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 Inc. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, AIC and Genco. 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. Below is a summary description of UE, AIC and Genco. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

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.

On October 1, 2010, after receiving all necessary approvals, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the AIC Merger. The second step of the reorganization involved the distribution of AERG stock from AIC to Ameren (the AERG distribution) and the subsequent contribution by Ameren of the AERG stock to Resources Company. For additional information regarding the corporate reorganization, see Note 16 – Corporate Reorganization and Discontinued Operations under Part II, Item 8, of this report.

The following table presents our total employees at December 31, 2010:

As of January 1, 2011, the IBEW, the IUOE, the LIUNA, the NCF&O and the UA labor unions collectively represented about 59% of Ameren’s total employees. They represented 64% of the employees at UE, 67% at AIC, and 67% at Genco. All collective bargaining agreements that expired in 2010 were renegotiated and ratified. The collective bargaining agreements have three- to five-year terms, and expire between 2011 and 2013. Several collective bargaining agreements between Ameren subsidiaries and the IBEW, IUOE, the LIUNA, NCF&O and the UA labor unions, covering approximately 925 employees, expire throughout 2011.

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: Ameren Missouri, Ameren Illinois, 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 and AIC 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 and AIC 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. Decisions made by these governmental entities regarding rates are largely outside of UE’s and AIC’s control. These decisions, 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 and AIC. Rate orders are also subject to appeal and stay requests, which create additional uncertainty as to the rates UE and AIC are ultimately allowed to charge for their services.

The ICC regulates rates and other matters for AIC and AITX. The MoPSC regulates rates and other matters for UE. The FERC regulates UE, AIC, Genco, and AITX 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 46% of Ameren’s electric and 15% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2010. About 31% of Ameren’s electric and 85% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2010. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.

Ameren Missouri (UE)

Electric

About 98% of UE’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2010. Beginning March 1, 2009, UE’s retail electric rates include a FAC that allows billing adjustments for changes in prudently incurred fuel and purchased power costs. On May 28, 2010, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $230 million. This order allowed UE to continue to use the regulatory tracking mechanisms for vegetation management and infrastructure costs and pension and postretirement benefit costs. See below for cost recovery of energy efficiency programs. UE’s 2009 and 2010 electric rate orders are still subject to court appeals.

On September 3, 2010, UE filed a request with the MoPSC to increase its annual revenues for electric service by approximately $263 million. Approximately $110 million of the request relates to recovery of the cost of installing and operating two scrubbers at UE’s Sioux plant. Also included in this requested increase is a $73 million anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. Absent initiation of this general rate proceeding, 95% of this amount would have been reflected in rate adjustments implemented under UE’s FAC. Capital additions relating to enhancements at the rebuilt Taum Sauk facility were also included in the increase request. As a part of its filing, UE also requested that the MoPSC approve the implementation of an infrastructure investment tracking mechanism as well as enhanced energy efficiency cost recovery. UE also requested continued use of its existing FAC, vegetation management and infrastructure cost tracker, and the regulatory tracking mechanism for pension and postretirement benefit costs the MoPSC previously authorized in earlier electric rate orders. In February 2011, the MoPSC staff responded to the UE request for an electric service rate increase. The MoPSC staff recommended an increase to UE’s annual revenues of between $45 million and $99 million based on a return on equity of 8.25% to

9.25%. Included in this recommendation was approximately $50 million of increases in normalized net fuel costs and $32 million of asset disallowances relating to the Sioux plant scrubbers. Other parties also made recommendations through testimony filed in this case.

FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files a regional transmission tariff for approval by FERC. All transmission service within that RTO is then subjected to that tariff. As a member of MISO, UE’s transmission rate is calculated in accordance with the MISO tariff rate formula. The transmission rate is updated in June of each year based on UE’s filing with FERC. This rate is charged directly to wholesale customers. This rate is not directly charged to Missouri retail customers because in Missouri the MoPSC includes transmission-related costs in setting bundled retail rates.

Natural Gas

All of UE’s natural gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2010. In January 2011, the MoPSC approved a stipulation and agreement that allows UE to increase annual natural gas revenues by $9 million resolving a June 2010 rate increase request. The new rates became effective on February 20, 2011. As part of the stipulation and agreement, UE agreed not to file a separate natural gas rate increase request before December 31, 2012; however, UE can file a combined natural gas and electric rate case before that date. Further, this agreement does not prevent UE from filing to recover infrastructure replacement costs through an ISRS during this moratorium. The return on equity to be used by UE for purposes of an ISRS tariff filing is 10%.

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.

For additional information on Missouri rate matters, including UE’s 2011 natural gas rate order, UE’s pending electric rate case, and UE’s 2009 and 2010 electric rate orders and related court appeals and regulatory proceedings, 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.

Ameren Illinois (AIC)

All of AIC’s electric and natural gas operating revenues were subject to regulation by the ICC or FERC in the year ended December 31, 2010.

Under the Illinois Customer Choice Law, all electric customers in Illinois may choose their own electric energy provider. However, AIC is required to serve as the provider of last resort (POLR) for electric customers within its territory who have not chosen an alternative retail electric supplier. AIC’s obligation to provide full requirements electric service, including power supply, as a POLR varies by customer size. AIC is not required to offer fixed-priced electric service to customers with electric demands of 400 kilowatts or greater, as the market for service to this group of customers has been declared competitive. Power procurement costs incurred by AIC are passed directly to its customers through a cost recovery mechanism.

In April 2010, the ICC issued a rate order for AIC, which was amended in May 2010, that approved a net increase in annual revenues for electric delivery service of $35 million and a net decrease in annual revenues for natural gas delivery service of $20 million. The rate changes became effective in May 2010. The ICC order confirmed the previously approved 80% allocation of fixed non-volumetric residential and commercial natural gas customer charges, and approved a higher percentage of recovery of fixed non-volumetric electric residential and commercial customer charges. The percentage of costs to be recovered through fixed non-volumetric electric residential and commercial customer and meter charges increased from 27% to 40%. AIC and certain intervenors were granted a rehearing with the ICC. In November 2010, the ICC approved an order on the rehearing issues, which authorized an increase in annual revenues of $25 million, in addition to the net $15 million increase authorized in the ICC’s May 2010 amended rate order. The overall annual delivery service revenue increase as a result of these orders is $40 million. The rate changes relating to the rehearing issues became effective on November 19, 2010.

AIC filed a request with the ICC in February 2011 to increase its annual revenues for electric and natural gas delivery service by $60 million and $51 million, respectively. In an attempt to limit regulatory lag, AIC is using a future test year, 2012, in this rate request. Additionally, AIC is requesting a rider mechanism for its pension costs and the continuation of existing riders described below, including cost recovery mechanisms for energy efficiency costs. The requested pension cost rider mechanism would allow AIC to recover from or refund to customers any difference between pension expense incurred and the amount allowed in rates annually without a formal regulatory proceeding.

AIC 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 from a trust fund established when Ameren acquired IP. At December 31, 2010, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, AIC 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. Following the AIC Merger, this rider is only applicable for claims that occurred within IP’s historical service territory. Similarly, the rider will seek recovery only from customers within IP’s historical service territory.

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 AIC’s electric and natural gas rate adjustment tariffs to recover bad debt expense not recovered in base rates.

If certain criteria are met, AIC’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 a regional transmission tariff for approval by FERC. All transmission service within that RTO is then subjected to that tariff. As a member of MISO, AIC’s transmission rate is calculated in accordance with the MISO tariff rate formula. The transmission rate is updated in June of each year based on AIC’s filings with 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 AIC’s 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 6,263 megawatts of capacity available for the 2011 peak summer electrical demand. As discussed below, Genco and AERG 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, PJM and investor-owned utilities, such as AIC. For additional information on Marketing Company’s hedging activities and Marketing Company’s sales to AIC, 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 and AIC 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 and AERG 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 the MoPSC and the ICC 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. In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The existing FERC license expired on June 30, 2010. On July 2, 2010, UE received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. UE conducted studies using current field data and submitted the study results to multiple state and federal agencies in February 2011. UE anticipates filing the study results with FERC in the spring of 2011. A FERC order is expected after a review of the study results is completed; however, we cannot predict the ultimate outcome of the order. Taum Sauk returned to service in April 2010 after the plant was rebuilt following the breach of its upper reservoir in December 2005. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.

For additional information on regulatory matters, see Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies 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 or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, UE and Genco, that operate coal-fired power plants. Significant new rules already proposed or promulgated within the past year include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO ₂ and NO _x emissions, lowering the existing ozone ambient air quality standard; the CATR, which would require further reduction of SO ₂ and NO _x emissions from power plants; and a regulation governing coal ash impoundments. Within the next year, the EPA is also expected to propose new regulations under the Clean Water Act that could require significant capital expenditures, such as new water intake structures or cooling towers at our power plants, and a MACT standard for the control of hazardous air pollutants, such as mercury and acid gases from power plants. Such new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effect of the new and proposed environmental regulations may result in significant capital expenditures or increased operating costs over the next five to eight years for Ameren, UE and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our generating facilities, which could have an adverse effect on our results of operations, financial position, and liquidity.

For additional discussion of environmental matters, including NO _x , SO ₂ , and mercury emission reduction requirements, global climate change, remediation efforts, UE’s receipt in January 2010 of a Notice of Violation from the EPA alleging violations of the Clean Air Act’s NSR and Title V Programs, and the complaint filed by the EPA

against UE in January 2011 alleging violation of the Clean Air Act and Missouri law in performing projects at UE’s Rush Island coal-fired generating facility, 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.

TRANSMISSION AND SUPPLY OF ELECTRIC POWER

Ameren owns an integrated transmission system that comprises the transmission assets of UE, AIC and ATXI. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes AIC, ATXI, Genco, excluding EEI and Genco’s Elgin CT facility, and AERG). During 2010, the peak demand in AMMO was 8,797 MW and in AMIL was 9,166 MW. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.

UE, AIC and ATXI are transmission-owning members of MISO. Transmission service on the Ameren 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, the Tennessee Valley Authority, and Louisville Gas and Electric Company. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.

On August 2, 2010, Ameren announced the formation of ATX. ATX intends to build projects initially within Illinois and Missouri, with the potential for expanding to other areas in the future. ATX’s initial investments are expected to be the Grand Rivers projects, the first of which involves building a 345 kilovolt line across the state of Illinois, from the Missouri border to the Indiana border. The investment could total more than $1.3 billion through 2021, with a potential investment of $265 million from 2011 to 2015.

The Ameren Companies and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in many 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. As a result of the Energy Policy Act of 2005, owners and operators of the bulk electric power system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and its regional entities, such as SERC, and enforced by FERC. The Ameren Companies must follow these standards, which are in place to require that proper functions are performed to ensure the reliability of the bulk electric power system.

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.

Ameren Missouri (UE)

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 2011 included the expectation that new baseload generation capacity would be required between 2020 and 2030. Because of the significant time required to plan, acquire permits for, and build a baseload power plant, UE continues to study future plant alternatives, as well as energy efficiency programs that could help defer new plant construction. To prepare for the long-term need for baseload capacity, and to prepare for potentially more stringent environmental regulation of coal-fired power plants, which could lead to the retirement of current baseload assets, UE is taking steps to preserve options to meet future demand. These steps include seeking improvements in regulatory treatment of energy efficiency investments, evaluating potential sites for natural gas-fired generation, and pursuing an ESP for an additional unit at its existing nuclear plant site, subject to passage of state legislation that would ensure rate recovery of the ESP costs once the ESP has been approved by the NRC. In December 2010 and January 2011, the Missouri Energy Partnership Act was separately introduced in both the Missouri Senate and House of Representatives. The purpose of this legislation is to maintain an option for nuclear power in the state of Missouri, recover the costs of the ESP for a period up to 20 years, and provide appropriate consumer protections. This legislation remains pending as of the date of this report.

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.

Ameren Illinois (AIC)

AIC is required to obtain from market sources all electric supply requirements for customers, except those customers in markets declared competitive, who do not purchase electric supply from third-party suppliers. The power procurement costs incurred by AIC are passed directly to its customers through a cost recovery mechanism.

As part of the 2007 Illinois Electric Settlement Agreement, a new competitive power procurement process led by the IPA was implemented beginning in January 2009. The IPA administers a RFP process that procures AIC’s expected supply obligation. Since the start of this process, the ICC has approved the outcomes of multiple electric power procurement RFPs for energy, capacity and renewable energy credits covering different time periods.

A portion of the electric power supply required for AIC to satisfy its distribution customers’ requirements is purchased in the RFP process administered by the IPA from Marketing Company on behalf of Genco, AERG and EEI. In addition, as part of the 2007 Illinois Electric Settlement Agreement, AIC 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 its round-the-clock power requirements during the period June 1, 2008, through December 31, 2012, at the market prices relevant 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 May 31, 2016. 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.

On September 28, 2010, Resources Company announced that it signed a cooperative agreement with the DOE that could lead to repowering a unit at Genco’s Meredosia plant. This would create the world’s first full-scale, oxy-combustion coal-fired plant designed for permanent CO ₂ capture and storage. Ameren and two independent companies will assess the project in phases to validate the project’s scope, cost, schedule and commercial viability. If the first phases are successful and the project has received regulatory approval, Ameren and its partners will initiate the construction necessary to repower the plant.

Coal

Ameren, UE and Genco have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2019. Ameren, UE and Genco expect to enter into additional contracts to purchase coal from time to time. Coal supply agreements typically have an initial term of up to five years, with about 20% of the contracts expiring annually. UE has an ongoing need for coal to serve its native load customers and pursues a price hedging strategy consistent with this requirement. Merchant Generation’s forward coal requirements are dependent on the volume of power sales that have been contracted. As such, Merchant Generation strives to achieve increased margin certainty by aligning its fuel purchases with its power sales. Ameren burned 39 million tons (UE – 22 million, Genco – 13 million) of coal in 2010. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.

About 97% of Ameren’s coal (UE – 97%, Genco – 97%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Ameren, UE and Genco have a goal to maintain coal inventory consistent with their risk management policies. Inventory may be adjusted because of changes in burn or 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, 2010, coal inventories for Ameren, UE and Genco were at targeted levels. However, in 2011 Merchant Generation is targeting a reduction in its coal inventory, relative to previous levels. Disruptions in coal deliveries could cause Ameren, UE and Genco 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

The steps in the process to provide nuclear fuel generally involve 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 2011 fall refueling at UE’s Callaway nuclear plant are scheduled for manufacture and

delivery to the plant during May to July 2011. UE also has agreements or inventories to price-hedge approximately 98%, 84%, and 71% of Callaway’s 2011, 2013, and 2014 refueling requirements, respectively. UE has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium and conversion requirements through at least 2014. UE has enriched uranium inventories and enrichment supply contracts sufficient to satisfy enrichment requirements through 2013. Fuel fabrication services are under contract through 2014. 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, enhance diversification and pursue opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in May 2010. There is no refueling scheduled for 2012 and 2015. 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 and Genco 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’s and Genco’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. This is accomplished by optimizing transportation and storage options and minimizing cost and price risk through various supply and price-hedging agreements that allow access to multiple gas pools, supply basins, and storage services. As of December 31, 2010, UE had price-hedged about 30% and Genco had price-hedged 84% of its expected natural gas supply requirements for generation in 2011.

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 15% by June 1, 2015, and to 25% by June 1, 2025. AIC has procured renewable energy credits under the IPA-administered procurement process to

meet the renewable energy portfolio requirement through May 2011. In December 2010, AIC entered into a 20-year power purchase agreement with renewable energy suppliers and will begin purchasing power under the agreement starting in June 2012, to help supplement these requirements. Approximately 50% of the 2012 renewable energy requirement will be met through this agreement. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, for additional information about the Illinois power procurement process.

In Missouri, utilities are required to purchase or generate from renewable energy sources electricity equaling at least 2% of native load sales, with that percentage increasing 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 nonsolar requirement through 2017 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 became effective in 2009 and the landfill gas project discussed below. Currently, UE expects to meet the solar energy requirement through the purchase of solar-generated renewable energy credits.

In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which is expected to generate approximately 15MW of electricity by burning methane gas collected from the landfill. Site preparation for the CTs began in 2010 and construction will begin in 2011. The CTs are expected to begin generating power in 2012. 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 law in Missouri allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The 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 and 2010. UE has set up a website at www.uefficiency.com in order to provide more information to its customers regarding energy efficiency.

AIC is participating in the Illinois Clean Energy Community Foundation, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities. In 2008, the ICC issued orders approving AIC’s electric energy efficiency plan as well as cost recovery mechanisms by which program costs are being recovered from customers. AIC has set up a website at www.actonenergy.com in order to provide more information to its customers regarding energy efficiency.

NATURAL GAS SUPPLY FOR DISTRIBUTION

UE and AIC are responsible for the purchase and delivery of natural gas to their gas utility customers. UE and AIC 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 and AIC primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, the Northern Border Pipeline Company 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 and AIC in Missouri and Illinois under PGA clauses, subject to prudency reviews by the MoPSC and the ICC. As of December 31, 2010, UE had price-hedged 90%, and AIC had price-hedged 89%, of its expected natural gas supply requirements for distribution in 2011.

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 10 – Callaway Nuclear Plant, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies 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:

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.