AEE · Read the filing

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, and actions by local jurisdictions that may affect the constructing or siting of facilities. 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, including the impact of inflationary pressures, 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, revenues, and sales volumes. Ameren Illinois’ natural gas rates established in those proceedings are

Table of Contents

based on estimated future costs, revenues, and sales volumes. Beginning in 2024 through at least 2027, Ameren Illinois’ electric distribution rates will be established through an MYRP as discussed in the following risk factor, which will be based on estimated future costs and an applicable revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap. 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 is utilizing the IEIMA performance-based formula ratemaking framework to establish annual customer rates effective through 2023. Effective for rates beginning in 2024 through at least 2027, Ameren Illinois will establish electric distribution rates through an MYRP, which is subject to a reconciliation cap and includes an ROE determined by the ICC applicable to each year of the four-year period. 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 are directly correlated to yields on United States Treasury bonds. Additionally, Ameren Illinois is subject to certain performance standards.

Ameren Illinois is utilizing the IEIMA performance-based formula ratemaking framework to establish annual customer rates effective through 2023 and will 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, or establish future rates through a traditional regulatory rate review, among other things. An MYRP would establish rates for a four-year period, and Ameren Illinois has the option to file for an MYRP every four years. Ameren Illinois elected to file an MYRP in January 2023 for rates effective in 2024 through 2027 with the ICC. The MYRP also allows Ameren Illinois to reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs would be excluded from the reconciliation cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and amortization of certain assets. The reconciliation cap also excludes costs recovered through riders outside of base rates, such as riders for electric energy-efficiency investments, power procurement and transmission services, renewable energy credit compliance, zero emission credits, certain environmental costs, and bad debt write-offs, among others. Ameren Illinois’ existing riders will remain effective and electric distribution service revenues will continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year would incorporate Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. In addition, the ICC will determine the ROE applicable to each year of the four-year period. Changes in economic conditions could result in the predetermined ROE becoming inadequate over the four-year period. 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’ electric energy-efficiency program rider, which includes a return at the applicable WACC on its program investments, is subject to performance-based formula ratemaking. The ICC annually reviews each Ameren Illinois rate filing 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 $12 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2023 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

Table of Contents

debt expense. The 2023 allowed ROE for electric distribution service is subject to the performance standards related to reduced estimated bills and bad debt expense, and may be decreased for penalties up to 10 basis points 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 2022, 2021, and 2020, there were no performance-related basis point adjustments that materially affected financial results. With respect to the MYRP, a September 2022 ICC order approved total ROE incentives and penalties of 24 basis points, allocated among the seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics and the ROE incentives and penalties will apply annually from 2024 through 2027 under the MYRP filed by Ameren Illinois.

While the ICC has approved a plan for Ameren Illinois to invest approximately $120 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.

With respect to its natural gas delivery service business, unless extended, Ameren Illinois’ QIP will expire after December 2023.

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 service rates are subject to a rate cap through 2023. Effective 2024, Ameren Missouri’s electric service business is subject to a limitation on increasing the annual revenue requirement due to the inclusion of incremental PISA deferrals in the revenue requirement.

Ameren Missouri’s rate cap under the PISA is effective through 2023 and limits electric service rate increases 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. Increased capital investments and operating costs could cause customer rates to exceed the 2.85% rate cap effective through 2023. In addition, a decrease in off-system sales or capacity revenues or an increase in purchased power expense, all of 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 until new rates are established in the next regulatory rate review. 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. Also, due to a change in customer behavior and certain business practices resulting from the COVID-19 pandemic, there has been a shift in sales volumes by customer class at Ameren Missouri, which began in 2020, resulting in an increase in residential sales, and a decrease in commercial and industrial sales.While Ameren Missouri's electric sales volumes in 2022, excluding the estimated effects of weather and customer energy-efficiency programs, were comparable to the same period in 2021 and to pre-pandemic levels, 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.

Table of Contents

by the MoPSC after January 1, 2024, and will be based on the revenue requirement established in the immediately preceding rate order. Increased capital expenditures could cause incremental PISA deferrals to exceed the 2.5% limitation when it is effective, and such amounts exceeding the 2.5% limitation would be excluded from recovery under future revenue requirements. Failure to align capital investments under the 2.5% limitation could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.

We are subject to various environmental and permitting 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 by 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, substations, 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.

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, 2022, Ameren Missouri’s coal-fired energy centers represented 9% and 17% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations under the Clean Air Act 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, as well as 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, capital expenditures associated with these modifications 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 compliance with 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 projects performed in 2007 and 2010 at the coal-fired Rush Island Energy Center 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 filed a motion in December 2021 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 March 31, 2024 compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. In July 2022, in response to an Ameren Missouri request for a final, binding reliability assessment, the MISO designated the Rush Island Energy Center as a system support resource and concluded that certain mitigation measures, including transmission upgrades, should occur before the energy center is retired. The transmission upgrade projects have been approved by the MISO, and design and procurement activities necessary to complete the upgrades are underway. Ameren Missouri expects to complete the upgrades by mid-2025. In October 2022, the FERC approved a system support resource agreement, which became effective retroactively as of September 1, 2022. The agreement details the manner of continued operation for a system support resource that results in operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. In September 2022, the Rush Island Energy Center began operating consistent with the system support resource agreement. In addition, in October 2022, the FERC established hearing and settlement procedures in response to an August 2022 request from Ameren Missouri for recovery of non-energy costs under the related MISO tariff. The FERC is under no deadline to issue an order related to this proceeding. Revenues and costs under the MISO tariff are expected to be included in the FAC. The district court has the authority to determine the

Table of Contents

retirement date and operating parameters for the Rush Island Energy Center and is not bound by the MISO determination of the Rush Island Energy Center as a system support resource or the FERC’s approval. The district court is under no deadline to issue a ruling modifying the remedy order. 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. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. 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 Missouri’s securitization statute. If the remaining unrecovered net plant balance for the Rush Island Energy Center and an associated return are not recoverable through base rates or other regulatory mechanisms, Ameren Missouri would recognize an abandonment loss equal to the difference between the remaining net book value of the asset and the present value of the expected future cash flows. As of December 31, 2022, the Rush Island Energy Center had a net plant balance of approximately $0.6 billion and a rate base of approximately $0.4 billion. 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.

In June 2022, the United States Supreme Court issued its decision in West Virginia v. EPA, clarifying that there are limits on how the EPA may regulate greenhouse gases absent further direction from the United States Congress. The court concluded that emission caps designed to shift generation from fossil-fuel-fired power plants to renewable energy facilities would require specific congressional authorization and that such authorization had not been given under the Clean Air Act. The decision by the United States Supreme Court may affect the EPA’s development of any new regulations to address CO2 emissions from coal- and natural gas-fired power plants; however, at this time, Ameren Missouri cannot predict the impact of any such regulations or the decision by the United States Supreme Court on the results of operations, financial position, and liquidity of Ameren or Ameren Missouri.

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 annual 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, resulting in the closure of the Venice Energy Center by 2029. The reductions could also limit the operations of Ameren Missouri's four natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. 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.

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. Federal, state, and local 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 a 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

Table of Contents

United States. In addition, the EPA 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 is targeting net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels. Ameren’s goals include both direct emissions from operations, as well as electricity usage at Ameren buildings, including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. 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; the ability to maintain system reliability during the transition to clean energy generation; and constructive energy and economic 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 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 regulatory compliance and proceedings, which could result in increasing costs, regulatory penalties, and/or 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 $1.5 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.

Additionally, pursuant to the IETL, Illinois utilities are subject to new requirements and provisions related to ethical conduct and transparency, including submitting an annual ethics and compliance report to the ICC. The law authorizes the ICC to initiate an investigation into how customer funds were used if ethical misconduct is determined to have occurred at an Illinois utility, potentially requiring the utility to issue refunds and imposing a potential penalty of up to $0.5 million per violation.

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 2022 Change to the 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 $20.5 billion (Ameren Missouri – up to $10.8 billion; Ameren Illinois – up to $9.5 billion; ATXI – up to $0.2 billion) of capital expenditures from 2023 through 2027. 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.

Table of Contents

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 or government actions; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects; 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 carbon emission reduction targets outlined in the 2022 Change to 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 battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to qualify for, and use or transfer, federal production or investment tax credits; changes in environmental laws or requirements, including those related to CO2 and other greenhouse gas emissions; and energy prices and demand. In addition, government investigations relating to the importation of solar panel components could affect the cost and the availability of solar panel components.

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;

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

•lack of adequate water required for cooling plant operations and to operate hydorelectric energy centers;

•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;

•disruptions to the global supply chain as a result of shortages for labor, materials, or equipment, international trade relations, delivery delays, economic pressures, including increased interest rates and inflation, and the impact of COVID-19, among other things;

•suppliers and contractors who do not perform as required under their contracts, including those obligations that are affected by supply chain disruptions;

•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, 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, which have increased in frequency and severity within the utility industry, acts of 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.

Table of Contents

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 97% 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 use 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, 2022, coal inventories at the Labadie and Sioux energy centers were below targeted levels due to transportation delays in 2022. Additional delays or 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;

•uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway Energy Center or 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;

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

•the ability to continue to attract and maintain qualified labor to operate the Callaway Energy Center;

•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 service businesses involve numerous risks that may result in accidents and increased operating costs.

Inherent in our natural gas distribution businesses, which includes transmission, distribution, and storage facilities, 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

Table of Contents

transmission and 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 facilities 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 and IETL 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, compounded by increasing interest rates and inflationary pressures, 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.

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. Under the IRA, a 15% minimum tax on adjusted financial statement income, as defined in the law, is assessed against corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years, effective for tax

Table of Contents

years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. As Ameren files a consolidated income tax return, it is reliant on its subsidiaries to pay the minimum tax once the threshold is exceeded. The payments related to the minimum tax by Ameren Missouri, Ameren Illinois, and ATXI are expected to be recovered, subject to approval by their respective regulators. 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 inflationary pressures related to prices of commodities, labor, services, materials and supplies, and other costs. We are uncertain whether these inflationary pressures will continue and at what rate. These inflationary pressures, as well as increasing interest rates, 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. In addition, these inflationary pressures and increasing interest rates could adversely affect our customers’ usage of, or payment for, our services. Additionally, volatility in the commodities market could increase collateral postings and prepayments. Also, market volatility could significantly affect the investment performance of Ameren’s COLI. Significant increases in our costs could increase our financing needs and otherwise adversely affect our results of operations, financial position, and liquidity. For additional information on purchased power costs, see Outlook under Part II, Item 7, of this report.

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 $377 million as of December 31, 2022. 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, 2022, its investment performance in 2022, and its pension funding policy, Ameren does not expect to make material contributions in 2023 through 2025, and expects to make aggregate contributions of $170 million in 2026 and 2027. Ameren Missouri and Ameren Illinois estimate that their portion of the future funding requirements will be 40% and 50%, respectively. 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.

GENERAL RISKS

Customers’, investors’, legislators’, regulators’, and creditors’ 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, regulators, and creditors could harm our reputation.

Our results are influenced by the expectations of our customers, investors, legislators, regulators, and creditors. 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 regulator and customer satisfaction.

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 2022 Change to the 2020 IRP, may affect customers’, investors’, legislators’, regulators’, and creditors’ 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’, regulators’, and creditors’ 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, regulators, or creditors 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

Table of Contents

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, 2022, approximately 25%, 25%, and 23% 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 47%, 59%, and 55% of Ameren’s, Ameren Missouri’s and Ameren Illinois’ total employees, respectively. The Ameren Missouri collective bargaining unit contracts expire in 2025 and 2026, which cover 4% and 96% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2023 and 2026, which cover 8% and 92% of represented employees, respectively. Remote working arrangements could increase our data security risks, including loss of data related to sensitive customer, employee, financial, and operating system information, through insider or outsider actions. 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 remote working arrangements, could adversely affect our operations.

Our operations are subject to acts of sabotage, 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 physical and cyber attacks, which could disrupt our ability to produce or distribute our energy products. In the industry, there continues to be attacks on energy infrastructure, such as substations and related assets. The threat landscape continues to expand, which may result in more attacks in the future. 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. Physical attacks could include sabotaging, vandalizing, or burglarizing transmission and distribution facilities, which are unmanned, widely dispersed, and often in isolated areas, or the theft of physical data and information. Cyber attacks could include viruses, malicious or destructive code, phishing attacks, denial of service attacks, supply chain attacks, ransomware and other extortion-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 of 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, availability of our services could be impacted, 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 physical or 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.

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. General economic factors beyond our control 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. These factors include depressed economic conditions, a recession,

Table of Contents

increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. 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.

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.

Table of Contents

The following table shows the anticipated capability of our energy centers at the time of the expected 2023 peak summer electrical demand for all energy centers owned as of December 31, 2022:

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

Ameren Missouri:

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

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

Hydroelectric Osage(f) Lakeside, Missouri 235,000

Pumped-storage Taum Sauk(f) 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 (CTs) Audrain(g) Audrain County, Missouri 608,000

Venice(h) Venice, Illinois 489,000

Goose Creek(h) Piatt County, Illinois 438,000

Pinckneyville(h) Pinckneyville, Illinois 316,000

Raccoon Creek(h) Clay County, Illinois 304,000

Kinmundy(h) Kinmundy, Illinois 210,000

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

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

Mexico(e) Mexico, Missouri 54,000

Moberly(e) Moberly, Missouri 54,000

Moreau(e) Jefferson City, Missouri 54,000

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

Solar Montgomery County Montgomery County, Missouri 5,700

O’Fallon O’Fallon, Missouri 4,500

BJC St. Louis, Missouri 1,600

Cape Girardeau Cape Girardeau, Missouri 1,200

Lambert St. Louis County, Missouri 900

South St. Louis St. Louis, Missouri 200

Ameren Illinois:

Solar East St. Louis East St. Louis, Illinois 2,500

(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 is scheduled to retire by 2025 as noted in the 2022 Change to 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)As noted in the 2022 Change to the 2020 IRP, Ameren Missouri has requested to extend the retirement date of the Sioux Energy Center from 2028 to 2030, which is subject to the approval of a change in the asset’s depreciable life by the MoPSC in Ameren Missouri’s 2022 electric service regulatory rate review. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on Ameren Missouri’s request to extend the retirement date of the Sioux Energy Center.

(e)The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to be retired by 2026 as noted in the 2020 IRP.

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

(g)There were economic development arrangements applicable to these CTs, as discussed below.

(h)The Venice Energy Center is scheduled to retire by 2029 and the Goose Creek, Pinckneyville, Raccoon Creek, and Kinmundy energy centers are scheduled to retire by 2040 as noted in the 2022 Change to the 2020 IRP. See Illinois Emissions Standards in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

Table of Contents

The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2022:

AmerenMissouri AmerenIllinois

Circuit miles of electric transmission lines(a) 3,126 4,716

Circuit miles of electric distribution lines 33,846 45,972

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

Miles of natural gas transmission and distribution mains 3,509 18,680

Underground natural gas storage fields — 12

(a)ATXI owns 545 circuit miles of electric 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 as of January 31, 2023 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 and Atchison Renewable 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 respective mortgage bonds.

Ameren Missouri conveyed most of its Peno Creek CT Energy Center to the city of Bowling Green, Missouri through December 2022. Ameren Missouri had 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 was responsible for all operation and maintenance at the energy center. Ownership of the energy center transferred to Ameren Missouri in December 2022, at which time the property, plant, and equipment became 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 had 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 was responsible for all operation and maintenance at the energy center. While the agreement was scheduled to expire in December 2023, Ameren Missouri and Audrain County mutually agreed to terminate the agreement in January 2023. Ownership of the energy center was transferred to Ameren Missouri in January 2023, at which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information for both agreements associated with the Peno Creek CT and Audrain County CT energy centers.

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.

Table of Contents

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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, 2022, all their positions and offices held with the Ameren Companies as of February 21, 2023, and their tenures as officers, and their titles for at least the last five years.

AMEREN CORPORATION:

Name Age Positions Period

Warner L. Baxter 61 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.

Table of Contents

SUBSIDIARIES:

Name Age Positions Period

Mark C. Birk 58 Chairman and President; Ameren Missouri January 2022 – Present

Shawn E. Schukar 61 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.

(b)Leonard P. Singh served as Senior Vice President of Consolidated Edison Company of New York from December 2020 to June 2022 and as Vice President, Manhattan Electric Operations of Consolidated Edison Company of New York from June 2015 to December 2020.

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 arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor 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 officer or any director 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.

Table of Contents

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 37,798 on January 31, 2023. 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, 2022, to December 31, 2022.

Performance Graph

The following graph shows Ameren’s cumulative TSR during the five years ended December 31, 2022. 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, 2017, 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

Table of Contents

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 and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri’s subsidiaries were created for the ownership of renewable generation projects. Ameren Illinois has no subsidiaries. All tabular 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, 2020, including comparisons with the year ended December 31, 2021, is included in Item 7 of our Form 10-K for the year ended December 31, 2021, filed with the SEC on February 23, 2022.

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.

Table of Contents

OVERVIEW

Our core strategy is driven by the following three pillars, which allow us to capitalize on opportunities to benefit our customers, our shareholders, and the environment:

Segment Regulatory Framework

AmerenTransmission Formula ratemakingAllowed ROE of 10.52%

Key announcements, updates, and regulatory outcomes

In February 2023, 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 2023. 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 $9.9 billion over the five-year period from 2023 through 2027, with expenditures largely recoverable under the PISA and the RESRAM. Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

In August 2022, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $316 million. The electric rate increase request is based on a 10.2% ROE, a capital structure composed of 51.9% common equity, a rate base of $11.6 billion, and a test year ended March 31, 2022, with certain pro-forma adjustments expected through an anticipated true-up date of December 31, 2022. In January 2023, the MoPSC staff recommended an increase to Ameren Missouri's annual electric service revenues of $199 million based on a 9.59% ROE, a capital structure composed of 51.84% common equity, and a rate base as of June 30, 2022, of $10.5 billion. Ameren Missouri expects the MoPSC staff will update its rate base estimate through the anticipated true-up date of December 31, 2022. The MoPSC staff’s recommendation includes an adjustment to annual electric service revenues for estimated true-up items from June 30, 2022, to December 31, 2022, including the impacts of any investments made during that period. The MoPSC proceeding

Table of Contents

relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by June 2023 and new rates effective by July 2023. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.

Missouri Senate Bill 745 became effective on August 28, 2022. The law extended Ameren Missouri’s PISA election through December 2028 and allows for an additional extension through December 2033 if requested by Ameren Missouri and approved by the MoPSC, among other things. The law established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024, and will be based on the revenue requirement established in the immediately preceding rate order. The current rate limitation, which is effective through 2023, is a 2.85% cap on the 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. The law also established electric and natural gas property tax trackers that allow Ameren Missouri to defer the difference between actual property taxes incurred and related taxes included in customer rates as a regulatory asset or regulatory liability, with the difference expected to be reflected in rate base in a subsequent rate order. Upon the effective date of the law, Ameren Missouri began deferring amounts under these trackers. In the 2022 electric service regulatory rate review discussed above, Ameren Missouri requested recovery of the amounts deferred under the electric property tax tracker.

In February 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, the Boomtown Solar Project, a 150-MW solar generation facility, which is expected to be located in southeastern Illinois, support Ameren Missouri’s transition to renewable energy generation, and serve customers under the Renewable Solutions Program, if approved by the MoPSC. In December 2022, the MoPSC staff filed a recommendation that the MoPSC should not approve Ameren Missouri’s July 2022 request for a certificate of convenience and necessity for the facility, arguing Ameren Missouri did not adequately demonstrate the facility is needed to continue providing service to customers. Ameren Missouri expects a decision by the MoPSC by April 2023. In June 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, the Huck Finn Solar Project, a 200-MW solar generation facility, which is expected to be located in central Missouri and support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of retail sales from renewable energy sources, of which 2% must be derived from solar energy sources. In February 2023, the MoPSC issued an order approving a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the Huck Finn Solar Project. Both acquisitions are aligned with the 2022 Change to the 2020 IRP, and are subject to certain conditions, including the issuance of certificates of convenience and necessity by the MoPSC for the Boomtown Solar Project and approval by the FERC for both acquisitions. Depending on the timing of regulatory approvals and the impact of potential sourcing issues, the facilities could be completed as early as the fourth quarter of 2024.

In December 2021, Ameren Missouri filed a motion with the United States District Court for the Eastern District of Missouri to modify a September 2019 remedy order issued by the district court 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 March 31, 2024 compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. Transmission upgrade projects to mitigate reliability concerns have been approved by the MISO and are expected to be completed by spring of 2025. In September 2022, the Rush Island Energy Center began operating consistent with a system support resource agreement approved by the FERC in October 2022. The district court has the authority to determine the retirement date and operating parameters for the Rush Island Energy Center. The district court is under no deadline to issue a ruling modifying the remedy order. 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. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. 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 Missouri’s securitization statute.See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.

Table of Contents

In January 2023, Ameren Illinois filed an MYRP with the ICC to be used in setting electric distribution service rates for 2024 through 2027. Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of the four-year period. The following table includes the forecasted revenue requirement, the requested ROE, the requested capital structure common equity percentage, and the forecasted average annual rate base for 2024 through 2027, as reflected in Ameren Illinois’ MYRP:

(a)A capital structure of up to and including 50% common equity is deemed prudent and reasonable by law. A higher equity ratio requires specific ICC approval.

Under an MYRP, the IETL permits any initial rate increase to be phased in, with at least 50% of the first annual period’s approved rate increase reflected in rates in the first annual period, with the remaining portion deferred as a regulatory asset that earns a return at the applicable WACC and is collected from customers over a period not to exceed two years beginning within one year after the second annual period’s rates are effective. Ameren Illinois’ MYRP filing utilizes this phase-in provision and proposes to defer 50% of the requested 2024 rate increase of $175 million as a regulatory asset to be collected from customers in 2026. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.

In September 2022, the ICC issued an order approving total ROE incentives and penalties under an MYRP of 24 basis points, allocated among seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics and the ROE incentives and penalties will apply annually from 2024 through 2027 under the MYRP filed by Ameren Illinois.

In December 2022, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $61 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2023. This order reflected an increase to the annual performance-based formula rate based on 2021 actual recoverable costs and expected net plant additions for 2022, an increase to include the 2021 revenue requirement reconciliation adjustment including a capital structure composed of 50% common equity, and a decrease for the conclusion of the 2020 revenue requirement reconciliation adjustment, which was fully collected from customers in 2022, consistent with the ICC’s December 2021 annual update filing order.

In December 2022, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $76 million beginning in January 2023, which represents an increase of $15 million from 2022 rates.

In June 2022, the ICC issued an order approving Ameren Illinois’ revised energy-efficiency plan that includes annual investments in electric energy-efficiency programs of approximately $120 million per year through 2025, which reflects the increased level of annual investments allowed under the IETL. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future 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 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Construction on the Ameren projects is expected to begin in 2025, with completion dates expected near the end of this decade. The MISO initiated requests for proposals in December 2022, and is expected to initiate additional requests for proposals in March and July 2023, for additional first tranche projects crossing Missouri, with total cost estimated by the MISO of approximately $0.7 billion, which are expected to be awarded between late-2023 and mid-2024. In November 2022, the MISO released plans for a second tranche of projects and began the process of identifying a list of projects for consideration under this tranche. Ameren expects the second tranche of projects to be approved in the first half of 2024. In July 2022, a group of industrial customers filed a complaint with the FERC, challenging provisions of a MISO tariff that exclude regional transmission projects from the MISO’s competitive bid process based on state laws related to the right of first refusal, which provide an incumbent utility the right to build, maintain, and own transmission lines located within its service territory. The complaint seeks to require MISO to revise its tariff to prohibit the application of state laws related to the right of first refusal in the MISO’s long-range transmission planning and require projects to be bid on a competitive basis, to the maximum extent possible. It also is asking for refunds related to any

Table of Contents

costs under the tariff that would not comply with the sought-after revisions. The FERC is under no deadline to issue an order in this proceeding.

The IRA was enacted in August 2022. The law extends federal production and investment tax credits for projects beginning construction through 2024 and creates new federal production and investment tax credits for projects placed in service after 2024, among other things. The federal production and investment tax credits will support Ameren’s net-zero carbon emission goals and Ameren Missouri’s 2022 Change to the 2020 IRP, incentivize electrification, and enhance customer affordability during Ameren’s transition to clean energy. In addition, the new law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, assessed against corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years, effective for tax years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information.

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. In February 2023, Ameren’s board of directors increased the quarterly common stock dividend to 63 cents per share, resulting in an annualized equivalent dividend rate of $2.52 per share.

Earnings

Net income attributable to Ameren common shareholders was $1,074 million, or $4.14 per diluted share, for 2022, and $990 million, or $3.84 per diluted share, for 2021. Net income was favorably affected in 2022, compared with 2021, by increased infrastructure investments across all business segments and a higher recognized ROE at Ameren Illinois Electric Distribution, increased retail electric sales volumes at Ameren Missouri, primarily resulting from colder winter and warmer summer temperatures experienced in 2022, and increased base rate revenues at Ameren Missouri pursuant to the December 2021 MoPSC electric rate order. Net income was unfavorably affected in 2022, compared with 2021, by increased other operations and maintenance expenses not subject to formula rates, riders, or trackers, primarily due to an increase due to the expiration of contracts relating to refined coal tax credits at Ameren Missouri in 2021, a reduction in the cash surrender value of COLI, and increased Callaway Energy Center costs. Earnings in 2022, compared with 2021, were also unfavorably affected by increased financing costs from debt issuances and higher interest on short-term borrowings.

Liquidity

At December 31, 2022, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.5 billion.

Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. As of December 31, 2022, Ameren had approximately $1 billion of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2022. For information regarding long-term debt issuances and maturities, common stock issuances, and outstanding forward sale agreements entered into under the ATM program through the date of this report, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.

Table of Contents

Ameren remains focused on strategic capital allocation. The following chart presents 2022 capital expenditures by segment and the midpoint of projected cumulative capital expenditures for 2023 through 2027 by segment:

Ameren Missouri(a) Ameren Illinois Natural Gas

Ameren Illinois Electric Distribution Ameren Transmission

(a)Ameren Missouri’s projected capital expenditures for 2023 through 2027 includes approximately $0.7 billion of capital expenditures related to coal-fired generation.

For 2023 through 2027, Ameren’s cumulative capital expenditures are projected to range from $18.9 billion to $20.5 billion. The following table presents the range of projected spending by segment:

Range (in billions)

Ameren Missouri(a) $ 10.0 – $ 10.8

Ameren Illinois Electric Distribution 3.5 – 3.8

Ameren Illinois Natural Gas 1.8 – 2.0

Ameren Transmission(b) 3.6 – 3.9

(a)Amount includes $2.5 billion of renewable generation investments through 2027 consistent with investments outlined in Ameren Missouri’s 2022 Change to the 2020 IRP.

(b)Amount includes $0.8 billion of capital expenditures through 2027 related to projects assigned to Ameren pursuant to the first tranche of projects under the MISO’s long-range transmission planning roadmap.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, 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, our pension and postretirement benefits costs, the cash surrender value of COLI, and the asset value of Ameren Missouri’s nuclear decommissioning trust fund. Almost all of Ameren’s 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.

Table of Contents

Due to a change in customer behavior and certain business practices resulting from the COVID-19 pandemic, there has been a shift in sales volumes by customer class from pre-pandemic levels at both Ameren Missouri and Ameren Illinois, which began in 2020, with an increase in residential sales, and a decrease in commercial and industrial sales. While our electric sales volumes in 2022, excluding the estimated effects of weather and customer energy-efficiency programs, were comparable to 2021 and, at Ameren Missouri, were comparable to pre-pandemic levels, Ameren Illinois’ sales volumes remain below pre-pandemic levels. However, 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. While our customers are also observing inflationary pressures, those pressures have not significantly affected customer payments. As of December 31, 2022, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 17%, 14%, and 20%, or $107 million, $35 million, and $71 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. In comparison, as of December 31, 2021, these percentages were 20%, 17%, and 24%, or $94 million, $34 million, and $60 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. 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.

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, 2022 and 2021:

Net income attributable to Ameren common shareholders $ 1,074 $ 990

Earnings per common share – diluted 4.14 3.84

Net income attributable to Ameren common shareholders in 2022 increased $84 million, or $0.30 per diluted share, from 2021. The increase was due to net income increases of $44 million, $37 million, $33 million, and $15 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 $45 million.

Earnings per share in 2022, compared with 2021, were favorably affected by:

•increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE due to a higher annual average of the monthly yields of the 30-year United States Treasury bonds at Ameren Illinois Electric Distribution, which increased revenues at these segments (23 cents per share);

•increased electric retail sales at Ameren Missouri, primarily resulting from colder winter temperatures and warmer summer temperatures experienced in 2022 (estimated at 13 cents per share);

•higher base rate revenues at Ameren Missouri pursuant to the December 2021 MoPSC electric rate order, partially offset by the amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a higher base level of expenses, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (10 cents per share);

•increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP and higher base rates, pursuant to the ICC’s January 2021 natural gas rate order (7 cents per share);

•increased base rate revenues at Ameren Missouri for the inclusion of previously deferred interest charges pursuant to the December 2021 MoPSC electric rate order, partially offset by lower deferral of interest charges related to infrastructure investments associated with the PISA and RESRAM (6 cents per share);

•increased electric retail sales at Ameren Missouri, excluding the estimated effects of weather, primarily due to increased sales volumes for commercial and residential customers (5 cents per share);

Table of Contents

•a change in the method of earning MEEIA performance incentives from metrics-based to spend-based, which resulted in an increased level of MEEIA performance incentives due to the recognition of incentives from two program years in 2022, compared with one program year in 2021 (4 cents per share);

•increased Ameren Missouri margins resulting from increased electric demand and customer charges, higher base rates pursuant to the December 2021 MoPSC natural gas rate order, and increased electric transmission service revenues (3 cents per share);

•increased other income, net, primarily due to increased non-service cost components of net periodic benefit income not subject to formula rates or trackers largely due to a decrease in net actuarial losses (3 cents per share); and

•the absence in 2022 of the FERC’s March 2021 order, primarily related to the historical recovery of materials and supplies inventories, which decreased Ameren Transmission revenues in 2021 (3 cents per share).

Earnings per share in 2022, compared with 2021, were unfavorably affected by:

•increased other operations and maintenance expenses not subject to formula rates, riders, or trackers, primarily due to the expiration of contracts relating to refined coal tax credits at Ameren Missouri in 2021, a reduction in the cash surrender value of COLI, and increased Callaway Energy Center costs (26 cents per share);

•increased financing costs, primarily at Ameren Missouri and Ameren (parent), primarily due to higher long-term debt balances and higher interest rates on short-term borrowings (13 cents per share);

•decreased other income, net, from lower earnings on equity method investments to advance clean and resilient energy technologies and increased charitable donations, primarily at Ameren (parent) (8 cents per share); and

•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 (3 cents per share).

The cents per share information presented is based on the weighted-average basic shares outstanding in 2021 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 2022 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.

Table of Contents

Below is Ameren’s table of income statement components by segment for the years ended December 31, 2022 and 2021:

Natural gas purchased for resale (104) — (553) — — (657)

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

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

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

Table of Contents

Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2022 and 2021:

Natural gas purchased for resale — (553) — — (553)

Natural gas margins — 627 — — 627

Other operations and maintenance expenses (580) (253) (49) — (882)

Depreciation and amortization (332) (98) (84) — (514)

Taxes other than income taxes (75) (82) (4) — (161)

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

Net income attributable to common shareholder $ 202 $ 123 $ 188 $ — $ 513

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

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.

Table of Contents

Electric Margins

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $451 Million

(a)Includes other/intersegment eliminations of $(25) million and $(29) million in 2022and 2021, respectively.

Natural Gas Margins

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $64 Million

(a)Includes other/intersegment eliminations of $(1) million and $(1) million in 2022and 2021, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Table of Contents

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2022, compared with 2021:

Electric and Natural Gas Margins

Electric revenue change:

Base rates (estimate)(b) $ 202 $ 87 $ — $ 53 $ — $ 342

Effect of weather (estimate)(c) 53 — — — — 53

MEEIA 2019 performance incentives 13 — — — — 13

Off-system sales, capacity, and FAC revenues, net 315 — — — — 315

Transmission service 3 — — — — 3

Demand and customer charges 4 — — — — 4

Other cost recovery mechanisms(e) 34 (3) — — — 31

Fuel and purchased power change:

Effect of weather (estimate)(c) (10) — — — — (10)

Effect of higher net energy costs included in base rates (10) — — — — (10)

Other (4) — — — — (4)

Cost recovery mechanisms – offset in electric revenue(d) 2 (518) — — 27 (489)

Total fuel and purchased power change $ (342) $ (518) $ — $ — $ 27 $ (833)

Net change in electric margins $ 295 $ 99 $ — $ 53 $ 4 $ 451

Natural gas revenue change:

Base rates (estimate) $ 3 $ — $ 4 $ — $ — $ 7

Effect of weather (estimate)(c) 12 — — — — 12

Change in rate design — — 1 — — 1

QIP rider — — 26 — — 26

Other 2 — 3 — — 5

Other cost recovery mechanisms(e) 3 — 18 — — 21

Total natural gas revenue change $ 56 $ — $ 223 $ — $ — $ 279

Natural gas purchased for resale change:

Effect of weather (estimate)(c) $ (8) $ — $ — $ — $ — $ (8)

Total natural gas purchased for resale change $ (44) $ — $ (171) $ — $ — $ (215)

Net change in natural gas margins $ 12 $ — $ 52 $ — $ — $ 64

(a)Includes an increase in transmission electric margins of $59 million in 2022, compared with 2021, at Ameren Illinois.

(b)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 for the recovery of lost electric margins resulting from the MEEIA customer energy-efficiency programs and a decrease in base rates for RESRAM. These changes in Ameren Missouri base rates are included in the “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” and “Cost recovery mechanisms - offset in fuel and purchased power” line items, respectively.

(c)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.

(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.

Table of Contents

Ameren

Ameren’s electric margins increased $451 million, or 11%, in 2022, compared with 2021, because of increased margins at Ameren Missouri, Ameren Illinois Electric Distribution, and Ameren Transmission, as discussed below. Ameren’s natural gas margins increased $64 million, or 10%, between years primarily because of increased margins at Ameren Illinois Natural Gas and Ameren Missouri, as discussed below.

Ameren Transmission

Ameren Transmission’s margins increased $53 million, or 9%, in 2022, compared with 2021. Base rate revenues were favorably affected by increased capital investment (+$23 million), as evidenced by a 10% increase in rate base used to calculate the revenue requirement, higher recoverable expenses (+$19 million), the absence in 2022 of the FERC’s March 2021 order (+$7 million), and a higher equity percentage in the capital structure at Ameren Illinois (+$4 million). 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 March 2021 FERC order.

Ameren Missouri

Ameren Missouri’s electric margins increased $295 million, or 12%, in 2022, compared with 2021. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” were comparable to 2021, with a decrease of $2 million in 2022, due to changes in amortization of costs previously deferred under the FAC that were reflected in customer rates. 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 cost variances under the FAC is reflected within “Off-system sales, capacity, and FAC revenues, net” and “Energy costs (excluding the estimated effect of weather)”.

The following items had a favorable effect on Ameren Missouri’s electric margins in 2022, compared with 2021:

•The December 2021 MoPSC electric rate order effective February 28, 2022, resulted in higher electric base rates, excluding the change in base rates for the MEEIA customer energy-efficiency programs and the RESRAM, partially offset by higher net energy costs included in base rates, increased margins $192 million. The change in electric base rates is the sum of the change in “Base rates (estimate)” (+$202 million) and the “Effect of higher net energy costs included in base rates” (-$10 million) in the table above.

•Summer temperatures were warmer as cooling degree days increased 3% through September, and winter temperatures were colder as heating degree days increased 11%. The aggregate effect of weather increased margins by an estimated $43 million. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (+$53 million) and the “Effect of weather (estimate)” on fuel and purchased power (-$10 million) in the table above.

•Other cost recovery mechanisms increased margins $34 million due to increased RESRAM revenues (+$38 million), primarily resulting from a lower deferral of revenues due to inclusion of production tax credits in base rates pursuant to the December 2021 electric rate order and increased excise taxes (+$9 million), partially offset by a decrease in recoverable MEEIA program costs (-$13 million).

•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues increased an estimated $17 million. The increase was primarily due to an increase in commercial and residential sales volumes and an increase in the average retail price per kilowatthour due to changes in customer usage patterns.

•The MEEIA 2019 performance incentives increased revenues $13 million due to a change in the method of earning MEEIA performance incentives from metrics-based to spend-based, resulting in the recognition in 2022 of performance incentives for program years 2021 and 2022, compared with recognition in 2021 of the performance incentive for program year 2020.

•Demand and customer charges increased revenues $4 million due to higher revenues from commercial customer demand charges and increased residential and commercial customer counts.

•Transmission service revenues increased $3 million, primarily due to increased volumes.

Ameren Missouri’s electric margins decreased $5 million due to its 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” (+$315 million) and “Energy costs (excluding the estimated effect of weather)” (-$320 million) in the table above. Net energy costs were higher than those reflected in base rates, primarily because of higher purchased power costs due to higher energy prices in 2022, compared with 2021. Higher purchased power costs were partially offset by a favorable net impact of capacity revenues and costs.Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. Capacity revenues and costs increased as the capacity price set by the annual MISO auction in 2022 increased from $5 per MW-day to $237 per MW-day. The April 2021 MISO auction pricing was effective from June 2021 through May 2022, while the April 2022 MISO auction pricing established the annual rate beginning in June 2022. In 2022, compared with 2021, increased capacity revenues of $367 million are reflected in “Off-system sales, capacity and FAC revenues, net” and increased capacity costs of $355 million are reflected in “Energy costs (excluding the estimated effect of weather)” in the table above. See Outlook for additional information related to the April 2022 MISO auction.

Table of Contents

Ameren Missouri’s natural gas margins increased $12 million, or 15%, in 2022, compared with 2021.Purchased gas costs increased $36 million in 2022, compared with 2021, due to 2022 amortization of natural gas costs previously deferred under the PGA, driven by a significant increase in cost and customer demand as result of the extremely cold weather in mid-February 2021.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 Missouri’s natural gas margins in 2022, compared with 2021:

•Revenues increased $4 million due to colder winter temperatures as heating degree days increased 11%. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on natural gas revenues (+$12 million) and the “Effect of weather (estimate)” on natural gas purchased for resale (-$8 million) in the table above.

•Revenues increased $3 million due to higher base rates as a result of the December 2021 MoPSC natural gas rate order effective February 28, 2022.

•Other cost recovery mechanisms increased revenues $3 million due to increased revenues for excise taxes.

Ameren Illinois

Ameren Illinois’ electric margins increased $158 million, or 10%, in 2022, compared with 2021, driven by increased margins at Ameren Illinois Electric Distribution and Ameren Illinois Transmission. Ameren Illinois Natural Gas’ margins increased $52 million, or 9%, between years.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $99 million, or 8%, in 2022, compared with 2021. Purchased power costs increased $518 million in 2022, compared with 2021, primarily due to increased energy prices (+$260 million), which largely reflect the results of IPA procurement events, and higher volumes (+$131 million), primarily due to residential and small commercial customer switching from alternative retail electric suppliers to Ameren Illinois’ supplied power. In addition to higher energy prices and volumes, purchased power costs increased due to higher capacity prices (+$91 million). In 2022, capacity revenues and costs increased as the capacity price set by the annual MISO auction in April 2022 increased from $5 per MW-day to $237 per MW-day. The April 2021 MISO auction pricing was effective from June 2021 through May 2022, while the April 2022 MISO auction pricing established the annual rate beginning in June 2022. See Outlook for additional information related to the April 2022 MISO auction. 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 2022, compared with 2021:

•Base rates increased due to higher recoverable non-purchased power expenses (+$67 million), a higher recognized ROE (+$21 million), as evidenced by an increase of 106 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, and increased capital investment (+$8 million), as evidenced by a 6% increase in year-end rate base, partially offset by the results from 2020 and 2021 revenue requirement reconciliation adjustment true-ups recognized in the following respective year (-$9 million). The sum of these changes collectively increased margins $87 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 $52 million, or 9%, in 2022, compared with 2021. Purchased gas costs increased $171 million in 2022, compared with 2021, due to 2022 amortization of natural gas costs previously deferred under the PGA, driven by a significant increase in cost and customer demand as a result of the extremely cold weather in mid-February 2021. 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 2022, compared with 2021:

•Revenues increased $26 million due to additional investment in natural gas infrastructure under the QIP.

•Other cost recovery mechanisms increased revenues $18 million, primarily due to increased revenues for excise taxes and various other riders.

Table of Contents

•Revenues increased $4 million due to higher base rates, primarily as a result of the January 2021 natural gas rate order.

Ameren Illinois Transmission

Ameren Illinois Transmission’s electric margins increased $59 million, or 16%, in 2022, compared with 2021. Base rate revenues were favorably affected by increased capital investment (+$25 million), as evidenced by a 16% increase in rate base used to calculate the revenue requirement, higher recoverable expenses (+$23 million), the absence in 2022 of the FERC’s March 2021 order (+$7 million), and a higher equity percentage in the capital structure (+$4 million). 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 March 2021 FERC order.

Other Operations and Maintenance Expenses

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

Overall Ameren Increase of $163 Million

(a)Includes $60 million and $62 million at Ameren Transmission in 2022 and 2021, respectively, and other/intersegment eliminations of $16 million and $(6) million in 2022and 2021, 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 $163 million in 2022, compared with 2021. In addition to changes by segment as discussed below, other operations and maintenance expenses increased $22 million in 2022 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of an increase in the elimination of the non-service cost component of net periodic benefit income at Ameren Services. The non-service cost component of net periodic benefit cost or income at Ameren Services is allocated to the segments and primarily included in the segments’ other operations and maintenance expenses.

Ameren Transmission

Other operations and maintenance expenses were comparable between periods.

Table of Contents

Ameren Missouri

The $80 million increase in Ameren Missouri’s other operations and maintenance expenses in 2022, compared with 2021, was primarily due to the following items:

•The absence in 2022 of $21 million in service fees received under refined coal production agreements, as the result of the expiration of refined coal tax credits at the end of 2021, which was reflected in electric service rates pursuant to the December 2021 MoPSC rate order.

•Labor and benefit costs increased $20 million, largely because of a higher base level of pension service costs reflected in electric service rates pursuant to the December 2021 MoPSC rate order.

•The cash surrender value of COLI decreased $20 million, primarily because of unfavorable market returns in 2022. In 2022, the effect of changes in the cash surrender value of COLI was a loss of $14 million, compared with a gain of $6 million in 2021.

•Callaway Energy Center costs increased $10 million, primarily because of the amortization of increased costs related to the spring 2022 refueling and maintenance outage and other non-outage related costs.

•The absence of a $5 million deferral to a regulatory asset of certain costs previously incurred to the COVID-19 pandemic, pursuant to MoPSC orders from March 2021, which decreased other operations and maintenance expenses in 2021.

•Technology-related expenditures increased $5 million, primarily because of costs associated with digital enablement projects and software licensing costs.

•Costs related to the wind energy centers increased $5 million, which are recovered under the RESRAM.

•Customer billing costs increased $4 million, primarily because credit card fees charged to customers were discontinued in March 2022 pursuant to the December 2021 MoPSC rate order, which incorporated an amount of such fees in electric service rates.

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

•MEEIA customer energy-efficiency program spend decreased $13 million, as approved by the MoPSC.

•Non-nuclear and non-wind energy center maintenance costs decreased $6 million, primarily because of reduced energy center maintenance outages and lower maintenance expenditures related to reduced operations at the Meramec and Rush Island energy centers.

Ameren Illinois

Other operations and maintenance expenses increased $62 million at Ameren Illinois in 2022, compared with 2021, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2022 and 2021.

Ameren Illinois Electric Distribution

The $46 million increase in Ameren Illinois Electric Distribution’s other operations and maintenance expenses in 2022, compared with 2021, was primarily due to the following items:

•Distribution system expenditures increased $15 million, primarily because of projects deferred to 2022 as a result of 2021 storm restoration efforts for which the associated costs were deferred as a regulatory asset in 2021.

•The cash surrender value of COLI decreased $10 million, primarily because of unfavorable market returns in 2022, compared with favorable market returns in 2021.

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

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

•Injuries and damages increased $6 million, primarily because of an increase in claims compared with 2021.

•Technology-related expenditures increased $4 million, primarily because of costs associated with digital enablement projects and software licensing costs.

The above increases were partially offset by a $4 million reduction in environmental remediation rider costs, primarily resulting from fewer remediation projects.

Ameren Illinois Natural Gas

Other operations and maintenance expenses at Ameren Illinois Natural Gas increased $17 million in 2022, compared with 2021, primarily because of the following items:

•The cash surrender value of COLI decreased $5 million, primarily because of unfavorable market returns in 2022, compared with favorable market returns in 2021. The effect of COLI was a loss of $4 million, compared with a gain of $1 million in 2021.

Table of Contents

•Increase of $5 million in costs recovered under various riders.

•Distribution system expenditures increased $4 million, primarily related to higher contractor service costs.

Depreciation and Amortization

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $143 Million

(a)Includes other/intersegment eliminations of $4 million and $4 million in 2022 and 2021, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

The $143 million, $100 million, and $42 million increases in depreciation and amortization expenses in 2022, compared with 2021, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, were primarily due to additional property, plant, and equipment across their respective segments. Ameren’s and Ameren Missouri’s depreciation and amortization expenses were affected by the following, which include the effect of the additional investments in property, plant, and equipment:

•Depreciation and amortization rate changes pursuant to the December 2021 MoPSC electric rate order, which increased depreciation and amortization expenses by $57 million.

•Increased depreciation and amortization expenses of $57 million for amounts previously deferred under the PISA and RESRAM and subsequently reflected in base rates pursuant to the December 2021 MoPSC electric rate order, largely due to investments in wind generation.

•Fewer deferrals of depreciation and amortization of expenses of $50 million due to less property, plant, and equipment eligible for recovery under the PISA and RESRAM as a result of the December 2021 MoPSC electric rate order.

•The net deferral related to the Meramec Energy Center retirement, which decreased depreciation and amortization by $51 million, pursuant to the December 2021 MoPSC electric rate order, which established a five-year recovery period for certain Meramec Energy Center costs.

•The deferral of RESRAM eligible expenses decreased depreciation and amortization expenses by $10 million.

Table of Contents

Taxes Other Than Income Taxes

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

Overall Ameren Increase of $27 Million

(a)Includes $9 million and $8 million at Ameren Transmission in 2022 and 2021, respectively, and other/intersegment eliminations of $10 million and $12 million in 2022and2021, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Taxes other than income taxes increased $27 million at Ameren in 2022, compared with 2021, primarily because of $12 million and $8 million increases in excise taxes at Ameren Missouri and Ameren Illinois Natural Gas, respectively, mostly due to higher base rates at Ameren Missouri, pursuant to the December 2021 MoPSC electric rate order, and increased sales at both segments. Taxes other than income taxes also increased $8 million at Ameren Missouri because of increased property taxes, primarily resulting from higher assessed values, that were incurred prior to the implementation of the electric and natural gas property tax trackers beginning in August 2022.

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

Table of Contents

Other Income, Net

Total by Segment Increase (Decrease) by Segment

Overall Ameren Increase of $24 Million

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Other income, net, increased $24 million at Ameren in 2022, compared with 2021, primarily because of increases in the non-service cost component net periodic benefit income of $19 million, $19 million, and $8 million for Ameren Illinois Electric Distribution, activity not reported as part of a segment, and Ameren Illinois Natural Gas, respectively, largely due to a decrease in net actuarial losses. These increases in other income, net, were partially offset by a $15 million increase in charitable contributions and a $10 million decrease in income from equity method investments, primarily associated with investments to advance clean and resilient energy technologies, both for activity not reported as part of a segment.

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.

Table of Contents

Interest Charges

Total by Segment Increase by Segment

Overall Ameren Increase of $103 Million

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Interest charges increased $103 million in 2022, compared with 2021, primarily because of the following items:

•Interest charges at Ameren and Ameren Missouri reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM. The amount of interest charges included in base rates for PISA and RESRAM was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order. Lower deferrals, due to the inclusion in base rates of interest associated with certain property, plant, and equipment previously deferred under the PISA and RESRAM increased interest charges by $49 million.

•Issuances of long-term debt at Ameren Missouri in June 2021 and April 2022 increased interest charges by $21 million.

•Interest charges at Ameren (parent) and Ameren Missouri increased $11 million and $4 million, respectively, because of higher interest rates on short-term borrowings.

•Issuances of long-term debt at Ameren (parent) in March 2021 and November 2021 increased interest charges by $10 million.

Table of Contents

Income Taxes

The following table presents effective income tax rates for the years ended December 31, 2022and 2021:

Ameren Missouri (2)% 1%

Ameren Illinois 26% 25%

Ameren Illinois Electric Distribution 25% 24%

Ameren Illinois Natural Gas 27% 27%

Ameren Illinois Transmission 26% 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.

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 $2.3 billion, $1.0 billion, and, $1.3 billion, respectively, which include $1.1 billion, $0.4 billion, and, $0.7 billion, respectively, in 2023.

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 2027. Ameren expects these equity issuances to total about $100 million annually. In addition, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. During 2022, Ameren issued a total of 3.4 million shares of common stock and received aggregate proceeds of $292 million under the ATM program. As of January 31, 2023, Ameren had multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 3.4 million shares of common stock. As of December 31, 2022, Ameren could have settled the forward sale agreements with physical delivery of 3.2 million shares of common stock to the respective counterparties in exchange for cash of $295 million. Ameren expects to settle approximately $300 million of the forward sale agreements and issue 3.2 million shares of common stock by December 31, 2023. Also, Ameren plans to issue approximately $500 million of equity each year from 2024 to 2027 in addition to issuances under the DRPlus and employee benefit plans. As of December 31, 2022, Ameren had approximately $1 billion of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2022. Ameren expects its equity to total capitalization to be about 45% through December 31, 2027, 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, including the forward sale agreements under the ATM program relating to common stock.

AEE US Equity

AEE · 10-K · period ended 2022-12-31

ITEM 1A.RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2.PROPERTIES

ITEM 3.LEGAL PROCEEDINGS

ITEM 4.MINE SAFETY DISCLOSURES

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

ITEM 6.(RESERVED)

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

AEE US Equity☆

AEE · 10-K · period ended 2022-12-31

ITEM 1A.RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2.PROPERTIES

ITEM 3.LEGAL PROCEEDINGS

ITEM 4.MINE SAFETY DISCLOSURES

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

ITEM 6.(RESERVED)

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

AEE US Equity