million increase in interest payments, a decrease in natural gas costs over-recovered from customers under the PGA, a $35 million increase in pension and postretirement plan contributions, lower electric margins, as discussed in Results of Operations, including the absence in 2009 of the 2008 lump-sum settlement payment received by Genco from a coal mine owner for the early termination of a coal supply contract, a $21 million decrease in customer advances for construction, $16 million of employee severance payments as a result of the 2009 voluntary and involuntary separation programs, an increase in annual incentive compensation payments, and an $8 million increase in cash payments for major storm restoration costs.
UE’s cash from operating activities increased in 2009 compared with 2008. The increase was primarily due to net income tax refunds of $208 million in 2009 compared with net income tax payments of $130 million in 2008, and a $256 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident, as discussed above. The significant change in income taxes is primarily a result of an acceleration of deductions due to economic stimulus legislation and a change in tax treatment of electric generation plant expenditures. Other factors contributing to the increase in cash from operating activities during 2009, compared with 2008, included a $20 million decrease in the cost of natural gas purchased for inventories because of lower prices, higher electric margins, as discussed in Results of Operations, and an increase in natural gas costs over-recovered from customers under the PGA. Additionally, as discussed in Results of Operations, less cash was used for operations and maintenance activities, because several plant-related projects were either reduced, deferred, or cancelled as well as the absence of a Callaway nuclear plant refueling and maintenance outage in 2009. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included the collection of an $85 million affiliate receivable in 2008 that did not occur in 2009, a $39 million increase in interest payments, a $16 million increase in pension and other postretirement plan contributions, a $10 million increase in energy efficiency expenditures for new customer programs, a $6 million increase in major storm restoration costs, and $6 million of employee severance payments as a result of the 2009 voluntary and involuntary separation programs.
CIPS’ cash from operating activities increased in 2009 compared with 2008. Factors contributing to the increase in cash from operating activities during 2009, compared with 2008, included a $57 million net reduction in collateral posted with suppliers due in part to improved credit ratings, a $40 million decrease in the cost of natural gas purchased for inventories because of lower prices, higher electric and natural gas margins as discussed in Results of Operations, an increase in electric costs over-recovered from customers under cost recovery mechanisms, and a $5 million decrease
in interest payments. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included net income tax payments of $24 million in 2009, compared with net income tax refunds of $21 million in 2008, a decrease in natural gas costs over-recovered from customers under the PGA, and a $5 million increase in major storm restoration costs.
Genco’s cash from operating activities decreased in 2009 compared with 2008. Factors contributing to a decrease in cash from operating activities during 2009, compared with 2008, included lower electric margins as discussed in Results of Operations, including the 2008 lump-sum settlement payment received from a coal mine owner as well as the absence of $7 million, net of premiums, of replacement power insurance recoveries received in 2008 from an affiliate as the policy was not renewed. Other factors contributing to the decrease in cash from operating activities during 2009, compared with 2008, included a $23 million increase in income tax payments, net of refunds, a $6 million increase in interest payments, and $4 million of employee severance payments as a result of the 2009 voluntary and involuntary separation programs. Factors offsetting the decrease in cash from operating activities during 2009, compared with 2008, included reduced coal purchases in 2009 as generation levels declined and a $10 million reduction in funding required by the 2007 Illinois Electric Settlement Agreement.
CILCO’s cash from operating activities increased in 2009 compared with 2008. Factors contributing to the increase in cash from operating activities during 2009, compared with 2008, included higher electric margins as discussed in Results of Operations, a $58 million decrease in the cost of natural gas purchased for inventories because of lower prices, and a $45 million net reduction in collateral posted with suppliers due in part to improved credit ratings. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included net income tax payments of $82 million in 2009, compared with net income tax refunds of $15 million in 2008, increased coal purchases to build inventories at the Duck Creek generating facility as a result of switching coal blends in 2009, a $6 million increase in pension and other postretirement plan contributions, a $6 million increase in interest payments, the absence of $5 million, net of premiums, of replacement power insurance recoveries received in 2008 from an affiliate as the policy was not renewed, a decrease in natural gas costs over-recovered from customers under the PGA, and an increase in annual incentive compensation payments.
IP’s cash from operating activities increased in 2009 compared with 2008. Factors contributing to the increase in cash from operating activities during 2009, compared with 2008, included higher electric and natural gas margins as discussed in Results of Operations, an $80 million decrease in the cost of natural gas purchased for inventories because
of lower prices, a $74 million net decrease in collateral posted with suppliers due in part to improved credit ratings, an increase in electric costs over-recovered from customers under cost recovery mechanisms, and a $3 million decrease in major storm restoration costs. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during 2009, compared with 2008, included net income tax payments of $22 million in 2009, compared with net income tax refunds of $43 million in 2008, a decrease in natural gas cost over-recovered from customers under the PGA, a $22 million increase in interest payments, and a $15 million reduction in customer advances for construction.
2008 versus 2007
Ameren’s cash from operating activities increased in 2008, compared to 2007, primarily because of higher electric and natural gas margins as discussed in Results of Operations, a $177 million decrease in income tax payments (net of refunds), and improved collections of receivables in 2008. The reduction in income tax payments was largely attributable to higher depreciation allowed for tax purposes. In 2007, receivables from the Ameren Illinois Utilities had increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential electric settlement agreement, and deterioration of collections. However, collections improved in 2008. Additionally, Ameren experienced an $87 million benefit to cash flows for 2008 as compared with 2007 because of the timing of cash receipts for MISO receivables. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared with 2007. Cash outflows in accordance with the settlement, net of reimbursements from generators, were $84 million less in 2008 than in 2007. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for a discussion of the 2007 Illinois Electric Settlement Agreement. In addition, Ameren’s cash flows from operations increased in 2008 compared with 2007 because of a $40 million reduction in storm restoration costs, over-recovery under the PGAs, and a $27 million payment received by Genco in 2008 as part of a coal contract settlement for increased costs for coal and transportation that Genco expected to incur in 2009 because of the premature closure of an Illinois mine at the end of 2007. See Note 1 - Summary of Significant Accounting Policies under Part II, Item 8, for information on the coal contract settlement. Factors that offset, in part, the favorable variance in cash flows from operations in 2008 were a $93 million increase in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries, an increase in natural gas inventories resulting from price increases, higher interest payments, and higher levels of collateral posted with suppliers.
At UE, cash from operating activities decreased in 2008, compared to 2007. The decrease is primarily due to a $24 million increase in net income tax payments in 2008, lower electric margins, increased system reliability expenditures as discussed in Results of Operations, and
higher levels of net collateral posted with suppliers. Also contributing to the unfavorable variance in 2008 was a $93 million increase in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries, and a $146 million net decrease in affiliate payables. Factors increasing cash from operations included a $34 million decrease in payments for storm restorations, a decrease in other operations and maintenance expenditures related to the Callaway nuclear plant refueling and maintenance outage in 2008 as compared with the 2007 refueling and maintenance outage, reduction in interest payments, and the collection in 2008 of an $85 million affiliate receivable. In addition, cash flows from operations increased in 2008 compared with 2007 because of the timing of cash receipts for MISO receivables.
At CIPS, cash from operating activities increased in 2008 compared with 2007. The increase was primarily due to net income tax refunds of $21 million in 2008, compared with net income tax payments of $44 million in 2007, an increase in gas cost over-recovery from customers under the PGA, a $7 million increase in customer advances for construction, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared with 2007. CIPS’ cash outflows from the settlement, net of reimbursements from generators, were $26 million less in 2008 than in 2007. CIPS experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the 2007 Illinois Electric Settlement Agreement compared with 2007. Partially offsetting the favorable variance in cash flow from operations was a larger increase in natural gas inventories in 2008 than in 2007, a decrease in electric costs over-recovered from customers, and higher net levels of collateral posted with suppliers.
Genco’s cash from operating activities decreased in 2008 compared with 2007 primarily due to an increase in fuel inventory and an increase in net income tax payments of $13 million. Reducing the unfavorable variance in cash flow from operations were higher electric margins, a payment from an Illinois coal mine owner for the premature closure of an Illinois mine, as discussed above, and a $6 million reduction in funding required by the 2007 Illinois Electric Settlement Agreement in 2008 compared with 2007.
CILCO’s cash from operating activities increased in 2008, compared with 2007. The increase was primarily due to net income tax refunds of $15 million in 2008 compared with net income tax payments of $35 million in 2007, higher electric margins, a reduction of coal inventory at AERG, an increase in gas cost recovered from customers under a PGA, an increase in electric cost over-recovered from customers, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a
potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared with 2007. The cash outflows related to the settlement, including AERG’s obligation, were $16 million lower in 2008 than in 2007. Partially offsetting these increases in cash from operations were a larger increase in natural gas inventories during 2008 compared with 2007, as both price and volumes increased, and higher net levels of collateral posted with suppliers.
IP’s cash from operating activities increased in 2008, compared with 2007. The increase was primarily due to net income tax refunds of $43 million in 2008, compared with net income tax payments of $18 million in 2007, increased electric and natural gas margins, an increase in gas cost recovered from customers under a PGA, an increase in electric power costs over-recovered from customers, a $7 million increase in customer advances for construction, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The 2007 Illinois Electric Settlement Agreement also had a positive effect on cash from operations in 2008 compared to 2007. IP cash outflows related to the settlement, net of reimbursements from generators, were $35 million lower in 2008 than in 2007. IP experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the 2007 Illinois Electric Settlement Agreement compared with 2007. In addition, operating cash required for major repairs in response to 2008 storms was $8 million less than major storm repairs in 2007. Partially offsetting these increases to operating cash flows were a $10 million increase in interest payments and higher net levels of collateral posted with suppliers.
Pension Funding
Ameren’s pension plans are funded in compliance with income tax regulations and to meet 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. Considering Ameren’s assumptions at December 31, 2009, its investment performance in 2009, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $225 million in each of the next five years, with aggregate estimated contributions of $740 million. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 66%, 6%, 9%, 9% and 10%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. In 2009, Ameren contributed $99 million to its pension plans. See Note 11 - Retirement Benefits under Part II, Item 8, of this report and Outlook for additional information.
Cash Flows from Investing Activities
2009 versus 2008
Ameren used less cash for investing activities in 2009 than in 2008. Net cash used for capital expenditures decreased in 2009 as a result of efforts to reduce, defer or cancel capital expenditure programs in light of economic conditions and the completion of power plant scrubber projects in the Merchant Generation business. Additionally, a $93 million decrease in nuclear fuel expenditures related to timing of purchases and a $10 million decrease in emission allowance purchases, because of lower prices and lower generation levels as well as reduced emission levels resulting from completion of plant scrubber projects in 2009, benefited cash during 2009.
UE’s cash used in investing activities decreased during 2009, compared with 2008. Nuclear fuel expenditures decreased $93 million as a result of the timing of purchases. Cash used in investing activities in 2009 did not benefit from the receipt of $36 million in proceeds from intercompany note receivables with Ameren, and one of its subsidiaries, as occurred during 2008. Capital expenditures were consistent year over year. Reductions in planned capital expenditures for distribution system and power plant improvements in 2009 were offset by increased expenditures to repair severe storm damage and $93 million of Taum Sauk rebuild expenditures.
CIPS’ cash used in investing activities during 2009 increased compared with 2008. Capital expenditures increased $14 million in 2009 from 2008 primarily because of increased capital expenditures to repair severe storm damage.
Genco’s cash used in investing activities increased in 2009 compared with 2008 because of $73 million of net money pool advances in 2009. Capital expenditures decreased $40 million, principally because of reduced spending related to power plant scrubber projects. One scrubber project was completed in November 2009 and a second scrubber project is estimated to be completed in 2010. Emission allowance purchases decreased $11 million, because of lower prices and lower generation levels as well as reduced emission levels resulting from the completion of a plant scrubber project in 2009, which resulted in a benefit to cash in 2009.
CILCO’s cash used in investing activities decreased in 2009, compared with 2008, as a result of a $165 million decrease in capital expenditures, primarily because of the completion of a power plant scrubber project in March 2009 and other reductions in capital expenditures at AERG.
IP’s cash used in investing activities decreased in 2009 compared with 2008, primarily as a result of money pool activity. During 2009, IP received a net repayment of $44 million in money pool advances compared with $44 million of net contributions during 2008. Partially offsetting this benefit to cash was an increase in advances to AITC for construction under a joint ownership agreement. IP received funding for this construction under a generator interconnection agreement related to on-going transmission upgrade projects.
2008 versus 2007
Ameren used more cash for investing activities in 2008, than in 2007. Net cash used for capital expenditures increased in 2008 as a result of power plant scrubber projects, upgrades at various power plants, and reliability improvements of the transmission and distribution system. Additionally, increased purchases and higher prices resulted in a $105 million increase in nuclear fuel expenditures.
UE’s cash used in investing activities increased during 2008, compared with 2007. Nuclear fuel expenditures increased $105 million resulting from increased purchases for future refueling outages at its Callaway nuclear plant and higher prices. In addition, capital expenditures increased $249 million. This increase was a result of increased spending related to a power plant scrubber project, reliability improvements of the transmission and distribution system, and various plant upgrades. This increase was partially offset by UE’s receipt of $36 million in proceeds from intercompany note receivables with Ameren, and one of its subsidiaries.
CIPS’ cash used in investing activities during 2008 increased, compared with 2007. Capital expenditures increased $17 million in 2008 from 2007, primarily because of reliability improvements to the transmission and distribution system. During both years, this was offset by cash received from payments on an intercompany note receivable from Genco.
Genco’s cash used in investing activities increased in 2008 compared with 2007. Capital expenditures increased $126 million, principally because of a power plant scrubber project. This increase was offset, in part, by a $7 million decrease in emission allowance purchases.
CILCO’s cash used in investing activities increased in 2008, compared with 2007. Cash used in investing activities increased as a result of a $65 million increase in capital expenditures, primarily because of a power plant scrubber project and plant upgrades at AERG. The receipt of net repayments of money pool advances in 2007 compared to 2008 also increased cash flows used in investing activities in 2008.
IP’s cash used in investing activities increased in 2008 compared with 2007. Capital expenditures increased by $8 million in 2008 from 2007, primarily because of reliability improvements to the transmission and distribution system. Net money pool advances increased by $44 million in 2008 compared with 2007.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2009, 2008, and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Ameren’s 2009 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $173 million toward a scrubber at one of its power plants and $93 million toward the Taum Sauk rebuild, and it incurred storm-related expenditures of $78 million. CIPS, CILCO and IP incurred storm-related expenditures of $29 million, $3 million, and $5 million, respectively. At Genco and AERG, there were cash outlays of $169 million and $38 million, respectively, for power plant scrubber projects. The scrubbers are necessary to comply with environmental regulations. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO and IP as well as various plant upgrades.
Ameren’s 2008 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $149 million toward a scrubber at one of its power plants, and incurred storm-related expenditures of $12 million. CIPS and IP incurred storm-related expenditures of $7 million and $8 million, respectively. At Genco and AERG, there were cash outlays of $205 million and $137 million, respectively, for power plant scrubber projects. The scrubbers are necessary to comply with environmental regulations. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP as well as various plant upgrades.
Ameren’s 2007 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $101 million toward a scrubber at one of its power plants, and incurred storm-related expenditures of $56 million. IP incurred storm-related expenditures of $24 million. At Genco and AERG, there were cash outlays of $102 million and $76 million, respectively, for power plant scrubber projects. In conjunction with the scrubber project, AERG also made expenditures for a power plant boiler upgrade of $45 million. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP as well as various plant upgrades.
The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2010 through 2014, including construction expenditures, capitalized interest for the Merchant Generation business, allowance for funds used during construction for our rate-regulated utility business, and estimated expenditures for compliance with environmental standards:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
UE’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with environmental regulations discussed below. CIPS’, CILCO’s (Illinois Regulated), and IP’s estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments. Genco’s estimated capital expenditures are primarily for compliance with environmental regulations and upgrades to existing coal and gas-fired generating facilities. CILCO’s (AERG) estimate includes capital expenditures primarily for compliance with environmental regulations at its generating facilities.
We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.
Environmental Capital Expenditures
Ameren, UE, Genco, AERG and EEI 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.
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, which include 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 MACT requirements under the Clean Air Act. In February 2009, the U.S. Supreme Court denied a 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 and other hazardous air pollutants, such as acid gases. In a consent order, the EPA agreed to propose the regulation by March 2011 and to finalize the regulation by November 2011. Compliance is expected to be required in 2015. We cannot predict at this time the estimated capital or operating costs for compliance with such future 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 EPA has stated that it expects to issue a new proposed version of the Clean Air Interstate Rule in 2010 and a final version in 2011.
The state of Missouri has adopted 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 by 30% and SO2 emissions by 75% by 2015. As a result of the Missouri rules, UE will use allowances and install pollution control equipment. UE’s costs to comply with SO2 emission reductions required by the Clean Air Interstate Rule could increase materially if the EPA determines that existing allowances granted to sources under the Acid Rain Program cannot be used for compliance with the Clean Air Interstate Rule, or if a new allowance program is mandated by revisions to the Clean Air Interstate Rule. Missouri also adopted rules to implement the federal
Clean Air Mercury Rule. However, these rules are not enforceable since 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 in the near term. Under the MPS, as amended, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NOx and SO2 controls. This rule, when fully implemented, is expected to reduce mercury emissions by 90%, NOx emissions by 50%, and SO2 emissions by 70% by 2015 in Illinois. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. Genco, CILCO (AERG) and EEI will also need to install additional 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. The Illinois Joint Committee on Administrative Rules approved a rule amendment in June 2009 that revised certain requirements of the MPS. As a result, Genco and CILCO (AERG) collectively were able to defer to subsequent years an estimated $300 million of environmental capital expenditures originally scheduled for 2009 through 2011.
In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. Illinois and Missouri have each submitted their recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas 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 future state implementation plans. In January 2010, the EPA announced its plans to revise the ozone standard to a level lower than the level set in 2008. At this time, we are unable to determine the impact state implementation plans for such regulations would have on our results of operations, financial position, and liquidity.
The table below presents estimated capital costs that are based on current technology to comply with state air quality implementation plans, the MPS, federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates shown in the table below could change depending upon additional federal or state requirements, the requirements under a MACT standard, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. 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. During 2009, Ameren identified significant opportunities to defer or reduce planned capital spending, which are reflected in the estimates provided in the table. The capital cost estimates are lower than previously anticipated, in part because of Ameren’s ability to manage its generating fleet to minimize emissions while
complying with emission limits and air permit requirements. Furthermore, previous estimates included assumptions about potential and developing air regulations, including rules that were subsequently vacated by the courts. These estimates include capital spending to comply primarily with existing and known regulations as of December 31, 2009.
(a) UE’s expenditures are expected to be recoverable in rates over time.
In 2009, UE developed four-year and 20-year Environmental Compliance Plans to comply with all environmental regulations, including rules under the Clean Water Act, to support its environmental cost recovery mechanism tariff request, which was a part of its July 2009 electric rate case filing. The plans contain a comprehensive assessment of environmental investments likely to be required of UE. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on UE’s pending electric rate case.
See Note 15 - Commitments and Contingencies under Part II, Item 8, of this report for a further discussion of environmental matters, including global climate change.
Cash Flows from Financing Activities
2009 versus 2008
As a result of turmoil in the capital and credit markets in 2008 and 2009, we sought to improve our liquidity position. We replaced and extended the expiration of our credit facilities and sought to reduce our reliance on borrowings from these credit facilities, increase cash balances and increase the equity content of our capitalization. We also sought to eliminate debt at CILCORP as a step in simplifying our organizational structure.
During 2009, Ameren and its subsidiaries issued $1 billion of senior debt and $634 million in common stock and used the proceeds to repurchase, redeem, and fund maturities of $631 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO and IP. Comparatively, during 2008, Ameren’s subsidiaries issued $1.9 billion of senior debt and $154 million in common stock and used the proceeds to repurchase, redeem, and fund maturities of $842 million of long-term debt, reduce short-term borrowings, and fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO and IP. Ameren’s capital issuance costs increased in 2009 compared with 2008 because of $40 million in banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit
Agreement and $17 million of issuance costs associated with Ameren’s September 2009 common stock issuance, partially offset by a decrease in issuance costs associated with long-term debt. Benefiting 2009 cash from financing activities, compared with 2008, was a $196 million decrease in common stock dividends, and a $47 million increase in generator advances received for construction under generator interconnection agreements, net of repayments.
UE’s net cash provided by financing activities decreased during 2009, compared with 2008, primarily because of $251 million of short-term borrowings repayments in 2009 compared with net short-term borrowings of $169 million in 2008, a $350 million decrease in the issuances of long-term debt, and a $184 million increase in net repayments under an intercompany borrowing arrangement with Ameren. Benefits to cash for 2009, compared with 2008, included a $436 million capital contribution from Ameren funded by the proceeds of Ameren’s September 2009 common stock issuance, a $378 million decrease in redemptions of long-term debt, and an $89 million decrease in common stock dividend payments. The proceeds from the capital contribution were primarily used to reduce outstanding short-term borrowings.
CIPS’ net cash used in financing activities increased during 2009 compared with 2008. CIPS used existing cash to fund a net reduction in money pool borrowings, to pay $47 million of dividends to Ameren in 2009, and to fund a $3 million increase in debt issuance costs as a result of the banking fees associated with the 2009 Illinois Credit Agreement. Benefiting the 2009 period was a $66 million capital contribution from Ameren.
Genco’s cash provided by financing activities increased during 2009 compared with 2008, primarily as a result of a $101 million reduction in dividends paid on common stock and $100 million change in short-term borrowings repayments. These benefits to cash during the 2009 period were slightly offset by a $106 million decrease in net money pool borrowings and a $51 million decrease in the issuance of long-term debt.
CILCO had a net use of cash from financing activities in 2009, compared with a net source of cash in 2008 primarily as a result of the change in CILCO’s money pool borrowings, $127 million increase in repayments of short-term borrowings, a $150 decrease in issuance of long-term debt, and a $6 million increase in capital issuance costs as a result of banking fees associated with the 2009 Illinois Credit Agreement. During 2009, CILCO repaid a net $98 million to the money pool; CILCO received $98 million of net borrowings in 2008. Cash from financing activities benefited from a $288 million increase in intercompany borrowings from Ameren, a $51 million capital contribution from CILCORP, and a $35 million decrease in redemptions of long-term debt and preferred stock.
IP had a net use of cash from financing activities during 2009, compared with a net source of cash in 2008, primarily as a result of a $730 million decrease in long-term debt issuances. During 2009, cash from financing activities
benefited from $175 million decrease in net short-term borrowings repayments, a $141 million decrease in redemptions and maturities of long-term debt, including IP SPT, $155 million capital contribution received from Ameren, and a $40 million increase in net generator advances received for construction under generator interconnection agreements. During 2009, IP used existing cash to fund the maturity of $250 million of its 7.50% mortgage bonds and to pay banking fees associated with the 2009 Illinois Credit Agreement. Comparatively, during 2008, IP issued $730 million of senior secured notes to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds, which had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market, and to fund debt maturities and common stock dividends.
2008 versus 2007
During the year ended December 31, 2008, the Ameren Companies issued $1.9 billion of senior debt. The proceeds were used to repurchase, redeem, and fund maturities of $842 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO and IP. During the year ended December 31, 2007, net short-term borrowings of $860 million and senior debt of $674 million were used to fund $488 million of maturities of long-term debt, to fund working capital needs at Ameren subsidiaries and to build liquidity during a period of legislative uncertainty in Illinois. Additionally, CILCO redeemed the remaining shares of its 5.85% Class A preferred stock to complete the mandatory sinking fund redemption requirement, which resulted in a $16 million use of cash during 2008 compared with 2007. Benefiting 2008, compared with 2007, was a $63 million increase in proceeds from the issuance of Ameren common stock, which resulted from increased sales through Ameren’s 401(k) plan and DRPlus.
UE’s net cash from financing activities increased in the year ended December 31, 2008, compared with the year ended December 31, 2007. During 2008, UE used $699 million in proceeds from the issuance of senior secured notes to redeem outstanding auction-rate environmental improvement revenue refunding bonds that had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market, and to fund the maturity of $148 million of UE’s 6.75% first mortgage bonds. Additionally, net short-term borrowings increased $321 million. These borrowings were primarily used to fund working capital needs and capital expenditures. In 2007, UE issued $424 million in senior secured notes and received a $380 million capital contribution from Ameren to fund working capital requirements and to reduce net short-term borrowings.
CIPS had a net use of cash from financing activities in 2008, compared with a net source of cash in 2007. This change occurred because CIPS used net money pool borrowings and existing cash to fund a net reduction in short-term borrowings, to redeem $35 million of auction-rate environmental improvement revenue refunding bonds that
had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market, and to fund the maturity of $15 million of its 5.375% senior secured notes during 2008. In 2007, CIPS used net short-term borrowings of $90 million to fund working capital needs to build liquidity, and to fund $40 million of common stock dividends.
Genco issued $300 million of 7.00% senior unsecured notes during 2008, which resulted in a net source of cash from financing activities compared with a net use of cash in 2007. The proceeds from the issuance were used to fund capital expenditures and other working capital requirements, including a net reduction of $200 million of short-term borrowings during 2008 compared with 2007.
CILCO’s cash provided by financing activities decreased in 2008 compared with 2007. This decrease was primarily the result of CILCO’s net repayments of short-term borrowings during 2008 compared with 2007. These repayments were funded by a net increase in money pool borrowings of $98 million, primarily at AERG, and CILCO’s issuance of $150 million of its 8.875% senior secured notes. Partially offsetting the decrease were reduced redemptions and maturities of long-term debt in 2008. During 2008, $19 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher interest rates as a result of the collapse of the auction-rate securities market were redeemed at CILCO. In 2007, $50 million of CILCO’s 7.50% bonds matured.
IP’s cash from financing activities decreased in 2008, compared with 2007. During 2008, IP issued $730 million of senior secured notes and used the proceeds to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market and to repay short-term borrowings. Additionally, during 2008, IP funded $60 million of common stock dividends to Ameren and had net short-term borrowings repayments of $175 million. Comparatively, during 2007, IP issued $250 million of senior secured notes, paid $61 million of common stock dividends, and had $100 million of net borrowings under the 2007 credit facility. These borrowings were used to fund $87 million of long-term debt maturities and $43 million of net money pool repayments to build liquidity in 2007.
Credit Facility Borrowings and Liquidity
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, or drawings under committed bank credit facilities. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.
The following table presents the committed bank credit facilities of Ameren and the Ameren Companies, and their availability as of December 31, 2009:
(a) Ameren Companies may access these credit facilities through intercompany borrowing arrangements.
(b) Includes the 2009 Multiyear Credit Agreement and the Supplemental Agreement. The Supplemental Agreement will terminate in July 2010 with all commitments and all outstanding amounts being consolidated with those under the 2009 Multiyear Credit Agreement. At that time, the combined maximum amount available to all borrowers will be $1.0795 billion, and the UE and Genco Borrowing Sublimits remain the same; Ameren’s Sublimit changes to $1.0795 billion.
(c) In addition to amounts drawn on these facilities, the amount available is further reduced by standby letters of credit issued under the facilities. The amount of such letters of credit at December 31, 2009, was $15 million.
The combined maximum amount available to all of the borrowers, collectively, under the 2009 Multiyear Credit Agreement and the Supplemental Credit Agreement (collectively, the “2009 Multiyear Credit Agreements”) is $1.3 billion. The combined maximum amount available to each borrower, individually, under the 2009 Multiyear Credit Agreements is limited as follows: Ameren - $1.15 billion, UE - $500 million and Genco - $150 million (such amounts being each borrower’s “Borrowing Sublimit”). CIPS, CILCO, and IP have no borrowing authority or liability under the 2009 Multiyear Credit Agreements. These credit facilities were also available for use, subject to applicable regulatory short-term borrowing authorizations, by EEI or other Ameren non-state-regulated subsidiaries through direct short-term borrowings from Ameren and by most of
Ameren’s merchant generating subsidiaries, including, but not limited to, Ameren Services, Resources Company, AERG, Marketing Company and AFS, through a non-state- regulated subsidiary money pool agreement. Ameren has money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. In addition, a unilateral borrowing agreement among Ameren, IP, and Ameren Services enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding external credit facility 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 money pool agreements. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of this report for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement.
The combined maximum amount available to all borrowers collectively under the 2009 Illinois Credit Agreement is $800 million, and the combined maximum amount available to each borrower individually, under the 2009 Illinois Credit Agreement is limited as follows: Ameren - $300 million, CIPS - $135 million, CILCO - $150 million, and IP - $350 million.
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. This term loan agreement was repaid at maturity in January 2010. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of this report for additional information.
In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At December 31, 2009, Ameren, UE, CIPS, Genco, CILCO, and IP had $622 million, $267 million, $28 million, $6 million, $88 million, and $190 million, respectively, of cash and cash equivalents.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2008, FERC issued an order authorizing these utility subsidiaries to issue such securities subject to the following limits on outstanding balances: UE - $1 billion, CIPS - $250 million, and CILCO - $250 million. The authorization was effective as of April 1, 2008, and terminates on March 31, 2010. UE, CIPS and CILCO have pending requests with FERC seeking authority to issue short-term debt securities subject to limits on outstanding balances of $1 billion, $300 million, and $250 million, respectively, for the period April 1, 2010, through March 31, 2012. IP has unlimited short-term borrowing authorization from FERC.
Genco was authorized by FERC in its March 2008 order to have up to $500 million of short-term debt outstanding at any time. Genco is seeking a renewal of that authorization. AERG and EEI have unlimited short-term borrowing authorization from FERC.
The issuance of short-term debt securities by Ameren is not subject to approval by any regulatory body.
The Ameren Companies continually evaluate the adequacy and appropriateness of their credit arrangements given changing business and credit market conditions. When business and credit market conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.
Long-term Debt and Equity
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt and preferred stock (net of any issuance discounts and including any redemption premiums) for the years 2009, 2008, and 2007 for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report.
In November 2008, Ameren, 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. In June 2008, UE 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.
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, 2009:
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 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, Ameren issued 3.2 million, 4.0 million, and 1.7 million shares of common stock in 2009, 2008, and 2007, respectively, which were valued at $82 million, $154 million, and $91 million for the respective years.
In September 2009, Ameren issued and sold 21.85 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the offering proceeds to make
investments in its rate-regulated utility subsidiaries in the form of capital contributions as follows: UE - $436 million, CIPS - $13 million, CILCO - $25 million, and IP - $61 million.
Ameren, UE, CIPS, Genco, CILCO and IP may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
See Note 4 - Credit Facility Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our bank credit and term loan facilities and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.
At December 31, 2009, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.
We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $338 million, or $1.54 per share, in 2009,
$534 million, or $2.54 per share, in 2008, and $527 million, or $2.54 per share, in 2007. This resulted in a payout rate based on net income of 55% in 2009, 88% in 2008, and 85% in 2007. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 17% in 2009, 35% in 2008 and 48% in 2007.
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, as it has done in the past, the board of directors is expected to consider various issues, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. On February 12, 2010, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 38.5 cents per share, payable on March 31, 2010, to shareholders of record on March 10, 2010.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances. At December 31, 2009, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.
UE would be restricted as to dividend payments on its common and preferred stock if it were to extend or defer interest payments on its subordinated debentures. CIPS’ articles of incorporation and mortgage indentures require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit it from making any dividend payments on common stock if debt service coverage ratios are below a defined threshold. CILCO has restrictions in its articles of incorporation on dividend payments on common stock relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock.
UE, CIPS, Genco, CILCO and IP as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, CIPS, CILCO and IP may not pay any dividend on their respective stock, unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless CIPS, CILCO or IP has specific authorization from the ICC.
The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents.
Certain of the Ameren Companies have issued preferred stock on which they are obligated to make preferred dividend payments. Each company’s board of directors considers the declaration of the preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 10 - Preferred Stock under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2009. See Note 11 - Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.
(a) Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(b) Excludes fair-market value adjustments of long-term debt of $6 million for IP.
(c) Excludes unamortized discount of $2 million at Ameren, $8 million at UE, $1 million at CIPS, $2 million at Genco, and $9 million at IP.
(d) The weighted average variable-rate debt has been calculated using the interest rate as of December 31, 2009.
(e) 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.
(f) See Other Obligations within Note 15 - Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items represented herein.
(g) Less than $1 million.
As of December 31, 2009, the amounts of unrecognized tax benefits were $135 million, $88 million, $- million, $28 million, $15 million and $- million for Ameren, UE, CIPS, Genco, CILCO and IP, respectively. It is reasonably possible to expect that the settlement of an unrecognized tax benefit will result in an underpayment or overpayment of tax and related interest. However, there is a high degree of uncertainty with respect to the timing of cash payments or receipts associated with unrecognized tax benefits. The amount and timing of certain payments or receipts is not reliably estimable or determinable at this time. See Note 13 - Income Taxes under Part II, Item 8, of this report for information regarding the Ameren Companies’ unrecognized tax benefits and related liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2009, none of the Ameren Companies had any off-balance-sheet financing arrangements other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
Credit Ratings
The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P, and Fitch effective on the date of this report:
Moody’s Ratings Actions
On January 29, 2009, Moody’s affirmed the ratings of CIPS, CILCO and IP and changed their rating outlooks to stable from positive. According to Moody’s, the change in the rating outlooks of these three companies was based on the near-term expiration of the 2007 and 2006 $500 million
credit facilities in January 2010 and related liquidity concerns. Moody’s also on January 29, 2009, affirmed the ratings of Ameren and UE with a stable outlook based on the January 2009 MoPSC electric rate order approving a rate increase and a FAC for UE.
On February 16, 2009, Moody’s affirmed the ratings of Ameren, UE, CIPS, Genco, CILCO, and IP with a stable outlook. The affirmation reflected Moody’s view that Ameren’s announcement to reduce its common dividend by 39% was a conservative, prudent, and credit positive action that would conserve cash and support financial coverage metrics. Moody’s stated that the more conservative dividend payout should also help facilitate the renewal of Ameren’s credit facilities that expired in 2010. They stated the dividend reduction should continue to reduce reliance on the credit facilities going forward and would likely be viewed favorably by lenders considering renewing or entering into new facilities with Ameren and its subsidiaries, which was important considering constrained credit market conditions at that time. According to Moody’s, the stable outlook on Ameren, UE, CIPS, Genco, CILCO, and IP reflected constructive rate case outcomes at UE, CIPS, CILCO and IP, including the approval of a FAC at UE; the improving regulatory environments for investor-owned utilities in Illinois and Missouri at that time; and Moody’s expectation that financial and cash flow coverage metrics should remain adequate to maintain current rating levels. In addition, Moody’s noted that the dividend reduction was supportive of the stable ratings outlooks and provided Ameren and its subsidiaries additional cushion at the rating levels.
On July 1, 2009, Moody’s stated that the successful execution of new two-year bank credit facilities was supportive of the credit quality of Ameren and its utility subsidiaries. However, Moody’s did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.
On August 3, 2009, Moody’s upgraded the majority of senior secured debt ratings of investment-grade regulated utilities by one notch. Senior secured debt ratings at UE were upgraded from Baa1 to A3 and at CIPS and IP from Baa3 to Baa2. Moody’s stated the rating action widened the notching between most senior secured debt ratings and senior unsecured debt ratings of investment-grade regulated utilities to two notches from one previously. Moody’s noted the wider notching was based on its analysis of the history of regulated utility defaults, which indicated that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than nonfinancial, nonutility corporate issuers.
On August 13, 2009, Moody’s upgraded the ratings of CIPS, CILCO and IP. Issuer/corporate credit ratings at CIPS, CILCO and IP were upgraded from Ba1 to Baa3. Moody’s also upgraded the senior secured debt ratings at CIPS, CILCO and IP from Baa2 to Baa1. Moody’s cited the execution of new bank credit facilities and an improved political and regulatory environment in Illinois as the basis for the return to investment grade status of the issuer/corporate ratings. Moody’s also affirmed the ratings of Ameren, UE and Genco
and assigned a stable outlook for Ameren and all of its rated subsidiaries.
S&P Ratings Actions
On February 25, 2009, S&P stated that it viewed the reduction in Ameren’s dividend as credit supportive. S&P did not make any changes in Ameren’s or its subsidiaries’ credit ratings or outlooks as a result of this action. S&P raised the business profile of UE to “excellent” from “strong” to reflect the electric rate order issued by the MoPSC in January 2009, which S&P viewed as constructive. S&P lowered the business profile of CILCO to “satisfactory” from “strong.”
On February 25, 2010, S&P assigned improved business risk profiles to CIPS and IP of “excellent” from “strong” and to CILCO of “strong” from “satisfactory.”
Fitch Ratings Actions
On February 17, 2009, Fitch stated that the reduction in Ameren’s common stock dividend and other cost cutting measures would be favorable to bondholders and credit quality. Fitch did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.
On March 9, 2009, Fitch lowered the credit ratings of UE by one notch as follows: issuer rating to BBB+, senior secured debt to A, subordinated debt to BBB+, and preferred stock to BBB+. The rating outlook was changed to stable. Fitch stated that these downgrades were made because of deteriorating financial measures over the past several years and the expectation that they will not improve materially without further rate support. They noted the financial deterioration was primarily due to increasing fuel and operating costs and a large capital expenditure program.
On July 31, 2009, Fitch affirmed the credit rating of Genco and changed its rating outlook to negative from stable. Additionally, Fitch affirmed the credit ratings of Ameren with a stable outlook. According to Fitch, the change in the credit rating outlook of Genco was based on the unfavorable outlook for wholesale energy prices and the sensitivity of the company’s largely coal-fired generating fleet to greenhouse gas and other environmental regulations. According to Fitch, the affirmation of Ameren’s credit ratings and stable outlook reflected the significant earnings and cash flow contribution derived from regulated utilities, the beneficial impact of recent rate increases in Illinois and Missouri, the savings generated by the February 2009 dividend reduction, and steps taken to maintain liquidity, including the renewal of bank credit facilities.
On January 22, 2010, Fitch announced new guidelines that affect its ratings on deferrable coupon hybrid securities and preferred stock for utility issuers. Under these new guidelines, Fitch will rate these securities two notches below the issuer’s senior unsecured debt ratings. The prior guidelines rated these securities one notch below. The ratings for UE, CIPS, CILCO and IP’s preferred stock, and for UE’s
7.69% subordinated deferrable interest debentures, were affected by this industry-wide methodology change.
Collateral Postings
Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power, and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties including postings related to exchange-traded contracts at December 31, 2009, were $106 million, $25 million, $3 million, $1 million, and $14 million at Ameren, UE, CIPS, CILCO and IP, respectively. The amount of collateral external counterparties posted with Ameren was $12 million at December 31, 2009. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at December 31, 2009, could have resulted in Ameren, UE, CIPS, Genco, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $368 million, $129 million, $29 million, $48 million, $44 million, and $52 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than December 31, 2009, levels in the next twelve months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $171 million, $82 million, $- million, $- million, $9 million, and $- million, respectively. If market prices were 15% lower than December 31, 2009, levels in the next twelve months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $329 million, $171 million, $14 million, $- million, $53 million, and $50 million, respectively.
The cost of borrowing under our credit facilities can also increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
OUTLOOK
Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2010 and beyond.
Economy and Capital and Credit Markets
In 2008 and 2009, global capital and credit markets experienced extreme volatility. While these markets improved during 2009, the availability and cost of capital and economic activity continue to be significantly affected. We believe that
these events have several implications for our industry as a whole, including Ameren. They include the following:

Access to Capital Markets and Cost of Capital - The extreme disruption in the capital markets limited the ability of many companies, including the Ameren Companies, to freely access the capital and credit markets to support their operations and to refinance debt. Ameren and its subsidiaries continued to have access to the capital markets, as evidenced by Ameren’s, UE’s, Genco’s, CILCO’s and IP’s sale of debt securities in late 2008 and 2009, as well as Ameren’s common stock offering in September 2009. This access has been at commercially acceptable but higher rates in the case of the issuance of certain debt securities.

Credit Facilities - On June 30, 2009, Ameren and certain of its subsidiaries successfully reached definitive multiyear credit facility agreements. These facilities cumulatively provide $2.1 billion of credit through July 14, 2010, reducing to $1.8795 billion through June 30, 2011, and to $1.0795 billion through July 14, 2011. The costs of these credit facilities are significantly higher than the facilities they replaced. The costs to enter into the multiyear credit facility agreements were $40 million in the aggregate (UE - $11 million, CIPS - $3 million, Genco - $4 million, CILCORP - $14 million, CILCO - $7 million, and IP - $7 million). The costs will be amortized over the term of the facilities. In addition, borrowing rates under the facilities increased significantly, including, in the case of Ameren, from LIBOR plus 0.5%, under the prior credit facilities, to LIBOR plus 2.75%. Ameren intends to replace or extend its credit facility agreements during 2010.

Economic Conditions - Weak economic conditions have resulted in reduced power prices, lower customer sales growth, or sales contraction, particularly with respect to industrial sales, and higher financing costs, among other things. Weak economic conditions also expose the Ameren Companies to greater risk of default by counterparties, potentially higher bad debt expenses, and the risk of impairment of goodwill and long-lived assets, among other things. Based on the results of the annual goodwill impairment test completed as of October 31, 2009, the estimated fair value of Ameren’s Merchant Generation reporting unit exceeded its carrying value by a nominal amount. The failure in the future of this reporting unit, or any reporting unit, to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. Although we are unable to predict when the U.S. economy will fully recover from the economic downturn, we currently expect economic conditions to improve in 2010. We are unable to predict the ultimate impact of the weak economy on our results of operations, financial position, or liquidity.

Investment Returns - The disruption in the capital markets, coupled with weak global economic conditions, adversely affected financial markets. As a result, we
experienced lower-than-expected investment returns in 2008 in our pension and postretirement benefit plans. During 2009, the actual return on investment of the pension plan assets was equal to the expected investment return while the actual return on investment of postretirement benefit assets exceeded the expected return. Lower returns increase our future pension and postretirement expenses and pension funding levels. Our future expenses and funding levels will also be affected by future investment returns and future discount rate levels.

Operating and Capital Expenditures - The Ameren Companies will continue to make significant levels of investments and incur expenditures for their electric and natural gas utility infrastructure in order to improve overall system reliability, comply with environmental regulations, and improve plant performance. However, in response to the significant level of disruption and uncertainties in the capital and credit markets and weak economic conditions that reduced power prices and to help our customers with their future energy costs, we reduced our planned capital expenditures for 2010 through 2013 by approximately $2 billion, as compared to earlier plans. Ameren also took steps to control operations and maintenance expenditures. Ameren is managing power plant outages and labor costs, among other things. Any expenditure control initiatives will be balanced against a continued long-term commitment to invest in our electric and natural gas infrastructure to provide safe, reliable electric and natural gas delivery services to our customers; to meet federal and state environmental, reliability, and other regulations; and the need to maintain a solid overall liquidity and credit ratings profile to meet our operating, capital, and financing needs under challenging capital and credit market conditions.

Liquidity - At December 31, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $1.9 billion, which was $0.6 billion more than it had at the end of 2008.
We believe that our liquidity is adequate given our expected operating cash flows, capital expenditures, and related financing plans (including accessing our existing credit facilities). However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets, or other unforeseen events will not materially affect our ability to execute our expected operating, capital or financing plans.
Current Capital Expenditure Plans

Between 2010 and 2017, Ameren expects to invest up to $1.9 billion, in the aggregate, to retrofit its coal-fired power plants with pollution control equipment in compliance with emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses.
Approximately 20% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers, subject to prudency reviews. Regulatory lag may materially impact the timing of such recovery and, therefore, our cash flows and related financing needs. The recoverability of amounts expended in Merchant Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for coal-fired generators.

Future federal and state legislation or regulations that mandate limits on emissions would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly situated electric power generators to close some coal-fired facilities. Investments to control emissions at Ameren’s coal-fired power plants to comply with future legislation or regulations would significantly increase future capital expenditures and operations and maintenance expenses, which if excessive could result in the closures of coal-fired power plants, impairment of assets, or otherwise materially adversely affect Ameren’s results of operations, financial position, and liquidity.

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s integrated resource plan filed with the MoPSC in February 2008 included the expectation that new baseload generation capacity would be required in the 2018 to 2020 time frame. Due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE continues to study future plant alternatives, including energy efficiency programs that could help defer new plant construction. UE introduced multiple energy efficiency programs in 2009. The goal of these and future UE energy efficiency programs is to reduce usage by 540 megawatts by 2025, which is the equivalent of a medium-size coal-fired power plant. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE will file with the MoPSC in 2011.

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. As of December 31, 2009, UE had capitalized approximately $69 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit or management concludes it is probable the costs incurred will be disallowed in rates, it is possible that a charge to earnings could be recognized in a future period.

UE intends to submit a license extension application with the NRC to extend its existing Callaway nuclear plant’s
operating license by 20 years so that the operating license will expire in 2044. UE cannot predict whether or when the NRC will approve the license extension.

Over the next few years, we expect to make significant investments in our electric and natural gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher labor and material costs for these capital expenditures. We expect these costs or investments at our rate-regulated businesses to be ultimately recovered in rates, subject to prudency reviews by regulators, although rate case outcomes and regulatory lag could materially impact the timing of such recovery and, therefore, our cash flows, related financing needs and the timing in which we are able to proceed with these projects.

Ameren is evaluating opportunities to expand its transmission assets. New transmission projects have the potential to reduce congestion, improve reliability, and facilitate movement of renewable energy, typically generated in remote areas, to population centers where demand is at its highest.

Increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs.
Revenues

The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. Rising costs, including labor, material, depreciation and financing costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, are expected. Ameren, UE, CIPS, CILCO and IP anticipate regulatory lag until their requests to increase rates to recover such costs on a timely basis are granted by state regulators. Ameren, UE, CIPS, CILCO and IP expect to file rate cases frequently. UE has agreed not to file a natural gas delivery rate case before March 15, 2010.

In current and future rate cases, UE, CIPS, CILCO and IP will continue to seek cost recovery and tracking mechanisms from their state regulators to reduce regulatory lag.

In July 2009, a new law became effective in Illinois that allows electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their base rates. In February 2010, the ICC approved the Ameren Illinois Utilities’ electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in rates. The tariffs provide utilities the ability to adjust their base rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. The Ameren Illinois Utilities were required to make a one-time donation of $10 million (CIPS - $2 million, CILCO - $2 million, and IP - $6 million) for customer assistance programs, as required by the legislation. The amount of the required one-time donation and the impact of the recovery of
2008 and 2009 bad debt expenses were reflected in 2009 earnings.

In June 2009, CIPS, CILCO and IP filed requests with the ICC to increase their annual revenues for electric and natural gas delivery services. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $115 million in the aggregate (CIPS - $38 million, CILCO - $17 million, and IP - $60 million). The electric rate increase requests are based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.3 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $15 million in the aggregate (CIPS - $6 million, CILCO - $2 million, and IP - $7 million). The natural gas rate increase requests are based on a 10.8% to 11.2% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. The ICC staff has recommended, as amended, a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $57 million in the aggregate (CIPS - $21 million increase, CILCO - $5 million increase, and IP - $31 million increase) and a net decrease in revenues for natural gas delivery service of $11 million in the aggregate (CILCO - $6 million decrease, and IP - $5 million decrease). The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010.

UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order, which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC. The initial electric rate increase was based on an 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro forma adjustments through the anticipated true-up date of January 31, 2010. In February 2010, UE filed rebuttal testimony relating to certain positions taken by interveners in the rate case and modified its recommended return on equity to 10.8%. The MoPSC staff has recommended an increase to UE’s annual revenues of between $218 million to $251 million. Included in this recommendation was approximately $214 million of increases in normalized net fuel costs. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to
11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010.

As part of its filing, UE also requested that the MoPSC approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker as well as the continued use of the FAC and the vegetation management and infrastructural inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order. The environmental cost recovery mechanism, if approved, would allow UE to adjust electric rates twice each year outside of general rate proceedings to reflect changes in its costs prudently incurred to comply with federal, state, or local environmental laws, regulations, or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews by the MoPSC. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.

The MoPSC issued an electric rate order in January 2009 approving an increase in annual electric revenues of approximately $162 million. New rates were effective March 1, 2009. In addition, pursuant to the accounting order issued by the MoPSC in April 2008, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007 should be amortized and recovered over a five-year period starting March 1, 2009. The MoPSC also allowed recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. UE recorded a regulatory asset for these costs at December 31, 2008, which are being amortized and recovered over a two-year period beginning March 1, 2009.

In its electric rate order issued in January 2009, the MoPSC approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. The FAC allows an 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, greater or less than the amount set in base rates, subject to MoPSC prudency reviews. The vegetation management and infrastructure inspection cost tracking mechanism provides for the tracking of expenditures that are greater 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.

Even though Taum Sauk was not available to generate electricity for off-system revenues during 2009, UE included $19 million in the calculation of the FAC as if Taum Sauk had generated off-system revenues. Therefore, UE’s customers received the benefit of Taum Sauk’s historical off-system revenues even though the plant was not operational. UE’s earnings and cash flows
from operations will increase after Taum Sauk becomes operational, which is expected to be in the second quarter of 2010, since the adjustment factor will be eliminated from the FAC calculation. Taum Sauk is expected to increase UE’s 2010 margins by $1.8 million per month, when Taum Sauk returns to service in the second quarter of 2010.

UE provides power to Noranda’s smelter plant in New Madrid, Missouri, which has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer. As a result of a severe ice storm in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines that deliver power to the substation serving the plant. Noranda stated in its Annual Report on Form 10-K for the year ended December 31, 2008, that the outage affected approximately 75% of the smelter plant’s capacity. In a September 30, 2009, press release, Noranda stated that its smelter plant had initiated steps to return operations to full capacity. These steps include restarting the third of its three production lines. The smelter plant’s load has been rising steadily as repairs have been made to its production lines, with full production expected to be reached in the second quarter of 2010. As a result, UE expects its margins from sales to Noranda will increase by approximately $40 million in 2010 compared with 2009. UE’s July 2009 electric rate case filing with the MoPSC seeks approval to revise the tariff under which it serves Noranda to prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant like the revenue losses resulting from the January 2009 storm-related power outage.

As part of the 2007 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 then-relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. Under the terms of the 2007 Illinois Electric Settlement Agreement, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.

Volatile power prices in the Midwest can affect the amount of revenues Ameren, Genco, CILCO (through AERG) and EEI generate by marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets. Spot power prices in the MISO were lower in 2009 than in 2008 and should be significantly affected by any prospect of global economic recovery, among other things.

With few scheduled maintenances outages in 2010 through 2012, the Merchant Generation segment expects to have available generation of 35 million megawatthours in each year. However, the Merchant Generation segment’s actual generation levels will be significantly
impacted by market prices for power in those years, among other things.

The availability and performance of Genco’s, AERG’s and EEI’s electric generation fleet can materially affect their revenues. The Merchant Generation segment expects to generate 30.5 million megawatthours of power from its coal-fired plants in 2010 (Genco - 15.6 million, AERG - 7.4 million, EEI - 7.5 million) based on expected power prices. Should power prices rise more than expected, the Merchant Generation segment has the capacity and availability to sell more generation.

The marketing strategy for the Merchant Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Merchant Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Merchant Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of January 31, 2010, Marketing Company had hedged approximately 26 million megawatthours of Merchant Generation’s expected 2010 generation, at an average price of $47 per megawatthour. For 2011, Marketing Company had hedged approximately 18 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $49 per megawatthour. For 2012, Marketing Company had hedged approximately 12 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $53 per megawatthour. Marketing Company has also entered into capacity-only sales contracts for 2010, 2011, and 2012, resulting in expected capacity-only revenues related to these contracts of $65 million, $45 million, and $15 million, respectively. Any unhedged sales will be exposed to relevant market prices at the time of the sale.

The development of a capacity market in MISO could increase the electric margins of Genco, AERG and EEI. A capacity requirement obligates a load serving entity to acquire capacity sufficient to meet its obligations. MISO continues to refine its treatment of capacity supply and obligations, but development of a true capacity market could still be several years away.

Current and future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could result in reduced demand for our electric generation and our electric and natural gas transmission and distribution services. Our regulated operations will seek a regulatory framework that allows either a return on these programs or recovery of their costs.
Fuel and Purchased Power

In 2009, 83% of Ameren’s electric generation (UE - 75%, Genco - 99%, AERG - 100%, EEI - 100%) was supplied by coal-fired power plants. About 96% of the coal used by these plants (UE - 96%, Genco - 99%,
AERG - 89%, EEI - 100%) was delivered by rail from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have occasionally been restricted because of rail maintenance, weather, and derailments. As of December 31, 2009, coal inventories for UE, Genco, AERG and EEI were 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, or purchasing power from other sources.

Ameren’s fuel costs (including transportation) are expected to increase in 2010 and beyond. As of December 31, 2009, Merchant Generation’s baseload hedged fuel costs, which include coal, transportation, diesel fuel surcharges, and other charges, had increased from an average cost of approximately $20.25 per megawatthour in 2009 to approximately $23.25 per megawatthour in 2010, $25.50 per megawatthour in 2011, and $26.50 per megawatthour in 2012. See
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; 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, 2009:
(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 the 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.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges 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. See Note 7 - Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2009.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. 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. At December 31, 2009, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. The risk associated with the Ameren Illinois Utilities’ electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows the Ameren Illinois Utilities to recover the difference between their actual bad debt expense and the bad debt expense included in their base rates. UE and the Ameren Illinois Utilities continue to monitor the impact of increasing rates and a weak economic environment on customer collections. UE and the Ameren Illinois Utilities make adjustments to their allowance for doubtful accounts as
deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.
UE, CIPS, Genco, CILCO, 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, 2009, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’, and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $2 million, net of collateral (2008 - 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 Energy and Operating Reserves Market to be $13 million at December 31, 2009 (2008 - $46 million).
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 ensure that sufficient funds are available to provide the benefits at the time they are payable and also to maximize total return on plan assets and minimize expense volatility 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.
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%.
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, 2009, this fund was
invested primarily in domestic equity securities (67%) and debt securities (33%). It totaled $293 million (2008 - $239 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 debt 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.
Commodity Price Risk
We are exposed to changes in market prices for electricity, emission allowances, 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 2010 through 2013:
(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.
We manage risks associated with changing prices of fuel for generation using techniques similar to 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 became effective March 1, 2009. 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 2010 through 2014, as of December 31, 2009. The projected required supply of these commodities could be significantly affected by changes in our assumptions for such matters as customer demand for 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 2010 represents January 2010 through March 2010. The year 2011 represents November 2010 through March 2011. This continues each successive year through March 2014.
(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 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 2010 through 2014.
(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 $10 million annually (UE - $5 million, Genco - $2 million, AERG - $1 million and EEI - $2 million). As of December 31, 2009, Ameren had a price cap for approximately 93% of expected fuel surcharges in 2010.
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 both fixed-priced and base-price-with- escalation agreements. It also 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 2012. UE has price hedges for 75% of the 2010 to 2014 nuclear fuel requirements.
Nuclear fuel market prices remain subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing its 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 that 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 Energy and Operating Reserves 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, 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 under Part II, Item 8, of this report for additional information.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause 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 coal, natural gas, and uranium inventories or emission allowances that differ from the cost of those commodities in inventory; and

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. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty. See Note 7 - Derivative Financial Instruments under Part II, Item 8, of this report for additional 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, 2009. We use various methods to determine the fair value of our contracts. In accordance with hierarchy levels outlined in authoritative accounting guidance, the sources we 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, 2009, 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 power forward contract values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes option contract values based on our estimates.
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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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) 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, 2009, 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 schedules, 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 schedules, 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.
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
February 26, 2010
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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
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
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.
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
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)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2009
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, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren 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 natural 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 1923 and is successor to a number of companies, the oldest of which was organized in 1902. It supplies electric and natural 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 383,000 customers and natural gas service to 182,000 customers.

Genco, or Ameren Energy Generating Company, operates a merchant electric generation business in Illinois and Missouri. Genco was incorporated in Illinois in March 2000. Genco’s coal, and natural gas and oil-fired electric generating facilities, are expected to have capacity of 3,454, 1,578, and 169 megawatts,
respectively, at the time of the 2010 peak summer electrical demand.

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, operates a rate-regulated electric transmission and distribution business, a merchant electric generation business (through its subsidiary AERG), and a rate-regulated natural gas transmission and distribution business, all in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and natural 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 211,000 customers and natural gas service to 214,000 customers. AERG, a wholly owned subsidiary of CILCO, is expected to have capacity of 1,125 megawatts from its coal-fired electric generating facilities at the time of the 2010 peak summer electrical demand.

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 natural 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 617,000 customers and natural gas service to 417,000 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. On January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% stock ownership interest in EEI to Genco through a capital contribution. 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 and CILCO are prepared on a consolidated basis. CIPS has no subsidiaries and therefore is not consolidated. UE had a subsidiary in 2007 (Union Electric Development Corporation), but in January 2008 this subsidiary was transferred to Ameren in the form of a stock dividend. Accordingly, UE’s financial statements were prepared on a consolidated basis for 2007 only. IP had a subsidiary in 2007 (Illinois Gas Supply Company) that was dissolved at December 31, 2007. Accordingly, IP’s financial statements were prepared on a consolidated basis for 2007 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 authoritative accounting guidance regarding accounting for the effects of certain types of regulation, UE, CIPS, CILCO
and IP defer certain costs as assets pursuant to actions of our rate regulators or the expected ability to recover such costs in rates charged to customers. UE, CIPS, CILCO and IP also defer certain amounts as liabilities pursuant to actions of regulators or the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 - Rate and Regulatory Matters for additional information on regulatory assets and liabilities. Assets are also recorded as construction work in progress and property and plant, net. See Note 3 - Property and Plant, Net.
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 and anticipated future collections environment. See Note 2 - Rate and Regulatory Matters for additional information regarding regulatory recovery of uncollectible accounts receivable by the Ameren Illinois Utilities.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2009 and 2008:
(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, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Interest during construction is capitalized as a cost of merchant generation 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 values, are charged to accumulated depreciation. Asset removal costs incurred by our merchant generation 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 additional 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 to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2009, 2008 and 2007 generally ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the 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, 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 annual allowance for funds used during construction rates that were utilized during 2009, 2008, and 2007:
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. Ameren’s goodwill relates to its acquisition of IP and an additional 20% EEI ownership interest acquired in 2004 as well as its acquisition of CILCORP and Medina Valley in 2003. IP’s goodwill relates to the acquisition of IP in 2004. See Note 17 - Goodwill for additional information.
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 and CILCO’s intangible assets at December 31, 2009 and 2008, 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, 2009. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.
(a) Vintages are from 2009 to 2019. Each company possesses additional allowances for use in periods beyond 2019.
(b) Vintage is 2009.
(c) The book value represents SO2 and NOx emission allowances for use in periods through 2039. The book value at December 31, 2008, for Ameren, UE, Genco, CILCO (AERG), and EEI was $167 million, $48 million, $49 million, $1 million, and $9 million, respectively.
(d) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(e) Includes $30 million and $24 million of fair-market value adjustments recorded in connection with Ameren’s 2003 acquisition of CILCORP and Ameren’s 2004 acquisition of an additional 20% ownership interest in EEI, respectively.
The following table presents amortization expense recorded in connection with the usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco and CILCO (AERG) during the years ended December 31, 2009, 2008, and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(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 classified as held and used 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 an impairment charge equal to the carrying value of the assets in excess of estimated fair value. In the period in which we determine an asset meets the held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. In 2009, Genco recorded asset impairment charges of $6 million as a result of the termination of a rail line extension project at a subsidiary of Genco and to adjust the carrying value of an office building owned by Genco to its estimated fair value as of December 31, 2009. The charge related to the office building was based on the expected net proceeds to be generated from its sale in 2010. In addition, CILCO recorded an asset impairment charge of $1 million to adjust the carrying value of CILCO’s (AERG’s) Indian Trails generation facility’s estimated fair value as of December 31, 2009. This charge was based on the net proceeds generated from the sale of the facility in January 2010.
In 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 generation 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. The charge was based on the net proceeds generated from the sale of the facility in 2009.
The 2009 and 2008 asset impairment charges were recorded in Operating Expenses - Other Operations and Maintenance Expense in the applicable statements of income and were included in Merchant 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 UE believes would be recovered in electric rates paid by its 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
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has
been incurred and the amount of the liability can be reasonably estimated. Estimated environmental expenditures are 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 natural gas service when it is delivered to customers. We accrue an estimate of electric and natural 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
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.
Purchased Gas, Power and Fuel Rate-adjustment Mechanisms
Ameren’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs.
In UE’s, CIPS’, CILCO’s, and IP’s retail natural gas utility jurisdictions, changes in natural 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 on the balance sheet of Ameren and in Current Regulatory Assets or Current Regulatory Liabilities on the balance sheet of UE, CIPS, CILCO and IP. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.
In the Ameren Illinois Utilities’ retail electric utility jurisdictions, changes in purchased power costs are generally reflected in billings to their electric utility customers through pass-through rate-adjustment clauses.
The difference between actual purchased power costs and costs billed to customers in a given period are deferred and included in Other Current Assets or Other Current Liabilities on the balance sheet of Ameren and in Current Regulatory Assets or Current Regulatory Liabilities on the balance sheets of CIPS, CILCO and IP. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.
In 2009, UE implemented a FAC for its retail electric jurisdiction. The FAC allows an 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, greater or less than the amount set in base rates, subject to MoPSC prudency review. The difference between the costs of fuel incurred and the cost of fuel recovered from UE’s customers are deferred and included in Other Current Assets or Other Current Liabilities on the balance sheet of Ameren and in Current Regulatory Assets or Current Regulatory Liabilities on the balance sheet of UE. The deferred amounts are either billed or refunded to UE’s electric utility customers 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 because of 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 authoritative guidance on revenue recognition.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date based on the fair value of the award. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period. See Note 12 - Stock-based Compensation for additional information.
Excise Taxes
Excise taxes imposed on us are reflected on Missouri electric, Missouri natural gas, and Illinois natural 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 Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the years ended 2009, 2008 and 2007:
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are calculated based on 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 because of 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 the authoritative accounting provisions for income taxes.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. 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, 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 of capital to the party receiving the benefit.
Noncontrolling Interests
Ameren’s noncontrolling interests comprise the 20% of EEI’s net assets not owned by Ameren and the preferred
stock not subject to mandatory redemption of the Ameren subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet.
Earnings per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2009, 2008, and 2007. 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 and 35,545 shares in 2007. There were no assumed stock option conversions in 2009, as the remaining stock options were not dilutive.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact the Ameren Companies.
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued authoritative guidance that established accounting and reporting standards for minority interests, which were recharacterized as noncontrolling interests. This guidance requires noncontrolling interests to 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 to be accounted for as equity transactions; net income attributable to the noncontrolling interest to 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, to be recorded at fair value, with any gain or loss recognized in earnings. We adopted the provisions of this guidance at the beginning of 2009. It applied prospectively, except for the presentation and disclosure requirements, for which it applied retroactively. See Noncontrolling Interests above for additional information.
Disclosures about Derivative Instruments and Hedging Activities
In March 2008, the FASB issued amended authoritative guidance that requires entities to provide greater transparency in interim and annual financial statements about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for, and how the instruments and related hedged items affect the financial position, results of operations, and cash flows of the entity. This guidance 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. The adoption of this guidance, effective for us in the first quarter of 2009, did not have a material impact on our results of operations, financial position, or liquidity because it required enhanced disclosure only. See Note 7 - Derivative Financial Instruments for additional information.
Employers’ Disclosures about Postretirement Benefit Plan Assets
In December 2008, the FASB issued authoritative guidance regarding additional disclosures related to pension and other postretirement benefit plan assets. Required additional disclosures include those related to the investment allocation decision-making process, the fair value of each major category of plan assets and the inputs and valuation techniques used to measure fair value and significant concentrations of risk within the plan assets. The adoption of this guidance, effective for us as of December 31, 2009, did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 11 - Retirement Benefits for additional information.
Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly
In April 2009, the FASB issued additional authoritative guidance regarding the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for an asset or liability. The guidance, which applies to all fair value measurements, does not change the objective of a fair value measurement. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.
Recognition and Presentation of Other-Than-Temporary Impairments
In April 2009, the FASB issued authoritative guidance that established a new method of recognizing and reporting other-than-temporary impairments of debt securities. It contains additional annual and interim disclosure requirements related to debt and equity securities. Under the new guidance, an impairment of debt securities is other-than-temporary if (1) the entity intends to sell the security, (2) it is more likely than not that the entity will be required to sell the security before recovery of its amortized cost basis, or (3) the entity does not expect to recover the security’s entire amortized cost basis. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.
Subsequent Events
In May 2009, the FASB issued authoritative guidance that established general standards of accounting for, and disclosure of, events that occur after the balance sheet date
but before financial statements are issued or are available to be issued. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity. In February 2010, the FASB issued amended guidance which was effective upon issuance. The adoption of the amended guidance did not have a material impact on our results of operations, financial position, or liquidity.
The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles
In June 2009, the FASB issued the FASB Accounting Standards Codification (the “Codification”), which is the primary source of authoritative GAAP to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification modifies the hierarchy of GAAP to include only two levels: authoritative and nonauthoritative. The Codification supersedes all non-SEC accounting and reporting standards. The adoption of the Codification, effective for us as of July 1, 2009, did not affect our results of operations, financial position, or liquidity.
Variable-Interest Entities
In June 2009, the FASB issued amended authoritative guidance that significantly changes the consolidation rules for VIEs. The guidance requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE based on whether the entity (1) has the power to direct matters that most significantly affect the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Further, the guidance requires an ongoing reconsideration of the primary beneficiary. It also amends the events that trigger a reassessment of whether an entity is a VIE. The adoption of this guidance, effective for us as of January 1, 2010, did not have a material impact on our results of operations, financial position, or liquidity.
Disclosures about Fair Value Measurements
In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance requires disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also requires information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. Further, the FASB clarified guidance regarding the level of disaggregation, inputs, and valuation techniques. This guidance was effective for us in the first quarter of 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which will be effective for us in the first quarter of 2011. The adoption of this guidance 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
Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. 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 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 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) The nuclear decommissioning trust fund assets of $293 million and $239 million as of December 31, 2009 and 2008, respectively, were restricted for decommissioning of the Callaway nuclear plant.
(c) Balance included $5 million in Other Current Liabilities on the balance sheet.
(d) Balance included in Other Deferred Credits and Liabilities on the balance sheet.
(e) Less than $1 million.
(f) All accretion expense was recorded as an increase to regulatory assets, except for Genco and CILCO (AERG).
(g) 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.
(h) UE and CILCO changed estimates for asbestos removal. Additionally, CILCO changed related estimates to retirement costs for its ash ponds.
Variable-Interest Entities
According to authoritative accounting guidance regarding variable-interest entities (VIEs), an entity is considered a 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 their equity interests, debt obligations, leases, contracts, and other agreements to determine their relationship to a VIE. We have determined that the following significant VIEs were held by the Ameren Companies at December 31, 2009:
Affordable housing partnership investments. At December 31, 2009 and 2008, Ameren had investments in multiple affordable housing and low-income real estate development partnerships as well as an investment in a commercial real estate development partnership of $64 million and $82 million in the aggregate, respectively. 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. 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.
Coal Contract Settlement
In June 2008, Genco entered into a settlement agreement with a coal mine owner. The owner provided Genco with a lump-sum payment of $60 million in July 2008 because of the coal supplier’s premature closing of a mine and the early termination of a coal supply contract. The settlement agreement compensated Genco, in total, for higher fuel costs it incurred in 2008 ($33 million) and in 2009 ($27 million) as a result of the mine closure and contract termination.
Employee Separation and Other Charges
In the third quarter of 2009, Ameren initiated a voluntary separation program that provided eligible management employees the opportunity to voluntarily terminate their employment and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management
employees at Ameren’s subsidiaries, including UE, CIPS, Genco, CILCO and IP. Additionally, in November 2009, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. Ameren recorded a pretax charge to earnings of $17 million in 2009 (UE - $8 million, CIPS - $1 million, Genco - $5 million, CILCO - $2 million, and IP - $1 million) for the severance costs related to both the voluntary and involuntary separation programs as well as for Merchant Generation staff reductions announced in the third quarter of 2009. These charges were recorded in other operations and maintenance expense in the applicable statements of income. Substantially all of this amount was paid prior to December 31, 2009. The number of positions eliminated as a result of these separation programs, including the Merchant Generation staff reductions, was approximately 300. In addition to these programs, Genco recorded a $4 million pretax charge to earnings in 2009 in connection with the retirement of two generating units at its Meredosia power plant and for related obsolete inventory.
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
2009 Electric Rate Order
In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. The rate changes necessary to implement the provisions of the MoPSC order were effective March 1, 2009. In February 2009, Noranda, UE’s largest electric customer, and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. In September 2009, the Circuit Court of Pemiscot County granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. The merits of the appeal continue to be briefed by the parties. A decision is likely to be issued by the Circuit
Court of Pemiscot County in the second quarter of 2010. During the stay, Noranda will pay into the court registry the contested portion of its monthly billings, approximately $0.5 million per month based on current usage levels. If UE wins the appeal, it will receive those monthly payments plus interest.
Pending Electric Rate Case
UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order, which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC. The balance of the increase request is based primarily on investments made to continue systemwide reliability improvements for customers, increases in costs essential to generating and delivering electricity, and higher financing costs. The initial electric rate increase request was based on an 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. In February 2010, UE filed rebuttal testimony relating to certain positions taken by interveners in the rate case and modified its recommended return on equity to 10.8%.
UE’s initial filing included a request for interim rate relief, which would have placed into effect approximately $37 million of the requested increase prior to completion of the full rate case. In January 2010, the MoPSC denied UE’s request for interim rate relief.
As part of its filing, UE also requested that the MoPSC approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker. The environmental cost recovery mechanism, if approved, would allow UE to adjust electric rates twice each year outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state, or local environmental laws, regulations, or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews by the MoPSC. UE’s request was consistent with the environmental cost recovery rules approved by the MoPSC in April 2009. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.
In addition, UE requested that the MoPSC approve the continued use of the FAC and the vegetation management and infrastructure inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order, and the continued use of the regulatory
tracking mechanism for pension and postretirement benefit costs that the MoPSC previously authorized in its May 2007 electric rate order. The UE request included the discontinuation of the SO 2 emission allowance sales tracker.
UE’s filing with the MoPSC also seeks approval to revise the tariff under which it serves Noranda to prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, such as the revenue losses resulting from the January 2009 storm-related power outage.
The MoPSC staff has responded to the UE request for an electric service rate increase. The MoPSC staff has recommended an increase to UE’s annual revenues of between $218 million to $251 million based on a return on equity range of 9.0% to 9.7%. Included in this recommendation was approximately $214 million of increases in normalized net fuel costs. Other parties also made recommendations through testimony filed in this case. MoPSC staff and other parties have expressed opposition to some of the requested cost recovery mechanisms as well as the proposed Noranda tariff revision.
The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010. Hearings are scheduled in March 2010. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the cost recovery mechanisms and trackers requested will be approved or continued, or whether any rate change that may eventually be approved will be sufficient to enable UE to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.
Renewable Energy Portfolio Requirement
A ballot initiative passed by Missouri voters in November 2008 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 implementing the renewable energy portfolio requirement are expected to be issued by the MoPSC in 2010. UE expects that any related costs or investments would ultimately be recovered in rates. In January 2010, UE issued an RFP to solicit solar renewable energy credits and energy in 2011 to meet the solar portion of this requirement. UE is currently evaluating the responses.
Missouri Energy Efficiency Investment Act
In July 2009, the Missouri governor signed a law that went into effect in August 2009, which, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. Recovery is permitted only if the program is approved by the MoPSC, results in energy savings, and is beneficial to all customers in the class for which the program is proposed. The new law could potentially, among other things, allow UE to earn a return on its energy efficiency programs equivalent to the return UE could earn with supply-side capital investments, such as new power plants.
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 a 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008.
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 the rate order to the Appellate Court of Illinois, Fourth District, specifically, the ICC’s affirmation of the recovery of a certain amount of fixed costs in the customer charge. In December 2009, the Appellate Court denied the Illinois attorney general’s appeal and sustained the ICC rate order.
Pending Electric and Natural Gas Delivery Service Rate Cases
In June 2009, CIPS, CILCO and IP filed requests with the ICC to increase their annual revenues for electric delivery service. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $115 million in the aggregate (CIPS - $38 million, CILCO - $17 million, and IP - $60 million). Additionally, the Ameren Illinois Utilities requested moving more of the electric delivery costs into the monthly non-volumetric charge, similar to the natural gas delivery rate design change approved by the ICC in 2008. The electric rate increase requests were based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.3 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010.
CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $15 million in the aggregate (CIPS - $6 million, CILCO - $2 million, and IP - $7 million). The natural gas rate increase requests were based on a 10.8% to 11.2% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010.
The ICC staff has responded to the filed requests by the Ameren Illinois Utilities. The ICC staff has recommended, as amended, a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $57 million in the aggregate (CIPS - $21 million increase, CILCO - $5 million increase, and IP - $31 million increase) and a net decrease in revenues for natural gas delivery service of $11 million in the aggregate (CILCO - $6 million decrease and IP - $5 million decrease). The ICC staff position was based on a 10.1% to 10.4% return on equity for electric delivery service and a 9.4% to 9.6% return on equity for natural gas delivery service. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.
In February 2010, administrative law judges issued a consolidated proposed order, which included a recommended revenue increase for electric delivery service for the Ameren Illinois Utilities of $66 million in the aggregate (CIPS - $26 million increase, CILCO - $6 million increase, and IP - $34 million increase) and a recommended revenue net decrease for natural gas delivery service of $10 million in the aggregate (CIPS - $1 million increase, CILCO - $ 6 million decrease, and IP - $5 million decrease). The ICC is not bound by the proposed order issued by the administrative law judges.
The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010. The Ameren Illinois Utilities cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the rate changes go into effect.
2007 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 2007 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 2007 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, 2009.
The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding under the 2007 Illinois Electric Settlement Agreement in a manner corresponding with the timing of the funding. As a result, 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, 2009, of $25 million, $3 million, $2 million, $5 million, $10 million, and $5 million, respectively (year ended December 31, 2008 - $42 million, $6 million, $3 million, $8 million, $17 million, and $8 million, respectively) under the terms of the 2007 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 before reimbursement is sought from the generators. At December 31, 2009, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $10 million, $3 million, $2 million, and $5 million, respectively. See Note 14 - Related Party Transactions for information on the impact of intercompany settlements.
The 2007 Illinois Electric Settlement Agreement provided that if before August 1, 2011, legislation is enacted in Illinois 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 2007 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
As part of the 2007 Illinois Electric Settlement Agreement, the reverse auction used for power procurement in Illinois was discontinued. However,
one-third of the existing supply contracts from the September 2006 reverse power procurement auction remain in place through May 2010. A new competitive power procurement process led by the IPA, which was established as a part of the 2007 Illinois Electric Settlement Agreement, was implemented beginning in January 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 that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy swaps, and renewable energy credits through an RFP process on behalf of the Ameren Illinois Utilities in the second quarter of 2009. See Note 14 - Related Party Transactions and Note 15 - Commitments and Contingencies for additional information about the Ameren Illinois Utilities’ purchased power agreements.
In December 2009, the ICC approved a plan for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The IPA will procure energy swaps, capacity and renewable energy credits and long-term renewable supply. The exact dates of each procurement event have not been determined. Following successful completion of the proposed 2010 procurement events, the Ameren Illinois Utilities will have sufficient capacity and energy hedges in place for 100% of their expected supply obligation for the period June 2010 through May 2011, 70% of their expected supply obligation for the period June 2011 through May 2012, and 44% of their expected supply obligations for the period June 2012 through May 2013. The Ameren Illinois Utilities will also have sufficient renewable energy credits to satisfy the 2010 planning year requirement along with 20-year renewable supply contracts consisting of 600,000 megawatthours per year of renewable energy power and credits with deliveries beginning June 1, 2012.
Also as part of the 2007 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 7 - Derivative Financial Instruments and Note 14 - Related Party Transactions for additional information on these financial contracts.
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. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. The Ameren Illinois Utilities expect they could incur an estimated $20 million ($15 million for distribution and $5 million for transmission) of capital costs and an estimated $66 million ($50 million for distribution and $16 million for transmission) of cumulative operations and maintenance expenses for the 2010 through 2013 time frame in order to implement the recommendations.
In December 2009, the Ameren Illinois Utilities requested ICC approval of a rider mechanism to recover the distribution-related costs associated with the Liberty Consulting Group’s recommendations. This request replaced a previous request for a rider mechanism, which had been part of the pending electric delivery rate cases. There is no statutory date by which the ICC must act, and no schedule is currently in place for this request.
The Ameren Illinois Utilities have committed to implement various audit recommendations, as outlined in their November 2008 plan. However, in order to fulfill that commitment in a timely manner, they must be able to synchronize the timing of their distribution-implementation expenditures with the recognition of those costs in rates. Without the necessary funding or a rider mechanism to recover the distribution costs, the Ameren Illinois Utilities may defer some of the projects until the distribution costs can be recovered either in base rates or through some other cost recovery mechanism.
Transmission-related costs, as incurred, will be recoverable through FERC’s ratemaking proceedings.
Illinois 2009 Energy Legislation
In July 2009, a new law became effective in Illinois that, among other things, established new energy efficiency targets for Illinois natural gas utilities, developed a percentage of income payment plan for low-income utility customers, and allowed electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their base rates. In February 2010, the ICC approved the Ameren Illinois Utilities’ electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in base rates. The tariffs provide utilities the ability to adjust their base rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. Upon ICC approval of the rate adjustment tariffs in February 2010, the Ameren Illinois Utilities made a one-time $10 million donation (CIPS - $2 million, CILCO - $2 million, and IP - $6 million) for customer assistance programs, as required by the legislation. The amount of the required one-time donation and the impact of the net recovery of 2008 and 2009 bad debt expenses were reflected in 2009 earnings.
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 have received 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 allow 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 provided 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. If UE were to withdraw from MISO in the future, it might need to
obtain FERC approval and to meet conditions imposed by FERC, in addition to obtaining MoPSC’s approval.
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 MISO and PJM for revenues lost when FERC eliminated the regional through-and-out rates previously applicable to transactions crossing the border between 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). Several parties filed rehearing requests of this initial decision. 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 charges of $10 million, $3 million, $1 million, and $6 million, respectively. CILCO’s net SECA charges were less than $1 million. In December 2009, a party that has not settled its SECA charges filed with the U.S. Court of Appeals for the District of Columbia Circuit seeking an order directing the FERC to resolve the SECA matters. In response to this filing, in January 2010, FERC agreed to issue an order on the SECA initial decision and rehearing requests by the end of May 2010. While we cannot predict the ultimate outcome of the SECA proceedings, we do not believe the outcome of the proceedings will have a material effect 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 issued an order granting the request for clarification. FERC directed MISO to reallocate certain MISO operational costs among MISO participants and provide refunds for the period April 2006 to August 2007 (“November 7, 2008 Clarification Order”). On November 10, 2008, FERC granted further relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding further reallocation for these MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward (“November 10, 2008 Complaint Order”).
Several parties to these proceedings protested MISO’s proposed implementation of these refunds, requested rehearing of FERC’s orders and, in some cases, appealed FERC’s orders to the courts. In March 2009, MISO began resettling its markets to provide refunds as FERC directed retroactive from August 10, 2007. In May 2009, FERC issued an order that upheld most of the conclusions of the November 10, 2008 Complaint Order but changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 10, 2008, instead of August 10, 2007. In June 2009, UE, CIPS, CILCO and IP filed for rehearing of the May 2009 order regarding the change to the refund effective date. This rehearing request is pending.
With respect to the November 7, 2008 Clarification Order, in June 2009 FERC issued an order dismissing rehearing requests of such clarification order and waiving refunds of amounts billed that were included in the MISO charge, under the assumption that there was a rate mismatch for the period April 25, 2006, through November 4, 2007. UE, CIPS, CILCO and IP filed a request for rehearing in July 2009. This rehearing request is pending.
With respect to the two rehearing requests discussed above, UE, CIPS, CILCO and IP do not believe that the ultimate resolution of either request will have a material effect on their results of operations, financial position, or liquidity.
MISO and PJM Dispute Resolution
During 2009, MISO and PJM discovered an error in the calculation quantifying certain transactions between the
RTOs. The error, which originated in April 2005, at the initiation of the MISO Energy and Operating Reserves Market was corrected prospectively in June 2009. Since discovering the error, MISO and PJM have worked jointly to estimate its financial impact on the respective markets. MISO and PJM are in agreement about the methodology used to recalculate the market flows occurring from June 2007 to June 2009 for the resettlement due from PJM to MISO estimated at $65 million. MISO and PJM are not in agreement about the methodology used to recalculate the market flows occurring from April 2005 to May 2007, nor are they in agreement about the resettlement amount. To resolve this issue, MISO and PJM have agreed to participate in FERC’s dispute resolution and settlement process in order to determine a resettlement amount for the entire period from April 2005 to June 2009. In October 2009, an administrative law judge was appointed as mediator, and multiple settlement conferences were held at FERC in late 2009 and early 2010. A final settlement between MISO and PJM, if and when reached, will probably require filings to be made by PJM and MISO with FERC. Ameren and its subsidiaries may receive a to-be-determined portion of the resettlement amount due from PJM to MISO. No prospective refund has been recorded related to this matter. Until a settlement has been reached and approved by FERC, we cannot predict the ultimate impact of these proceedings on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.
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. The complaint 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, and UE paid these charges. Additional charges continued during the remainder of the term of the power purchase agreement, which expired on August 31, 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 also 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 was just and reasonable. In January 2010, FERC issued an opinion reversing the administrative law judge’s initial decision and ruling that Entergy may not pass additional charges to UE. In February 2010, Entergy filed a request for rehearing of the January 2010 opinion. UE has recorded the additional charges related to the July 2007 order, but has not recorded any prospective refund. UE is unable to predict how or when the FERC will rule on the motions. Therefore, UE is unable to predict whether FERC ultimately will order Entergy to refund to UE the additional charges.
Additionally, LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy Services, Inc. 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 decisions. 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, although FERC’s ruling in January 2010, discussed above, assuming it is upheld after any rehearings or appeals, likely will prevent FERC from ordering UE to pay any amounts retroactively. 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, 2009. UE plans to participate in any proceeding that FERC initiates to address the court’s decisions.
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 new 1,600-megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. UE also signed contracts for COLA-related services and certain long lead-time nuclear-unit related equipment (heavy forgings).
In early 2009, the Missouri Clean and Renewable Energy Construction Act was separately introduced in both the Missouri Senate and House of Representatives. One purpose of these bills was to allow the MoPSC to authorize utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant is being constructed. Recovery of actual construction costs still would not begin until a plant goes into service. UE believes legislation allowing timely recovery of financing costs during construction must be enacted in order for it to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of this or other legislation was not a commitment or guarantee that UE would build a new nuclear unit.
In April 2009, senior management of UE announced that they had asked the legislative sponsors of the Missouri Clean and Renewable Energy Construction Act to withdraw the bills from consideration by the Missouri General Assembly. UE believed that the legislation being considered in the Missouri Senate in its then proposed form would not provide UE with the financial and regulatory certainty it needed to pursue the project. As a result, UE announced that it was suspending its efforts to build a new nuclear unit at its existing Missouri nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. The contract for COLA-related services was amended in December 2009 in several respects, including changes to the termination provisions in
light of UE’s decision to suspend its efforts to build a new nuclear unit. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE will file with the MoPSC in 2011.
As of December 31, 2009, UE had capitalized approximately $69 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned or management concludes it is probable the cost incurred will be disallowed in rates, it is possible that a charge to earnings could be recognized in a future period.
Prior to June 30, 2009, UE made contractual payments to the heavy forgings manufacturer of $14 million and had
remaining contractual commitments of $81 million. In July 2009, when an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings procurement agreement, $5 million in previous payments was retained by the manufacturer as a penalty for terminating the contract. That amount was charged to earnings in June 2009.
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 application for relicensing is pending.
Regulatory Assets and Liabilities
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, 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, 2009 and 2008:
(a) Includes intercompany eliminations.
(b) These assets earn a return.
(c) Under-recovered fuel costs for the accumulation periods from June 2009 through September 2009 and October 2009 through December 2009. Recovery of the earlier accumulation period will begin in February 2010 while the recovery of the later accumulation period will begin in June 2010.
(d) Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(e) Current portion of deferral of commodity-related derivative MTM losses, as well as the current portion of the MTM losses on financial contracts entered into by the Ameren Illinois Utilities with Marketing Company. See Illinois - Power Procurement Plan discussion above for additional information.
(f) Included in Current Regulatory Assets on the balance sheet of UE, CIPS, CILCO and IP and in Other Current Assets on the balance sheet of Ameren.
(g) 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. See Note 11 - Retirement Benefits for additional information.
(h) Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period.
(i) 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.
(j) 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.
(k) 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.
(l) The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost recovery riders in Illinois. The period of recovery will depend on the timing of actual expenditures. See Note 15 - Commitments and Contingencies for additional information.
(m) Reorganization costs related to the integration and restructuring of IP into the Ameren system. Pursuant to the ICC order approving Ameren’s acquisition of IP, these costs are recoverable in rates through 2010.
(n) A portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP. 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.
(o) Deferral of commodity-related derivative MTM losses, as well as the MTM losses on financial contracts entered into by the Ameren Illinois Utilities with Marketing Company. See Illinois - Power Procurement Plan discussion above for additional information.
(p) 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. In its pending rate case, UE requested the discontinuation of this tracker.
(q) 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. They will be amortized over a two-year period beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
(r) A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE and the level of such costs built into electric rates. UE’s vegetation management and infrastructure inspection costs from January 1, 2008, through February 28, 2009, exceeded the amount allowed in base rates. The excess costs incurred between January 1, 2008, through September 30, 2008, are being amortized over three years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order. The amortization period for the excess costs incurred from October 1, 2008, through February 28, 2009, will be determined in UE’s pending electric rate case.
(s) 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 five years, beginning on June 4, 2007. The 2008 storm costs are being amortized over five years, beginning on 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 on March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
(t) Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. These costs are being amortized over ten years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
(u) Reserve for workers’ compensation claims.
(v) A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by the Ameren Illinois Utilities and the level of such costs built into electric and natural gas rates. The under-recovery relating to 2008 will be recovered from customers from March 2010 through December 2010. The under-recovery relating to 2009 will be recovered from customers from June 2010 through May 2011.
(w) 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 low-income weatherization and other miscellaneous items.
(x) Over-recovered fuel costs for the accumulation period from March 2009 through May 2009. Customer refunds began in October 2009 and will continue through September 2010.
(y) Current portion of deferral of commodity-related derivative MTM gains.
(z) Included in Current Regulatory Liabilities on the balance sheet of IP and in Other Current Liabilities on the balance sheets of Ameren, UE, CIPS and CILCO.
(aa) Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.
(bb) 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.
(cc) The deferral of gains on emission allowance vintage swaps UE entered into during 2005. This gain will be amortized through February 2011.
(dd) A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE and the level of such costs built into electric rates. This over-recovery relates to the period March 1, 2009, through December 31, 2009. The amortization period for this over-recovery will be determined in a future UE electric rate case.
(ee) Deferral of commodity-related derivative MTM gains.
(ff) A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by the Ameren Illinois Utilities and the level of such costs built into electric and natural gas rates. The over-recovery relating to 2009 will be refunded to customers June 2010 through May 2011.
(gg) 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.
(hh) 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.
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. To the extent that payments of regulatory liabilities are no longer probable, the amounts are credited to earnings.
NOTE 3 - PROPERTY AND PLANT, NET
The following table presents property and plant, net, for each of the Ameren Companies at December 31, 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(b) Amounts in Ameren and UE include two electric generation CTs under two separate capital lease agreements with a gross asset value of $226 million and $222 million at December 31, 2009 and 2008, respectively. The total accumulated depreciation associated with the two CTs was $41 million and $36 million at December 31, 2009 and 2008, respectively.
The following table provides accrued capital expenditures at December 31, 2009, 2008, and 2007, which represent noncash investing activity excluded from the statements of cash flows:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 4 - CREDIT FACILITY BORROWINGS AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, or 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, 2009 and 2008, respectively, and excludes letters of credit issued under the credit facility:
(a) The 2009 Multiyear Credit Agreement amended and restated the Prior $1.15 Billion Credit Facility. Therefore, information in this table includes borrowing activity under the Prior $1.15 Billion Credit Facility.
(b) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the $150 million Supplemental Agreement described below for the year ended December 31, 2009:
(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the $800 million 2009 Illinois Credit Agreement described below for the year ended December 31, 2009:
(a) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company may not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit facility, which was terminated during 2009, for the years ended December 31, 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Calculated through the termination date.
(c) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit facility, which was terminated during 2009, for the years ended December 31, 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Calculated through the termination date.
(c) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings under all facilities during 2009 were $1 billion.
On June 30, 2009, Ameren and certain of its subsidiaries entered into multiyear credit facility agreements with 24 international, national, and regional lenders, with no single lender providing more than $146 million of credit. These facilities, as described below, cumulatively provide $2.1 billion of credit through July 14, 2010, reducing to $1.8795 billion through June 30, 2011, and to $1.0795 billion through July 14, 2011.
2009 Multiyear Credit Agreements
On June 30, 2009, Ameren, UE, and Genco entered into an agreement (the “2009 Multiyear Credit Agreement”) to amend and restate the $1.15 billion five-year revolving credit agreement that was originally entered into on July 14, 2005, amended and restated as of July 14, 2006, and due to expire in July 2010 (the “Prior $1.15 Billion Credit Facility”). Ameren, UE, and Genco also entered into a $150 million Supplemental Credit Agreement to the 2009 Multiyear Credit Agreement (the “Supplemental
Agreement”), which provides Ameren, UE, and Genco with an additional facility of $150 million with terms and conditions substantially identical to the 2009 Multiyear Credit Agreement. Collectively, these agreements are the “2009 Multiyear Credit Agreements.”
The obligations of each borrower under the 2009 Multiyear Credit Agreements are several and not joint. Except under limited circumstances relating to expenses and indemnities, the obligations of UE or Genco are not guaranteed by Ameren or by any other subsidiary of Ameren. The combined maximum amount available to all of the borrowers, collectively, under the 2009 Multiyear Credit Agreements is $1.3 billion, and the combined maximum amount available to each borrower, individually, under the 2009 Multiyear Credit Agreements is limited as follows: Ameren - $1.15 billion, UE - $500 million and Genco - $150 million (such amounts being each borrower’s “Borrowing Sublimit”). CIPS, CILCO and IP have no borrowing authority or liability under the 2009 Multiyear Credit Agreements.
On July 14, 2010, when the Supplemental Agreement terminates, all commitments and all outstanding amounts under the Supplemental Agreement will be consolidated with those under the 2009 Multiyear Credit Agreement, and the combined maximum amount available to all borrowers will be $1.0795 billion. The UE and Genco Borrowing Sublimits will remain as noted above; the Ameren sublimit will change to $1.0795 billion. Ameren has the option of seeking additional commitments from existing or new lenders to increase the total facility size to $1.3 billion after July 14, 2010. The 2009 Multiyear Credit Agreement will terminate with respect to Ameren on July 14, 2011, one year after the Prior $1.15 Billion Credit Facility. The Borrowing Sublimits of UE and Genco will continue to be subject to extensions on a 364-day basis (but in no event later than July 14, 2011). The current maturity date of their Borrower Sublimits under the 2009 Multiyear Credit Agreements is June 29, 2010.
The obligations of all borrowers under the 2009 Multiyear Credit Agreements are unsecured. The interest rates applicable to loans under the 2009 Multiyear Credit Agreements will be either the alternate base rate, as defined, plus the margin applicable to the particular borrower or the eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by reference to such borrower’s long-term unsecured credit ratings in effect at the time. A competitive bid rate is also available if requested by a borrower. Letters of credit in an aggregate undrawn face amount not to exceed $287.5 million are available for issuance for account of the borrowers under the 2009 Multiyear Credit Agreements (but within the $1.3 billion overall combined facility limitation).
Under the 2009 Multiyear Credit Agreements, the principal amount of each revolving loan will be due and payable no later than the final maturity of the agreements, for Ameren, and the last day of the then applicable 364-day period for UE and Genco. Ameren, UE and Genco will use the proceeds of any borrowings under the 2009 Multiyear Credit Agreements for general corporate purposes, including working capital, and to fund loans under the Ameren money pool arrangements.
2009 Illinois Credit Agreement
Also on June 30, 2009, Ameren, CIPS, CILCO, and IP entered into an $800 million multiyear, senior secured credit agreement (the “2009 Illinois Credit Agreement”). The 2009 Illinois Credit Agreement replaced the Ameren Illinois Utilities’ $500 million credit facility dated July 14, 2006 (the “2006 $500 Million Credit Facility (Terminated)”), and their $500 million credit facility dated February 9, 2007 (the “2007 $500 Million Credit Facility (Terminated)”), each as previously amended (collectively, the “Terminated Illinois Credit Facilities”). They were terminated when the 2009 Illinois Credit Agreement went into effect.
Ameren was not a borrower under the Terminated Illinois Credit Facilities, but it is a borrower under the 2009 Illinois Credit Agreement. AERG was a borrower under the
Terminated Illinois Credit Facilities, but it was not party to or a borrower under the 2009 Illinois Credit Agreement. All obligations of AERG under the Terminated Illinois Credit Facilities have been repaid, and all liens securing such obligations have been released. AERG expects to meet its external liquidity needs through borrowings under the Ameren non-state-regulated subsidiary money pool arrangements or other liquidity arrangements.
The obligations of each borrower under the 2009 Illinois Credit Agreement are several and not joint. They are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower under the facility is limited as follows: Ameren - $300 million, CIPS - $135 million, CILCO - $150 million and IP - $350 million (such amounts being such borrower’s “Borrowing Sublimit”).
The 2009 Illinois Credit Agreement will terminate with respect to all borrowers on June 30, 2011. Each borrowing under the 2009 Illinois Credit Agreement must be repaid no later than 364 days after such borrowing. In each case, the borrower may on such date make a new borrowing, or convert or continue such borrowing as a new borrowing subject to satisfaction of the applicable conditions. The obligations of the Ameren Illinois Utilities under the 2009 Illinois Credit Agreement are secured by the issuance of mortgage bonds, for collateral support, by each such utility under its respective mortgage indenture, in an amount equal to its respective Borrowing Sublimit. Ameren’s obligations are unsecured.
Loans are available on a revolving basis under the 2009 Illinois Credit Agreement. They may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates applicable under the 2009 Illinois Credit Agreement are the alternate base rate, as defined, plus the margin applicable to the particular borrower or the eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined, in the case of Ameren, by Ameren’s long-term unsecured credit ratings in effect, at the time, and in the case of the Ameren Illinois Utilities, such utility’s long-term secured credit ratings at the time. Letters of credit in an aggregate undrawn face amount not to exceed $200 million are also available for issuance for the account of the borrowers under the 2009 Illinois Credit Agreement (but within the $800 million overall facility limitation).
Due to outstanding borrowings under the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement (including reductions for $15 million of letters of credit issued under the 2009 Multiyear Credit Agreements), the available amounts under the facilities at December 31, 2009, were $555 million and $700 million, respectively.
Other Agreements
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. The average annual interest rate for borrowing under the $20 million term loan agreement was 2.03% during the year ended December 31, 2009. This term loan agreement was repaid at maturity in January 2010.
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. The average annual interest rate for borrowing under the $300 million term loan agreement was 1.97% during the period it was outstanding in 2009. This term loan was repaid at maturity in June 2009 with proceeds from the issuance by Ameren of $425 million principal amount of senior unsecured notes due May 2014. See Note 5 - Long-term Debt and Equity Financings.
Indebtedness Provisions and Other Covenants
The 2009 Multiyear Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. The 2009 Multiyear Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, and to merge with other entities. In addition, Ameren and certain subsidiaries are restricted to limited investments in and other transfers to affiliates, including investments in the Ameren Illinois Utilities and their subsidiaries.
The 2009 Multiyear Credit Agreements contain identical default provisions including a cross default of a borrower to the occurrence of a default by such borrower under any other agreement covering indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and non-material subsidiaries) in excess of $25 million in the aggregate. A default by an Ameren Illinois utility under the 2009 Illinois Credit Agreement does not constitute a default under the 2009 Multiyear Credit Agreements. Any default of Ameren under the 2009 Illinois Credit Agreement that occurs solely as a result of a default by an Ameren Illinois utility thereunder will not constitute a default under either of the 2009 Multiyear Credit Agreements while Ameren is otherwise in compliance with all of its obligations under the 2009 Illinois Credit Agreement.
The 2009 Multiyear Credit Agreements require Ameren, UE and Genco each to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a calculation set forth in the facilities. All of the consolidated subsidiaries of Ameren, including the Ameren Illinois Utilities, are included for purposes of determining compliance with this capitalization test with respect to Ameren. Failure to satisfy the capitalization covenant constitutes a default under the 2009 Multiyear Credit Agreements. As of December 31, 2009, the ratios of consolidated indebtedness to total consolidated
capitalization, calculated in accordance with the provisions of the 2009 Multiyear Credit Agreements, were 51%, 48% and 54%, for Ameren, UE and Genco, respectively.
The 2009 Illinois Credit Agreement contains conditions to borrowings and issuance of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding, for so long as ratings conditions shall be satisfied, any representation after the closing date as to the absence of material adverse change and material litigation, which is new to the 2009 Illinois Credit Agreement), and required regulatory authorizations. The rating condition is satisfied if the borrower has a Moody’s rating of Baa3 or higher or an S&P rating of BBB- or higher (in the case of Ameren, with respect to senior unsecured long-term debt, and in the case of the Ameren Illinois Utilities, with respect to senior secured long-term debt). The 2009 Illinois Credit Agreement contains nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, and to merge with other entities. The Ameren Illinois Utilities may engage in certain mergers or similar transactions that may cause their utility operations to be conducted by a single legal entity. In addition, the 2009 Illinois Credit Agreement has nonfinancial covenants that limit the ability of a borrower to invest in or to transfer assets to affiliates, covenants regarding the status of the collateral securing the 2009 Illinois Credit Agreement, and maintenance of the validity of the security interests therein.
The 2009 Illinois Credit Agreement contains default provisions. Defaults under the 2009 Illinois Credit Agreement apply separately to each borrower; provided that a default by an Ameren Illinois utility will constitute a default by Ameren. Defaults include a cross default of a borrower to the occurrence of a default by such borrower under any other agreement covering indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and non-material subsidiaries) in excess of $25 million in the aggregate. A default by Genco or UE under the 2009 Multiyear Credit Agreements does not constitute an event of default under the 2009 Illinois Credit Agreement. Any default of Ameren under the 2009 Multiyear Credit Agreements that occurs solely as a result of a default by UE or Genco thereunder will not constitute a default under the 2009 Illinois Credit Agreement while Ameren is otherwise in compliance with all of its obligations under the 2009 Multiyear Credit Agreements. Furthermore, under the 2009 Illinois Credit Agreement, the occurrence of a default resulting from an event or conditions effecting AERG shall be deemed to constitute a default with respect to Ameren under the 2009 Illinois Credit Agreement, but shall not in itself constitute a default with respect to CILCO, unless the liability that CILCO has for such default or such underlying event or condition giving rise to such default would otherwise constitute a default with respect to CILCO if the underlying event or condition had occurred or existed at CILCO.
The 2009 Illinois Credit Agreement requires Ameren and each Ameren Illinois utility to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation. All of the consolidated subsidiaries of Ameren are included for purposes of determining compliance with this capitalization test with respect to Ameren. As of December 31, 2009, the ratios of consolidated indebtedness to total consolidated capitalization for Ameren, CIPS, CILCO and IP, calculated in accordance with the provisions of the 2009 Illinois Credit Agreement, were 51%, 44%, 41%, and 46%, respectively. In addition, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, at the end of the most recent four fiscal quarters, calculated and subject to adjustment in accordance with the 2009 Illinois credit agreement. Ameren’s ratio as of December 31, 2009, was 4.6 to 1. Failure to satisfy these covenants constitutes a default under the 2009 Illinois Credit Agreement.
In addition, the 2009 Illinois Credit Agreement prohibits CILCO from issuing any preferred stock if, after such issuance, the aggregate liquidation value of all CILCO preferred stock issued after June 30, 2009, would exceed $50 million.
None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause default or acceleration of repayment of outstanding balances. At December 31, 2009, 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 are the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent 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, 2009, was 0.19% (2008 - 2.85%).
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 the 2009 Multiyear Credit Agreements through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any time is reduced by borrowings made by Ameren’s subsidiaries, but 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 2009 Multiyear Credit Agreements at December 31, 2009. 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, 2009 was 1.64% (2008 - 3.51%).
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, 2009, 2008, and 2007.
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 credit facility 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 unilateral borrowing 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, 2009 and 2008:
(a) At December 31, 2009, 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 101% of par, declining to 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 102.28% of par, declining annually thereafter to 100% of par in June 2012); 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 - 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 and 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 2009 and 2008 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. If UE should elect to defer interest payments, UE dividend payments to Ameren would be prohibited. UE has not elected to defer any interest payments.
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2009:
(a) Excludes unamortized discount and premium of $2 million, $8 million, $1 million, $2 million, and $9 million at Ameren (Parent), UE, CIPS, Genco, and IP, respectively.
(b) Excludes $45 million due in 2010 related to a note payable to an affiliate. See Note 14 - Related Party Transactions for additional information.
(c) Excludes $6 million related to IP’s long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt.
All of the Ameren Companies expect to fund maturities of long-term debt, short-term borrowings, credit facility borrowings and contractual obligations through a combination of cash flow from operations and external financing. See Note 4 - Credit Facility Borrowings and Liquidity for a discussion of external financing availability.
In November 2008, Ameren, 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. In June 2008, UE 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.
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, 2009:
Ameren
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, Ameren issued 3.2 million, 4.0 million, and 1.7 million shares of common stock in 2009, 2008, and 2007, respectively, which were valued at $82 million, $154 million, and $91 million for the respective years.
In May 2009, Ameren issued $425 million of 8.875% senior unsecured notes due May 15, 2014, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2009. Ameren received net proceeds of $420 million, which were used, together with other corporate funds, to repay borrowings under its $300 million term loan agreement and, by way of a capital contribution to CILCORP, providing funds for CILCORP to repay its outstanding 8.70% senior notes on their due date of October 15, 2009.
In September 2009, Ameren issued and sold 21.85 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of equity capital contributions as follows: UE - $436 million, CIPS - $13 million, CILCO - $25 million, and IP - $61 million.
UE
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 would 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 would not, prior to maturity, cause a first mortgage bond release date to occur. The first mortgage bond 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.
In March 2009, UE issued $350 million of 8.45% senior secured notes due March 15, 2039, with interest payable semiannually on March 15 and September 15 of each year, beginning in September 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $346 million, which were used to repay short-term debt. In connection with this issuance of $350 million of senior secured notes, UE agreed that, so long as these senior secured notes are outstanding, it would 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 was used to fund capital expenditures, to repay short-term debt, and for other general corporate purposes. Genco exchanged the outstanding unregistered unsecured notes for registered unsecured notes in July 2008.
In November 2009, Genco issued $250 million of 6.30% senior unsecured notes due April 1, 2020, with interest payable semiannually on April 1 and October 1 of each year, beginning in April 2010. Genco received net proceeds of $247 million, which were used to repay short-term debt, and for general corporate purposes.
CILCORP
In October 2009, $124 million of CILCORP’s 8.70% senior notes matured and were retired.
In December 2009, CILCORP paid $256 million, including tender offer and consent payments and accrued interest, in connection with the repurchase and cancellation of $208 million principal amount outstanding of its 9.375% senior bonds. After the repurchase, approximately $2 million principal amount of senior bonds remained outstanding. Sufficient consents were received to approve the adoption of amendments to eliminate certain restrictive covenants to the related indenture. As a result of this cancellation, fair-market value adjustments related to the senior bonds were reduced by $44 million during 2009.
In February 2010, CILCORP completed a covenant defeasance of its remaining outstanding 9.375% senior bonds due 2029 by depositing approximately $2.7 million in U.S. government obligations and cash with the indenture trustee. This deposit will be used solely to satisfy the principal and remaining interest obligations on these bonds. In connection with this covenant defeasance, the lien on the capital stock of CILCO securing these bonds was released.
CILCO
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 borrowings. 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 would 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
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 would 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.
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 would 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. In March 2009, IP exchanged all $400 million of its unregistered 9.75% senior secured notes for a like amount of registered 9.75% senior secured notes due November 15, 2018.
In June 2009, $250 million of IP’s 7.50% series first mortgage bonds matured and were retired.
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 issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, not meeting these ratios would not result in a default under these covenants and provisions. 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, 2009, 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 required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $95 million, $18 million, $44 million, and $536 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, 2009, CILCO had earnings equivalent to at least 38% of the principal amount of all mortgage bonds outstanding.
(e) See Note 4 - Credit Facility Borrowings and Liquidity for a discussion regarding a restriction on the issuances of preferred stock by CILCO.
UE, CIPS, Genco, CILCO and IP as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations; however, FERC has consistently
interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, CIPS, CILCO and IP may not pay any dividend on their respective stock, unless, among other things, their respective earnings
and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless CIPS, CILCO or IP has specific authorization from the ICC.
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, 2009.
CIPS’ articles of incorporation and mortgage indentures require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus.
CILCO’s articles of incorporation prohibit the payment of dividends on its common stock from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock. Dividend payment is also prohibited if at the time of dividend declaration the earned surplus account (after deducting the payment of such dividends) would not contain an amount at least equal to two times the annual dividend requirement on all outstanding shares of CILCO’s preferred stock.
Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco 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, 2009:
(a) Interest coverage ratio relates to covenants about 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 four fiscal quarters most recently ended.
(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.
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.
In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2009, 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, 2009, 2008, and 2007:
(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, coal, diesel, electricity, uranium, and emission allowances. Such price fluctuations may cause 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 coal, natural gas, and uranium inventories or emission allowances that differ from the cost of those commodities in inventory; and

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. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross derivative volumes by commodity type as of December 31, 2009:
(a) Contracts through December 2013, March 2015, and September 2035 for coal, natural gas, and power, respectively.
(b) Contracts through December 2012 for power.
(c) Contracts through April 2012, December 2013, and May 2013 for natural gas, heating oil, and power, respectively.
(d) Contracts through October 2015, December 2013, December 2012, and November 2011 for natural gas, heating oil, power, and uranium, respectively.
(e) Includes amounts from Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(f) Not applicable.
Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 - Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or
expense recorded in connection with NPNS contracts is recognized at the contract price upon physical delivery.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting treatment. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting treatment are recorded at fair value with
changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.
Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. Regulatory assets or regulatory liabilities are amortized to the statement of income as related losses and gains are reflected in rates charged to customers.
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.
Authoritative accounting guidance 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. The Ameren Companies did not elect to adopt this guidance for any eligible financial instruments or other items.
The following table presents the carrying value and balance sheet classification of all derivative instruments as of December 31, 2009:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Balance sheet line item not applicable to registrant.
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of December 31, 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Represents net gains associated with power forwards at Ameren as of December 31, 2009. The power forwards are a partial hedge of electricity price exposure through August 2012 as of December 31, 2009. Current gains of $22 million and $123 million were recorded at Ameren as of December 31, 2009 and 2008, respectively. UE recorded current gains of $39 million as of December 31, 2008.
(c) Includes net gains 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, 2009 and 2008, was $1 million and $2 million, respectively. Over the next twelve months, $0.7 million of the gain will be amortized.
(d) Includes net losses 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 loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at December 31, 2009 and 2008, was a loss of $11 million and $13 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e) Represents net losses associated with natural gas swaps, forwards and futures contracts. The swaps, forwards and futures contracts are a partial hedge of natural gas requirements through October 2014 at IP, through March 2015 at UE and CIPS, and through October 2015 at CILCO, in each case as of December 31, 2009. Current gains deferred as regulatory liabilities include $1 million, $1 million, $2 million, and $1 million at UE, CIPS, CILCO and IP, respectively, as of December 31, 2009. Current losses deferred as regulatory assets include $8 million, $8 million, $7 million, and $17 million at UE, CIPS, CILCO and IP, respectively, as of December 31, 2009. Current gains deferred as regulatory liabilities include $10 million, $16 million, $17 million, and $36 million at UE, CIPS, CILCO and IP, respectively, as of December 31, 2008.
(f) Represents net losses associated with power forwards. The power forwards are a partial hedge of power price exposure through December 2011 at UE and December 2012 at CIPS, CILCO and IP, in each case as of December 31, 2009. Current gains deferred as regulatory liabilities include $5 million at UE as of December 31, 2009. Current losses deferred as regulatory assets include $6 million, $45 million, $20 million, and $68 million at UE, CIPS, CILCO and IP, respectively, as of December 31, 2009. Current losses deferred as regulatory assets include $14 million, $7 million, and $21 million at CIPS, CILCO and IP, respectively, as of December 31, 2008.
(g) Represents net gains on heating oil options and swaps at UE. The options and swaps are a partial hedge of our transportation costs for coal through December 2013 as of December 31, 2009. Current gains deferred as regulatory liabilities include $5 million at UE as of December 31, 2009. Current losses deferred as regulatory assets include $9 million at UE as of December 31, 2009.
(h) Represents net losses on uranium swaps at UE. The swaps are a partial hedge of our uranium requirements through November 2011 as of December 31, 2009. Current losses deferred as regulatory assets include $1 million at UE as of December 31, 2009.
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure as of December 31, 2009, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.
(a) Primarily comprised of Marketing Company’s exposure to Ameren Illinois Utilities related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 - Related Party Transactions for additional information on these financial contracts.
(b) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The following table presents the amount of cash collateral held from counterparties as of December 31, 2009, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:
(a) Represents amounts held by Marketing Company. As of December 31, 2009, Ameren registrant subsidiaries held no cash collateral.
The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. Other collateral consisted of letters of credit in the amount of $32 million, $1 million and $1 million held by Ameren, UE and Genco, respectively, as of December 31, 2009. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of December 31, 2009:
(a) Primarily comprised of Marketing Company’s exposure to Ameren Illinois Utilities related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 - Related Party Transactions for additional information on these financial contracts.
(b) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2009, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2009, and (2) those counterparties with rights to do so requested collateral:
(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.
(c) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Cash Flow Hedges
The following table presents the pretax net gain or loss associated with derivative instruments designated as cash flow hedges for the year ended December 31, 2009:
(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d) Includes amounts from Ameren registrants and nonregistrant subsidiaries.
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f) Less than $1 million.
Other Derivatives
The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the year ended December 31, 2009:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Derivatives Subject to Regulatory Deferral
The following table represents the net change in market value associated with derivatives that qualify for regulatory deferral for the year ended December 31, 2009:
(a) Includes intercompany eliminations.
UE, CIPS, CILCO and IP believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating expenses as related losses and gains are reflected in revenue through rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.
As part of the electric rate order issued by the MoPSC in January 2009, UE was granted permission to implement a FAC, which was effective March 1, 2009. UE uses derivatives to mitigate its exposure to changing prices of fuel for generation and related transportation costs, and for power price volatility. In connection with the MoPSC’s approval of the FAC, gains and losses associated with these types of derivatives are considered refundable to, or recoverable from, customers and thus represent regulatory liabilities or regulatory assets, respectively. During the first quarter of 2009, UE recorded a net regulatory liability of $5 million associated with the reclassification of unrealized gains and losses previously recorded in accumulated OCI and earnings related to open UE derivative positions with delivery dates subsequent to March 1, 2009. The reclassification of previously recorded unrealized gains associated with the derivatives resulted in a $47 million reduction of accumulated OCI. The reclassification of previously recognized unrealized losses resulted in a $42 million increase in pretax earnings, of which $38 million offset fuel expense and $4 million increased operating revenues. See Note 2 - Rate and Regulatory Matters for additional information on the FAC.
As part of the 2007 Illinois Electric Settlement Agreement and the 2009 RFP process, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives subject to regulatory deferral by the Ameren Illinois Utilities. 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 by the Ameren Illinois Utilities and OCI by Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments are eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts.
NOTE 8 - FAIR VALUE MEASUREMENTS
Fair value is defined 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 market 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. Authoritative accounting guidance established 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 are primarily 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. We value Level 3 instruments by 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, an evaluation 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 fair value measurements. 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.
In accordance with applicable authoritative accounting guidance, 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). The guidance 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 losses totaling less than $1 million in 2009 related to valuation adjustments for counterparty default risk. At December 31, 2009, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $3 million, $- million, $6 million, $- million, $8 million, and $10 million for Ameren, UE, CIPS, Genco, 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, 2009:
(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 $1 million of receivables, payables, and accrued income, net.
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 associated with financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 31, 2009:
(a) See Note 7 - Derivative Financial Instruments for additional information regarding the recording of net gains and losses on derivatives to the statement of income.
The following table summarizes the changes in the fair value associated with financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 31, 2008:
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 from previous periods. 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.
See Note 11 - Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 2009, as well as a table summarizing the changes in Level 3 plan assets during 2009.
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, 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Preferred stock along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
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 additional 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, 2009, and 2008.
Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities. Due to market conditions in 2008, the equity securities weighting was less than 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 resulting from those sales for the years ended December 31, 2009, 2008, and 2007:
Net realized and unrealized gains and losses are deferred and recorded as regulatory assets or regulatory liabilities on Ameren’s and UE’s Consolidated Balance Sheets. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which are expected to 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, 2009 and 2008:
(a) Amount less than $1 million.
(b) 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, 2009:
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 to the NRC to extend the 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, 2009:
(a) Amount less than $1 million.
NOTE 10 - PREFERRED STOCK
All classes of UE’s, CIPS’, CILCO’s and IP’s preferred stock are entitled to cumulative dividends and have voting rights. 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 redeemable, at the option of the issuer, at the prices presented as of December 31, 2009 and 2008:
(a) In the event of voluntary liquidation, $105.50.
(b) Redemption price as of December 31, 2009. Declining to $100 per share in 2012.
In addition, the Ameren Companies have classes of preferred stock that are authorized but no shares of which are outstanding. 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, with no such preference stock outstanding. CILCO has 2 million shares of no par value preference stock authorized, with no such preference stock outstanding. CILCO also has 3.5 million shares of no par value preferred stock authorized, with no shares 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.
NOTE 11 - RETIREMENT BENEFITS
The primary objective of the Ameren retirement plan and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. We offer defined benefit and postretirement benefit plans covering substantially all employees of UE, CIPS, 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.
The following table presents the benefit liability recorded on the balance sheets of each of the Ameren Companies as of December 31, 2009:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Ameren recognizes the underfunded status of its pension and postretirement plans as a liability on its balance sheet, with offsetting entries to accumulated OCI and regulatory assets, in accordance with authoritative accounting guidance. The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2009 and 2008. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 2009 and 2008, that have not been recognized in net periodic benefit costs.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Not applicable.
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, which resulted 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. Prior to closing its swap position, U.S. Treasury yields increased, which resulted in Ameren’s pension plan recognizing a $74 million net loss in 2009. Ameren’s postretirement benefit plans did not have a similar interest rate hedge.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2009 and 2008:
Ameren determines discount rate assumptions by using an interest rate yield curve pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations. The yield curve is based on the yields of over 500 high-quality 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.
Funding
Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plan is funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2009, its investment performance in 2009, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $225 million in each of the next five years, with aggregate estimated contributions of $740 million. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 66%, 6%, 9%, 9%, and 10%, respectively. These amounts are estimates. They may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. Our funding 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 cash contributions made to our defined benefit retirement plan and to our postretirement plans during 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Investment Strategy and Policies
Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, to the extent authority is delegated to it by the finance committee of Ameren’s board of directors, implements investment strategy and asset allocation guidelines for the plan assets. The investment committee is composed of members of senior management. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable, and second, to maximize total return on plan assets and minimize expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. As appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. The investment committee 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. The Ameren Companies will utilize an expected return on plan assets of 8% in 2010. No plan assets are expected to be returned to Ameren during 2010.
Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration, market capitalization, country, style (growth or value) and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk. The following table presents our target allocations for 2010 and our pension and postretirement plans’ asset categories as of December 31, 2009 and 2008.
In general, the U.S. large capitalization equity investments are passively managed or indexed, whereas the international, emerging markets, U.S. small capitalization, and U.S. mid capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed income vehicles. Debt security investments in high-yield securities, emerging market securities, and non-U.S. dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. Ameren’s investment in private equity funds consists of 13 different limited partnerships, with invested capital ranging from $200,000 to $10 million individually, which invest primarily in a diversified number of small U.S.-based companies. No further commitments may be made to private equity investments without approval by the finance committee of the board of directors. Additionally, Ameren’s investment committee allows investment managers to use derivatives, such as index futures, exchange traded funds, foreign exchange futures, and options, in certain situations, to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2009. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information. The fair value of real estate is based on annual appraisal reports prepared by an independent real estate appraiser.
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2009:
(a) Includes $77 million of medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.
(b) Excludes $1 million net payable related to pending security purchases.
The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair value hierarchy for the year ended December 31, 2009:
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2009:
(a) Excludes $77 million of medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.
(b) Excludes net $3 million of Medicare and interest receivables, offset by payables related to pending security purchases.
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit plans during 2009, 2008, and 2007:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The current year expected return on plan assets is primarily determined by adjusting the prior-year market-related asset value for current year 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 estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2010 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, CILCO and IP are responsible for their share of the pension and postretirement benefit costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2009, 2008 and 2007:
(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, as of December 31, 2009, 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, 2009, 2008, and 2007:
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, 2009. 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 $24 million, $23 million, and $21 million in 2009, 2008, and 2007, respectively.
The following table presents the portion of the 401(k) matching contribution to the Ameren plan attributable to each of the Ameren Companies for the years ended December 31, 2009, 2008, and 2007:
(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, 2009, and changes during the year ended December 31, 2009, 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 March 2009 under the 2006 Plan.
(b) Includes share units granted in 2007 that were not earned based on performance provisions of the award grants.
(c) Includes share units granted in 2007 that vested as of December 31, 2009, 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 $15 million, $22 million, and $18 million for the years ended December 31, 2009, 2008, and 2007, respectively, and a related tax benefit of $6 million, $8 million, and $7 million for the years ended December 31, 2009, 2008, and 2007, respectively. As of December 31, 2009, total compensation cost of $8 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 16 months.
Performance Share Units
Performance share unit awards were granted under the 2006 Plan each year since 2006. 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, certain specified performance or market conditions have been met 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. For performance share units granted in 2006, 2007 and 2008, vested performance shares units are held for a 2-year period before being paid to the employee in shares of Ameren common stock. During this 2-year hold period, the employee is paid dividend equivalents on a current basis.
The fair value of each share unit awarded in March 2009 under the 2006 Plan was determined to be $15.52. That amount was based on Ameren’s closing common share price of $22.20 at March 2, 2009, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder
return for a three-year performance period relative to the designated peer group beginning January 1, 2009. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.24%, volatility of 21.3% to 33.1% for the peer group, and Ameren’s attainment of earnings per share of at least $2.54 during each year of the three-year performance period.
The fair value of each share unit awarded in February 2008 under the 2006 Plan was determined to be $32.35. That amount was based on Ameren’s closing common share price of $44.30 at the grant date and lattice simulations. 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 attainment of earnings per share of at least $2.54 during each year of the three-year performance period.
Restricted Stock
Restricted stock awards of 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
Options to purchase 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 58,350 at December 31, 2009, expired in February 2010. There is no expense from stock options for the years ended December 31, 2009, 2008 and 2007, 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, 2009, 2008 and 2007:
(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 and CILCO, company-owned life insurance for Ameren and CILCO, impacts of Medicare Part D for Ameren, UE, Genco and CILCO, employee stock ownership plan dividends for Ameren, and nondeductible expenses for IP.
(b) Primarily includes low-income housing tax credits and research credits for Ameren and UE.
(c) Primarily includes settlements with state taxing authorities for Ameren, state apportionment changes for Ameren, CIPS, Genco, and CILCO, research credits for Ameren, Genco, and CILCO and low-income housing tax credits for Ameren and CIPS.
(d) Primarily includes low-income housing tax credits for Ameren, UE, CIPS and IP.
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2009, 2008, and 2007:
(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, 2009 and 2008:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes $18 million, $10 million, and $17 million as current assets recorded in the balance sheets for CIPS, CILCO and IP, respectively. Includes $38 million, $12 million and $26 million as current liabilities recorded in the balance sheets for Ameren, UE and Genco respectively.
(c) Includes $3 million, $5 million, $15 million, and $15 million as current assets recorded in the balance sheets for UE, CIPS, CILCO and IP, respectively. Includes $4 million and $15 million as current liabilities recorded in the balance sheets for Ameren and Genco, respectively.
Ameren and IP have Illinois net operating loss carryforwards of $3 million and $1 million, respectively. These will begin to expire in 2017.
Uncertain Tax Positions
On January 1, 2007, the Ameren Companies adopted authoritative accounting guidance, which addressed 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 during the years ended December 31, 2007, 2008 and 2009, is as follows:
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest charges (income) and penalties accrued on tax liabilities on a pretax basis as interest charges (income) or miscellaneous expense in the statements of income.
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2007, 2008 and 2009, is as follows:
As of January 1, 2007, December 31, 2007, December 31, 2008, and December 31, 2009, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.
Ameren’s 2005 and 2006 federal income tax returns are before the Appeals Office of the Internal Revenue Service. The Internal Revenue Service is currently examining Ameren’s 2007 and 2008 income tax returns.
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 currently 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.
2007 Illinois Electric Settlement Agreement
As part of the 2007 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 to provide $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities.
At December 31, 2009, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of less than $1 million each. Also at December 31, 2009, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million each. During the year ended December 31, 2009, Genco incurred charges to earnings of $10 million for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $3 million, CILCO - $2 million, IP - $5 million), and AERG incurred charges to earnings of $5 million (CIPS - $2 million, CILCO - $1 million, and IP - $2 million). The Ameren Illinois Utilities recorded most of the reimbursements received from Genco and AERG as electric revenue. An immaterial amount was recorded as miscellaneous revenue.
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, 2009, 2008, and 2007:
(a) Both Genco and AERG have a power supply agreement with Marketing Company whereby Genco and AERG sell and Marketing Company purchases all the capacity and energy available from Genco’s and AERG’s generation fleets.
(b) Marketing Company contracted with CIPS, CILCO, and IP to provide power based on the results of the September 2006
Illinois power procurement auction. The values in this table reflect the physical sales volumes provided in that agreement.
In December 2006, Genco and AERG entered into two separate power supply agreements (PSA) with Marketing Company, whereby Genco and AERG agreed to sell and Marketing Company agreed to purchase all of the capacity available from Genco’s and AERG’s generation fleets and all of the associated energy. In March 2008, Genco and AERG entered into an amendment to their respective PSAs with Marketing Company. Under the amendment, Genco and AERG are 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 and AERG’s liability in such cases will be for the positive difference, if any, between the market price of capacity or energy Genco and AERG do not deliver and the contract price under the PSA for that capacity or energy. An unplanned outage or derate that continues for one year or more is an event of default under the PSA. In the event of Marketing Company’s unexcused failure to receive energy under the PSA, Marketing Company would be required to pay Genco and AERG the positive difference, if any, between the contract price and the price that Genco and AERG, acting in a commercially reasonable manner, actually receives when it resells the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs. In January 2010, Genco and AERG entered into an amendment to their respective PSAs with Marketing Company primarily because of the EEI ownership transfer to Genco.
Both of the PSAs 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.
Capacity Supply Agreements
To replace the power supply contracts that expired on May 31, 2008, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the 2007 Illinois Electric Settlement Agreement, to contract for the necessary capacity requirements for the period from June 1, 2008,
through May 31, 2009. Marketing Company and UE were two of the winning suppliers in the Ameren Illinois Utilities’ capacity RFPs. 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.
CIPS, CILCO and IP, as electric load serving entities, must acquire capacity sufficient to meet their obligations to customers. In 2009, the Ameren Illinois Utilities used an RFP process, administered by the IPA, to contract the necessary capacity for the period from June 1, 2009, through May 31, 2012. Both Marketing Company and UE were winning suppliers in the Ameren Illinois Utilities’ capacity RFP process. In April 2009, Marketing Company contracted to supply capacity to the Ameren Illinois Utilities for $4 million, $9 million, and $8 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively. In April 2009, UE contracted to supply capacity to the Ameren Illinois Utilities for $2 million, $2 million, and $1 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively.
Energy Swaps
As part of the 2007 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 then-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. They are accounted for as cash flow hedges by Marketing Company and as derivatives subject to regulatory deferral by Ameren Illinois Utilities. 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. See Note 7 - Derivative Financial Instruments for additional information on these derivatives. Below are the remaining contracted volumes and prices per megawatthour as of December 31, 2009:
To replace the supply contracts that expired on May 31, 2008, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the 2007 Illinois Electric Settlement Agreement, to contract for the necessary financial energy swaps requirement 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 swap RFP process. Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities paid for about two million megawatthours at approximately $60 per megawatthour.
CIPS, CILCO and IP, as electric load serving entities, must acquire energy sufficient to meet their obligations to customers. In 2009, the Ameren Illinois Utilities used an RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2009, through May 31, 2011. Marketing Company was a winning supplier in the Ameren Illinois Utilities’ energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities will pay for approximately 80,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2010 and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2011.
Electric Resource Sharing Agreement
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 were required to support the additional electric power upgrades made at Genco’s Coffeen power plant. Under the agreement, Genco paid CIPS for the costs of the transmission upgrades. When the transmission assets were placed in service, CIPS paid Genco, with interest, for the costs of the transmission upgrades. In 2009, CIPS paid Genco $2 million when the transmission assets were placed in service. These transactions were eliminated in consolidation on Ameren’s financial statements.
In September 2009, Marketing Company and CIPS signed an agreement requiring Marketing Company to fund the cost of certain upgrades to CIPS’ electric transmission system. Under the agreement, Marketing Company paid CIPS $5 million for the costs of the transmission upgrades. These amounts were a contribution in aid of construction and will not be refunded to Marketing Company. These transactions were eliminated in consolidation on Ameren’s financial statements.
Joint Ownership Agreement
In 2006, IP and AITC entered into a joint ownership agreement to construct, own, operate, and maintain certain electric transmission systems in Illinois. Under the terms of this agreement, IP and AITC are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. This agreement will terminate when either IP or AITC is the sole owner of the transmission systems or when the transmission systems are decommissioned.
Support Services Agreements
Ameren Services and AFS provide support services to their affiliates. Ameren Energy, Inc. provided support services until December 31, 2007. The cost of support services, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred.
CILCO Support Services
On January 1, 2009, approximately 570 Ameren Services employees who provided support services to the Ameren Illinois Utilities were transferred to CILCO (Illinois Regulated). As CILCO employees, they provide services to CIPS and IP as well as to CILCO. The cost of support services provided by CILCO to CIPS and IP, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred.
Executory Tolling, Gas Sales, and Transportation Agreements
Prior to 2009, 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.
Money Pools
See Note 5 - Long-term Debt and Equity Financings for discussion of affiliate borrowing arrangements.
Intercompany Borrowings
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 charges for this note recorded by CIPS and Genco, respectively, were $4 million, $7 million, and $10 million for the years ended December 31, 2009, 2008, and 2007, respectively. 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.
CILCO (AERG) had outstanding borrowings from Ameren of $288 million at December 31, 2009, and had no outstanding borrowings directly from Ameren at December 31, 2008. The average interest rate on these borrowings was 6.1% for the year ended December 31, 2009. CILCO (AERG) recorded interest charges of $13 million for Ameren borrowings for the year ended December 31, 2009.
UE had no outstanding borrowings directly from Ameren at December 31, 2009, and had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. The average interest rate on these borrowings was 1.2% for the year ended December 31, 2009 (2008 - 3.6%). UE recorded interest charges of less than $1 million, $1 million, and $4 million for Ameren borrowings for the years ended December 31, 2009, 2008, and 2007, respectively.
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, 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, which means that Marketing Company as the supplier is the only counterparty required to post collateral. At December 31, 2009 and 2008, there were no collateral postings necessary by Marketing Company related to the 2006 auction power supply agreements.
Under the terms of the 2008 Illinois power procurement RFPs, collateral had to be posted by Marketing Company and the Ameren Illinois Utilities under certain market conditions. The collateral postings were bilateral, which means that either counterparty could 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.
Under the terms of the 2009 Illinois power procurement agreements entered into through an RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance. The collateral postings are unilateral, which means only the suppliers are required to post collateral. Therefore, UE, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of December 31, 2009, there were no collateral postings necessary between UE and the Ameren Illinois Utilities or between Marketing Company and the Ameren Illinois Utilities related to the 2009 Illinois power procurement agreements.
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. 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. Genco recorded operating revenues from the lease agreement of $2 million and $11 million for the years ended December 31, 2008 and 2007, respectively.
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 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 had an 80% ownership interest in EEI.
On January 1, 2010, as part of an internal reorganization, Resources Company transferred its 80% ownership interest in EEI to Genco, through a capital contribution. The transfer of EEI to Genco was accounted for as a transaction between entities under common control, whereby Genco recognized the assets and liabilities of EEI at their book value as of January 1, 2010.
The following table presents the impact on UE, CIPS, Genco, CILCO, and IP of related party transactions for the years ended December 31, 2009, 2008 and 2007. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 - Credit Facility Borrowings and Liquidity.
(a) Not applicable.
(b) Includes revenues relating to Property and Plant additions during 2009 (CIPS - $6 million and IP - $11 million).
(c) Amount less than $1 million.
(d) In January 2009, CILCO transferred the tolling agreement to Marketing Company.
(e) Ameren Energy, Inc. was eliminated December 31, 2007, through an internal reorganization.
(f) Represents insurance premiums paid to Energy Risk Assurance Company, 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, 2009. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.
(a) Effective January 1, 2010, limit was increased to $375 million.
(b) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(c) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(d) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(e) 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.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our 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.
(g) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our 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, 2009:
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) See Properties under Part I, Item 2, and Note 3 - Property and Plant, Net of this report for additional 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 because that period is indefinite.
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. The following table presents total rental expense, included in other operations and maintenance expenses, for the years ended December 31, 2009, 2008 and 2007:
(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, nuclear fuel, and methane gas. We also have entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. The table below presents our estimated fuel, electric capacity, and other commitments at December 31, 2009. Ameren’s and UE’s electric capacity obligations include a 15-year, 102-MW power purchase agreement with a wind farm operator. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, meter reading services, and an Ameren tax credit obligation at December 31, 2009. Ameren’s tax credit obligation is a $51 million note payable issued for an investment in a commercial real estate development partnership to acquire tax credits. This note payable was netted against the related investment in Other Assets at December 31, 2009, as Ameren has a legally enforceable right to offset under authoritative accounting guidance.
In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which would generate approximately 15 MW of electricity by burning methane gas collected from the landfill. Construction of the CTs is expected to begin in 2010, and the CTs are expected to begin generating power in 2011. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas. The obligation information presented below includes total estimated methane gas purchase commitments. Related design and construction commitments associated with this project are included in the Other column in the table below.
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) See Ameren Illinois Utilities’ Purchase Power Agreements below for additional information regarding electric capacity commitments.
Ameren Illinois Utilities’ Power Purchase Agreements
Beginning on 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.
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.
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. As a result, in the second quarter of 2009, the IPA procured electric capacity, financial energy swaps, and renewable energy credits through an RFP process on behalf of the Ameren Illinois Utilities. Electric capacity was procured in April 2009 for the period June 1, 2009, through May 31, 2012. The Ameren Illinois Utilities contracted to purchase between 800 and 3,500 MW of capacity per month at an average price of approximately $41 per MW-day over the three-year period. Financial energy swaps were procured in
May 2009 for the period June 1, 2009, through May 31, 2011. The Ameren Illinois Utilities contracted to purchase approximately ten million megawatthours of financial energy swaps at an average price of approximately $36 per megawatthour. Renewable energy credits were procured in May 2009 for the period June 1, 2009, through May 31, 2010. The Ameren Illinois Utilities contracted to purchase 720,000 renewable energy credits at an average price of approximately $16 per credit. For additional information regarding electric capacity and financial energy swaps entered into with UE and Marketing Company, see Note 14 - Related Party Transactions. The following table presents the Ameren Illinois Utilities’ commitments for these contracts at December 31, 2009:
2007 Illinois Electric Settlement Agreement
The 2007 Illinois Electric Settlement Agreement provided $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 is provided by 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, 2009:
(a) Estimated.
Also as part of the 2007 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 7 - Derivative Financial Instruments and 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 facilities, 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, land 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. 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, which include 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 MACT requirements under the Clean Air Act. In February 2009, the U.S. Supreme Court denied a 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 and other hazardous air pollutants, such as acid gases. In a consent order, the EPA agreed to propose the regulation by March 2011 and finalize the regulation by November 2011. Compliance is expected to be required in 2015. We cannot predict at this time the estimated capital or operating costs for compliance with such future 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 EPA has stated that it expects to issue a new proposed version of the Clean Air Interstate Rule in 2010 and a final version in 2011.
The state of Missouri has adopted 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 by 30% and SO2 emissions by 75% by 2015. As a result of the Missouri rules, UE will use allowances and install pollution control equipment. UE’s costs to comply with SO2 emission reductions required by the Clean Air Interstate Rule could increase materially if the EPA determines that existing allowances granted to sources under the Acid Rain Program cannot be used for compliance with the Clean Air Interstate Rule or if a new allowance program is mandated by revisions to the Clean Air Interstate Rule. Missouri also adopted rules to implement the federal Clean Air Mercury Rule. However, these 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 in the near term. Under the MPS, as amended, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NO x and SO2 controls. This rule, when fully implemented, is expected to reduce mercury emissions by 90%, NOx emissions by 50%, and SO2 emissions by 70% by 2015 in Illinois. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. Genco, CILCO (AERG) and EEI will also need to install additional 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. The Illinois Joint Committee on Administrative Rules approved a rule amendment in June 2009 that revised certain requirements of the MPS. As a result, Genco and CILCO (AERG) collectively were able to defer to subsequent years an estimated $300 million of environmental capital expenditures originally scheduled for 2009 through 2011.
In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. Illinois and Missouri have each submitted their recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas 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 future state implementation plans. In January 2010, the EPA announced its plans to revise the ozone standard to a level lower than the level set in 2008. At this time, we are unable to determine the impact state implementation plans for such regulations would have on our results of operations, financial position, and liquidity.
The table below presents estimated capital costs that are based on current technology to comply with state air quality implementation plans, the MPS, federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates shown in the table below could change depending upon additional federal or state requirements, the requirements under a MACT standard, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. 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. During 2009, Ameren identified significant opportunities to defer or reduce planned capital spending, which are reflected in the estimates provided in the table. The capital cost estimates are lower than previously anticipated, in part because of Ameren’s ability to manage its generating fleet to minimize emissions while complying with emission limits and air permit requirements. Furthermore, previous estimates included assumptions about potential and developing air regulations, including rules that were subsequently vacated by the courts. These estimates include capital spending to comply primarily with existing and known regulations as of December 31, 2009.
(a) UE’s expenditures are expected to be recoverable from ratepayers.
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. 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 classified as intangible assets as of December 31, 2009.
UE, Genco, CILCO (AERG) and EEI expect to use a substantial portion of their 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 SO 2 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, CILCO (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. Allocations for UE’s Missouri generating facilities for the years 2009 through 2014 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. Allocations for UE’s, Genco’s, CILCO’s (AERG), and EEI’s Illinois generating facilities for the years 2010 and 2011 were 90, 3,442, 1,368, and 1,758 tons per ozone season, respectively, and 93, 8,302, 3,419, and 4,565 tons annually, respectively.
Global Climate Change
In June 2009, the U.S. House of Representatives passed energy legislation entitled “The American Clean Energy and Security Act of 2009” that, if enacted, would establish an economy-wide cap-and-trade program. The overarching goal of this proposed cap-and-trade program is to reduce greenhouse gas emissions from capped sources, including coal-fired electric generation units, to 3% below
2005 levels by 2012, 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. The proposed legislation provides an allocation of free emission allowances and greenhouse gas offsets to utilities, as well as certain merchant coal-fired electric generators in competitive markets. This aspect of the proposed legislation would mitigate some of the cost of compliance for the Ameren Companies. However, the amount of free allowances decline over time and are ultimately phased out. The proposed legislation also contains, among other things, a federal renewable energy standard of 6% by 2012 that increases gradually to 20% by 2020, of which up to 25% of the goal can be met by energy efficiency. The proposed legislation also establishes performance standards for new coal plants, requires electric utilities to develop plans to support plug-in hybrid vehicles, and requires load-serving entities to reduce peak electric demand through energy efficiency and Smart Grid technologies. In September 2009, climate change legislation entitled “The Clean Energy Jobs and American Power Act” was introduced in the U.S. Senate that was similar to that passed by the U.S. House of Representatives in June 2009, although it proposes a slightly greater reduction in greenhouse gas emissions in the year 2020 and grants fewer emission allowances to the electricity sector. Under both proposed pieces of legislation, large sources of CO2 emissions will be required to obtain and retire an allowance for each ton of CO2 emitted. The allowances may be allocated to the sources without cost, sold to the sources through auctions or other mechanisms, or traded among parties. “The Clean Energy Jobs and American Power Act” was voted out of committee in November 2009. In December 2009, Senators Kerry, Graham and Lieberman introduced a framework for Senate legislation in 2010. The framework lacks specifics, but it is consistent with the House-passed legislation except that it emphasizes the need for greater support for nuclear power and energy independence through support for clean energy and drilling for oil and natural gas. Senate leadership has stated that consideration of climate legislation will be postponed until spring 2010. In addition, the reduction of greenhouse gas emissions has been identified as a high priority by President Obama’s administration. Although we cannot predict the date of enactment or the requirements of any future climate change legislation or regulations, we believe it is possible that some form of federal legislation or regulations to control emissions of greenhouse gases will become law during the current administration.
Potential impacts from climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing allowances, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s analysis shows that if either
“The American Clean Energy and Security Act of 2009” or “The Clean Energy Jobs and American Power Act” were enacted into law in its current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest 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 electricity generation also could affect the cost of heating for our utility customers and many industrial processes. 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.
In early December of 2009, representatives from countries around the globe met in Copenhagen, Denmark, to attempt to develop an international treaty to supersede the Kyoto Protocol, which set mandatory greenhouse gas reduction requirements for participating countries. The parties were unable to reach agreement regarding mandatory greenhouse gas emissions reductions. However, certain countries, including the United States, entered into an agreement called the “Copenhagen Accord.” The Copenhagen Accord provides a mechanism for countries to make economy-wide greenhouse gas emission mitigation commitments for reducing emissions of greenhouse gases by 2020 and provides for developed countries to fund greenhouse gas emissions mitigation projects in developing countries. Any commitment under the Copenhagen Accord is subject to congressional action on climate change.
Additional requirements to control greenhouse gas emissions and address global climate change may also arise 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. The advisory group to the Midwest governors provided draft final recommendations on the design of a greenhouse gas reduction program in June 2009. In October 2009, the Midwestern Governors Association held a forum to review some of the advisory group’s recommendations. The October 2009 forum did not yield any significant updates to the Midwest Greenhouse Gas Reduction Accord’s work toward a cap-and-trade mechanism. The recommendations have not been endorsed or approved by the individual state governors. It is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.
With regard to the control of greenhouse gas emissions under federal regulation, in 2007, the U.S. Supreme Court issued a decision finding 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 required the EPA to determine whether
greenhouse gas emissions may reasonably be anticipated to endanger public health or welfare, or, in the alternative, to provide a reasonable explanation as to why greenhouse gas emissions should not be regulated. In December 2009, in response to the decision of the U.S. Supreme Court, the EPA issued its “endangerment finding” determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. It is expected that the EPA will issue a rule by the end of March 2010 to control greenhouse gas emissions from light-duty vehicles such as automobiles. Once this rule is effective, greenhouse gases will, for the first time, be a regulated air pollutant under the Clean Air Act. The EPA has taken the position that the regulation of greenhouse gas emissions from new motor vehicles under the Clean Air Act will trigger the applicability of other Clean Air Act provisions, such as the Title V Operating Permit Program and the NSR provisions, which apply to greenhouse gas emissions from stationary sources. This would include fossil-fuel-fired electricity generating plants.
Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA announced in September 2009 a proposed rule, known as the “tailoring rule,” that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule would require any source that emits at least 25,000 tons per year of greenhouse gases measured as CO2 equivalents (CO 2e) to have an operating permit under Title V Operating Permit Program of the Clean Air Act. Sources that already have an operating permit would have greenhouse gas-specific provisions added to their permits upon renewal. Currently, all Ameren power plants have operating permits that, depending on the final rule, may be modified when they are renewed to address greenhouse gas emissions. The proposed tailoring rule also provides that if physical changes or changes in operation at major sources result in an increase in emissions of greenhouse gases over a threshold ranging from 10,000 tons to 25,000 tons of CO2e, the emitters would be required to obtain a permit under the NSR/Prevention of Significant Deterioration program and to install the best available technology to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology. The EPA has committed to provide guidance about the best available control technology for new and modified major sources of greenhouse gas emissions. The tailoring rule is expected to be finalized in March 2010, but any federal climate change legislation that is enacted may preempt the proposed rule, particularly as it relates to power plant greenhouse gas emissions. This proposed rule has no immediate impact on Ameren’s, UE’s, Genco’s or CILCO’s (AERG) generating facilities. The extent to which this proposed rule could have a material impact on our generating facilities depends upon future EPA guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or change in operation subject to the rule
would occur at our power plants, and whether federal legislation that preempts the proposed rule is passed.
The EPA also finalized regulations in September 2009 that would require certain categories of businesses, including fossil-fuel-fired power plants, to monitor and report their annual greenhouse gas emissions, beginning in January 2011 for 2010 emissions. CO2 emissions from fossil-fuel-fired power plants subject to the Clean Air Act’s acid rain program have been monitored and reported for over fifteen years. Thus, this new rule covering greenhouse gas emissions is not expected to have a material effect on our operations. It will require additional reporting of greenhouse gas emissions from various gas operations and possibly other minor sources within our system.
Recent federal appellate court decisions have ruled that common law causes of action, such as nuisance, can be used to redress damages resulting from global climate change. In State of Connecticut v. American Electric Power (“AEP”), the U.S. Court of Appeals for the Second Circuit ruled in September 2009 that public nuisance claims brought by states, New York City and public land trusts could proceed and were not beyond the scope of judicial relief. Ameren’s generating plants were not named in the AEP litigation. In Comer v. Murphy Oil (“Comer”), a Mississippi property owner sued several industrial companies, alleging that CO2 emissions created the atmospheric conditions, that resulted in Hurricane Katrina. The U.S. Court of Appeals for the Fifth Circuit issued a ruling in Comer in October 2009 that permits this cause of action to proceed. Comer is seeking class action certification on behalf of similarly situated property owners. Additional legal challenges and appeals are expected in both the Comer and AEP cases. The rulings in these cases may spur other claimants to file suit against greenhouse gas emitters, including Ameren. The courts did not rule on the merits of the lawsuits, only that plaintiffs had standing to pursue their claims. Under some of the versions of greenhouse gas legislation currently pending in Congress, nuisance claims could be rendered moot. We are unable to predict the outcome of lawsuits seeking damages that litigants claim are attributable to climate change and their impact on our results of operations, financial position, and liquidity.
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. Moreover, to the extent we request recovery of these costs through rates, our regulators might deny some or all of, or defer timely recovery of, these 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 and could lead to possible impairment of assets and reduced revenues. 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, and liquidity.
The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Although compliance costs are unlikely in the near future, federal legislative, federal regulatory and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired generation plants and our customers’ costs is unknown, but any impact would likely be negative. 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, and liquidity.
NSR and Notice of Violation
The EPA is engaged in an enforcement initiative targeted at coal-fired power plants in the United States to determine whether those power plants failed to comply with the requirements of the NSR and New Source Performance Standards (NSPS) provisions under the Clean Air Act when the plants implemented modifications. The EPA’s inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.
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 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. In May 2009, we completed our response to the most recent information request, but we are unable to predict the outcome of this matter.
In January 2010, UE received a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V programs. In the Notice of Violation, the EPA contends that various maintenance, repair and replacement projects at UE’s Labadie, Meramec, Rush Island, and Sioux coal-fired power plant facilities, dating back to the mid-1990s, triggered NSR requirements. The EPA alleges that UE violated the Title V operating permit program by failing to include such NSR requirements in its operating permits or applications for those permits. If litigation regarding this matter occurs, it could take many years to resolve the underlying issues alleged in the Notice of Violation. UE believes its defenses to the allegations described in the Notice of Violation are meritorious and will defend itself vigorously; however, there can be no assurances that it will be successful in its efforts.
Resolution of these matters could have a material adverse impact on the future results of operations, financial position, and 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.
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 facilities to install additional technology on their cooling water intakes or take 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 generating facilities. On April 1, 2009, the U.S. Supreme Court ruled that the EPA can compare the costs of technology for protecting aquatic species to the benefits of that technology in order to establish the “best technology available” standards applicable to the cooling water intake structure at existing power plants under the Clean Water Act. The EPA is expected to propose revised rules in 2010. Until the EPA reissues the rules and such rules are adopted, and until the studies on the aquatic impacts of 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. All major generation facilities at UE, Genco, AERG and EEI with cooling water systems could be subject to these new regulations.
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, respectively, for remediation costs associated with preexisting environmental contamination at the transferred sites.
As of December 31, 2009, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 15, CILCO has 4, and IP has 25 sites. All of these sites are in various stages of investigation, evaluation, and remediation. Ameren currently anticipates completion of remediation at these sites by 2015, except for a CIPS site that is expected to be completed by 2017. 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. Costs are subject to annual review by the ICC. As of December 31, 2009, estimated obligations were: CIPS - $47 million to $62 million, CILCO - less than $1 million, and IP - $112 million to $175 million. CIPS, CILCO and IP have liabilities of $47 million, less than $1 million, and $112 million, respectively, recorded to represent estimated minimum obligations, as no other amount within the range was a better estimate. In 2009, after the completion of site investigations and the selection of remediated actions, CIPS and IP increased their remediation liabilities.
CIPS is also responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of December 31, 2009, CIPS estimated that 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, 2009, IP recorded a liability of $0.8 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 site in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. 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, 2009, UE estimated its obligation at $3 million to $5 million. UE has a liability of $3 million recorded 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 waste sites in Missouri that have corporate cleanup liability as a result of federal agency mandates. UE concluded cleanups at two of these sites, and no further remediation actions are anticipated at those two sites. One of the remaining waste sites for which UE has corporate cleanup responsibility is a former coal tar distillery located in St. Louis, Missouri. In July 2008, the EPA issued an administrative order to UE pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site, but UE did not conduct any of the manufacturing operations involving coal tar or its byproducts. UE along with two other PRPs have reached an agreement with the EPA about the scope of the site investigation. The investigation will occur later this year. As of December 31, 2009, UE estimated this obligation at $2 million to $5 million. UE has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
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.
The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA and a record of decision is expected in 2010. Once the EPA has selected a remedy, it will begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and all 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, 2009, UE estimated its obligation at $0.4 million to $10 million. UE has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In December 2004, AERG submitted a plan 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. CILCO (AERG) has a liability of $3 million at December 31, 2009, for the estimated cost of the remediation effort, which involves discharging recycle-system water into the Duck Creek reservoir and the eventual closure of ash ponds in order to address these groundwater and surface water issues.
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 whether such practices will result in future environmental commitments or impact our results of operations, financial position, or liquidity.
Ash Management
There has been increased activity at both state and federal levels to examine the need for additional regulation of ash pond facilities and coal combustion byproducts (CCB) and wastes. The EPA is considering regulating CCB under the hazardous waste regulations, which could impact future disposal and handling costs at our power plant facilities. We believe it is likely that the EPA will continue to allow some beneficial use, such as recycling, of CCB without classifying them as hazardous wastes. As part of its proposed regulations, the EPA is considering requirements that coal-fired power plants engage in the mandatory closure of active surface impoundments used for the management of CCB. In September 2009, the EPA announced that it expects to revise federal rules governing wastewater discharges from coal-fired power plants. Some
form of additional regulation concerning ash ponds, and the handling and disposal of CCB and waste, is expected to be proposed in early 2010. Depending upon the scope and timing of these rules, Ameren may be required to alter the management of CCB waste, including beneficial reuse, and to discontinue or phase out the use of the ash ponds. Ameren’s CCB impoundments were not identified in the EPA’s 2009 list of 44 high-hazard potential impoundments containing CCB.
In addition, the Illinois EPA has requested that UE, Genco, CILCO (AERG) and EEI establish groundwater monitoring plans for their active and inactive ash impoundments in Illinois. Genco is currently petitioning the Illinois Pollution Control Board to issue a site specific rule approving the closure of an ash pond at its Hutsonville power plant. Ameren has entered into discussions with the Illinois EPA about a framework for closure of additional ash ponds in Illinois, including the ash ponds at Venice and Duck Creek, when such facilities are ultimately taken out of service. The permits for the Venice and Duck Creek ash ponds both expire in 2010. UE, Genco and CILCO (AERG) have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.
At this time, we are unable to predict the effects any such state and federal regulations might have on our results of operations, financial position, and liquidity.
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 settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident.
UE has property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance does 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 upper reservoir, will be approximately $205 million. As of December 31, 2009, UE had paid $205 million, including costs resulting from the FERC-approved stipulation and consent agreement. As of December 31, 2009, UE had recorded expenses of $35 million, primarily in prior years, for items not covered by insurance and had recorded a $170 million receivable for amounts recoverable from insurance companies under liability coverage. As of December 31, 2009, UE had received $100 million from insurance companies, which reduced the insurance receivable balance subject to liability coverage to $70 million.
UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of testing the rebuilt facility. UE expects the Taum Sauk plant to become operational in the second quarter of 2010. The estimated cost to rebuild the upper reservoir is in the range of $490 million. As of December 31, 2009, UE had recorded
a $420 million receivable due from insurance companies under property insurance coverage related to the rebuilding of the facility and the reimbursement of replacement power costs. As of December 31, 2009, UE had received $362 million from insurance companies, which reduced the property insurance receivable balance as of December 31, 2009, to $58 million.
Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the Circuit Court of St. Louis County, Missouri, seeking a declaratory judgment that the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized. The three insurers allege that they, along with the other policy participants, presented a rebuild design that was consistent with their insurance coverage obligations and that the insurance policies do not require these insurers to pay their share of the costs of construction associated with the design being used. These insurers have estimated a cost of approximately $214 million for their rebuild design compared to the estimated $490 million cost of the design approved by FERC and implemented by Ameren. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri, against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. Ameren seeks payment of a sum to-be-determined for all amounts covered by these policies incurred in the facility rebuild, including power replacement costs, interest, and attorneys’ fees. The insurers that are parties to the litigation represent approximately 40%, on a weighted average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million.
On August 31, 2009, Ameren and the property insurance carriers that are not parties to the above litigation (the “Settling Insurance Companies”) reached a settlement of any and all claims, liabilities, and obligations arising out of, or relating to, coverage under its property insurance policy, including those related to the rebuilding of the facility and the reimbursement of replacement power costs. All payments from the Settling Insurance Companies were received by UE in September 2009.
Until Ameren’s remaining insurance claims and the related litigation are resolved, among other things, we are unable to determine the total impact the breach could have on Ameren’s and UE’s results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren and UE expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 State of Missouri settlement agreement. In that settlement, UE agreed that it would not attempt to recover from rate payers costs incurred in the
reconstruction expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that were not at that time reasonably foreseeable and costs that would have been incurred absent the Taum Sauk incident. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the in-service date of the rebuilt facility. As of December 31, 2009, UE had capitalized in property and plant qualifying Taum Sauk- related costs of $99 million that UE believes qualify for potential recovery in electric rates under the terms of the November 2007 State of Missouri Settlement. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC in a future rate case. Any amounts not recovered through insurance, in electric rates, or otherwise, could result in charges to earnings, which could be material.
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 192 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of December 31, 2009, the average number of parties was 71.
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, 2009:
(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, 2009, nine 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.
At December 31, 2009, Ameren, UE, CIPS, CILCO and IP had liabilities of $14 million, $4 million, $3 million, $2 million and $5 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.
IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered by IP from a trust fund established by IP. At December 31, 2009, the trust fund balance was approximately $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’s last announced date of when it expects a permanent storage facility for spent fuel to be available was 2020, and the DOE continues to evaluate permanent storage alternatives. 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.
UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license from 2024 to 2044. If the Callaway nuclear plant’s license is extended, additional spent fuel storage will be required. UE is evaluating the installation of a dry spent fuel storage facility at its Callaway nuclear plant.
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. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removed
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. Decommissioning costs are included in the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2009, 2008, and 2007. 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 cost study, filed in September 2008, included 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 Consolidated Balance Sheet and UE’s Balance Sheet. This amount is legally restricted and 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, with an offsetting adjustment to the related regulatory asset. See Note 9 - Nuclear Decommissioning Trust Fund Investments for additional information.
NOTE 17 - GOODWILL
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. Goodwill impairment testing 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, a second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities in a manner similar to a purchase price allocation. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss equivalent to the difference is recorded as a reduction of goodwill and a charge to operating expense.
During the first quarter of 2009, we concluded that events had occurred and circumstances had changed which
required us to perform an interim goodwill impairment test. The following events triggered this impairment test:

A significant decline in Ameren’s market capitalization.

The continuing decline in market prices for electricity.

A decrease in observable industry market multiples.
The fair value of Ameren’s and IP’s reporting units was estimated based on a risk-adjusted, 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 cash flows, and an exit value based on observable industry market multiples. We use our best estimates in making these evaluations. We consider various factors, including forward price curves for energy and fuel costs, the regulatory environment, and operating costs. For the interim test conducted as of March 31, 2009, the discount rate used was 3.8%, based on the 20-year treasury yield. To assess the reasonableness of the estimated reporting unit fair values, the sum of the estimated fair values of the Ameren reporting units is reconciled to our current market capitalization plus an estimated control premium. Ameren’s reporting units and IP’s reporting unit did not require a second step assessment; the results of the step one tests indicated no impairment of goodwill as of March 31, 2009.
The annual impairment test, conducted as of October 31, 2009, did not result in a second step assessment; the test indicated no impairment of Ameren’s or IP’s goodwill. The annual test was conducted in a manner similar to the interim test described above. Ameren’s market capitalization was less than the book value of its equity as of the October 31, 2009, testing date and
during the remainder of 2009. However, the sum of the estimated fair values of Ameren reporting units exceeded the combined Ameren reporting unit carrying value as of October 31, 2009. We believe the difference between Ameren’s market capitalization and the sum of the estimated fair values of the Ameren reporting units as of October 31, 2009, can be explained by the application of a reasonable control premium to our share price. The discount rate used was 4.2%, based on the 20-year treasury yield. At Ameren’s Illinois Regulated reporting unit and IP’s Illinois Regulated reporting unit, 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 the reporting unit exceeding their fair values. However, the estimated fair value of Ameren’s Merchant Generation reporting unit exceeded its carrying value by a nominal amount as of October 31, 2009. The estimated fair value of Ameren’s Merchant Generation reporting unit exceeded its carrying value by approximately $95 million, or 3%. The failure in the future of any reporting unit to achieve forecasted operating results and cash flows or a decline of observable industry market multiples may further reduce its estimated fair value below its carrying value, which would likely result in the recognition of a goodwill impairment charge.
Ameren and IP will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity, and observable industry market multiples of their reporting units for signs of possible declines in estimated fair value and potential goodwill impairment.
Ameren has identified three reporting units, which also represent Ameren’s reportable segments. The Ameren reporting units are Missouri Regulated, Illinois Regulated, and Merchant Generation. IP has one reporting unit, Illinois Regulated. Ameren’s reporting units have been defined and goodwill has been evaluated at the operating segment level in accordance with authoritative accounting guidance. The following tables provide a reconciliation of the beginning and ending carrying amounts of goodwill by reporting unit, for Ameren and IP, for the years 2009 and 2008:
Ameren
(a) Includes amounts for Ameren registrants and nonregistrant subsidiaries.
IP
NOTE 18 - SEGMENT INFORMATION
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Merchant 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). 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, and AITC. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, Medina
Valley and Marketing Company. The category called Other primarily includes Ameren parent company activities.
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.
CILCO has two reportable segments: Illinois Regulated and Merchant Generation. The Illinois Regulated segment for CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Merchant Generation segment for CILCO consists of the generation business of AERG. Other comprises minor activities not reported in the Illinois Regulated or Merchant Generation segments.
The following tables present information about the reported revenues and specified items included in net income of Ameren, UE, and CILCO for the years ended December 31, 2009, 2008 and 2007, and total assets as of December 31, 2009, 2008 and 2007.
Ameren
(a) Represents net income (loss) available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
UE
(a) Included 40% interest in EEI through February 29, 2008.
(b) Represents net income available to the common stockholder (Ameren).
CILCO
(a) Represents net income available to the common stockholder (CILCORP); 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) The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding and changes in the number of weighted-average shares outstanding each period.
(a) Genco had no preferred stock outstanding.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
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 2009 fiscal year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2009, 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, management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2009. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2009, 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, 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 might become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures might 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. 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 2009 that has not previously been reported on an SEC Form 8-K.
PART III
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 2010 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 2010 annual meeting 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’ 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco 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, 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, Susan S. Elliott, Ellen M. Fitzsimmons and Stephen R. Wilson 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, 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. 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. 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 2010 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 2010 annual meeting 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 included in CIPS’ definitive information statement for CIPS’ 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
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, 2009, 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, 124,953 of the securities represent PSUs that vested at December 31, 2009 (including accrued and reinvested dividends), and 1,327,354 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, 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 2010 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 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco, 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, 2010. To our knowledge, other than Ameren, there are no beneficial owners of 5% or more of IP’s outstanding shares of preferred stock as of February 1, 2010, 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. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Information required by Item 404 and Item 407(a) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by Item 404 of SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by Item 404 of SEC Regulation S-K item for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to Genco, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
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 2010 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(1) Financial Statements
Page No.
Ameren
Report of Independent Registered Public Accounting Firm
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheet - December 31, 2009 and 2008
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2009, 2008 and 2007
UE
Report of Independent Registered Public Accounting Firm
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Balance Sheet - December 31, 2009 and 2008
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Consolidated Statement of Common Stockholders’ Equity
CIPS
Report of Independent Registered Public Accounting Firm
Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Balance Sheet - December 31, 2009 and 2008
Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Statement of Common Stockholders’ Equity
Genco
Report of Independent Registered Public Accounting Firm
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheet - December 31, 2009 and 2008
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2009, 2008 and 2007
CILCO
Report of Independent Registered Public Accounting Firm
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheet - December 31, 2009 and 2008
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2009, 2008 and 2007
IP
Report of Independent Registered Public Accounting Firm
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Balance Sheet -December 31, 2009 and 2008
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2009, 2008 and 2007
(a)(2) Financial Statement Schedules
Schedule I - Condensed Financial Information of Parent - Ameren:
Condensed Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Condensed Balance Sheet - December 31, 2009 and 2008
Condensed Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Schedule I - Condensed Financial Information of Parent - CILCO:
Condensed Statement of Income - Years Ended December 31, 2009, 2008 and 2007
Condensed Balance Sheet - December 31, 2009 and 2008
Condensed Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2009, 2008 and
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.
(a)(3)
Exhibits.
Reference is made to the Exhibit Index commencing on page 191.
(b)
Exhibits are listed in the Exhibit Index commencing on page 191.
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2009
NOTE 1 - BASIS OF PRESENTATION
Ameren Corporation (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 under Part II, Item 8, of this report.
NOTE 2 - LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of long-term obligations of Ameren Corporation (parent company only).
NOTE 3 - COMMITMENTS AND CONTINGENCIES
See Note 15 - Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of Ameren Corporation (parent company only).
CENTRAL ILLINOIS LIGHT COMPANY (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31,
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 under Part II, Item 8, of this report.
NOTE 2 - LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings 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 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: February 26, 2010
By
/s/ Thomas R. Voss
Thomas R. Voss
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.
/s/ Thomas R. Voss
Thomas R. Voss
President, Chief Executive Officer
and Director
(Principal Executive Officer)
February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial and Accounting Officer)
February 26, 2010
*
Stephen F. Brauer
Director
February 26, 2010
*
Susan S. Elliott
Director
February 26, 2010
*
Director
February 26, 2010
Ellen M. Fitzsimmons
*
Walter J. Galvin
Director
February 26, 2010
*
Gayle P.W. Jackson
Director
February 26, 2010
*
James C. Johnson
Director
February 26, 2010
*
Charles W. Mueller
Director
February 26, 2010
*
Douglas R. Oberhelman
Director
February 26, 2010
*
Gary L. Rainwater
Director
February 26, 2010
*
Harvey Saligman
Director
February 26, 2010
*
Patrick T. Stokes
Director
February 26, 2010
*
Stephen R. Wilson
Director
February 26, 2010
*
Jack D. Woodard
Director
February 26, 2010
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
UNION ELECTRIC COMPANY (registrant)
Date: February 26, 2010
By
/s/ Warner L. Baxter
Warner L. Baxter
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.
/s/ Warner L. Baxter
Warner L. Baxter
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
*
Daniel F. Cole
Director
February 26, 2010
*
Adam C. Heflin
Director
February 26, 2010
*
Richard J. Mark
Director
February 26, 2010
*
Steven R. Sullivan
Director
February 26, 2010
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (registrant)
Date: February 26, 2010
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.
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
*
Daniel F. Cole
Director
February 26, 2010
*
Steven R. Sullivan
Director
February 26, 2010
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
AMEREN ENERGY GENERATING COMPANY (registrant)
Date: February 26, 2010
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.
/s/ Charles D. Naslund
Charles D. Naslund
Chairman, President and Director
(Principal Executive Officer)
February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
*
Daniel F. Cole
Director
February 26, 2010
*
Steven R. Sullivan
Director
February 26, 2010
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
CENTRAL ILLINOIS LIGHT COMPANY (registrant)
Date: February 26, 2010
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.
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
*
Daniel F. Cole
Director
February 26, 2010
*
Steven R. Sullivan
Director
February 26, 2010
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
ILLINOIS POWER COMPANY (registrant)
Date: February 26, 2010
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.
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
*
Daniel F. Cole
Director
February 26, 2010
*
Steven R. Sullivan
Director
February 26, 2010
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
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:
Articles of Incorporation/ By-Laws
3.1(i)
Ameren
Restated Articles of Incorporation of Ameren
File No. 33-64165, Annex F
3.2(i)
Ameren
Certificate of Amendment to Ameren’s Restated Articles of Incorporation filed December 14, 1997
1998 Form 10-K, Exhibit 3(i), File No. 1-14756
3.3(i)
UE
Restated Articles of Incorporation of UE
1993 Form 10-K, Exhibit 3(i), File No. 1-2967
3.4(i)
CIPS
Restated Articles of Incorporation of CIPS
March 31, 1994 Form 10-Q, Exhibit 3(b), File No. 1-3672
3.5(i)
Genco
Articles of Incorporation of Genco
Exhibit 3.1, Form S-4, File No. 333-56594
3.6(i)
Genco
Amendment to Articles of Incorporation of Genco filed April 19, 2000
Exhibit 3.2, Form S-4, File No. 333-56594
3.7(i)
CILCO
Articles of Incorporation of CILCO as amended May 29, 1998
1998 Form 10-K, Exhibit 3, File No. 1-2732
3.8(i)
IP
Amended and Restated Articles of Incorporation of IP, dated September 7, 1994
September 7, 1994 Form 8-K, Exhibit 3(a), File No. 1-3004
3.9(i)
IP
Articles of Amendment to IP’s Amended and Restated Articles of Incorporation filed March 28, 2002
Exhibit 4.1(ii), File No. 333-84008
3.10(ii)
Ameren
By-Laws of Ameren as amended effective October 10, 2008
October 14, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-14756
3.11(ii)
UE
By-Laws of UE as amended July 28, 2008
July 29, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-2967
3.12(ii)
CIPS
By-Laws of CIPS as amended July 28, 2008
July 29, 2008 Form 8-K, Exhibit 3.2(ii), File No. 1-3672
3.13(ii)
Genco
By-Laws of Genco as amended to October 8, 2004
September 30, 2004 Form 10-Q, Exhibit 3.1, File No. 333-56594
3.14(ii)
CILCO
By-Laws of CILCO as amended effective July 28, 2008
July 29, 2008 Form 8-K, Exhibit 3.3(ii), File No. 1-2732
3.15(ii)
IP
By-Laws of IP as amended July 28, 2008
July 29, 2008 Form 8-K, Exhibit 3.4(ii), File No. 1-3004
Instruments Defining Rights of Security Holders, Including Indentures
4.1
Ameren
Indenture of Ameren with The Bank of New York Mellon Trust Company, N.A., as successor trustee, relating to senior debt securities dated as of December 1, 2001 (Ameren’s Senior Indenture)
Exhibit 4.5, File No. 333-81774
4.2
Ameren
First Supplemental Indenture to Ameren’s Senior Indenture dated as of May 19, 2008
June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756
4.3
Ameren
Ameren Company Order dated May 15, 2009, establishing 8.875% Senior Notes, due 2014 (including the global note)
May 15, 2009 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756
4.4
Ameren
UE
Indenture of Mortgage and Deed of Trust dated June 15, 1937 (UE Mortgage), from UE to The Bank of New York Mellon, as successor trustee, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941
Exhibit B-1, File No. 2-4940
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.5
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of April 1, 1971
April 1971 Form 8-K, Exhibit 6, File No. 1-2967
4.6
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of February 1, 1974
February 1974 Form 8-K, Exhibit 3, File No. 1-2967
4.7
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of July 7, 1980
Exhibit 4.6, File No. 2-69821
4.8
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of May 1, 1993
1993 Form 10-K, Exhibit 4.6, File No. 1-2967
4.9
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of October 1, 1993
1993 Form 10-K, Exhibit 4.8, File No. 1-2967
4.10
Ameren
UE
Supplemental Indenture to the UE Mortgage dated as of February 1, 2000
2000 Form 10-K, Exhibit 4.1, File No. 1-2967
4.11
Ameren
UE
Supplemental Indenture to the UE Mortgage dated August 15, 2002
August 23, 2002 Form 8-K, Exhibit 4.3, File No. 1-2967
4.12
Ameren
UE
Supplemental Indenture to the UE Mortgage dated March 5, 2003
March 11, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.13
Ameren
UE
Supplemental Indenture to the UE Mortgage dated April 1, 2003
April 10, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.14
Ameren
UE
Supplemental Indenture to the UE Mortgage dated July 15, 2003
August 4, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.15
Ameren
UE
Supplemental Indenture to the UE Mortgage dated October 1, 2003
October 8, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.16
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004A (1998A) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967
4.17
Ameren
UE
Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004B (1998B) Bonds
March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967
4.18
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
4.19
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
4.20
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
4.21
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
4.22
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
4.23
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
4.24
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
4.25
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
4.26
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
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.27
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
4.28
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
4.29
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
4.30
Ameren
UE
Supplemental Indenture to the UE Mortgage dated April 1, 2008
April 8, 2008 Form 8-K, Exhibit 4.7, File No. 1-2967
4.31
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
4.32
Ameren
UE
Supplemental Indenture to the UE Mortgage dated March 1, 2009
March 23, 2009 Form 8-K, Exhibit 4.5, 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, as successor trustee (relating to senior secured debt securities)
August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967
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
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
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 8, 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
4.55
Ameren
UE
UE Company Order dated March 20, 2009, establishing 8.45% Senior Secured Notes due 2039 (including the global note)
March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.56
Ameren
CIPS
Indenture of Mortgage or 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
4.57
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated September 1, 1947
Amended Exhibit 7(b), File No. 2-7341
4.58
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated January 1, 1949
Second Amended Exhibit 7.03, File No. 2-7795
4.59
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 1, 1965
Amended Exhibit 2.02, File No. 2-23569
4.60
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated April 1, 1971
Amended Exhibit 2.02, File No. 2-39587
4.61
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated December 1, 1973
Exhibit 2.03, File No. 2-60232
4.62
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated February 1, 1980
Exhibit 2.02(a), File No. 2-66380
4.63
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
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.64
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
4.65
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated December 1, 1998
Exhibit 4.2, File No. 333-59438
4.66
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
4.67
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated October 1, 2004
2004 Form 10-K, Exhibit 4.91, File No. 1-3672
4.68
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
4.69
Ameren
CIPS
Supplemental Indenture to the CIPS Mortgage, dated June 15, 2009
June 30, 2009 Form 10-Q, Exhibit 4.1, 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
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 2010
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 2032
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
Genco
Seventh Supplemental Indenture, dated as of November 1, 2009, to Genco Indenture, relating to Genco 6.30% Senior Notes, Series l due 2020
November 17, 2009 Form 8-K, Exhibit 4.8, File No. 333-56594
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 December 1, 2008
December 9, 2008 Form 8-K, Exhibit 4.5, File No. 1-2732
4.91
Ameren
CILCO
Supplemental Indenture to the CILCO Mortgage, dated June 15, 2009
June 30, 2009 Form 10-Q, Exhibit 4.2, File No. 1-2732
4.92
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
4.93
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
4.94
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
4.95
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
4.96
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
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.97
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
4.98
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
4.99
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
4.100
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
4.101
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
4.102
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
4.103
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
4.104
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
4.105
Ameren
IP
Supplemental Indenture dated as of November 15, 2007, to IP Mortgage for the series BB bonds
November 20, 2007 Form 8-K, Exhibit 4.4, File No. 1-3004
4.106
Ameren
IP
Supplemental Indenture dated as of April 1, 2008, to IP Mortgage for the series CC bonds
April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004
4.107
Ameren
IP
Supplemental Indenture dated as of October 1, 2008, to IP Mortgage for the series DD bonds
October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
4.108
Ameren
IP
Supplemental Indenture dated as of June 15, 2009, to IP Mortgage for the 2009 Credit Agreement series bonds
June 30, 2009 Form 10-Q, Exhibit 4.3, File No. 1-3004
4.109
Ameren
IP
Indenture, dated as of June 1, 2006 from IP to The Bank of New York Mellon Trust Company, N.A., as successor trustee
June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004
4.110
Ameren
IP
IP Company Order, dated June 14, 2006, establishing the 6.25% Senior Secured Notes due 2016 (including the global note)
June 19, 2006 Form 8-K, Exhibit 4.7, File No. 1-3004
4.111
Ameren
IP
IP Company Order, dated November 15, 2007, establishing the 6.125% Senior Secured Notes due 2017 (including the global note)
November 20, 2007 Form 8-K, Exhibit 4.2, File No. 1-3004
4.112
Ameren
IP
IP Company Order, dated April 8, 2008, establishing the 6.25% Senior Secured Notes due 2018 (including the global note)
April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
4.113
Ameren
IP
IP Company Order dated October 23, 2008, establishing the 9.75% Senior Secured Notes due 2018 (including the global note)
October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004
4.114
Ameren
CIPS
Genco
Amended and Restated Genco Subordinated Promissory Note dated as of May 1, 2005
May 2, 2005 Form 8-K, Exhibit 4.1, File No. 1-14756
Material Contracts
10.1
Ameren
Genco
Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and Genco
March 28, 2008 Form 8-K, Exhibit 10.3, File No. 1-14756
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.2
Ameren
Genco
First Amendment dated January 1, 2010, to Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and Genco
10.3
Ameren
IP
Unilateral Borrowing Agreement by and among Ameren, IP and Ameren Services, dated as of September 30,
October 1, 2004 Form 8-K, Exhibit 10.3, File No. 1-3004
10.4
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
10.5
Ameren
Genco
Ameren Corporation System Amended and Restated Non-Regulated Subsidiary Money Pool Agreement, dated March 1,
March 31, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.6
Ameren
UE
Genco
Amended and Restated Credit Agreement dated as of July 14, 2006, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as agent
July 18, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.7
Ameren
UE
Genco
Amendment Agreement dated as of June 30, 2009, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as administrative agent, in respect of the Amended and Restated Credit Agreement dated as of July 14, 2006, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as agent
June 30, 2009 Form 10-Q, Exhibit 10.3, File No. 1-14756
10.8
Ameren
UE
Genco
Supplemental Credit Agreement dated as of June 30, 2009, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as agent
June 30, 2009 Form 10-Q, Exhibit 10.4, File No. 1-14756
10.9
Ameren
CIPS
CILCO
IP
Credit Agreement dated as of June 30, 2009, among Ameren, CIPS, CILCO, IP and JPMorgan Chase Bank, N.A., as agent
June 30, 2009 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.10
Ameren
*Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on August 8, 2008
September 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.11
Ameren Companies
*Ameren’s Long-Term Incentive Plan of 1998
1998 Form 10-K, Exhibit 10.1, File No. 1-14756
10.12
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
10.13
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
10.14
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
10.15
Ameren Companies
*Amendment dated October 12, 2009, to Ameren’s Deferred Compensation Plan for Members of the Board of Directors, effective January 1, 2010
10.16
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
10.17
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:
10.18
Ameren Companies
*Ameren 2007 Deferred Compensation Plan
December 5, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.19
Ameren Companies
*Ameren 2008 Deferred Compensation Plan
June 30, 2008 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.20
Ameren Companies
*Ameren’s Deferred Compensation Plan as amended and restated effective January 1, 2010
October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.21
Ameren Companies
*2006 Ameren Executive Incentive Plan
February 16, 2006 Form 8-K, Exhibit 10.2, File No. 1-14756
10.22
Ameren Companies
*2007 Ameren Executive Incentive Plan
February 15, 2007 Form 8-K, Exhibit 99.3, File No. 1-14756
10.23
Ameren Companies
*2008 Ameren Executive Incentive Plan
December 18, 2007 Form 8-K, Exhibit 99.1, File No. 1-14756
10.24
Ameren Companies
*2009 Ameren Executive Incentive Plan
February 19, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.25
Ameren Companies
*2010 Ameren Executive Incentive Plan
December 17, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.26
Ameren Companies
*2007 Base Salary Table for Named Executive Officers
March 31, 2007 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.27
Ameren Companies
*2008 Base Salary Table for Named Executive Officers
2008 Form 10-K, Exhibit 10.31, File No. 1-14756
10.28
Ameren Companies
*2009 Base Salary Table for Named Executive Officers
2008 Form 10-K, Exhibit 10.36, File No. 1-14756
10.29
Ameren Companies
*2010 Base Salary Table for Named Executive Officers
10.30
Ameren Companies
*Second Amended and Restated Ameren Corporation Change of Control Severance Plan
2008 Form 10-K, Exhibit 10.37, File No. 1-14756
10.31
Ameren Companies
*First Amendment dated October 12, 2009, to the Second Amended and Restated Ameren Change of Control Severance Plan
October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756
10.32
Ameren Companies
*Revised Schedule I to Second Amended and Restated Ameren Change of Control Severance Plan, as amended
10.33
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
10.34
Ameren Companies
*Table of 2007 Target Performance Share Unit Awards Issued to Named Executive Officers
February 15, 2007 Form 8-K, Exhibit 99.4, File No. 1-14756
10.35
Ameren Companies
*Table of 2008 Target Performance Share Unit Awards Issued to Named Executive Officers
February 14, 2008 Form 8-K, Exhibit 99.1, File No. 1-14756
10.36
Ameren Companies
*Table of 2009 Target Performance Share Unit Awards Issued to Executive Officers
March 2, 2009 Form 8-K, Exhibit 99.1, File No. 1-14756
10.37
Ameren Companies
*Formula for Determining 2010 Target Performance Share Unit Awards to be Issued to Named Executive Officers
December 17, 2009 Form 8-K, Exhibit 99.1, File No. 1-14756
10.38
Ameren Companies
*Ameren Corporation 2006 Omnibus Incentive Compensation Plan
February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756
10.39
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
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.40
Ameren Companies
*Form of Performance Share Unit for Award Issued in 2009 pursuant to 2006 Omnibus Incentive Compensation Plan
March 2, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.41
Ameren Companies
*Form of Performance Share Unit for Award to be Issued in 2010 pursuant to 2006 Omnibus Incentive Compensation Plan
December 17, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756
10.42
Ameren Companies
*Ameren Supplemental Retirement Plan amended and restated effective January 1, 2008, dated June 13, 2008
June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.43
Ameren Companies
*First Amendment to amended and restated Ameren Supplemental Retirement Plan dated October 24, 2008
2008 Form 10-K, Exhibit 10.44, File
No. 1-14756
10.44
Ameren
CILCO
*CILCO Executive Deferral Plan as amended effective August 15, 1999
1999 Form 10-K, Exhibit 10, File
No. 1-2732
10.45
Ameren
CILCO
*CILCO Executive Deferral Plan II as amended effective April 1, 1999
1999 Form 10-K, Exhibit 10(a), File
No. 1-2732
10.46
Ameren
CILCO
*CILCO Restructured Executive Deferral Plan (approved August 15, 1999)
1999 Form 10-K, Exhibit 10(e), File
No. 1-2732
Statement re: Computation of Ratios
12.1
Ameren
Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2
UE
UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3
CIPS
CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.4
Genco
Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.5
CILCO
CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.6
IP
IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
Code of Ethics
14.1
Ameren Companies
Code of Ethics amended as of June 11, 2004
June 30, 2004 Form 10-Q, Exhibit 14.1, File No. 1-14756
Subsidiaries of the Registrant
21.1
Ameren Companies
Subsidiaries of Ameren
Consent of Experts and Counsel
23.1
Ameren
Consent of Independent Registered Public Accounting Firm with respect to Ameren
23.2
UE
Consent of Independent Registered Public Accounting Firm with respect to UE
23.3
CIPS
Consent of Independent Registered Public Accounting Firm with respect to CIPS
23.4
Genco
Consent of Independent Registered Public Accounting Firm with respect to Genco
23.5
CILCO
Consent of Independent Registered Public Accounting Firm with respect to CILCO
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
23.6
IP
Consent of Independent Registered Public Accounting Firm with respect to IP
Power of Attorney
24.1
Ameren
Power of Attorney with respect to Ameren
24.2
UE
Power of Attorney with respect to UE
24.3
CIPS
Power of Attorney with respect to CIPS
24.4
Genco
Power of Attorney with respect to Genco
24.5
CILCO
Power of Attorney with respect to CILCO
24.6
IP
Power of Attorney with respect to IP
Rule 13a-14(a)/15d-14(a) Certifications
31.1
Ameren
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2
Ameren
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3
UE
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE
31.4
UE
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE
31.5
CIPS
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS
31.6
CIPS
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS
31.7
Genco
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8
Genco
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
31.9
CILCO
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO
31.10
CILCO
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO
31.11
IP
Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP
31.12
IP
Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP
Section 1350 Certifications
32.1
Ameren
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2
UE
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE
32.3
CIPS
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS
32.4
Genco
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco
32.5
CILCO
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO
32.6
IP
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
Additional Exhibits
99.1
Ameren
CILCO
Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and AERG
March 28, 2008 Form 8-K, Exhibit 99.1, File No. 1-14756
99.2
Ameren
CILCO
First Amendment dated January 1, 2010, to Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and AERG
XBRL - Related Documents
101.INS**
Ameren
XBRL Instance Document
101.SCH**
Ameren
XBRL Taxonomy Extension Schema Document
101.CAL**
Ameren
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**
Ameren
XBRL Taxonomy Extension Label Linkbase Document
101.PRE**
Ameren
XBRL Taxonomy Extension Presentation Linkbase Document
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; CILCO, 1-2732; and IP, 1-3004.
*Compensatory plan or arrangement.
**Attached as Exhibit 101 to this report is the following financial information from Ameren’s Annual Report on Form 10-K for the year ended December 31, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statement of Income for the years ended December 31, 2009, 2008 and 2007, (ii) the Consolidated Balance Sheet at December 31, 2009, and December 31, 2008, (iii) the Consolidated Statement of Cash Flows for the years ended December 31, 2009, 2008 and 2007 and (iv) the Combined Notes to the Financial Statements for the year ended December 31, 2009, tagged as blocks of text. These Exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.
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.