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ITEM 1A.RISK FACTORS

Investors should review carefully the following material 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 further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect the results of operations, financial position, and liquidity of the Ameren Companies.

REGULATORY AND LEGISLATIVE RISKS

We are subject to extensive regulation of our businesses.

We are subject to federal, state, and local regulation. The extensive regulatory frameworks, some of which are more specifically identified in the following risk factors, regulate, among other matters, the electric and natural gas utility industries; the rate and cost structure of utilities, including an allowed ROE; the operation of nuclear power plants; the construction and operation of generation, transmission, and distribution facilities; the acquisition, disposal, depreciation and amortization of assets and facilities; the electric transmission system reliability; and wholesale and retail competition. In the planning and management of our operations, we must address the effects of existing and proposed laws and regulations and potential changes in our regulatory frameworks, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities. Significant changes in the nature of the regulation of our businesses, including expiration or discontinuation of, or significant changes to, existing regulatory mechanisms, could require changes to our business planning and management of our businesses and could adversely affect our results of operations, financial position, and liquidity. Failure to obtain adequate rates or regulatory approvals in a timely manner; failure to obtain necessary licenses or permits from regulatory authorities; the impact of new or modified laws, regulations, standards, interpretations, or other legal requirements; or increased compliance costs could adversely affect our results of operations, financial position, and liquidity.

The electric and natural gas rates that we are allowed to charge are determined through regulatory proceedings, which are subject to intervention and appeal. Rates are also subject to legislative actions, which are largely outside of our control. Certain events could prevent us from recovering our costs in a timely manner or from earning adequate returns on our investments.

The rates that we are allowed to charge for our utility services significantly influence our results of operations, financial position, and liquidity. The electric and natural gas utility industry is highly regulated. The utility rates charged to customers are determined by governmental entities, including the MoPSC, the ICC, and the 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, customer intervention, and economic conditions, as well as social and political views. Decisions made by these governmental entities regarding customer rates are largely outside of our control. We are exposed to regulatory lag and cost disallowances to varying degrees by jurisdiction, which, if unmitigated, could adversely affect our results of operations, financial position, and liquidity. Rate orders are also subject to appeal, which creates additional uncertainty as to the rates that we will ultimately be allowed to charge for our services. From time to time, our regulators may approve trackers, riders, or other recovery mechanisms that allow electric or natural gas rates to be adjusted without a traditional regulatory rate review. These mechanisms could be changed or terminated.

Ameren Missouri’s electric and natural gas utility rates and Ameren Illinois’ natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Ameren Missouri’s electric and natural gas utility rates established in those proceedings are primarily based on historical costs and revenues. Ameren Illinois’ natural gas rates established in those proceedings are based on

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estimated future costs and revenues. Thus, the rates that we are allowed to charge for utility services may not match our actual costs at any given time.

Rates include an allowed return on investments established by the regulator, including a return at the applicable WACC on rate base, and an amount for income taxes based on the currently applicable statutory income tax rates and amortization associated with excess deferred income taxes. Although rate regulation is premised on providing an opportunity to earn a reasonable rate of return on rate base, there can be no assurance that the regulator will determine that our costs were prudently incurred or that the regulatory process will result in rates that will produce full recovery of such costs or provide for an opportunity to earn a reasonable return on those investments. Ameren Missouri and Ameren Illinois, and the utility industry generally, have an increased need for cost recovery, primarily driven by capital investments, which is likely to continue in the future. The resulting increase to the revenue requirement needed to recover such costs and earn a return on investments could result in more frequent regulatory rate reviews and requests for cost recovery mechanisms. Additionally, increasing rates could result in regulatory or legislative actions, as well as competitive or political pressures, all of which could adversely affect our results of operations, financial position, and liquidity.

Ameren Illinois expects to use the IEIMA performance-based formula ratemaking framework to establish annual customer rates effective through 2023. Effective for rates beginning in 2024, Ameren Illinois will establish electric distribution rates through either a traditional regulatory rate review or an MYRP. As a result of its participation in the IEIMA performance-based formula ratemaking, Ameren Illinois’ ROE for its electric distribution service through 2023 and its electric energy-efficiency investments is directly correlated to yields on United States Treasury bonds. Additionally, Ameren Illinois is subject to certain performance standards. With respect to its natural gas delivery service business, unless extended, Ameren Illinois’ QIP will expire after December 2023.

Ameren Illinois expects to continue to use the current IEIMA performance-based formula ratemaking framework to establish annual customer rates effective through 2023 and reconcile the related revenue requirements through an IEIMA reconciliation. The IETL resulted in changes to the regulatory framework applicable to Ameren Illinois’ electric distribution business by giving Ameren Illinois the option to file an MYRP with the ICC by mid-January 2023, with rates effective beginning in 2024, among other things. Subject to a constructive outcome regarding the ICC’s determination of performance metrics, Ameren Illinois anticipates filing an MYRP for rates effective beginning in 2024. An MYRP would establish rates for a four-year period, and Ameren Illinois has the option to file for an MYRP every four years. For rates effective beginning in 2024, Ameren Illinois will be required to establish future rates through a traditional regulatory rate review or an MYRP with the ICC, which might result in rates that do not produce a full or timely recovery of costs or provide for an adequate return on investments and would expose Ameren Illinois’ electric distribution business to the risks described in the immediately preceding risk factor. By law, Ameren Illinois’ electric distribution revenues are decoupled from sales volumes regardless of the process used to establish electric distribution rates, which ensures that the electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. Ameren Illinois also has an electric energy-efficiency program rider, which includes a return at the applicable WACC on its program investments, that is subject to performance-based formula ratemaking. The ICC annually reviews Ameren Illinois’ rate filings for reasonableness and prudency. If the ICC were to conclude that Ameren Illinois’ costs were not prudently incurred, the ICC would disallow recovery of such costs.

The allowed ROE under the IEIMA and electric energy-efficiency formula ratemaking recovery mechanisms is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual ROE for its electric distribution business is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $11 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2022 projected year-end rate base, including electric energy-efficiency investments.

Ameren Illinois’ electric distribution business is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed ROE calculated under the formula ratemaking recovery mechanisms. The performance standards applicable to electric distribution service under the IEIMA include improvements in service reliability to reduce both the frequency and duration of outages, a reduction in the number of estimated bills, a reduction of consumption from inactive meters, and a reduction in bad debt expense. The allowed ROE for electric distribution service may be decreased for penalties up to 38 basis points in 2022 and up to 10 basis points in 2023 if these performance standards are not met. The allowed ROE on energy-efficiency investments can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings goals. Any adjustments to the allowed ROE for energy-efficiency investments will depend on annual performance for a historical period relative to energy savings goals. In 2021, 2020, and 2019, there were no performance-related basis point adjustments that materially affected financial results. With respect to the MYRP, the ICC-determined ROE would be subject to annual adjustments during the four-year period based on certain performance metrics, with aggregate symmetrical performance-based ROE incentives and penalties ranging from 20 to 60 basis points annually.

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While the ICC has approved a plan for Ameren Illinois to invest approximately $100 million per year in electric energy-efficiency programs through 2025, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in the future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs.

The QIP provides Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that are placed in service between regulatory rate reviews. Infrastructure investments under the QIP earn a return at the applicable WACC. Ameren Illinois’ QIP is subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. If the rate impact limitation was met in a particular year, the amount of rate base causing the QIP rate to exceed the limitation would be exposed to regulatory lag until a year when that amount could be recovered under QIP or is added to rate base as a part of a regulatory rate review. Upon issuance of a natural gas delivery service rate order, QIP rate base is transferred to base rates and the QIP is reset to zero. Without legislative action, the QIP will expire after December 2023. If Ameren Illinois is unable to recover investments under the QIP or there is no other regulatory change, Ameren Illinois will be subject to increased regulatory lag on its natural gas infrastructure investments that are placed in service between regulatory rate reviews, which could adversely affect Ameren’s and Ameren Illinois’ investment plans and results of operations, financial position, and liquidity.

As a result of the election to use the PISA, Ameren Missouri’s electric rates are subject to a rate cap. Additionally, Ameren Missouri’s investment plan assumes use of PISA through December 2028, which is subject to MoPSC approval that has not yet been requested.

As a result of Ameren Missouri’s election to use the PISA, its rate increases are limited to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in a July 2018 MoPSC order. Both the rate cap and the PISA election are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.

Increased capital investments and operating costs could cause customer rates to exceed the rate cap. In addition, a decrease in off-system sales, which are included in net energy costs within the FAC, could also contribute to customer rates exceeding the rate cap. Off-system sales are affected by generation availability, which is affected by planned and unplanned outages at Ameren Missouri’s energy centers, curtailment of generation resulting from unfavorable economic conditions, the addition of new generation sources, and retirements of Ameren Missouri’s energy centers, among other things. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the2.85%rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review would be subject to the rate cap. Any deferred overages approved for recovery would be recovered over a period of 20 years following approval of amounts in a regulatory rate review. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the amount of deferred overage that would cause customer rates to exceed the2.85%rate cap. A penalty incurred as the result of exceeding the rate cap could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.

Ameren Missouri’s planned capital expenditures of up to $9.2 billion from 2022 through 2026 are based on the assumption of continued constructive regulatory frameworks, including an assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028. If Ameren Missouri does not obtain approval to use the PISA through December 2028, it could adversely affect Ameren’s and Ameren Missouri’s investment plans and results of operations, financial position, and liquidity.

We are subject to various environmental laws. Significant capital expenditures may be required to achieve and to maintain compliance with these environmental laws. Failure to comply with these laws could result in the closing of facilities, alterations to the manner in which these facilities operate, increased operating costs, delays and increased costs of building new facilities, or exposure to fines and liabilities.

Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety including permitting programs implemented via federal, state, and local authorities. Such environmental laws address air emissions; discharges to water bodies; the storage, handling and disposal of hazardous substances and waste materials; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. Further, we are subject to risks from changing or conflicting interpretations of existing laws, modification to existing laws, new laws, and new or modified permit terms.

We are also subject to liability under environmental laws that address the remediation of environmental contamination on property currently or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such properties include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws against us. They could allege injury from exposure to hazardous materials, allege a failure to comply with environmental laws, seek to compel remediation of environmental contamination, or seek to recover damages resulting from that contamination.

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Environmental regulations have a significant impact on the electric utility industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, 2021, Ameren Missouri’s coal-fired energy centers represented 10% and 20% of Ameren’s and Ameren Missouri’s rate base, respectively. Clean Air Act regulations that apply to the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx, mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Regulations implementing the Clean Water Act govern both intake and discharges of water and may require evaluation of the ecological and biological impact of our operations and could require modifications to water intake structures or more stringent limitations on wastewater discharges. Depending upon the scope of modifications ultimately required by state regulators, these capital expenditures could be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR Rule, which require the closure of our surface impoundments at Ameren Missouri’s coal-fired energy centers. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers.

In January 2011, the United States Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri alleging that in performing projects at its coal-fired Rush Island Energy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2017, the district court issued a liability ruling against Ameren Missouri and, in September 2019, entered a remedy order. That remedy order included a requirement to install a flue gas desulfurization system at the Rush Island Energy Center, which was upheld through an appeals process by the United States Court of Appeals for the Eighth Circuit in the fourth quarter of 2021. Based on its assessment of available legal, operational and regulatory alternatives, Ameren Missouri has determined not to further appeal the court rulings and, in December 2021, filed a motion with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The district court is under no deadline to issue a ruling revising the remedy order. In January 2022, the MISO completed a preliminary assessment regarding potential impacts of the retirement to the regional electric power system, which indicated transmission upgrades and voltage support would be needed in advance of the retirement to address reliability concerns. In February 2022, Ameren Missouri expects to formally notify the MISO of its intent to retire the Rush Island Energy Center. Upon receipt of the formal notification, the MISO will conduct a final reliability assessment. The MISO must also separately approve the specific upgrades and transmission support required to address reliability concerns noted in the assessment. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center, including potential impacts on the reliability and cost of Ameren Missouri’s service to its customers, Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement, and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. The MoPSC staff is under no deadline to complete this review. As of December 31, 2021, the Rush Island Energy Center had a net plant balance of approximately $0.6 billion and a rate base of approximately $0.4 billion. In addition, Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect the planned acceleration of the retirement of the Rush Island Energy Center from 2039, the retirement year for the facility as reflected in the 2020 IRP and reflected in depreciation rates approved by the December 2021 MoPSC electric rate order. Ameren Missouri is unable to predict the ultimate resolution of this matter; however, such resolution could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

The EPA’s Affordable Clean Energy Rule repealed the Clean Power Plan and replaced it with a new rule that established emission guidelines for states to follow in developing plans to limit CO2 emissions and identified certain efficiency measures as the best system of emission reduction for coal-fired electric generating units. In January 2021, the United States Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy Rule, and ruled that the EPA had the discretion to consider emission reduction measures that include efficiency measures and generation shifting to lower carbon emissions. The United States Supreme Court agreed to review the court of appeals’ ruling and oral arguments will occur in February 2022 with a decision expected by mid-2022. A decision by the United States Supreme Court could impact the EPA’s development of new regulations to address carbon emissions from coal- and natural gas-fired electric generating units. At this time, Ameren Missouri cannot predict the outcome of the legal challenge or future rulemakings. As such, any impact on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri is uncertain.

The EPA’s CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and will result in the closure of surface impoundments at Ameren Missouri’s energy centers. In January 2022, Ameren Missouri received notice of a proposed determination by the EPA that it has rejected Ameren Missouri’s requests to extend the timeline for operating certain impoundments located at the Sioux and Meramec energy centers. Compliance with the CCR Rule’s requirements for closure of the impoundments would be required 135 days after the EPA issues a final determination, which Ameren Missouri expects to be issued in the spring of 2022. If Ameren Missouri was no longer able to use the surface impoundments at the Sioux or Meramec energy centers, Ameren Missouri would not be able to operate the energy centers unless an alternative for handling the CCR material is in place. Ameren Missouri plans to retire the Meramec Energy Center in 2022, and is accelerating its construction plans to build a CCR Rule-compliant impoundment at the Sioux Energy Center to allow for continued operations. Additionally, Ameren Missouri is seeking a reliability determination from the MISO, which, if granted, would extend the deadline to comply with the requirement to close the impoundments and allow the energy centers to operate.

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The IETL established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois will be subject to limits on emissions, including CO2 and NOx, equal to their unit-specific average emissions from 2018 through 2020, for any rolling twelve-month period beginning October 1, 2021, through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, which could limit the operations of Ameren Missouri's five natural gas-fired energy centers located in the state of Illinois, and will result in the closure of one or more energy centers earlier than anticipated. These energy centers are utilized to support peak loads. Subject to conditions in the IETL, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service as necessary. Ameren Missouri is reviewing the emission standards and the effect they may have on its generation strategy, including any increases in capital expenditures or operating costs, and changes to the useful lives of the five natural gas-fired energy centers. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect, among other things, the impact of these new emissions standards.

Ameren and Ameren Missouri have incurred, and expect to incur, significant costs with respect to environmental compliance and site remediation. New or revised environmental regulations, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, penalties or fines, reduced operations or closure of some of Ameren Missouri’s coal-and natural gas-fired energy centers, which, in turn, could lead to increased liquidity and financing needs, and higher financing costs. Actions required to ensure that Ameren Missouri’s facilities and operations are in compliance with environmental laws could be prohibitively expensive for Ameren Missouri if the costs are not fully recovered through rates. Environmental laws could require Ameren Missouri to close or to alter significantly the operations of its energy centers. If Ameren Missouri requests recovery of capital expenditures and costs for environmental compliance through rates, the MoPSC could deny recovery of all or a portion of these costs, prevent timely recovery, or make changes to the regulatory framework in an effort to minimize rate volatility and customer rate increases. Capital expenditures and costs to comply with future legislation or regulations might result in Ameren Missouri closing coal-fired energy centers earlier than planned. If these costs are not recoverable through base rates or other regulatory mechanisms, it could lead to an impairment of assets and reduced revenues. Any of the foregoing could have an adverse effect on our results of operations, financial positions, and liquidity.

We are subject to business and financial risks related to the impact of climate change legislation, regulation, and emission reduction goals.

There is increasing concern and activism among various external stakeholders, both nationally and internationally, about climate change, including public concerns about the potential environmental impacts from the combustion of fossil fuels, as well as pressure from public interest groups regarding limiting the use of natural gas. State and federal authorities, including the United States Congress, have considered initiatives to further restrict greenhouse gases to address global climate change. Additionally, international agreements could lead to future federal or state legislation or regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius. The Biden administration has announced a new policy commitment regarding a reduction in greenhouse gas emissions for the United States, but rulemaking to achieve such reductions has not yet been implemented. Actions taken to implement the Paris Agreement could result in future additional greenhouse gas reduction requirements in the United States. In addition, the Biden administration has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions targeting the utility industry.

As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2 emissions. Future federal and state legislation or regulations that mandate limits on the emission of, or impose taxation on, greenhouse gases could result in a significant increase in capital expenditures and operating costs, decreased revenues, penalties or fines, or reduced operations of some of Ameren Missouri’s coal- and natural gas-fired energy centers, which, in turn, could lead to increased liquidity and financing needs, and higher financing costs. Moreover, to the extent Ameren Missouri 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 related to climate change might force Ameren Missouri to close some coal-fired energy centers earlier than planned, which could lead to possible loss on abandonment and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.

Ameren established a goal of achieving net-zero carbon emissions by 2050. Ameren is also targeting a 50% CO2 emission reduction by 2030 and an 85% reduction by 2040 from the 2005 levels. Achievement of these goals is dependent on many factors, including the pace and extent of development and deployment of low- to zero-carbon energy technologies and carbon capture technologies, and the cost of those technologies; natural gas prices; new transmission infrastructure; and constructive energy policies, including those that address investment in energy infrastructure, global climate change, incentives for clean energy technologies, and environmental regulations. Additional factors associated with operational risks for the construction and acquisition of electric and natural gas infrastructure may also affect the achievement of these goals, as further discussed below. The strategy to achieve these goals also relies on continuing to pursue a diverse portfolio including low-carbon and carbon-free resources and energy-efficiency resources; continuing to participate in efforts to help advance the development of technologies such as carbon capture, utilization, and sequestration; the use of hydrogen fuel for electric production and

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energy storage, next generation nuclear, and large-scale long-cycle battery energy storage; and constructively engaging with legislators, regulators, investors, customers, and other stakeholders to support outcomes leading to a net-zero future.

We are subject to federal regulatory compliance and proceedings, which could result in increasing costs and the potential for regulatory penalties and other sanctions.

We are subject to FERC regulations, rules, and orders, including standards required by the NERC. As owners and operators of bulk power transmission systems and electric energy centers, we are subject to mandatory NERC reliability standards, including cybersecurity standards. In addition, our natural gas transmission, distribution, and storage facilities systems are subject to PHMSA rules and regulations. Compliance with these reliability standards, rules, and regulations may subject us to higher operating costs and may result in increased capital expenditures. We may also incur higher operating costs to comply with potential new regulations issued by these regulatory bodies. If we were found not to be in compliance with these mandatory NERC reliability standards, PHMSA rules and regulations, or FERC regulations, rules, and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations, financial position, and liquidity. The FERC can impose civil penalties of approximately $1.4 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards. The FERC also conducts audits and reviews of Ameren Missouri’s, Ameren Illinois’, and ATXI’s accounting records to assess the accuracy of their respective formula ratemaking process, and it can require refunds to customers for previously billed amounts, with interest.

OPERATIONAL RISKS

The construction and acquisition of, and capital improvements to, electric and natural gas utility infrastructure, along with Ameren Missouri’s ability to implement its Smart Energy Plan, which is aligned with its 2020 IRP, involve substantial risks.

We expect to make significant capital expenditures to maintain and improve our electric and natural gas utility infrastructure and to comply with existing environmental regulations. We estimate that we will invest up to $18.0 billion (Ameren Missouri – up to $9.2 billion; Ameren Illinois – up to $8.6 billion; ATXI – up to $0.2 billion) of capital expenditures from 2022 through 2026. For additional information on these estimates, see Liquidity and Capital Resources – Capital Expenditures in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. Investments in Ameren’s rate-regulated operations are expected to be recoverable from customers, but they are subject to prudence reviews and are exposed to regulatory lag of varying degrees by jurisdiction.

Our ability to complete construction projects successfully within projected estimates, including schedule, performance, and/or cost, and to implement Ameren Missouri’s Smart Energy Plan, which may include acquisition of generation facilities after they are constructed, is contingent upon many factors and subject to substantial risks. These factors include, but are not limited to, the following: project management expertise; escalating costs and/or shortages for labor, materials, and equipment, including changes to tariffs on materials; the ability of suppliers, contractors, and developers to meet contractual commitments timely; changes in the scope and timing of projects; the ability to obtain required regulatory, project, and permit approvals; the ability to obtain necessary rights-of-way, easements, and transmission connections at an acceptable cost in a timely fashion; unsatisfactory performance by the projects when completed; the inability to earn an adequate return on invested capital; the ability to raise capital on reasonable terms; and other events beyond our control, including construction delays due to weather. With respect to the transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2020 IRP, factors also include MoPSC approval for the retirement of energy centers and new or continued customer energy-efficiency programs; the ability to enter into build-transfer agreements for renewable generation and acquire that generation at a reasonable cost; levels of customer participation in the energy-efficiency programs; the cost and commercial availability of wind, solar, and other renewable generation and storage technologies; the ability to qualify for, and use, federal production or investment tax credits; changes in environmental laws or requirements, including those related to carbon emissions; and energy prices and demand.

Any of these risks could result in higher costs, the inability to complete anticipated projects, or facility closures, and could adversely affect our results of operations, financial position, and liquidity.

Our electric generation, transmission, and distribution facilities are subject to operational risks.

Our financial performance depends on the successful operation of electric generation, transmission, and distribution facilities. Operation of electric generation, 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;

•failures of equipment that can result in unanticipated liabilities or unplanned outages, such as the unplanned outage resulting from non-nuclear operating issues related to the Callaway Energy Center’s generator that occurred from December 2020 to August 2021;

•aging infrastructure that may require significant expenditures to operate and maintain;

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•an energy center that might not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected;

•lack of adequate water required for cooling plant operations;

•labor disputes;

•disruptions in the delivery of electricity to our customers;

•inability to maintain reliability of our electric utility services as coal-fired energy centers are retired and renewable energy generation is placed in service;

•suppliers and contractors who do not perform as required under their contracts;

•failure of other operators’ facilities and the effect of that failure on our electric system and customers;

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

•handling, storage, and disposition of CCR;

•unusual or adverse weather conditions or other natural disasters, including those that may result from climate change, such as severe storms, droughts, floods, tornadoes, earthquakes, icing, sustained high or low temperatures, such as the extremely low temperatures experienced in mid-February 2021, solar flares, and electromagnetic pulses;

•the level of wind and solar resources;

•inability to operate wind generation facilities at full capacity resulting from requirements to protect natural resources, including wildlife;

•the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, civil unrest, pandemic health events, including the COVID-19 pandemic, or other similar events;

•accidents that might result in injury or loss of life, extensive property damage, or environmental damage;

•ineffective vegetation management programs;

•cybersecurity risks, including loss of operational control of Ameren Missouri’s energy centers and our transmission and distribution systems and loss of data, including sensitive customer, employee, financial, and operating system information, through insider or outsider actions;

•limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities;

•inability to implement or maintain information systems;

•failure to keep pace with and the ability to adapt to rapid technological change; and

•other unanticipated operations and maintenance expenses and liabilities.

The foregoing risks could affect the controls and operations of our facilities or impede our ability to meet regulatory requirements, which could increase operating costs, increase our capital requirements and costs, reduce our revenues, or have an adverse effect on our liquidity.

Ameren Missouri’s ability to obtain an adequate supply of coal could limit operation of its coal-fired energy centers.

Ameren Missouri owns and operates coal-fired energy centers. About 98% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming, which has a limited number of suppliers. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion, staffing and equipment issues, infrastructure maintenance, derailments, weather, and supplier financial hardship. Coal suppliers in the Powder River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations and concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2021, coal inventories at the Sioux and Rush Island energy centers were near targeted levels, and coal inventories at the Labadie Energy Center were below targeted levels due to transportation disruptions in 2021. Ameren Missouri is actively managing inventories at the Meramec Energy Center in preparation for its expected 2022 retirement. However, additional disruptions in the delivery of coal, failure of our coal suppliers to provide adequate quantities or quality of coal, or lack of adequate inventories of coal, including low-sulfur coal used to comply with environmental regulations, could have adverse effects on Ameren Missouri’s electric generation operations. If Ameren Missouri is unable to obtain an adequate supply of coal under existing agreements, it may be required to purchase coal at higher prices or be forced to reduce generation at its coal-fired energy centers, which could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.

Ameren Missouri’s ownership and operation of a nuclear energy center creates business, financial, and waste disposal risks.

Ameren Missouri’s ownership of the Callaway Energy Center subjects it to risks associated with nuclear generation, including:

•potential harmful effects on the environment and human health resulting from radiological releases associated with the operation of nuclear facilities and the storage, handling, and disposal of radioactive materials;

•continued uncertainty regarding the federal government’s plan to permanently store spent nuclear fuel and, as a result, the need to provide for long-term storage of spent nuclear fuel at the Callaway Energy Center;

•limitations on the amounts and types of insurance available to cover losses that might arise in connection with the Callaway Energy Center or other United States nuclear facilities;

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•uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway Energy Center or any other United States nuclear facilities;

•public and governmental concerns about the safety and adequacy of security at nuclear facilities;

•limited availability of fuel supply and our reliance on licensed fuel assemblies from the one NRC-licensed supplier of Callaway Energy Center’s assemblies;

•costly and extended outages for scheduled or unscheduled maintenance and refueling, such as the unplanned outage resulting from non-nuclear operating issues related to the Callaway Energy Center’s generator that occurred from December 2020 to August 2021;

•uncertainties about the technological and financial aspects of decommissioning nuclear facilities at the end of their licensed lives;

•the adverse effect of poor market performance and other economic factors on the asset values of nuclear decommissioning trust funds and the corresponding increase, upon MoPSC approval, in customer rates to fund the estimated decommissioning costs; and

•potential adverse effects of a natural disaster, acts of sabotage or terrorism, including a cyber attack, or any accident leading to a radiological release.

The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear facilities. In the event of noncompliance, the NRC has the authority to impose fines or to 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 the Callaway Energy Center. In addition, if a serious nuclear incident were to occur, it could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial condition, and liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation of any domestic nuclear unit and could also cause the NRC to impose additional conditions or requirements on the industry, which could increase costs and result in additional capital expenditures. While the Callaway Energy Center is in compliance with the current NRC standards relating to seismic design and risk, these standards also require Ameren Missouri to address periodic changes to seismic hazard data and evaluation methods for the impact of an earthquake on its Callaway Energy Center due to its proximity to a fault line, which could require seismic risk evaluation updates and installation of additional capital equipment.

Our natural gas distribution and storage activities involve numerous risks that may result in accidents and increased operating costs.

Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, explosions, mechanical problems and cybersecurity risks, which could cause substantial financial losses, including fines and penalties. In addition, these hazards could result in serious injury, loss of human life, significant damage to property, environmental impacts, and impairment of our operations, which in turn could lead us to incur substantial losses. The location of distribution mains and storage facilities near populated areas, including residential areas, business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. A major domestic incident involving natural gas distribution, and storage systems could result in additional capital expenditures and/or increased operations and maintenance expenses for us and increased regulation of natural gas utilities. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.

Significant portions of our electric generation, transmission, and distribution facilities and natural gas transmission and distribution facilities are aging. This aging infrastructure may require significant additional maintenance or replacement. Ameren Missouri could be adversely affected if it is unable to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs.

Our aging infrastructure may pose risks to system reliability and expose us to expedited or unplanned significant capital expenditures and operating costs. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978, and the Callaway Energy Center began operating in 1984. The age of these energy centers increases the risks of unplanned outages, reduced generation output, and higher maintenance expense. Further, Ameren Missouri would be adversely affected if the MoPSC does not allow recovery of the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. In addition, as discussed above, Ameren Missouri expects the retirement date of its Rush Island Energy Center to be accelerated from the date reflected in depreciation rates approved in the December 2021 MoPSC electric rate order. Aging transmission and distribution facilities are more prone to failure than new facilities, which results in higher maintenance expense and the need to replace these facilities with new infrastructure. Even when the system is properly maintained, its reliability may ultimately deteriorate and negatively affect our ability to serve our customers, which could result in increased costs associated with regulatory oversight. The frequency and duration of customer outages are among the IEIMA performance standards. Any failure to achieve these standards will result in a reduction in Ameren Illinois’ allowed ROE on electric distribution assets. The higher maintenance costs associated with aging infrastructure and capital expenditures for new or replacement infrastructure could cause additional rate volatility for our customers, resistance by our regulators to allow customer rate increases, and/or regulatory lag in some of our jurisdictions, any of which could adversely affect our results of operations, financial position, and liquidity.

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Energy conservation, energy efficiency, distributed generation, energy storage, technological advances, and other factors could reduce energy demand from our customers.

Without a regulatory mechanism to ensure recovery, declines in energy usage could result in an under-recovery of our revenue requirement or an increase in our customer rates, as the revenue requirement would be spread over less sales volumes, which could adversely affect our results of operations, financial position, and liquidity. Such declines could occur due to a number of factors, including:

•customer energy-efficiency programs that are designed to reduce energy demand;

•energy-efficiency efforts by customers not related to our energy-efficiency programs;

•increased customer use of distributed generation sources, such as solar panels and other technologies, which have become more cost-competitive, with decreasing costs expected in the future, as well as the use of energy storage technologies; and

•macroeconomic factors resulting in low economic growth or contraction within our service territories, which could reduce energy demand.

Decreased use of our generation, transmission, and distribution services might result in stranded costs, which ultimately might not be recovered through rates, and therefore, could lead to an impairment or abandonment of assets.

FINANCIAL, ECONOMIC, AND MARKET RISKS

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 its investments in the common stock of its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. 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 dependent upon the earnings of its operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under affiliate indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations, and other items affecting retained earnings, and available cash. 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 affiliate borrowing arrangements and cash payments under the tax allocation agreement) to Ameren. Certain financing agreements, corporate organizational documents, and certain statutory and regulatory requirements may impose restrictions on the ability of Ameren Missouri, Ameren Illinois, and ATXI to transfer funds to Ameren in the form of cash dividends, loans, or advances.

Significant increases in prices of commodities, labor, services, materials, and supplies and other costs, including costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits, could adversely affect our results of operations, financial position, or liquidity.

A part of our core strategy focuses on disciplined cost management, including prudently monitoring all of our expenses. However, we have observed and expect future inflationary pressures related to prices of commodities, labor, services, materials, and supplies and other costs, including in the areas of health care and pension costs. These inflationary pressures could impact our ability to control costs, to make substantial investments in our businesses, to recover costs and investments, to earn our allowed ROEs within frameworks established by our regulators, and/or to maintain affordability of our services for our customers. Significant increases in our costs could increase our financing needs and otherwise adversely affect our results of operations, financial position, and liquidity.

Related to benefits, Ameren has defined benefit pension plans covering substantially all of its employees and has postretirement benefit plans covering non-union employees hired before October 2015 and union employees hired before January 2020. Assumptions related to future costs, returns on investments, interest rates, timing of employee retirements, and mortality, as well as other actuarial matters, have a significant impact on our customers’ rates and our plan funding requirements. Ameren’s total pension and postretirement benefit plans were overfunded by $717 million as of December 31, 2021. Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on its assumptions at December 31, 2021, its investment performance in 2021, and its pension funding policy, Ameren, Ameren Missouri, and Ameren Illinois do not expect to make material contributions in the aggregate over the next five years. These estimated contributions may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In addition to the costs of our pension 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. Future legislative changes related to health care could also significantly change our benefit programs and costs.

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GENERAL RISKS

Our results of operations, financial position, and liquidity have been and are expected to continue to be adversely affected by the international public health emergency associated with the COVID-19 pandemic.

The COVID-19 pandemic continues to affect our results of operations, financial position, and liquidity. While our electric sales volumes, excluding the estimated effects of weather and customer energy-efficiency programs, increased in 2021, compared to 2020, and total sales volume levels were more comparable to pre-pandemic levels, there has been a shift in sales volumes by customer class, with an increase in residential sales, and a decrease in commercial and industrial sales. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. In addition, although restrictions on social activities and nonessential businesses implemented in our service territories in 2020 have been relaxed, additional restrictions may be imposed in the future. As a result of the COVID-19 pandemic, economic activity has been disrupted in the service territories of Ameren Missouri and Ameren Illinois.

The COVID-19 pandemic could continue to affect total electric sales volumes and sales by customer class. Pursuant to the PISA, Ameren Missouri’s electric rates are limited to a 2.85% rate cap. Long-term declines in sales volumes, along with increased capital investments and operating costs, could result in Ameren Missouri’s inability to recover amounts exceeding the rate cap. While the revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission businesses are decoupled from changes in sales volumes, earnings at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers are exposed to such changes.

Our customers’ payment for our services has been impacted by the COVID-19 pandemic, resulting in a decrease to cash from operations. For most of the period from March 2020 through June 2021, the ICC limited disconnection activities and late fees for customer nonpayment to varying degrees based on customer class. A March 2021 ICC order also required Ameren Illinois to offer deferred payment arrangements extending to 18 months to all residential customers through June 2021. Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri has not experienced and does not expect a material impact to earnings from increases in bad debt expense.

In addition, suppliers and contractors may not perform as provided under their contracts. This could cause delays in construction projects, or the performance of necessary maintenance to our electric and natural gas infrastructure, which could lead to failures of equipment that can result in unanticipated liabilities or unplanned outages. Delays in our construction projects could also result in reduced planned capital expenditures and decreased rate base growth.

Also, our businesses depend on skilled professional and technical employees. Our operations could be adversely affected if a large portion of our employees contracted COVID-19 or became quarantined at the same time. This could lead to facility shutdowns and disruptions in the delivery of electricity and natural gas to our customers. In addition, remote working arrangements increase our data security risks, including loss of data related to sensitive customer, employee, financial, and operating system information, through insider or outsider actions. Further, compliance with any future vaccine mandates associated with COVID-19 may result in labor shortages, including shortages in skilled professional and technical labor, supply chain disruptions, delays in contractors’ performance or completion of work, and/or increased costs for us, our contractors, or our suppliers.

Ameren cannot predict the extent or duration of the COVID-19 pandemic or its effects on the global, national, or local economy, the capital markets, or its customers, suppliers, business continuity plans, results of operations, financial position, liquidity, planned rate base growth, or sales volumes.

Customers’, investors’, legislators’, and regulators’ opinions of us are affected by many factors, including system reliability, implementation of our strategic plan, protection of customer information, rates, media coverage, and ESG practices, as well as actions by other utility companies. Negative opinions developed by customers, investors, legislators, or regulators could harm our reputation.

Our results are influenced by the expectations of our customers, investors, legislators, and regulators. Those expectations are based, in part, on the reliability and affordability of our utility services. Service interruptions and facility shutdowns can occur due to failures of equipment as a result of severe or destructive weather or other causes. The ability of Ameren Missouri and Ameren Illinois to respond promptly to such failures can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, our ability to safeguard sensitive customer information and protect our systems from cyber attacks, and other actions can affect customer satisfaction. The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction.

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Our ability to successfully execute our strategic plan, including the transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2020 IRP, may affect customers’, investors’, legislators’, and regulators’ opinions and actions. Additionally, negative perceptions or publicity resulting from increasing scrutiny of ESG practices could negatively impact our reputation, investment in our common stock, or our access to capital markets. Customers’, investors’, legislators’, and regulators’ opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation.

If customers, investors, legislators, or regulators have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the ROEs we are allowed to earn, as well as the access to, and the cost of, capital. Additionally, negative opinions about us or other utility companies could make it more difficult for our businesses to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volume reductions or increased use of distributed generation by our customers. Any of these consequences could adversely affect our results of operations, financial position, and liquidity.

We are subject to employee work force factors that could adversely affect our operations.

Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. Certain specialized knowledge that focuses on skilled-craft and STEM-related disciplines is required to construct and operate generation, transmission, and distribution assets. Further, a significant portion of our work force is nearing retirement. As of December 31, 2021, approximately 26%, 27%, and 25% of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ total employees were 55 years old or older, respectively. We are also party to collective bargaining agreements that collectively represent about 48%, 58%, and 55% of Ameren’s, Ameren Missouri’s and Ameren Illinois’ total employees, respectively. All of the Ameren Missouri collective bargaining unit contracts expire in 2022. The Ameren Illinois collective bargaining unit contracts expire in 2022 and 2023, which cover 92% and 8% of represented employees, respectively. Due to the COVID-19 pandemic, a large portion of our non-field employees have been primarily working from home since March 2020. While our workforce has largely been stable, we experienced an increase in our attrition rate in 2021. Certain events, such as significant delays in finding appropriate replacement talent, inadequately trained replacement employees, a mismatch of skill sets to future needs, any work stoppage experienced in connection with negotiations of collective bargaining agreements, or challenges with transitioning working arrangements, could adversely affect our operations.

Our operations are subject to acts of terrorism, cyber attacks, and other intentionally disruptive acts.

Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and enterprise information systems may be affected by malicious acts, terrorist activities and other intentionally disruptive acts, including cyber attacks, which could disrupt our ability to produce or distribute our energy products. There have been attacks in the industry on energy infrastructure, such as substations and related assets, in the past, and there may be more attacks in the future as technology becomes more prevalent in energy infrastructure and the threat landscape continues to expand. Any such incident could limit our ability to generate, purchase, or transmit power or natural gas and could have significant regional economic consequences. Any such disruption could result in a significant decrease in revenues, a significant increase in costs including those for repair, or adversely affect economic activity in our service territory which, in turn, could adversely affect our results of operations, financial position, and liquidity.

There has been an increase in the number and sophistication of physical and cyber attacks across all industries worldwide. Cyber attacks could include viruses, malicious or destructive code, phishing attacks, denial of service attacks, ransomware and other ransom-based attacks, improper access by third parties, attacks on email systems, and attacks leading to data loss, operational control, or exploitation of vulnerabilities specific to internally developed systems or to those provided and/or maintained by our suppliers, among various other security breaches. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm resulting from theft or the inappropriate release or destruction of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected grid. Therefore, a disruption caused by a cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. Insurance might not be adequate to cover losses that arise in connection with these events. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.

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Our businesses are dependent on our ability to access the capital markets successfully. We might not have access to sufficient capital in the amounts and at the times needed, as well as on reasonable terms.

We rely on the issuance of short-term and long-term debt and equity as significant sources of liquidity and funding for capital requirements not satisfied by our operating cash flow, as well as to refinance existing long-term debt. The inability to raise debt or equity capital on reasonable terms, or at all, could negatively affect our ability to maintain or to expand our businesses. Events beyond our control, such as depressed economic conditions, the COVID-19 pandemic, or extreme volatility in the debt, equity, or credit markets, might create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity, or credit markets, including our ability to draw on bank credit facilities. Any adverse change in our credit ratings could reduce access to capital and trigger collateral postings and prepayments. Such changes could also increase the cost of borrowing and the costs of fuel, power, and natural gas supply, among other things, which could adversely affect our results of operations, financial position, and liquidity.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.PROPERTIES

For information on our principal properties, see the energy center and in-service utility-related properties tables 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 a discussion of planned additions. See also Note 5 – Long-term Debt and Equity Financings and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

The following table shows the anticipated capability of Ameren Missouri’s energy centers at the time of Ameren Missouri’s expected 2022 peak summer electrical demand for all energy centers owned as of December 31, 2021:

Primary Fuel Source Energy Center Location Net Kilowatt Capability(a)

Coal Labadie(b) Franklin County, Missouri 2,372,000

Rush Island(c) Jefferson County, Missouri 1,178,000

Sioux(d) St. Charles County, Missouri 972,000

Meramec(d) St. Louis County, Missouri 510,000

Nuclear Callaway(e) Callaway County, Missouri 1,194,000

Hydroelectric Osage(e) Lakeside, Missouri 235,000

Pumped-storage Taum Sauk(e) Reynolds County, Missouri 440,000

Wind High Prairie Renewable Adair and Schuyler Counties, Missouri 400,000

Atchison Renewable Atchison County, Missouri 298,800

Natural gas Audrain(f) Audrain County, Missouri 616,000

Venice(g) Venice, Illinois 489,000

Goose Creek(g) Piatt County, Illinois 444,000

Pinckneyville(g) Pinckneyville, Illinois 316,000

Raccoon Creek(g) Clay County, Illinois 308,000

Meramec(d) St. Louis County, Missouri 226,000

Kinmundy(g) Kinmundy, Illinois 210,000

Peno Creek(f) Bowling Green, Missouri 172,000

Oil (CTs) Fairgrounds(d) Jefferson City, Missouri 55,000

Mexico(d) Mexico, Missouri 55,000

Moberly(d) Moberly, Missouri 55,000

Moreau(d) Jefferson City, Missouri 55,000

Methane gas (CT) Maryland Heights Maryland Heights, Missouri 9,000

Solar O’Fallon O’Fallon, Missouri 4,500

Lambert St. Louis County, Missouri 900

BJC St. Louis, Missouri 1,600

South St. Louis St. Louis, Missouri 200

Total Ameren and Ameren Missouri 10,765,000

(a)Net kilowatt capability, except for wind and solar generating facilities, is the generating capacity available for dispatch from the energy center into the electric transmission grid. Capability for wind and solar generating facilities represents nameplate capacity. This capacity is only attainable when wind/solar conditions are sufficiently available. The on-demand capability for wind and solar units is zero.

(b)The Labadie Energy Center is scheduled to retire 1,186,000 kilowatts by 2036 and 1,186,000 kilowatts by 2042.

(c)The Rush Island Energy Center was scheduled to retire by 2039 as noted in the 2020 IRP. However, changes to the retirement date are subject to a final judgment to be issued by the United States District Court for the Eastern District of Missouri regarding a September 2019 remedy order. For additional information, see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

(d)The Sioux and Meramec energy centers are scheduled to retire by 2028 and 2022, respectively. The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to be retired by 2026 as noted in the 2020 IRP.

(e)The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively.

(f)There are economic development arrangements applicable to these CTs, as discussed below.

(g)See Illinois Emissions Standards in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

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The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2021:

AmerenMissouri AmerenIllinois

Circuit miles of electric transmission lines(a) 3,109 4,659

Circuit miles of electric distribution lines 33,656 45,890

Percentage of circuit miles of electric distribution lines underground 24 % 16 %

Miles of natural gas transmission and distribution mains 3,480 18,620

Underground natural gas storage fields — 12

(a)ATXI owns 545 miles of transmission lines not reflected in this table.

Our other properties include office buildings, warehouses, garages, and repair shops.

With only a few exceptions, we have fee title to all principal energy centers 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 to certain permitted liens and judgment liens). The exceptions are as follows:

•Certain property is situated on lands occupied under leases, easements, franchises, licenses, or permits. That property includes a portion of Ameren Missouri’s Osage Energy Center reservoir; certain facilities at Ameren Missouri’s Sioux Energy Center; most of Ameren Missouri’s High Prairie Renewable, Atchison Renewable, Peno Creek CT and Audrain CT energy centers; Ameren Missouri’s Maryland Heights, Lambert, and BJC energy centers; certain substations; and most transmission and distribution lines and natural gas mains. The United States or the state of Missouri may own or may have paramount rights with respect 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 Ameren Missouri’s energy centers 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 Ameren Missouri’s Keokuk Energy Center is located.

Substantially all of the properties and plant of Ameren Missouri and Ameren Illinois are subject to the liens of the indentures securing their mortgage bonds.

Ameren Missouri has conveyed most of its Peno Creek CT Energy Center to the city of Bowling Green, Missouri through December 2022. Ameren Missouri has rights and obligations as the operator of the energy center under a long-term agreement with the city of Bowling Green. Under the terms of this agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the agreement, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri mortgage bond indenture.

Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as the operator of the energy center under a long-term agreement with Audrain County. Under the terms of this agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. The agreement will expire in December 2023. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the agreement, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri 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. For additional information on material legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report. Pursuant to Item 103(c)(3)(iii) of Regulation S-K, our policy is to disclose environmental proceedings to which a governmental entity is a party if we reasonably believe such proceedings will result in monetary sanctions of $1 million or more.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS:

The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2021, all their positions and offices held with the Ameren Companies as of February 22, 2022, and their tenures as officers, and their titles for at least the last five years.

AMEREN CORPORATION:

Name Age Positions Period

Warner L. Baxter 60 Executive Chairman; Ameren January 2022 – Present

Chairman, President, and Chief Executive Officer; Ameren 2014(a) – January 2022

Chairman and President; Ameren Missouri December 2019 – January 2022

Chairman and President; Ameren Services March 2016 – December 2019

Chairman and President; Ameren Services December 2019 – Present

Chairman and President; Ameren Missouri April 2014 – December 2019

Vice President, Internal Audit; Ameren June 2014 – July 2018

(a)Elected President of Ameren in February 2014, Chief Executive Officer of Ameren in April 2014, and Chairman of Ameren in July 2014.

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SUBSIDIARIES:

Name Age Positions Period

Mark C. Birk 57 Chairman and President; Ameren Missouri January 2022 – Present

Richard J. Mark 66 Chairman and President; Ameren Illinois June 2012 – Present

Shawn E. Schukar 60 Chairman and President; ATXI May 2017 – Present

(a)Bhavani Amirthalingam served as the Chief Information Officer and Vice President North America for Schneider Electric SE from January 2015 to March 2018.

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 executive officers or between any executive officers and any directors of the Ameren Companies. Except as noted, the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.

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PART II

ITEM 5.MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES

Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 40,340 on January 31, 2022. There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding common stock of Ameren Missouri and Ameren Illinois.

Purchases of Equity Securities

Ameren Corporation, Ameren Missouri, and Ameren Illinois did not purchase any equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 2021, to December 31, 2021.

Performance Graph

The following graph shows Ameren’s cumulative TSR during the five years ended December 31, 2021. The graph also shows the cumulative total returns of the S&P 500 Index, S&P 500 Utility Index, and the Philadelphia Utility Index. The S&P 500 Utility Index and the Philadelphia Utility Index are market capitalization-weighted indices of U.S. public utility companies. The comparison assumes that $100 was invested on December 31, 2016, in Ameren common stock and in each of the indices shown and that all of the dividends were reinvested.

Comparison of Five-Year Cumulative Return

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Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.

ITEM 6.(RESERVED)

ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries.Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries.

Below is a summary description of Ameren’s principal subsidiaries – Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

•Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.

•Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.

•ATXI operates a FERC rate-regulated electric transmission business in the MISO.

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. See Note 16 – Segment Information under Part II, Item 8, of this report for further discussion of Ameren’s and Ameren Illinois’ segments.

Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated, except as disclosed in Note 13 – Related-party Transactions under Part II, Item 8, of this report. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular and graphical dollar amounts are in millions, unless otherwise indicated.

The following discussion should be read in conjunction with the financial statements contained in this Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Discussion regarding our financial condition and results of operations for the year ended December 31, 2019, including comparisons with the year ended December 31, 2020, is included in Item 7 of our Form 10-K for the year ended December 31, 2020, filed with the SEC on February 22, 2021.

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per diluted share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per diluted share information helps readers to understand the impact of these factors on Ameren’s earnings per diluted share.

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OVERVIEW

Our core strategy is driven by the following three pillars:

Improved Reliability(f)

Rate Base ($ in billions)(a) Constructive Regulatory Frameworks(c)

Segment Regulatory Framework

Key announcements, updates, and regulatory outcomes

The COVID-19 pandemic continues to affect our results of operations, financial position, and liquidity. While our electric sales volumes, excluding the estimated effects of weather and customer energy-efficiency programs, increased in 2021, compared to 2020, and total sales volume levels were more comparable to pre-pandemic levels, there has been a shift in sales volumes by customer class, with an increase in residential sales, and a decrease in commercial and industrial sales. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. We continue to assess the impacts the COVID-19 pandemic is having on our businesses, including impacts on electric and natural gas sales volumes, liquidity, bad debt expense, and supply chain operations. For further discussion of these and other matters discussed below, see Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Mattersunder Part II, Item 8, of this report, and Results of Operations, Liquidity and Capital Resources, and Outlook sections below. In addition, for information regarding Ameren Illinois’ suspension and

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subsequent reinstatement of customer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

Due to extremely cold winter weather in mid-February 2021, Ameren Missouri and Ameren Illinois experienced higher than anticipated commodity costs for natural gas purchased for resale and purchased power, which contributed to the acceleration of the timing of certain planned 2021 long-term debt issuances. Ameren Missouri and Ameren Illinois have cost recovery mechanisms in place that provide recovery of the higher natural gas costs and purchased power from customers over periods of time established under the applicable mechanisms.

In January 2021, Ameren Missouri acquired a 300-MW wind generation project located in northwestern Missouri. As of June 30, 2021, Ameren Missouri had placed the project in service as the Atchison Renewable Energy Center. The purchase price of the energy center was approximately $500 million, including an immaterial amount of transaction costs. In December 2020, Ameren Missouri acquired a 400-MW wind generation project located in northeastern Missouri for approximately $615 million, and placed the assets in service as the High Prairie Renewable Energy Center. The purchase price included $564 million of cash, a deferred purchase price obligation withheld as credit support in relation to certain potential claims, contingent consideration, and transaction costs. Both renewable energy centers support Ameren Missouri’s compliance with the Missouri renewable energy standard.

During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. After replacement of certain key components of the generator, the energy center returned to service in early August 2021. The cost of generator repairs was approximately $60 million, which was largely capital expenditures. See Note 9 – Callaway Energy Center under Part II, Item 8, of this report for additional information.

In August 2021, the United States Court of Appeals for the Eighth Circuit issued a decision that affirmed the United States District Court for the Eastern District of Missouri’s January 2017 liability ruling and the district court’s September 2019 remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In November 2021, the court of appeals issued an order denying requests for consideration previously sought by both Ameren Missouri and the United States Department of Justice. Based on its assessment of available legal, operational and regulatory alternatives, Ameren Missouri has determined not to further appeal the court rulings and, in December 2021, filed a motion with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The district court is under no deadline to issue a ruling revising the remedy order. In January 2022, the MISO completed a preliminary assessment regarding potential impacts of the retirement to the regional electric power system, which indicated transmission upgrades and voltage support would be needed in advance of the retirement to address reliability concerns. In February 2022, Ameren Missouri expects to formally notify the MISO of its intent to retire the Rush Island Energy Center. Upon receipt of the formal notification, the MISO will conduct a final reliability assessment. The MISO must also separately approve the specific upgrades and transmission support required to address reliability concerns noted in the assessment. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center, including potential impacts on the reliability and cost of Ameren Missouri’s service to its customers, Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement, and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. The MoPSC staff is under no deadline to complete this review. Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute that became effective in August 2021.See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.

In September 2021, the MoPSC issued an order approving Ameren Missouri’s energy savings results for the second year of the MEEIA 2019 program. As a result of this order, and in accordance with revenue recognition guidance, Ameren Missouri recognized revenues of $9 million in 2021.

In December 2021, the MoPSC issued orders in Ameren Missouri’s 2021 electric service and natural gas delivery service regulatory rate reviews. The orders will result in increases of $220 million and $5 million to Ameren Missouri’s annual revenue requirements for electric retail service and natural gas delivery service, respectively. The electric revenue requirement increase is based on a rate base of $10.2 billion, infrastructure investments as of September 30, 2021, and a change in the depreciable lives of the Sioux and Rush Island energy centers’ assets consistent with Ameren Missouri’s 2020 IRP. The electric order did not specify an ROE, but specified that Ameren Missouri’s September 30, 2021 capital structure, which was composed of 51.97% common equity, will be used in the PISA and RESRAM. The electric rate order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard costs that the MoPSC previously authorized in earlier electric rate orders. It also establishes a five-year recovery period for $61 million of certain costs associated with the Meramec Energy Center, which is expected to be retired in 2022. The orders also approved for recovery $9 million of certain costs and forgone customer late fee and reconnection fee revenues resulting from the COVID-19 pandemic that were accumulated pursuant to March 2021 MoPSC orders. The new electric and natural gas rates will become effective on February 28, 2022.

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In February 2022, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2022. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4 billion over the five-year period from 2022 through 2026, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 through 2026 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA from December 2023 to December 2028.

In March 2021, the ICC issued an order approving Ameren Illinois’ requested tariff to reconcile its electric distribution service revenue requirement once Ameren Illinois ceases to update customer rates under performance-based formula ratemaking. The last update under such ratemaking is anticipated to be for 2023 customer rates. The tariff would allow Ameren Illinois to reconcile its revenue requirement for customer rates established for 2022 and 2023. To utilize the reconciliation, Ameren Illinois is required to file a request to update its electric distribution service rates through either a traditional regulatory rate review, which may be based on a future test year and would reflect a proposed ROE subject to ICC approval, or through the filing of an MYRP, which Ameren Illinois expects to file for rates effective beginning in 2024 pursuant to the IETL as described below. The rate update request would need to be filed by mid-January 2023. Pursuant to the order, Ameren Illinois’ 2022 and 2023 revenues would reflect each year’s actual recoverable costs, year-end rate base, and a return at the applicable WACC, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The revenue requirement reconciliation adjustment would be collected from, or refunded to, customers within two years from the end of the reconciled year.

In September 2021, the IETL was enacted, which resulted in changes to the regulatory framework applicable to Ameren Illinois’ electric distribution business, among other things. The IETL allows Ameren Illinois to file an MYRP with the ICC by mid-January 2023, with rates effective beginning in 2024. Subject to a constructive outcome regarding the ICC’s determination of performance metrics, Ameren Illinois anticipates filing an MYRP by mid-January 2023 to establish rates for 2024. Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of a four-year period, based on each year's forecasted recoverable costs, an ICC-determined ROE applied to each calendar year of the four-year period, and a common equity ratio of up to 50% being deemed prudent and reasonable by law, with a higher equity ratio requiring specific ICC approval. The approved ROE would be subject to adjustment during the four-year period based on certain performance metrics, with aggregate symmetrical performance-based ROE incentives and penalties ranging from 20 to 60 basis points. The MYRP would also allow Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to an aggregate reconciliation cap of 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs and costs recovered through riders outside of base rates would be excluded from the reconciliation cap. Electric distribution service revenues would continue to be decoupled from sales volumes under an MYRP. If Ameren Illinois does not file an MYRP for rates effective beginning in 2024, its next opportunity to file an MYRP would be for rates effective beginning in 2028.

In July 2021, the ICC issued an order approving Ameren Illinois’ energy-efficiency plan that includes annual investments in electric energy-efficiency programs of approximately $100 million per year from 2022 through 2025. Pursuant to the IETL, the planned annual investments in electric energy-efficiency programs will increase to approximately $120 million. Ameren Illinois expects to file a revised energy-efficiency plan with the ICC by early March 2022 to reflect the expected increased level of annual investments. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not recovered through the electric distribution service performance-based formula ratemaking framework.

In December 2021, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $58 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2022. This order reflected an increase to the annual performance-based formula rate based on 2020 actual recoverable costs and expected net plant additions for 2021, an increase to include the 2020 revenue requirement reconciliation adjustment including a capital structure composed of 51% common equity, and an increase for the conclusion of the 2019 revenue requirement reconciliation adjustment, which was fully refunded to customers in 2021, consistent with the ICC’s December 2020 annual update filing order.

In December 2021, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $61 million beginning in January 2022, which represents an increase of $10 million from 2021 rates.

In February 2021, Ameren’s board of directors increased the quarterly common stock dividend to 55 cents per share, resulting in an annualized equivalent dividend rate of $2.20 per share. In February 2022, Ameren’s board of directors increased the quarterly common stock dividend to 59 cents per share, resulting in an annualized equivalent dividend rate of $2.36 per share.

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Earnings

Net income attributable to Ameren common shareholders was $990 million, or $3.84 per diluted share, for 2021, and $871 million, or $3.50 per diluted share, for 2020. Net income was favorably affected in 2021, compared with 2020, by increased infrastructure investments across all business segments; increased Ameren Missouri electric retail sales, primarily resulting from improving economic conditions and the effects of weather; and by the results of Ameren Missouri’s March 2020 electric rate order. Earnings in 2021, compared with 2020, were also favorably affected by higher delivery service rates at Ameren Illinois Natural Gas and a higher recognized ROE at Ameren Illinois Electric Distribution. Net income was unfavorably affected in 2021, compared with 2020, by the effect of dilution and higher other operations and maintenance expenses at Ameren Missouri due to the amortization of expenses related to the 2020 scheduled refueling and maintenance outage at the Callaway Energy Center and increased non-nuclear energy center and distribution maintenance costs, as well as higher other operations and maintenance expenses due to increased infrastructure maintenance and compliance costs at Ameren Illinois Natural Gas. Earnings in 2021, compared with 2020, were also unfavorably affected by the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which increased earnings in the year-ago period, and the result of the FERC’s March 2021 order, primarily related to the historical recovery of materials and supplies inventories; increased financing costs at Ameren (parent) and Ameren Missouri, primarily due to higher long-term debt balances; and increased depreciation and amortization expenses not recoverable under riders or trackers at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to additional property, plant, and equipment investments.

Liquidity

At December 31, 2021, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.8 billion.

In May 2021, Ameren entered into an equity distribution sales agreement pursuant to which Ameren may offer and sell from time to time up to $750 million of its common stock through an ATM program, which includes the ability to enter into forward sales agreements. During 2021, Ameren issued 1.8 million shares of common stock and received proceeds of $148 million. In September 2021, December 2021, and January 2022, Ameren entered into forward sale agreements under the ATM program with counterparties relating to 0.4 million, 0.5 million, and 0.2 million shares of common stock, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.

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Ameren remains focused on strategic capital allocation. The following chart presents 2021 capital expenditures by segment and the midpoint of projected cumulative capital expenditures for 2022 through 2026 by segment:

Ameren Missouri(a) Ameren Illinois Natural Gas

Ameren Illinois Electric Distribution Ameren Transmission

(a)Ameren Missouri’s capital expenditures include $525 million for wind generation expenditures for the year ended December 31, 2021. Ameren Missouri’s projected capital expenditures for 2022 through 2026 includes approximately $0.7 billion of capital expenditures related to coal-fired generation.

For 2022 through 2026, Ameren’s cumulative capital expenditures are projected to range from $16.6 billion to $18.0 billion. The following table presents the range of projected spending by segment:

Range (in billions)

Ameren Missouri(a) $ 8.5 – $ 9.2

Ameren Illinois Electric Distribution 3.0 – 3.3

Ameren Illinois Natural Gas 1.7 – 1.8

Ameren Transmission 3.4 – 3.7

(a)Amounts exclude renewable generation investment opportunities of 1,200 MWs by 2026, which are included in Ameren Missouri’s 2020 IRP, and additional investment opportunities that may be approved by the MISO to address reliability concerns in connection with the planned accelerated retirement of the Rush Island Energy Center.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, including those resulting from the COVID-19 pandemic discussed below, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing, and our pension and postretirement benefits costs. Almost all of our revenues are subject to state or federal regulation. This regulation has a material impact on the rates we charge customers for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, with the frameworks established by our regulators. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory frameworks.

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We continue to assess the impacts of the COVID-19 pandemic on our businesses, including impacts on electric and natural gas sales volumes, supply chain operations, and bad debt expense. Regarding uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri has not experienced and does not expect a material impact to earnings from increases in bad debt expense. Our accounts receivable balances that were past due or that were a part of a deferred payment arrangement are more comparable to pre-pandemic levels. As of December 31, 2021, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 20%, 17%, and 24%, or $94 million, $34 million, and $60 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. As of December 31, 2019, these percentages were 18%, 18%, and 20%, or $75 million, $30 million, and $45 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. Ameren Missouri’s electric sales volumes have been, and continue to be, affected by the COVID-19 pandemic, including a shift in sales volumes by customer class compared to pre-pandemic levels, with an increase in residential sales, and a decrease in commercial and industrial sales, excluding the estimated effects of weather and customer energy-efficiency programs.

Ameren Missouri principally uses coal and enriched uranium for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, inflation, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution business, and a FAC for Ameren Missouri’s electric business.

We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of Ameren Missouri’s energy centers and our transmission and distribution systems and the level and timing of operations and maintenance costs and capital investment are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.

Earnings Summary

The following table presents a summary of Ameren’s earnings for the years ended December 31, 2021 and 2020:

Net income attributable to Ameren common shareholders $ 990 $ 871

Earnings per common share – diluted 3.84 3.50

Net income attributable to Ameren common shareholders in 2021 increased $119 million, or $0.34 per diluted share, from 2020. The increase was due to net income increases of $82 million, $22 million, $14 million, and $9 million at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively. The increases in net income were partially offset by an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent) of $8 million.

Earnings per share in 2021, compared with 2020, were favorably affected by:

•investments in infrastructure and wind generation pursuant to the PISA and the RESRAM, which resulted in increased deferral of interest expense (21 cents per share);

•increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE at Ameren Illinois Electric Distribution, which increased revenues at these segments (19 cents per share);

•the results of the MoPSC’s March 2020 electric rate order, which reduced the base level of expenses at Ameren Missouri, partially offset by lower base rates, net of recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs and recoverable depreciation under the PISA (10 cents per share);

•increased electric retail sales, excluding the estimated effects of weather and MEEIA, at Ameren Missouri, largely due to improving economic conditions, which resulted in increased sales volumes (10 cents per share);

•higher base rates pursuant to the ICC's January 2021 natural gas rate order, which increased margins at Ameren Illinois Natural Gas (8 cents per share);

•higher other income, net, due to the absence of charitable donations made in 2020 pursuant to the MoPSC’s March 2020 electric rate order, increased earnings from equity method investments to advance clean and resilient energy technologies, and a return to more normal levels of charitable donations at Ameren (parent) (8 cents per share);

•the impact of weather on electric retail sales at Ameren Missouri, primarily resulting from warmer summer temperatures experienced in 2021 (estimated at 6 cents per share); and

•the results of true-ups to the 2020 revenue requirement reconciliation adjustment in 2021 related to Ameren Illinois’ rates for electric distribution delivery service and electric customer energy-efficiency program investments (2 cents per share).

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Earnings per share in 2021, compared with 2020, were unfavorably affected by:

•increased other operations and maintenance expenses at Ameren Missouri, primarily due to the amortization of expenses related to the 2020 scheduled refueling and maintenance outage at the Callaway Energy Center and increased non-nuclear energy center and distribution maintenance costs, and at Ameren Illinois Natural Gas due to increased infrastructure maintenance and compliance activity (17 cents per share);

•the effect of dilution, primarily due to increased weighted-average basic common shares outstanding resulting from issuances of common shares as detailed in Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report (14 cents per share);

•the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which increased Ameren Transmission earnings in the year-ago period, and the result of the FERC’s March 2021 order, primarily related to the historical recovery of materials and supplies inventories, which decreased Ameren Transmission earnings in 2021 (7 cents per share);

•increased financing costs, primarily at Ameren (parent) and Ameren Missouri, largely due to higher long-term debt balances (5 cents per share);

•increased depreciation and amortization expenses not recoverable under riders or trackers at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to additional property, plant, and equipment investments (5 cents per share); and

•decreased income tax benefits at Ameren (parent), primarily related to employee retention tax credits, changes in the distribution of taxable income by state, and company owned life insurance, partially offset by increased amortization of excess deferred income taxes at Ameren Missouri (3 cents per share).

The cents per share information presented is based on the weighted-average basic shares outstanding in 2020 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 2021 statutory tax rate of 26%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income, Net, Interest Charges, and Income Taxes, see the major headings below.

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Below is Ameren’s table of income statement components by segment for the years ended December 31, 2021 and 2020:

Natural gas purchased for resale (60) — (382) — — (442)

Noncontrolling interests – preferred stock dividends (3) (1) — (1) — (5)

Natural gas purchased for resale (43) — (229) — — (272)

Noncontrolling interests – preferred stock dividends (3) (1) (1) (1) — (6)

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Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2021 and 2020:

Natural gas revenues — 957 — — 957

Natural gas purchased for resale — (382) — — (382)

Natural gas margins — 575 — — 575

Other operations and maintenance expenses (534) (236) (50) — (820)

Depreciation and amortization (309) (90) (73) — (472)

Taxes other than income taxes (76) (73) (4) — (153)

Preferred stock dividends (1) — (1) — (2)

Net income attributable to common shareholder $ 165 $ 108 $ 152 $ — $ 425

Natural gas revenues — 760 — — 760

Natural gas purchased for resale — (229) — — (229)

Natural gas margins — 531 — — 531

Other operations and maintenance expenses (506) (221) (48) — (775)

Depreciation and amortization (288) (81) (65) — (434)

Taxes other than income taxes (72) (65) (3) — (140)

Preferred stock dividends (1) (1) (1) — (3)

Net income attributable to common shareholder $ 143 $ 99 $ 137 $ — $ 379

Margins

Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural gas purchased for resale. 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.

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Electric Margins

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $202 Million

(a)Includes other/intersegment eliminations of $(29) million and $(29) million in 2021and 2020, respectively.

Natural Gas Margins

Total by Segment(a) Increase (Decrease) by Segment

Overall Ameren Increase of $44 Million

(a)Includes other/intersegment eliminations of $(1) million and $(2) million in 2021and 2020, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

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The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2021, compared with 2020:

Electric and Natural Gas Margins

Electric revenue change:

Effect of weather (estimate)(b) $ 24 $ — $ — $ — $ — $ 24

Base rates (estimate)(c) (6) 63 — 39 — 96

MEEIA performance incentives 3 — — — — 3

Off-system sales, capacity, and FAC revenues, net 96 — — — — 96

Customer energy-efficiency program investments — 12 — — — 12

Other cost recovery mechanisms(e) — 1 — — — 1

Fuel and purchased power change:

Energy costs $ (99) $ — $ — $ — $ — $ (99)

Sales volumes (excluding the estimated effects of weather) (3) — (3)

Effect of weather (estimate)(b) (4) — — — — (4)

Effect of lower net energy costs included in base rates 36 — — — — 36

Other (7) — — — — (7)

Cost recovery mechanisms – offset in electric revenue(d) (70) (59) — — 22 (107)

Total fuel and purchased power change $ (147) $ (59) $ — $ — $ 22 $ (184)

Net change in electric margins $ 81 $ 82 $ — $ 39 $ — $ 202

Natural gas revenue change:

Effect of weather (estimate)(b) $ (4) $ — $ — $ — $ — $ (4)

Base rates (estimate) — — 28 — — 28

Change in rate design — — (2) — — (2)

QIP rider — — 9 — — 9

Other (1) — — — 1 —

Other cost recovery mechanisms(e) — — 9 — — 9

Total natural gas revenue change $ 16 $ — $ 197 $ — $ 1 $ 214

Natural gas purchased for resale change:

Effect of weather (estimate)(b) $ 4 $ — $ — $ — $ — $ 4

Total natural gas purchased for resale change $ (17) $ — $ (153) $ — $ — $ (170)

Net change in natural gas margins $ (1) $ — $ 44 $ — $ 1 $ 44

(a)Includes an increase in transmission electric margins of $36 million in 2021, compared with 2020, at Ameren Illinois.

(b)Represents the estimated variation resulting primarily from changes in cooling and heating degree days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.

(c)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates. For Ameren Missouri, base rates exclude an increase of $7 million for the recovery of lost electric margins in 2021, compared with 2020, resulting from the MEEIA customer energy-efficiency programs. This amount is included in the “sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” line item.

(d)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of income, resulting in no change to electric and natural gas margins. Activity in Other/Intersegment Eliminations represents the elimination of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI, as well as Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution. See Note 13 – Related-party Transactions and Note 16 – Segment Information under Part II, Item 8, of this report for additional information on intersegment eliminations.

(e)Offsetting expense increases or decreases are reflected in “Other operations and maintenance,” “Depreciation and amortization,” or in “Taxes other than income taxes” within the “Operating Expenses” section of the statement of income. These items have no overall impact on earnings.

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Ameren

Ameren’s electric margins increased $202 million, or 5%, in 2021, compared with 2020, because of increased margins at Ameren Missouri, Ameren Illinois Electric Distribution, and Ameren Transmission, as discussed below. Ameren’s natural gas margins increased $44 million, or 7%, between years primarily because of increased margins at Ameren Illinois Natural Gas, as discussed below.

Ameren Transmission

Ameren Transmission’s electric margins increased $39 million, or 7%, in 2021, compared with 2020. Base rate revenues were favorably affected by continued capital investment (+$23 million), as evidenced by a 12% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$33 million). These increases were partially offset by the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE and the effect of the FERC’s March 2021 order (-$17 million), which required refunds primarily related to historical recovery of materials and supplies inventories. See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the May 2020 and March 2021 FERC orders.

Ameren Missouri

Ameren Missouri’s electric margins increased $81 million, or 3%, in 2021, compared with 2020. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $70 million in 2021, compared with 2020. The increased revenues are fully offset by an increase in fuel and purchased power costs, which increased primarily due to higher electric prices, the absence of the Callaway Energy Center generation and a significant increase in customer demand for electricity in mid-February 2021 due to extremely cold weather. The changes to “Cost recovery mechanisms – offset in fuel and purchased power” are fully offset by “Cost recovery mechanisms – offset in electric revenue” in the table above, and result in no impact to margins. Ameren Missouri’s 5% exposure to net energy costs variances under the FAC is reflected within “Off-system sales, capacity and FAC revenues, net” and “Energy costs”.

The following items had a favorable effect on Ameren Missouri’s electric margins in 2021, compared with 2020:

•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric sales margins increased an estimated $32 million. The increase was primarily due to an increase in retail sales volumes in 2021, which were unfavorably affected by the COVID-19 pandemic in 2020, partially offset by a decrease in the average retail price per kilowatthour due to changes in customer usage patterns. The change in sales margins is the sum of the change in “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” on electric revenues (+$35 million) and “Sales volumes (excluding the estimated effects of weather)” on fuel and purchased power (-$3 million). While the MEEIA customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins under the MEEIA ensured that electric margins were not affected.

•The March 2020 MoPSC electric rate order that resulted in lower net energy costs included in base rates, partially offset by lower electric base rates, increased margins $30 million. The change in electric base rates is the sum of the change in “Base rates (estimate)” (-$6 million) and the “Effect of lower net energy costs included in base rates” (+$36 million) in the table above.

•Summer temperatures were warmer as cooling degree days increased 12%, and winter temperatures were warmer as heating degree days decreased 4%. The aggregate effect of weather increased margins by an estimated $20 million. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (+$24 million) and the “Effect of weather (estimate)” on fuel and purchased power (-$4 million) in the table above.

Ameren Missouri’s electric margins decreased $3 million due to higher net energy costs. The absence of the Callaway Energy Center generation and the extremely cold weather in mid-February 2021, partially offset by insurance recoveries related to the unplanned Callaway Energy Center maintenance outage, drove net energy costs higher than those reflected in base rates, resulting from Ameren Missouri’s 5% exposure to net energy cost variances under the FAC. The change in net energy costs is the sum of “Off-system sales, capacity and FAC revenues, net” (+$96 million) and “Energy costs” (-$99 million) in the table above.

Ameren Missouri’s natural gas margins were comparable between years. Purchased gas costs increased $21 million in 2021, compared with 2020, primarily resulting from higher natural gas prices throughout 2021 and the significant increase in customer demand and prices for natural gas in mid-February 2021 due to extremely cold weather. The increased purchased gas costs are fully offset by an increase in natural gas revenues under the PGA, resulting in no impact to margin. The increase in purchased gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above.

Ameren Illinois

Ameren Illinois’ electric margins increased $118 million, or 8%, in 2021, compared with 2020, driven by increased margins at Ameren Illinois Electric Distribution and Ameren Illinois Transmission. Ameren Illinois Natural Gas’ margins increased $44 million, or 8%, between years.

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Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $82 million, or 8%, in 2021, compared with 2020. Purchased power costs increased $59 million in 2021, compared with 2020, primarily resulting from higher electric prices and the significant increase in customer demand for electricity in mid-February 2021 due to extremely cold weather. The increased purchased power costs are fully offset by an increase in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin. The increase in purchased power cost is reflected in “Cost recovery mechanisms – offset in electric revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in fuel and purchased power” in the table above.

The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in 2021, compared with 2020:

•Base rates increased due to a higher recognized ROE (+$9 million), as evidenced by an increase of 49 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, increased capital investment (+$10 million), as evidenced by a 8% increase in year-end rate base, higher recoverable non-purchased power expenses (+$35 million), and revenue requirement reconciliation adjustment true-ups for 2020 (+$9 million). The sum of these changes collectively increased margins $63 million.

•Revenues increased $12 million due to the recovery of and return on increased customer energy-efficiency program investments under performance-based formula ratemaking.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins increased $44 million, or 8%, in 2021, compared with 2020. Purchased gas costs increased $153 million in 2021, compared with 2020, primarily resulting from higher natural gas prices throughout 2021 and the significant increase in customer demand for natural gas in mid-February 2021 due to extremely cold weather. The increased purchased gas costs are fully offset by an increase in natural gas revenues under the PGA, resulting in no impact to margin. The increase in purchased gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins in 2021, compared with 2020:

•Revenues increased $28 million due to higher natural gas base rates as a result of the January 2021 natural gas rate order.

•Revenues increased $9 million due to additional investment in qualified natural gas infrastructure under the QIP.

•Other cost recovery mechanisms increased revenues $9 million, primarily due to increased revenues for excise taxes.

Ameren Illinois Transmission

Ameren Illinois Transmission’s electric margins increased $36 million, or 11%, in 2021, compared with 2020. Margins were favorably affected by increased capital investment (+$23 million), as evidenced by an 18% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$26 million). These increases were partially offset by the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE and the effect of the FERC’s March 2021 order (-$13 million), which required refunds primarily related to historical recovery of materials and supplies inventories. See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the May 2020 and March 2021 FERC orders.

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Other Operations and Maintenance Expenses

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $113 Million

(a)Includes $62 million and $57 million at Ameren Transmission in 2021 and 2020, respectively, and other/intersegment eliminations of $(6) million and $(9) million in 2021and 2020, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Ameren

Other operations and maintenance expenses at Ameren increased $113 million in 2021, compared with 2020. In addition to changes by segments discussed below, other operations and maintenance expenses increased $3 million in 2021 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of increased costs for support services.

Ameren Transmission

Other operations and maintenance expenses at Ameren Transmission increased $5 million in 2021, compared with 2020, primarily because of increased maintenance activity.

Ameren Missouri

The $62 million increase in Ameren Missouri’s other operations and maintenance expenses in 2021, compared with 2020, was primarily due to the following items:

•Energy center maintenance costs, other than Callaway refueling and maintenance costs, increased $29 million, primarily because of costs related to new wind generation facilities, which are recovered under the RESRAM, and the deferral of projects in 2020.

•Callaway Energy Center refueling and maintenance costs increased $28 million because of the amortization of those costs, beginning in January 2021, which were previously deferred as a regulatory asset, pursuant to the MoPSC’s February 2020 order.

•Recoverable customer energy-efficiency program costs increased $16 million because of increased participation in the MEEIA programs in 2021.

•Technology-related expenditures increased $11 million, primarily because of cloud computing licensing costs and software maintenance.

•Transmission and distribution expenditures increased $6 million, primarily because of increased storm costs.

•The cash surrender value of company-owned life insurance decreased $6 million because of less favorable market returns in 2021, compared with 2020.

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The following items partially offset the above increases in other operations and maintenance expenses between years:

•Labor and benefit costs decreased $12 million, primarily because of higher capitalization of costs resulting from increased construction activity.

•Amortization of regulatory balances, primarily solar rebate costs pursuant to the MoPSC’s March 2020 electric rate order and RESRAM deferrals, decreased $11 million.

•Expenses decreased $10 million because of increased bad debt costs in 2020 largely due to the COVID-19 pandemic.

•Deferral to a regulatory asset of $5 million of certain costs incurred in 2020 related to the COVID-19 pandemic, pursuant to the MoPSC’s March 2021 orders.

Ameren Illinois

Other operations and maintenance expenses increased $45 million at Ameren Illinois in 2021, compared with 2020, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2021 and 2020.

Ameren Illinois Electric Distribution

The $28 million increase in Ameren Illinois Electric Distribution’s other operations and maintenance expenses in 2021, compared with 2020, was primarily due to the following items:

•Amortization of regulatory assets associated with customer energy-efficiency program investments under formula ratemaking increased $8 million.

•Technology-related expenditures increased $8 million, primarily because of cloud computing licensing costs and software maintenance.

•Increased bad debt expense of $7 million, primarily because of increased recovery of bad debt costs allowed by the ICC.

•Expenses increased $5 million because of the true-up of vegetation management expenditures consistent with the December 2021 ICC electric distribution service rate order.

•The cash surrender value of company-owned life insurance decreased $3 million because of less favorable market returns in 2021 compared with 2020.

The above increases were partially offset by a $7 million reduction in environmental remediation rider costs, which resulted from a decline in the required remediation efforts.

Ameren Illinois Natural Gas

Other operations and maintenance expenses at Ameren Illinois Natural Gas increased $15 million in 2021, compared with 2020, largely due to an $8 million increase in infrastructure maintenance and compliance activity. Other operations and maintenance expenses also increased $5 million because of the absence in 2021 of miscellaneous amortizations of regulatory liabilities, which lowered expenses in 2020. These increases were partially offset by $3 million reduction in recoverable bad debt expense and environmental remediation rider costs consistent with the amounts allowed by the ICC.

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Depreciation and Amortization

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $71 Million

(a)Includes other/intersegment eliminations of $4 million and $4 million in 2021 and 2020, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

The $71 million, $28 million, and $38 million increase in depreciation and amortization expenses in 2021, compared with 2020, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, was primarily due to additional property, plant, and equipment across their respective segments. Ameren’s and Ameren Missouri’s depreciation and amortization expenses reflected a deferral to a regulatory asset of depreciation and amortization expenses pursuant to the PISA and the RESRAM. The PISA and RESRAM deferrals of depreciation and amortization expenses was $98 million and $27 million in 2021 and 2020, respectively.

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Taxes Other Than Income Taxes

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $29 Million

(a)Includes $8 million and $8 million at Ameren Transmission in 2021 and 2020, respectively, and other/intersegment eliminations of $12 million and $10 million in 2021and2020, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Taxes other than income taxes increased $29 million at Ameren in 2021, compared with 2020, primarily because of increased excise taxes of $11 million and $7 million at Ameren Missouri and Ameren Illinois Natural Gas, respectively, resulting from increased sales. Additionally, taxes other than income taxes increased $5 million, compared with the year-ago period, at Ameren Missouri because of increased property taxes, primarily resulting from the addition of wind generation properties and higher assessed values, partially offset by lower natural gas property taxes. Taxes other than income taxes also increased $3 million at Ameren Illinois Electric Distribution because of increased excise taxes, resulting from decreased tax credits compared with 2020.

See Excise Taxes in Note 15 – Supplemental Information under Part II, Item 8, of this report for additional information.

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Other Income, Net

Total by Segment Increase by Segment

Overall Ameren Increase of $51 Million

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Other income, net, increased $51 million at Ameren in 2021, compared with 2020, primarily because of the following items:

•The non-service cost component of net periodic benefit income increased $20 million, primarily because of increases of $9 million, $5 million, and $4 million for Ameren Missouri, Ameren Illinois Electric Distribution, and activity not reported as part of a segment, respectively.

•Income from equity method investments to advance clean and resilient energy technologies increased $9 million for activity not reported as part of a segment.

•Charitable donations were $8 million lower at Ameren Missouri due to the absence of charitable donations made in the year-ago period pursuant to the MoPSC’s March 2020 electric rate order. Charitable donations were $7 million lower for activity not reported as part of a segment due to a return to normal levels at Ameren (parent).

•The equity portion of allowance for funds used during construction increased $7 million at Ameren Missouri due to higher construction work in progress balances during 2021.

See Note 6 – Other Income, Net under Part II, Item 8, of this report for additional information. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for more information on the non-service cost components of net periodic benefit income.

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Interest Charges

Total by Segment Increase (Decrease) by Segment

Overall Ameren Decrease of $36 Million

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Interest charges decreased $36 million and $53 million in 2021, compared with 2020, at Ameren and Ameren Missouri, respectively, primarily because of increased deferrals to a regulatory asset of interest charges pursuant to the PISA and RESRAM. The PISA and RESRAM deferrals of interest charges were $82 million and $12 million in 2021 and 2020, respectively. Interest charges increased $9 million at Ameren Illinois in 2021, compared with 2020, as discussed below.

The following items partially offset the above decreases in interest charges in 2021, compared with 2020:

•Issuances of long-term debt at Ameren Missouri in October 2020 and June 2021 collectively increased interest charges by $11 million and $6 million, respectively.

•Issuance of long-term debt at Ameren (parent) in April 2020 increased interest charges by $7 million.

•Interest charges at Ameren Illinois Transmission increased by $5 million as a result of the Ameren Illinois issuances of long-term debt in November 2020 and June 2021 and a March 2021 FERC order, primarily related to the historical recovery of materials and supplies inventories.

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Income Taxes

The following table presents effective income tax rates for the years ended December 31, 2021and 2020:

Ameren Missouri 1% 7%

Ameren Illinois 25% 24%

Ameren Illinois Electric Distribution 24% 22%

Ameren Illinois Natural Gas 27% 26%

Ameren Illinois Transmission 25% 25%

Ameren Transmission 26% 26%

See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois.

The effective income tax rate was higher at Ameren Illinois Electric Distribution in 2021, compared with 2020, primarily because of decreased tax benefits from certain depreciation differences on property-related items largely attributable to lower amortization of excess deferred taxes.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash provided by operating activities, we use available cash, drawings under committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). In addition, to support a portion of its fuel requirements for generation, Ameren Missouri has entered into various long-term commitments to meet these requirements. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. Ameren’s, Ameren Missouri’s, and Ameren Illinois’ estimated minimum purchase obligations associated with these commitments totaled $1.6 billion, $0.7 billion, and, $0.8 billion, respectively, which include $0.7 billion, $0.3 billion, and, $0.4 billion, respectively, in 2022.

We expect to make significant capital expenditures over the next five years, as discussed in the Capital Expenditures sections below, supported by a combination of long-term debt and equity, as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy target requirements, environmental compliance, and other improvements. For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2026. Ameren expects these issuances to provide equity of about $100 million annually. In addition, in 2021, Ameren established an ATM program under which Ameren may offer and sell from time to time up to $750 million of its common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. During 2021, Ameren issued a total of 3.4 million shares of common stock and received aggregate proceeds of $261 million under the ATM program and the settlement of the remaining portion of the August 2019 forward sale agreement. Ameren plans to issue approximately $300 million of equity each year from 2022 to 2026 in addition to issuances under the DRPlus and employee benefit plans. Ameren expects its equity to total capitalization to be about 45% through December 31, 2026, with the long-term intent to support solid investment-grade credit ratings. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the ATM program, the 2021 settlement of the remaining portion of the August 2019 forward sale agreement, and the September 2021, December 2021, and January 2022 forward sale agreements.

The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments at the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2021, for Ameren, Ameren Missouri, and Ameren Illinois. With the credit capacity available under the Credit Agreements, and cash and cash equivalents, Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively had net available liquidity of $1.8 billion at December 31, 2021. See Credit Facility Borrowings and Liquidity and Long-term Debt and Equity below for additional information.

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The following table presents net cash provided by (used in) operating, investing, and financing activities for the years ended December 31, 2021 and 2020:

Cash Flows from Operating Activities

Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional regulatory rate review, subject to prudence reviews. Similar regulatory mechanisms exist for certain other operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by seasonal customer rates and changes in customer demand due to weather, such as increased demand resulting from the extremely cold weather in mid-February 2021, significantly affects the amount and timing of our cash provided by operating activities. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our regulatory frameworks.

Ameren

Ameren’s cash provided by operating activities decreased $66 million in 2021, compared with 2020. The following items contributed to the decrease:

•A $62 million increase in payroll tax payments primarily due to the employer portion of Social Security taxes as a result of a payment deferral allowed in 2020 under the Coronavirus Aid, Relief, and Economic Security Act. Half of the 2020 deferral was paid at the end of 2021 and the remaining half will be paid at the end of 2022.

•A $49 million increase in the cost of natural gas held in storage, primarily at Ameren Illinois, because of higher prices.

•A $44 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of power, natural gas, and other fuels.

•A $43 million increase in interest payments, primarily due to an increase in the average outstanding debt.

•An $18 million increase in energy center maintenance costs, other than those associated with the Callaway refueling and maintenance outage, at Ameren Missouri, primarily because of costs related to new wind generation facilities.

•A $15 million increase in major storm restoration costs at Ameren Illinois, primarily due to a January 2021 storm.

•An $8 million increase in pension and postretirement benefit plan contributions.

•A $6 million increase in payments to contractors at Ameren Illinois, primarily related to distribution expenditures for increased natural gas infrastructure maintenance and compliance costs.

•A $6 million increase in property tax payments at Ameren Missouri due to higher assessed property tax values.

The following items partially offset the decrease in Ameren’s cash from operating activities between periods:

•A $74 million increase due to the net impact of customer collections, the effect of riders, and increased commodity costs. An increase at Ameren Missouri, as discussed below, and increased customer collections at ATXI were partially offset by a decrease at Ameren Illinois, as discussed below.

•A $30 million decrease in payments for nuclear refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. There was no scheduled refueling and maintenance outage in 2021.

•A $21 million decrease in payments to settle ARO liabilities, primarily related to the closure of Ameren Missouri’s CCR storage facilities.

•A $21 million increase, primarily resulting from reduced purchases of materials and supplies at Ameren Illinois to support operations in 2021 as levels were increased in 2020 to mitigate against potential supply disruptions associated with the COVID-19 pandemic.

•A $21 million increase resulting from a reduction in payments for certain cloud computing arrangements.

•A $14 million increase resulting from income tax refunds of $1 million in 2021, compared with income tax payments of $13 million in 2020, primarily from lower taxable income and the timing of payments in 2021.

•A $12 million decrease in payments related to charitable donations.

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Ameren Missouri

Ameren Missouri’s cash provided by operating activities increased $18 million in 2021, compared with 2020. The following items contributed to the increase:

•An $86 million increase due to the net impact of customer collections, the effect of riders, and increased commodity costs. The increase resulted from increased retail sales and a net increase attributable to riders, excluding the PGA. These increases were partially offset by increased purchases for natural gas for resale and purchased power as a result of the significant increase in customer demand and increased prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, which also contributed to a net decrease under the PGA, and a decrease in collections of outstanding account receivables. See Outlook below for additional information about the extension of the collection period for the PGA related to the extremely cold weather in mid-February 2021.

•A $30 million decrease in payments for nuclear refueling and maintenance outages at the Callaway Energy Center. There was no scheduled refueling and maintenance outage in 2021.

•A $22 million decrease in payments to settle ARO liabilities, primarily related to the closure of CCR storage facilities.

•An $11 million increase resulting from a reduction in payments for certain cloud computing arrangements.

The following items partially offset the increase in Ameren Missouri’s cash from operating activities between periods:

•A $45 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of power, natural gas, and other fuels.