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ITEM 1A.RISK FACTORS

Investors should review carefully the following material risk factors and the other information contained in this report. The risks that the Ameren Companies face are not limited to those in this section. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect the results of operations, financial position, and liquidity of the Ameren Companies.

REGULATORY AND LEGISLATIVE RISKS

We are subject to extensive regulation of our businesses.

We are subject to federal, state, and local regulation. The extensive regulatory frameworks, some of which are more specifically identified in the following risk factors, regulate, among other matters, the electric and natural gas utility industries; the rate and cost structure of utilities, including an allowed ROE; the operation of nuclear power plants; the construction and operation of generation, transmission, and distribution facilities; the acquisition, disposal, depreciation and amortization of assets and facilities; the electric transmission system reliability; and wholesale and retail competition. In the planning and management of our operations, we must address the effects of existing and proposed laws and regulations and potential changes in our regulatory frameworks, including reinterpretation of such regulations, as well 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, and the current federal administration’s approach to United States energy policy and resultant changes in regulatory enforcement priorities, and/or evolving interpretations of existing regulatory requirements, could require changes to our business planning, strategy 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 at all, 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 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.

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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 based on historical costs, revenues, and sales volumes. Ameren Illinois’ natural gas rates established in those proceedings are based on estimated future costs, revenues, and sales volumes. Effective for rates in 2024 through at least 2027, Ameren Illinois’ electric distribution rates have been established through an MYRP as discussed in the following risk factor. An MYRP includes a 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 and to earn a return on investments, 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.

In addition, in June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by a wholly owned, special purpose subsidiary of Ameren Missouri to finance approximately $476 million of costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri will collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. The securitized tariff bonds were issued in December 2024. The financing order also included a determination that the decision to retire the Rush Island Energy Center was reasonable and prudent. The MoPSC did not make a determination regarding the prudency of Ameren Missouri's prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, however, claims regarding such actions could be considered in future regulatory proceedings. If future regulatory proceedings result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

In 2024 through at least 2027, electric distribution rates for Ameren Illinois are established through an MYRP, which are subject to ongoing regulatory and judicial proceedings and associated risks, and are subject to a reconciliation cap. Additionally, Ameren Illinois is subject to certain performance metrics that if not achieved would result in a reduction to the company’s allowed ROE.

The CEJA 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 or establish rates through a traditional regulatory rate review, among other things. An MYRP establishes 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 for rates effective in 2024 through 2027. Under the MYRP, Ameren Illinois is allowed to reconcile its actual electric distribution revenue requirement, as adjusted for certain cost variations, to the ICC-approved revenue requirement 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 are 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 outside of base rates through riders. The actual revenue requirement for a particular year incorporates Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the resulting revenue requirement does not exceed the 105% reconciliation cap and the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. Ameren Illinois’ existing riders continue to be effective under the MYRP. In addition, the ICC determines the ROE applicable to each year of the four-year period. Economic conditions could result in the annual predetermined ROE becoming inadequate over the four-year period. Ameren Illinois has filed an appeal of the ICC-determined ROE for 2024 through 2027 to the Illinois Appellate Court for the Fifth Judicial District. For additional information on the appeal see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. Failure to limit capital expenditures and operation and maintenance expenses to amounts that maintain revenue requirements under the reconciliation cap limit would adversely affect Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity.

Ameren Illinois’ electric distribution service business is also subject to performance metrics. Failure to achieve the metrics would result in a reduction in the company’s allowed ROE calculated under the MYRP. In 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points under the MYRP, 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

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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 apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, 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.

As a result of the election to use the PISA, 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.

Pursuant to a Missouri law, Ameren Missouri’s PISA election was extended through December 2028 and an additional extension through December 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things. This law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates, compared to the revenue requirement established in the immediately preceding rate order, due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation is effective for revenue requirements approved by the MoPSC after January 1, 2024. Increased capital expenditures could cause incremental PISA deferrals to exceed the 2.5% limitation, and such amounts exceeding the 2.5% limitation would be excluded from recovery under future revenue requirements. Failure to limit capital investments to an amount which maintains PISA deferrals 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, and 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 regulate air emissions; protect water bodies; manage the 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 energy-related 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, modifications to existing laws, new laws, new or modified permit terms, and enforcement of environmental laws and permits by federal, state, and local authorities.

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, individuals and non-governmental organizations may seek to enforce environmental laws against us, 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 purported 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 and natural gas-fired energy centers. As of December 31, 2024, Ameren Missouri’s coal-fired energy centers represented 6% and 11% of Ameren’s and Ameren Missouri’s rate base, respectively. Compliance obligations under the Clean Air Act include the NSPS, the MATS, emission allowance programs and the CSAPR, 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. Regulations implementing the Clean Water Act govern potential impacts from our operations on water bodies including wetlands subject to the Act, as well as evaluation of the ecological and biological impact of those operations. Implementation of the Clean Air Act and the Clean Water Act requirements typically occurs through the issuance of permits by state regulators or resource agencies, and capital expenditures associated with compliance could be significant. Coal-fired energy centers must comply with management and disposal requirements for coal ash under the Resource Conservation and Recovery Act and federal regulations known as the CCR Rule. Surface impoundments at Ameren Missouri’s coal-fired energy centers are subject to closure and groundwater monitoring requirements and the implementations of corrective measures if necessary. 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 April 2024, the EPA issued a final rule that sets CO2 emission standards for existing coal-fired and new natural gas-fired power plants based on the emissions expected from adoption of carbon capture technology and/or natural gas co-firing for coal-fired power plants and

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carbon capture technology for new natural gas-fired power plants. Affected power plants are required to comply with the rule through a phased-in approach or retire. Compliance with the new rule could be required as early as 2030 for certain existing coal-fired power plants and 2032 for certain new natural gas-fired power plants. In December 2024, the United States Court of Appeals for the District of Columbia Circuit heard arguments from various stakeholders including the EPA, environmental organizations, state attorney generals, and industry groups regarding the legal merits of the final rule. In February 2025, the EPA requested that the appellate court suspend the case for 60 days and not issue an opinion so the EPA can decide how to proceed. Ameren and Ameren Missouri estimate capital expenditures of approximately $580 million may be necessary to comply with the final rule assuming it is not revised or overturned. Ameren and Ameren Missouri are monitoring the legal challenges and assessing the impacts of the final rule and, at this time, cannot predict the final impacts on their results of operations, financial position, and liquidity.

Currently as required by the CEJA, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other 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 CEJA, 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 could 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 initiatives.

There is 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. Also, state and local authorities have proposed restrictions on the use of natural gas, and the ICC is conducting a future of gas proceeding to explore issues involved with decarbonization of the natural gas distribution system in the state of Illinois. Further, federal, state, and local authorities, including the United States Congress, have considered initiatives to further restrict greenhouse gases to address global climate change, and the EPA previously announced plans to implement new climate change programs, including regulation of greenhouse gas emissions from the utility industry. Additionally, international agreements have in the past, and could again, 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. In accordance with the new presidential administration’s approach to United States energy policy, in January 2025, the United States withdrew from the Paris Agreement. The current federal administration is expected to review, and has already revised, compliance requirements under a number of federal environmental regulatory programs; however, differences in energy policy priorities adopted by future federal administrations could result in additional greenhouse gas reduction requirements in the United States.

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 its remaining 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.

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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 in a safe, reliable, and affordable manner. Ameren’s goals include both reduction of direct emissions from operations (scope 1), as well as electricity usage at Ameren buildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. Achievement of these targets 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, the cost of those technologies, and support of such technologies by regulators; natural gas prices; new transmission infrastructure; the ability to maintain system reliability during and after 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 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 executive orders, regulations, or reinterpretations of existing 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 $1.6 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 be issued to customers for previously billed amounts, with interest.

Additionally, pursuant to the CEJA, Illinois utilities are subject to requirements and provisions related to ethical conduct, 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 a violation of the law is determined to have occurred at an Illinois utility, potentially requiring the utility to issue refunds and imposing a 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 and its 2025 Change to the 2023 PRP, 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 $27.4 billion (Ameren Missouri – up to $17.5 billion; Ameren Illinois – up to $7.0 billion; ATXI – up to $2.9 billion) of capital expenditures from 2025 through 2029. For additional information on these estimates, see Liquidity and Capital Resources – Capital Expenditures in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. Investments in Ameren’s rate-regulated operations are expected to be recoverable from customers, but they are subject to prudence reviews and are exposed to regulatory lag of varying degrees by jurisdiction.

Our ability to complete construction projects successfully within projected estimates, including schedule, performance, and/or cost, and to implement Ameren Missouri’s Smart Energy Plan, which may include acquisition of generation facilities after they are constructed, is contingent upon many factors and subject to substantial risks. These factors include, but are not limited to, the following: project management expertise; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment; escalating costs, including but not limited to changes to tariffs on materials or government actions; 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 connection agreements 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; geopolitical conflict and other events beyond our control, including delays arising from government shutdowns or construction delays due to weather.

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With respect to the transition of Ameren Missouri’s generation fleet that will be included in its 2025 Change to the 2023 PRP and carbon emission reduction targets, factors also include Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources, battery storage, or nuclear or natural gas-fired generation, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability to enter into agreements for renewable, natural gas-fired, or nuclear generation and acquire or construct that generation at a reasonable cost; the ability to obtain NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date; the continued existence and ability to qualify for, and use or transfer, federal production or investment tax credits; the cost of wind, solar, and other renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the cost of nuclear generation; the ability to maintain system reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; energy prices; and demand.

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

Our electric generation and electric and natural gas transmission and distribution facilities, including natural gas storage facilities, are subject to operational risks.

Our financial performance depends on the successful operation of electric generation and electric and natural gas transmission and distribution facilities, including natural gas storage facilities. Operation of these 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;

•natural gas leaks or explosions near populated areas, including residential areas, business centers, industrial sites, and other public gathering places;

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

•labor disputes;

•disruptions in the delivery of electricity and natural gas 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, as well as our ability to meet generation capacity obligations;

•disruptions to the global supply chain as a result of shortages for labor, materials, or equipment, tariffs and international trade relations, geopolitical conflict, delivery delays, and economic pressures, including elevated interest rates and inflation, 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 and natural gas systems and customers;

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

•handling, storage, and disposition of CCR;

•unusual or adverse weather conditions or other natural disasters, including but not limited to those that may result from climate change, such as severe storms, droughts, wildfires, 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, or other conditions limiting full capacity, such as the 2024 collapse of three turbines at the High Prairie Energy Center; pending the results of an ongoing investigation, approximately 90% of the turbines of the High Prairie Energy Center remain idle and the timing and costs necessary to return the energy center to full capacity are uncertain;

•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, 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 facilities, electric and natural gas transmission and distribution facilities, and natural gas storage 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.

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The foregoing risks could affect the operations of our facilities, impede our ability to meet regulatory requirements, or expose us to an increase in litigation, 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. As of December 31, 2024, coal inventory at the Labadie and Sioux energy centers were at targeted levels. 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 insurance 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 primarily 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 retain 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 and result in serious injury, loss of human life, significant damage to property, environmental impacts, and impairment of our operations, it would 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.

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. Both 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

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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. 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 subject to regulatory recovery risk. The frequency and duration of customer outages are among the CEJA 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 high 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.

Forecasted energy demand from potential new customers and electrification might not be realized. Energy conservation, energy efficiency, distributed generation, energy storage, technological advances, and other factors could reduce energy demand from our existing customers.

The Ameren Companies have experienced minimal growth in energy demand for the past two decades. Recent industry projections reflect the potential for significant growth in energy demand over the next decade, primarily arising from data centers to support artificial intelligence and further augmented by onshoring and electrification of manufacturing and an increase in transportation electrification. The Ameren Companies may or may not experience energy demand growth depending on the decisions of potential new customers about whether to locate their operations within our service territories. If new customers elect to locate operations within our service territories, the Ameren Companies may not be able to provide the necessary electric service within the time periods required by those customers. The Ameren Companies may need to accelerate new generation build within current plans, and construct or obtain new generation sources and expand transmission and distribution facilities that are not currently within their plans. The Ameren Companies may not be able to plan, receive regulatory approvals, and execute those plans in a timely manner. Future demand from these customers may not be realized at the current projected pace as a result of increased efficiency in computing, and these new customers may be transitory and exit our service territory. Significant uncertainty exists regarding future increases in energy demand within the Ameren Companies’ service territory, and whether and how the Ameren Companies will construct or obtain the assets necessary to timely serve that additional demand.

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 the subsidiaries’ 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 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

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Missouri, Ameren Illinois, and ATXI are expected to be recovered, subject to approval by their respective regulators. In addition, interpretations, regulations, amendments, or technical corrections that affect the amount and timing of income tax payments, credits available, or the transferability of production and investment tax credits could adversely affect our liquidity. 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 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. Higher than expected inflation levels could continue to put pressure on the prices of labor, services, materials and supplies, and other costs. Elevated inflation levels, as well as elevated interest rates, tariffs, trade wars, or a recession 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 various economic pressures 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.

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 $734 million as of December 31, 2024. 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, 2024, its investment performance in 2024, and its pension funding policy, Ameren does not expect to make material contributions in 2025 and expects to make aggregate contributions of $170 million in 2026 through 2029. 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’, creditors’, and rating agencies’ opinions of us are affected by many factors, including system safety and reliability, implementation of our strategic plan, protection of customer information, rates, media coverage, and company policies or practices, as well as actions by other utility companies. Negative opinions developed by customers, investors, legislators, regulators, creditors, and rating agencies could harm our reputation.

Our results are influenced by the expectations of our customers, investors, legislators, regulators, creditors and ratings agencies. 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 prevent, mitigate, or respond promptly to such failures can affect customer satisfaction or potentially subject us to litigation. In addition to system reliability issues, the success of modernization efforts, our ability to safeguard sensitive customer information and protect our systems from physical or 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 that will be included in its 2025 Change to the 2023 PRP, may affect customers’, investors’, legislators’, regulators’, creditors’, and rating agencies’ opinions and actions. Additionally, negative perceptions or publicity resulting from increasing scrutiny of company policies or practices could negatively impact our reputation, investment in our common stock, or our access to capital and credit markets. Customers’, investors’, legislators’, regulators’, creditors’, and rating agencies’ 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, creditors or rating agencies have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the ROEs we are allowed to earn, as well as the access to, and the cost of, capital. Additionally, negative opinions about us or other utility companies could make it more difficult for our businesses to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volume reductions or

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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 workforce 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, 2024, approximately 23% of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ total employees were 55 years old or older. We are also party to collective bargaining agreements that collectively represent about 46%, 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, and cover 4% and 96% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2026 and 2027, and cover 92% and 8% of represented employees, respectively. Certain events, such as significant delays in finding appropriate replacement talent, inadequately trained replacement employees, a mismatch of skill sets to future needs, or any work stoppage experienced in connection with negotiations of collective bargaining agreements could adversely affect our operations.

Our operations are subject to acts of sabotage, terrorism, cyber attacks, and other 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 or subject us to significant liability. 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, physical harm or loss of life, 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 or quishing 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, including those attacks arising from or generated by artificial intelligence, among various other security breaches. In addition, the increasingly widespread adoption of artificial intelligence technologies, including generative artificial intelligence, may increase cyber attacks and other operational, legal, privacy, and reputational risks in our industry and worldwide. Also, 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. 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 leverage systems that support our operations and maintain customer and employee data. An interruption of these third-party systems could adversely affect our business as if it was a disruption of our own system. If a significant breach or other interruption occurred, whether due to an intentional or unintentional act, 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 disruption. Our generation, transmission, and distribution systems are part of an interconnected grid. Therefore, a breach or other 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 and credit markets successfully. We might not have access to sufficient capital on reasonable terms, and in the amounts and at the times needed.

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,

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increasing interest rates, inflation, sanctions, trade restrictions, tariffs or trade wars, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. In addition, volatility in stock prices of perceived significant energy consumers, such as technology companies involved with artificial intelligence or cryptocurrency, or other significant developments with such companies, could cause increased volatility in stock prices of energy utility companies such as Ameren. 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 1C.CYBERSECURITY

The Ameren Companies have identified cybersecurity as an enterprise risk, which is managed through Ameren's integrated enterprise risk management program. The program is designed to continuously assess risk and evaluate the likelihood and probability of impact to determine the appropriate risk tolerance and risk management strategies that inform our cybersecurity policies, investments, practices, controls, and countermeasures. The program is a comprehensive, consistently applied management framework that is designed to ensure all forms of material risk and opportunity are identified, reported, and managed in an effective manner overseen by the risk management steering committee. The risk management steering committee, which is composed of executive management and senior-level Ameren officers, with Ameren board of directors’ oversight, oversees and governs Ameren's enterprise risk management processes, which include the identification, assessment, mitigation, and monitoring of risks including strategic, operational, and cybersecurity risks.

Ameren's board of directors maintains a standing committee, the Cybersecurity and Digital Technology Committee, which is focused on the oversight of Ameren's cybersecurity and digital technology risks.The committee has primary responsibility for oversight of cybersecurity and digital technology risk management, including the programs, policies, procedures, processes, controls and safeguards for digital technology, information security, prevention and detection of cybersecurity incidents or data breaches, and cybersecurity and digital technology matters as they relate to crisis preparedness, incident response plans, and disaster recovery and business continuity capabilities.The committee receives regular updates from the Chief Information Security Officer, the Chief Information Officer, executive management, and other members of senior management who collectively maintain the responsibility for both the execution and ongoing management of Ameren’s cybersecurity program and respective initiatives. The Cybersecurity and Digital Technology Committee regularly reports on its activities to Ameren’s board of directors, including reviewing and advising Ameren’s board of directors of any developments it believes should be considered.

Ameren's cybersecurity program and team are led by the Chief Information Security Officer, who possesses over 25 years of critical infrastructure experience both managing and protecting information systems in concert with extensive cybersecurity operations and leadership roles. The Chief Information Security Officer regularly engages with senior-level Ameren officers, reports to the risk management steering committee, and has recurring meetings with the Cybersecurity and Digital Technology Committee as part of ongoing risk management and oversight of the cybersecurity program. In addition, Ameren’s board of directors participate in periodic cybersecurity drills to prepare for potential crisis scenarios.

To manage against existing and emerging cybersecurity threats, we maintain enterprise-wide cybersecurity, crisis management, and information security policies and regular training and tests that reinforce the acceptable use of Ameren's information assets, protection of customer and employee data, and the role each employee plays in protecting Ameren against cybersecurity threats. Incident response plans and procedures are continuously tested through recurring companywide cybersecurity exercises to promote readiness across the organization. The plans and procedures are also designed to escalate incidents to appropriate members of management to guide the prevention, detection, response, recovery, and remediation from a material cybersecurity incident. These cybersecurity plans and procedures are positioned to promote the expedient identification, escalation, handling and reporting of a potentially material cybersecurity event or incident. To address cybersecurity threats, we work closely with law enforcement, cybersecurity consulting firms, and industry associations to enhance information sharing and guard against cybersecurity attacks.

Ameren employs a third-party cybersecurity risk management program, which extends the governance elements of Ameren’s cybersecurity program, in addition to other diligence measures, to our critical third-party providers and suppliers. The supply chain and third-party risks introduced to Ameren are evaluated prior to the commencement of any new engagement or relationship, monitored closely throughout the lifecycle of the supplier and managed through privacy and cybersecurity provisions within the respective commercial contracts. Procedures have been established to address supplier incidents as well as supplier off-boarding at the expiration of the relationship.

We leverage common and widely accepted external cybersecurity risk management frameworks, such as the National Institute of Standards and Technology Cybersecurity framework, to assess, guide, and enhance our cybersecurity posture. Our program effectiveness is measured through formal cybersecurity scorecards and metrics reported to senior-level Ameren officers, the risk management steering

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committee, and the Cybersecurity and Digital Technology Committee. These metrics include but are not limited to measures on the effectiveness of our cybersecurity controls across core National Institute of Standards and Technology Cybersecurity framework functions (Govern, Identify, Protect, Detect, Respond, and Recover), our ability to manage first- and third-party cybersecurity events and incidents, cybersecurity incident response exercises, results of our recurring internal assessments, vulnerability assessments, penetration tests, external assessments, and audits that Ameren regularly undergoes. Ameren regularly engages external cybersecurity experts to assist with evaluating our cybersecurity program. These engagements provide insights into control design and implementation, prioritized recommendations for enhancements to our cybersecurity strategy, and an overview of the cybersecurity threat landscape that collectively inform our investments and technical controls to protect Ameren's most critical assets. The results of these engagements are reviewed with senior-level Ameren officers, the risk management steering committee, and the Cybersecurity and Digital Technology Committee.

We are not aware of any cybersecurity events that have materially affected or are reasonably likely to materially affect Ameren, including our business strategy, results of operations, financial position, or liquidity.

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.

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The following table shows the anticipated capability of our energy centers at the time of the expected 2025 peak summer electrical demand for all energy centers owned as of December 31, 2024:

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

Ameren Missouri:

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

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

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

Hydroelectric Osage(d) Lakeside, Missouri 235,000

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

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

Atchison Atchison County, Missouri 298,800

Solar Huck Finn(e) Audrain and Ralls Counties, Missouri 200,000

Boomtown White County, Illinois 150,000

Cass County Cass County, Illinois 150,000

Other Solar(f) Various 15,300

Natural gas (CTs) Audrain Audrain County, Missouri 608,000

Venice(g) Venice, Illinois 487,000

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

Pinckneyville(g) Pinckneyville, Illinois 316,000

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

Kinmundy(g) Kinmundy, Illinois 210,000

Peno Creek Bowling Green, Missouri 172,000

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

Mexico(h) Mexico, Missouri 54,000

Moberly(h) Moberly, Missouri 54,000

Moreau(h) Jefferson City, Missouri 54,000

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

Ameren Illinois:

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

East St. Louis II East St. Louis, Illinois 1,900

(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)Ameren Missouri plans to extend the retirement date of the Sioux Energy Center from 2030 to 2032, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC in Ameren Missouri’s 2024 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.

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

(e)There were economic development arrangements applicable to this solar energy center, as discussed below.

(f)Includes 10 solar energy centers that each have a nameplate capacity of 6,000 kilowatts or less.

(g)The Venice Energy Center is scheduled to retire by the end of 2029 and the Goose Creek, Pinckneyville, Raccoon Creek, and Kinmundy energy centers are scheduled to retire by the end of 2039. See Illinois Emissions Standards in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

(h)The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to retire by the end of 2029.

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The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2024:

AmerenMissouri AmerenIllinois

Circuit miles of electric transmission lines(a) 3,114 4,786

Circuit miles of electric distribution lines 34,319 46,299

Percentage of circuit miles of electric distribution lines underground 25 % 16 %

Miles of natural gas transmission and distribution mains 3,558 18,750

Underground natural gas storage fields — 12

(a)ATXI owns 561 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 December 31, 2024 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 and Atchison energy centers; Ameren Missouri’s Boomtown, Cass County, Huck Finn, and Maryland Heights 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 operates the Huck Finn Energy Center located in Audrain and Ralls Counties, Missouri. Ameren Missouri has rights and obligations as the operator of the energy center under long-term agreements with Audrain and Ralls Counties. Under the terms of these agreements, Ameren Missouri is responsible for all operation and maintenance for the energy center. The agreements are scheduled to expire in December 2059, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri mortgage bond indenture.

ITEM 3.LEGAL PROCEEDINGS

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses. For additional information on material legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report. Pursuant to Item 103(c)(3)(iii) of Regulation S-K, our policy is to disclose environmental proceedings to which a governmental entity is a party if we reasonably believe such proceedings will result in monetary sanctions of $1 million or more.

ITEM 4.MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 33,414 on January 31, 2025. 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, 2024, to December 31, 2024.

Performance Graph

The following graph shows Ameren’s cumulative TSR during the five years ended December 31, 2024. 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, 2019, in Ameren common stock and in each of the indices shown and that all of the dividends were reinvested.

Comparison of Five-Year Cumulative Return

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

ITEM 6.(RESERVED)

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

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

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

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

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

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

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

Ameren’s 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 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, 2022, including comparisons with the year ended December 31, 2023, is included in Item 7 of our Form 10-K for the year ended December 31, 2023.

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

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OVERVIEW

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

Rate Base ($ in billions)(a) Regulatory Frameworks(c) Electric Customer Rates(f)

Segment Regulatory Framework

Key announcements, updates, and regulatory outcomes

In September 2023, the United States District Court for the Eastern District of Missouri granted Ameren Missouri’s request to modify a September 2019 remedy order issued by the district court in order to allow the retirement of the Rush Island Energy Center in advance of its previously expected retirement date of 2039, in lieu of installing a flue gas desulfurization system. Ameren Missouri retired the Rush Island Energy Center on October 15, 2024. In December 2024, the United States District Court for the Eastern District of Missouri issued an order resolving all outstanding claims in this case. The order requires Ameren Missouri to fund a program to provide electric buses and charging stations to schools in the metro St. Louis area and a program to provide air purifiers to eligible Ameren Missouri electric residential customers. These programs are estimated to cost approximately $64 million. As of December 31, 2024, Ameren and Ameren Missouri recorded liabilities of $64 million and charges of $59 million in 2024 related to the cost of these programs.

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In June 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service. In February 2025, Ameren Missouri filed an updated electric rate increase request seeking approval to increase its annual revenues for electric service by $446 million. The electric rate increase request is based on a 10.25% ROE, a capital structure composed of 52% common equity, a rate base of $13.9 billion, and a test year ended March 31, 2024, with certain pro-forma adjustments through the true-up date of December 31, 2024. In February 2025, the MoPSC staff recommended an increase to Ameren Missouri's annual electric service revenues of $384 million based on a 9.74% ROE, a capital structure composed of 52% common equity, and a rate base of $13.9 billion. The MoPSC proceeding 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 May 2025 and new rates effective by June 2025.

In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance $476 million of costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri will collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. The securitized tariff bonds were issued in December 2024. The financing order also included a determination that the decision to retire the Rush Island Energy Center was reasonable and prudent. The MoPSC did not make a determination regarding the prudency of Ameren Missouri's prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, however, claims regarding such actions could be considered in future regulatory proceedings. If future regulatory proceedings result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

In 2024, the MoPSC issued orders approving requested CCNs for the Split Rail, Vandalia, Bowling Green, and Cass County solar projects. Ameren Missouri acquired the Cass County, Boomtown, and Huck Finn solar projects in June 2024, September 2024, and October 2024, respectively, and placed the assets of the projects, totaling $1 billion, in service in December 2024. In October 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement filed by Ameren Missouri, the MoPSC staff, and other intervenors requesting a CCN for the Castle Bluff Natural Gas Project. The order also includes the use of a post-construction cost deferral related to the project, which allows Ameren Missouri to defer and recover depreciation expense, financing costs, and applicable income taxes incurred from the date the project is placed in service to the date when project costs are reflected in updated base rates as a result of a regulatory rate review. The period of deferral would be limited to the earlier of the time the project costs are reflected in base rates or six months.

In September 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for natural gas delivery service by $40 million. The natural gas rate increase request is based on a 10.25% ROE, a capital structure composed of 52% common equity, a rate base of $531 million, and a test year ended March 31, 2024, with certain pro-forma adjustments expected through the true-up date of December 31, 2024. The MoPSC proceeding relating to the proposed natural gas delivery service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by August 2025 and new rates effective by September 2025.

In November 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement for Ameren Missouri’s MEEIA 2025 plan, which includes a portfolio of customer energy-efficiency and demand response programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from customers its actual MEEIA program costs, related lost electric revenues, and performance incentives. Ameren Missouri intends to invest $51 million annually in 2025 and 2026 and $22 million in 2027 for customer energy-efficiency and demand response programs. In addition, the order approved performance incentives applicable to each plan year to earn revenues by achieving certain spending and demand response goals. If 100% of the goals are achieved in 2025, 2026, and 2027, Ameren Missouri would earn performance incentive revenues of $5 million, $5 million, and $2 million, respectively.

In February 2025, 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 2025. 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 $16.2 billion over the five-year period from 2025 through 2029, with expenditures largely recoverable under the PISA. Ameren Missouri’s Smart Energy Plan includes approximately $1 billion in capital expenditures that may be necessary to comply with regulations issued by the EPA in 2024 relating to CO2 emissions and MATS, if such regulations are not revised or overturned. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, for additional information on the EPA regulations. The Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million based on a 9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of approximately $2.85 billion. The order reflected a reduction of approximately $93 million of planned distribution and transmission capital investments included in Ameren Illinois’ requested revenue increase, which used a 2024 future test year. The new rates became effective on November 28, 2023. In December 2023, Ameren Illinois filed a request for rehearing of the ICC's November 2023 order. The filing requested the ICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and

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transmission capital investments included in the order, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request, and Ameren Illinois filed an appeal with the Illinois Appellate Court for the Fifth Judicial District. In January 2025, the appellate court ruled on the appeal filed by Ameren Illinois. In that ruling, the court reversed a reduction of planned transmission capital investments of $48 million, but affirmed the ICC-approved 9.44% ROE and the remaining reduction of planned distribution capital investments. Ameren Illinois took prudent steps to align its operations with the ICC order, while continuing to ensure safe and adequate service is maintained.

In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding. Rate changes consistent with the December 2023 order became effective in January 2024 and remained effective through late June 2024, when new rates became effective pursuant to the June 2024 ICC rehearing order discussed below. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027 using Ameren Illinois’ previously approved 2022 year-end rate base. In January 2024, the ICC partially denied a rehearing requested by Ameren Illinois to revise the allowed ROE in the December 2023 order and granted Ameren Illinois’ rehearing request to reconsider the rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. In June 2024, the ICC issued an order on Ameren Illinois’ rehearing request approving revenue requirements for electric distribution services for 2024 through 2027. New rates became effective in late June 2024 and remained effective through late December 2024, when new rates became effective pursuant to the December 2024 ICC order discussed below. In July 2024, Ameren Illinois filed a request for rehearing of the ICC’s June 2024 rehearing order to include an asset associated with other postretirement benefits in the rate base. Subsequently, in August 2024, the ICC denied the rehearing request. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order, including the 8.72% ROE, and subsequently updated the appeal filing in September 2024 to include the June 2024 rehearing order regarding the inclusion of an asset associated with other postretirement benefits in the rate base to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal and Ameren Illinois cannot predict the ultimate outcome of the appeal. In March 2024, pursuant to the December 2023 ICC order discussed above, Ameren Illinois filed a revised Grid Plan and a revised MYRP to update the requested revenue requirements for 2024 through 2027. In December 2024, the ICC issued an order in connection with Ameren Illinois’ revised Grid Plan and revised MYRP, approving revenue requirements for electric distribution services for 2024, 2025, 2026, and 2027 of $1,206 million, $1,287 million, $1,367 million, and $1,422 million, respectively. Rate changes consistent with the December 2024 order became effective in December 2024. In January 2025, Ameren Illinois filed a request for rehearing of the ICC’s December 2024 order to revise the allowed ROE and to include an asset associated with other postretirement benefits in the rate base, among other things. Subsequently, in February 2025, the ICC denied the rehearing request. Ameren Illinois intends to file an appeal of the ICC’s December 2024 order and update the appeal filed in September 2024 to the Illinois Appellate Court for the Fifth Judicial District as discussed above. In 2024, Ameren Illinois took prudent steps to align its operations with the December 2023 and June 2024 ICC orders, while continuing to ensure safe and adequate service was maintained.

In November 2024, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $126 million beginning in January 2025, which represents an increase of $26 million from 2024 rates. This order was based on a projected 2025 year-end rate base of $434 million.

In December 2024, the ICC issued an order approving Ameren Illinois’ 2023 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $158 million, which reflected Ameren Illinois’ actual 2023 recoverable costs, year-end rate base of $4.2 billion, and capital structure composed of 50% common equity. The approved reconciliation adjustment will be collected from customers in 2025.

In January 2025, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $140 million. The request is based on a 10.7% ROE, a capital structure composed of 52% common equity, and a rate base of $3.3

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billion. Ameren Illinois used a 2026 future test year in this proceeding. A decision by the ICC in this proceeding is required by early December 2025, with new rates expected to be effective in December 2025.

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 2022, the MISO approved the first tranche of projects under 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. Related to these projects, Ameren began substation upgrades in May 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade. In addition, the MISO awarded three competitive bid projects to ATXI that represent a total estimated investment of approximately $220 million for ATXI.In February 2024, Ameren Illinois and ATXI filed a request for a CCN, among other things, with the ICC related to the portion of the MISO long-range transmission projects they will construct within the ICC’s jurisdiction. A decision by the ICC is expected by mid-2025. In 2024, ATXI filed requests for CCNs, among other things, with the MoPSC related to the MISO long-range transmission projects that it expects to construct within the MoPSC’s jurisdiction. Decisions by the MoPSC are expected in 2025. Also in December 2024, the MISO approved a first set of second tranche projects. A portion of these projects were assigned to Ameren and are estimated to cost approximately $1.3 billion, based on the MISO’s cost estimate. The first set of second tranche projects also includes competitive bid projects that are estimated to cost $6.5 billion, which includes projects located in Illinois that are estimated to cost $1.8 billion, based on the MISO’s cost estimate. The competitive bid process is expected to take place through 2026. The MISO is assessing future long-range transmission scenarios in the first quarter of 2025 and development of a second set of second tranche projects will follow this assessment.

In October 2024, the FERC issued an order, which decreased the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff from 10.02% to 9.98% and required refunds, with interest, for the periods from November 2013 to February 2015 and from late September 2016 forward. In November 2024, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a request for rehearing with the FERC, arguing, among other things, the FERC should not have ordered refunds back to September 2016 or imposed interest on those refunds. Also in November 2024, another intervenor filed a request for rehearing with the FERC, requesting the FERC correct aspects of the ROE methodology used in the October 2024 order and reconsider its decision in a February 2015 complaint case to deny refunds for the period from February 2015 to May 2016. In December 2024, the FERC issued a notice indicating a future order related to the rehearing requests will be issued but did not specify a timeline. In January 2025, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed an appeal of the October 2024 order to the United States Court of Appeals for the District of Columbia Circuit. As a result of the October 2024 order, Ameren and Ameren Illinois recognized reductions to electric revenues of $10 million and $7 million, respectively, and recognized interest expense of $2 million and $1 million, respectively, on their statements of income in 2024.

In February 2024, Ameren’s board of directors increased the quarterly common stock dividend to 67 cents per share, resulting in an annualized equivalent dividend rate of $2.68 per share. In February 2025, Ameren’s board of directors increased the quarterly common stock dividend to 71 cents per share, resulting in an annualized equivalent dividend rate of $2.84 per share.

For further information on the matters discussed above, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and the Outlook section below.

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Earnings

Net income attributable to Ameren common shareholders was $1,182 million, or $4.42 per diluted share, for 2024, and $1,152 million, or $4.38 per diluted share, for 2023. Net income was favorably affected in 2024, compared with 2023, by increased infrastructure investments at Ameren Transmission and Ameren Missouri. Net income was also favorably affected in 2024, compared with 2023, by increased base rate revenues pursuant to the MoPSC's June 2023 electric rate order as well as higher base rate revenues pursuant to the ICC's November 2023 natural gas rate order, which increased earnings at Ameren Illinois Natural Gas. Additionally, earnings in 2024, compared with 2023, were favorably affected by decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, largely because of lower energy center maintenance costs, lower storm costs, disciplined cost management including lower labor costs from decreased headcount and decreased use of contractors, and lower amortization of refueling costs for the Callaway Energy Center, partially offset by the absence of the regulatory deferrals associated with the June 2023 MoPSC rate order. Net income in 2024, compared with 2023, was also favorably affected by increased retail electric sales volumes at Ameren Missouri, primarily due to higher sales excluding customer energy-efficiency programs. Net income was unfavorably affected in 2024, compared with 2023, by two charges related to matters that originated over a decade ago. The first of these charges was recorded by Ameren Missouri related to an order from the United States District Court for the Eastern District of Missouri, which resolved all outstanding claims in the NSR and Clean Air Act litigation related to the Rush Island Energy Center. The second charge was recognized by Ameren Illinois and ATXI for the decrease in the allowed base ROE under the MISO tariff resulting from the October 2024 FERC order, which included customer refunds for certain historical periods. Net income in 2024, compared with 2023, was also unfavorably affected by increased financing costs due to higher long-term debt balances and interest rates at Ameren Missouri and Ameren (parent), a lower recognized ROE under the MYRP, and an increase in the weighted-average basic common shares outstanding, which reduced earnings per diluted share.

Liquidity

At December 31, 2024, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.4 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 sale agreements, subject to market conditions and other factors. As of December 31, 2024, Ameren had approximately $550 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2024. 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.

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Ameren remains focused on strategic capital allocation. The following chart presents 2024 capital expenditures by segment and the midpoint of projected cumulative capital expenditures for 2025 through 2029 by segment:

Ameren Missouri(a) Ameren Illinois Natural Gas

Ameren Illinois Electric Distribution Ameren Transmission(b)

For 2025 through 2029, Ameren’s cumulative capital expenditures are projected to range from $25.2 billion to $27.4 billion. The following table presents the range of projected spending by segment:

Range (in billions)

Ameren Missouri(a) $ 16.0 – $ 17.5

Ameren Illinois Electric Distribution 3.1 – 3.3

Ameren Illinois Natural Gas 1.7 – 1.8

Ameren Transmission(b) 4.4 – 4.8

(a)Amounts include investments under Ameren Missouri’s Smart Energy Plan.

(b)Amounts include the MISO long-range transmission projects assigned to Ameren, as well as the first tranche competitive projects awarded to ATXI discussed above.

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 and by weather conditions, such as storms, 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.

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

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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, 2024 and 2023:

Net income attributable to Ameren common shareholders $ 1,182 $ 1,152

Earnings per common share – diluted 4.42 4.38

Net income attributable to Ameren common shareholders in 2024 increased $30 million, and $0.04 per diluted share, from 2023. The increase was due to net income increases of $27 million, $15 million, and $14 million at Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Missouri, respectively. The increases in net income were partially offset by a net income decrease of $24 million at Ameren Illinois Electric Distribution and an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent), of $2 million.

Earnings per share in 2024, compared with 2023, were favorably affected by:

•increased allowance for equity funds used during construction and increased base rate revenues for the inclusion of previously deferred PISA and RESRAM interest charges pursuant to the June 2023 MoPSC electric rate order effective July 9, 2023, and decreased interest charges resulting from higher deferrals related to infrastructure investments associated with the PISA and RESRAM, at Ameren Missouri (17 cents per share);

•increased rate base investments at Ameren Transmission, which increased earnings in this segment (16 cents per share);

•increased base rate revenues at Ameren Missouri effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, partially offset by the net effect of amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a lower base level of expenses included in trackers, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (9 cents per share);

•increased retail electric sales volumes at Ameren Missouri, primarily due to higher sales excluding customer energy-efficiency programs (estimated at 8 cents per share);

•increased other income, net, primarily due to lower donations and a gain on the extinguishment of debt, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for more information, partially offset by decreased non-service cost components of net periodic benefit income not subject to formula rates or trackers largely due to lower investment returns (6 cents per share);

•increased base rate revenues at Ameren Illinois Natural Gas effective November 28, 2023, pursuant to the November 2023 ICC natural gas rate order, partially offset by increased depreciation and amortization expenses included in base rates (4 cents per share); and

•decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, excluding a charge related to the NSR and Clean Air Act litigation discussed below largely because of lower energy center maintenance costs, lower storm costs, disciplined cost management including lower labor costs from decreased headcount and decreased use of contractors, and lower amortization of refueling costs for the Callaway Energy Center, partially offset by the absence of regulatory deferrals associated with the June 2023 MoPSC rate order (2 cents per share).

Earnings per share in 2024, compared with 2023, were unfavorably affected by:

•a charge recorded by Ameren Missouri, included in other operation and maintenance expenses, related to an order from the United States District Court for the Eastern District of Missouri, which resolved all outstanding claims in the NSR and Clean Air Act litigation related to the Rush Island Energy Center, see Note 14 - Commitments and Contingencies under Part II, Item 8, of this report for more information (17 cents per share);

•increased financing costs primarily at Ameren Missouri and Ameren (parent), largely due to higher long-term debt balances and interest rates, partially offset by lower levels of short-term borrowings (17 cents per share);

•lower revenue at Ameren Illinois Electric Distribution due to a lower recognized ROE under the MYRP (9 cents per share);

•increased weighted-average basic common shares outstanding resulting from issuances of common shares (7 cents per share);

•the result of the October 2024 FERC order reducing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which decreased Ameren Transmission earnings (4 cents per share); and

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•increased taxes other than income taxes at Ameren Missouri, largely resulting from the absence in 2024 of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act (2 cents per share).

The cents per share variances above are presented based on the weighted-average basic shares outstanding in 2023 and do not reflect the impact of dilution on earnings per share, unless otherwise noted. The amounts above other than variances related to income taxes have been presented net of income taxes using Ameren’s 2024 blended federal and state statutory tax rate of 26%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Operating Revenues for both Electric Revenues and Natural Gas Revenues; Fuel and Purchased Power Expenses; Other Operations and Maintenance Expenses; Depreciation and Amortization Expenses; Taxes Other Than Income Taxes; Other Income, Net; Interest Charges; and Income Taxes, see the major headings below.

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Below is Ameren’s table of income statement components by segment for the years ended December 31, 2024 and 2023:

Natural gas purchased for resale (60) — (260) — — (320)

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

Natural gas purchased for resale (79) — (276) — — (355)

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

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Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2024 and 2023:

Natural gas revenues — 938 — — 938

Natural gas purchased for resale — (260) — — (260)

Other operations and maintenance expenses (619) (230) (57) — (906)

Taxes other than income taxes (75) (78) (4) — (157)

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

Net income attributable to common shareholder $ 234 $ 149 $ 237 $ — $ 620

Natural gas revenues — 897 — — 897

Natural gas purchased for resale — (276) — — (276)

Other operations and maintenance expenses (532) (237) (49) — (818)

Taxes other than income taxes (75) (67) (4) — (146)

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

Net income attributable to common shareholder $ 258 $ 134 $ 215 $ — $ 607

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Operating Revenues

The following table presents the increases (decreases) by Ameren segment for electric and natural gas revenues in 2024, compared with 2023:

Electric revenue change:

Base rates (estimate)(b) $ 62 $ 14 $ — $ 89 $ — $ 165

Effect of weather (estimate)(c) 3 — — — — 3

Customer charges 2 — — — — 2

Rush Island Energy Center base rate revenue deferral (13) — — — — (13)

MEEIA 2019 performance incentives 1 — — — — 1

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

Recovery of power restoration efforts provided to other utilities 1 3 — — — 4

Ameren Illinois energy-efficiency program investment revenues — 21 — — — 21

Electric deferred income tax adjustment(d) — (23) — — — (23)

Other cost recovery mechanisms(f) 22 45 — — — 67

Natural gas revenue change:

Base rates (estimate) $ — $ — $ 47 $ — $ — $ 47

Sales volume (excluding the estimated effects of weather) 2 — — — — 2

Effect of weather (estimate)(c) 1 — — — — 1

Other — — 3 — — 3

Other cost recovery mechanisms(f) (2) — 7 — — 5

Total natural gas revenue change $ (19) $ — $ 41 $ — $ — $ 22

(a)Includes an increase in transmission revenues of $84 million in 2024, compared with 2023, at Ameren Illinois.

(b)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases in operating revenues related to the revenue requirement reconciliation adjustment under the MYRP and formula rates, respectively. For Ameren Missouri, base rates exclude an increase for the recovery of lost electric revenue, less the associated fuel and purchased power expenses, 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 “Retail 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 National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.

(d)The electric deferred income tax adjustment relates to certain excess deferred income taxes that will be amortized through 2025. Offsetting expense increases or decreases are reflected within "Income Taxes" on the statement of income. This item has no overall impact on earnings.

(e)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel and purchased power” and “Natural gas purchased for resale” on the statement of income. Activity in Other/Intersegment Eliminations of $12 million represents the changes in eliminations of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI (-$6 million), as well as changes in Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution

(-$6 million). 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. These items have no overall impact on earnings.

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

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Electric Revenues

Ameren

Ameren’s electric revenues increased $101 million, or 2%, in 2024, compared with 2023, due to increased revenues at Ameren Missouri and Ameren Transmission, partially offset by decreased revenues at Ameren Illinois Electric Distribution, as discussed below.

Ameren Transmission

Ameren Transmission’s electric revenues increased $104 million, or 15%, in 2024, compared with 2023. Revenues were favorably affected by higher recoverable expenses (+$55 million), increased capital investment (+$44 million), as evidenced by a 15% increase in rate base used to calculate the revenue requirement, and increased facility rental revenues (+$15 million) related to ATXI’s transmission operations control center, which was placed in service in December 2023. ATXI provides affiliates with access to this facility. Rental revenues associated with this facility are affiliate transactions and eliminated in consolidation for Ameren’s consolidated financial statements. See Note 13 – Related-party Transactions under Part II, Item 8, of this report for additional information. Revenues were unfavorably affected by a decrease in the allowed base ROE under the MISO tariff resulting from the October 2024 FERC order, which included customer refunds for certain historical periods (-$10 million). See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the FERC complaint cases.

Ameren Missouri

Ameren Missouri’s electric revenues increased$153 million, or 4%, in 2024, compared with 2023.

The following items had a favorable effect on Ameren Missouri’s electric revenues in 2024, compared with 2023:

•“Off-system sales, capacity, transmission, and FAC revenues, net” increased $96 million, primarily due to higher summer and fall capacity prices which were set by annual MISO auctions.

•Higher electric base rates, resulting from the June 2023 MoPSC electric rate order effective July 9, 2023, increased revenues an estimated $62 million.

•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues increased an estimated $27 million, due to an increase in residential customer counts, retail sales volumes from large commercial and industrial customers, the absence of customer outages resulting from major storms experienced throughout the service territory in July and August 2023, and an additional day in 2024 as a result of the leap year. The increase is partially offset by lower realized prices due to changes in customer usage patterns and economic development discounts.

•Revenues associated with other cost recovery mechanisms increased$22 million, primarily due to an increase in RESRAM revenues and an increase in excise taxes due to increased retail sales revenue.

•Other revenues increased $6 million due to pole rents (+$2 million), other rentals (+$2 million), and other miscellaneous revenues

(+$2 million).

•The aggregate effect of weather increased revenues an estimated $3 million as cooling degree days increased 7% and heating degree days decreased 4%.

The following items had an unfavorable effect on Ameren Missouri’s electric revenues in 2024, compared with 2023:

•Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” decreased $54 million, due to decreased revenue related to the 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 changes to “Cost recovery mechanisms - offset in electric revenue” in fuel and purchased power.

•In accordance with the June 2024 MoPSC financing order, revenues decreased $13 million due to the deferral of base rate revenues to a regulatory liability related to the Rush Island Energy Center since its October 15, 2024 retirement date. The regulatory liability will be refunded to customers in a future rate proceeding.

Ameren Illinois

Ameren Illinois’ electric revenues decreased $51 million, or 2%, in 2024, compared with 2023, driven by decreased revenues at Ameren Illinois Electric Distribution, partially offset by increased revenues at Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s revenues decreased $129 million, or 6%, in 2024, compared with 2023.

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The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s revenues in 2024, compared with 2023:

•Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” decreased $193 million, due to decreased purchased power expenses recovered from customers. The decreases in electric revenues are fully offset by decreases in purchased power expenses under cost recovery mechanisms for purchased power, as discussed below.

•Pursuant to an ICC order, revenues decreased $23 million, due to an increase in the amortization rate for certain excess deferred income taxes.

The following items had a favorable effect on Ameren Illinois Electric Distribution’s revenues in 2024, compared with 2023:

•Other cost recovery mechanisms increased revenues by $45 million, primarily due to a higher amount of bad debt and purchased receivables from alternative retail electric suppliers included in customer rates pursuant to their associated riders, partially offset by lower environmental remediation revenues.

•Revenues associated with customer energy-efficiency program investments increased $21 million, due to the recovery of program expenses (+$15 million), an increase in the ROE (+$4 million) primarily due to maximum achievement of the annual 2023 energy savings goals, and increased investment of $2 million.

•Base rates increased revenues by $14 million, primarily due to higher recoverable non-purchased power expenses (+$38 million), partially offset by a lower recognized ROE (-$24 million). The MYRP utilizes a fixed ROE approved by the ICC of 8.72%, with adjustments for any performance incentives and penalties, while the IEIMA formula-based ROE was based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points (9.84% as of December 31, 2023).

•The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts, primarily caused by hurricane damage, increased revenues by $3 million.

Ameren Illinois Transmission

Ameren Illinois Transmission’s revenues increased $84 million, or 18%, in 2024, compared with 2023. Base rate revenues were favorably affected by higher recoverable expenses (+$58 million) and increased capital investment (+$33 million), as evidenced by a 17% increase in rate base used to calculate the revenue requirement. Base rate revenues were unfavorably affected by a decrease in the allowed base ROE under the MISO tariff resulting from the October 2024 FERC order, which included customer refunds for certain historical periods (-$7 million). See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the FERC ROE complaint cases.

Natural Gas Revenues

Ameren

Ameren’s natural gas revenues increased $22 million, or 2%, in 2024, compared with 2023, due to increased revenues at Ameren Illinois Natural Gas, partially offset by decreased revenues at Ameren Missouri, as discussed below.

Ameren Missouri

Ameren Missouri’s natural gas revenues decreased $19 million, or 12%, in 2024, compared with 2023. Revenues associated with “Cost recovery mechanisms – offset in natural gas purchased for resale” decreased $20 million in 2024, compared with 2023, due to lower commodity prices and the absence of amortization of natural gas costs deferred under the PGA related to the extremely cold weather in mid-February 2021. Changes in natural gas revenues under the PGA are fully offset by corresponding changes in natural gas purchased for resale expenses.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ revenues increased $41 million, or 5%, in 2024, compared with 2023. Revenues increased an estimated $47 million due to higher natural gas base rates as a result of the November 2023 natural gas rate order, and revenues associated with other cost recovery mechanisms increased $7 million primarily due to increased revenues for excise taxes. “Cost recovery mechanisms – offset in natural gas purchased for resale” decreased revenues $16 million, due to lower collection of natural gas costs previously deferred under the PGA. Changes in natural gas revenues under the PGA are fully offset by the decrease in natural gas purchased for resale expenses.

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Fuel and Purchased Power

The following table presents the increases (decreases) by Ameren segment for fuel and purchased power in 2024, compared with 2023:

Fuel and purchased power change:

Effect of higher net energy costs included in base rates 22 — — — — 22

Retail sales volumes 6 — — — — 6

Transmission service charges 8 — — — — 8

Other (3) — — — — (3)

Total fuel and purchased power change $ 74 $ (193) $ — $ — $ (12) $ (131)

(a)“Cost recovery mechanisms — offset in electric revenue” changes are offset by corresponding changes in “Cost recovery mechanisms — offset in fuel and purchased power” in electric revenues. Activity in Other/Intersegment Eliminations of $12 million represents the changes in eliminations of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI (-$6 million), as well as changes in Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution (-$6 million). 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. These items have no overall impact on earnings.

Ameren

Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for fuel and purchased power. Ameren’s electric fuel and purchased power expenses decreased $131 million, or 7%, in 2024, compared with 2023, primarily due to decreased fuel and purchased power expenses at Ameren Illinois Electric Distribution, partially offset by increased fuel and purchased power expenses at Ameren Missouri, as discussed below.

Ameren Missouri

Ameren Missouri’s fuel and purchased power expenses increased $74 million, or 7%, in 2024, compared with 2023.

The following items increased Ameren Missouri’s fuel and purchased power expense in 2024, compared with 2023:

•Energy costs increased $95 million in 2024, compared with 2023, primarily due to higher summer and fall capacity prices, which were set by annual MISO auctions. Ameren Missouri’s 5% exposure to net energy cost variances under the FAC is the difference between “Off-system sales, capacity, transmission, and FAC revenues, net” and “Energy costs (excluding the estimated effect of weather)”. These results had an immaterial impact on earnings in 2024, compared with 2023.

•The effect of higher net energy costs included in base rates increased Ameren Missouri’s fuel and purchased power expenses $22 million in 2024, compared with 2023, as a result of the June 2023 MoPSC electric rate order.

•Transmission service charges increased $8 milliondue to higher transmission rates related to increased revenue requirements of other transmission operators.

•Increases in retail sales volumes increased Ameren Missouri’s fuel and purchased power expenses $6 million.

“Cost recovery mechanisms — offset in electric revenue” decreased $54 million in 2024, compared with 2023, due to decreased amortization of costs previously deferred under the FAC. The changes to “Cost recovery mechanisms - offset in electric revenue” are fully offset by “Cost recovery mechanisms - offset in fuel and purchased power” in electric revenues.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s purchased power expenses decreased $193 million, or 21%, in 2024, compared with 2023, primarily due to decreased energy prices (-$94 million), which largely reflect the results of IPA procurement events, decreased capacity prices (-$77 million), which were set by annual MISO auctions, and lower volumes (-$43 million) primarily due to residential and small commercial customers switching from Ameren Illinois’ supplied power to alternative retail electric suppliers and customer adoption of solar technology through initiatives required under Illinois law. These decreases in purchased power expenses were partially offset by increased expenses associated with the amortization of renewable energy credit costs (+$20 million). The changes to “Cost recovery mechanisms - offset in electric revenue” are fully offset by changes to “Cost recovery mechanisms - offset in fuel and purchased power” in electric revenues.

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Natural Gas Purchased for Resale

The following table presents the increases (decreases) by Ameren segment for natural gas purchased for resale in 2024, compared with 2023:

Natural gas purchased for resale change:

Effect of weather (estimate)(a) $ 1 $ — $ — $ — $ — $ 1

Cost recovery mechanisms – offset in natural gas revenue(b) (20) — (16) — — (36)

Total natural gas purchased for resale change $ (19) $ — $ (16) $ — $ — $ (35)

(a)Represents the estimated variation resulting primarily from changes in heating degree-days on 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.

(b)Natural gas purchased for resale changes are offset by corresponding changes in “Natural gas revenues” on the statement of income. These items have no overall impact on earnings.

Ameren

Ameren Missouri and Ameren Illinois are allowed to pass on to customers prudently incurred costs for natural gas purchased for resale. Ameren’s natural gas purchased for resale expenses decreased $35 million, or 10%, in 2024, compared with 2023, due to decreased natural gas purchased for resale expenses at Ameren Missouri and Ameren Illinois Natural Gas, as discussed below.

Ameren Missouri

Ameren Missouri’s natural gas purchased for resale expenses decreased $19 million, or 24%, in 2024, compared with 2023. Expenses associated with “Cost recovery mechanisms – offset in natural gas revenue” decreased $20 million in 2024, compared with 2023, due to lower commodity prices and the absence of amortization of natural gas costs deferred under the PGA related to the extremely cold weather in mid-February 2021. Changes in natural gas purchased for resale expenses are fully offset by corresponding changes in natural gas revenues under the PGA.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ natural gas purchased for resale expenses decreased $16 million, or 6%, in 2024, compared with 2023, primarily due to lower amortization of natural gas costs that were previously deferred under the PGA and lower natural gas prices. Changes in natural gas purchased for resale expenses are fully offset by changes in natural gas revenues under the PGA.

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Other Operations and Maintenance Expenses

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

Overall Ameren Increase of $103 Million

(a)Includes $70 million and $60 million at Ameren Transmission in 2024 and 2023, respectively, and other/intersegment eliminations of $0 million and $34 million in 2024and 2023, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Ameren

Other operations and maintenance expenses increased $103 million in 2024, compared with 2023 because of the changes discussed below. In addition to changes by segment as discussed below, other operations and maintenance expenses decreased $34 million in 2024 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of a $14 million increase in the elimination of intercompany rent related to ATXI’s operations control center discussed below; a $10 million increase in the elimination of the non-service cost component of net periodic benefit income at Ameren Services; and a $8 million gain on the sale of land. 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 increased $10 million in 2024, compared with 2023, primarily because of increased costs related to ATXI’s operations control center, which was placed in service in December 2023. ATXI provides affiliates with access to this facility. The rent expense associated with this facility is an affiliate transaction and eliminated in consolidation for purposes of Ameren’s consolidated financial statements. See Note 13 - Related-party Transactions under Part II, Item 8, of this report for additional information.

Ameren Missouri

Other operations and maintenance expenses increased $47 million in 2024, compared with 2023, primarily due to the following items:

•A $59 million charge related to an order from the United States District Court for the Eastern District of Missouri, which resolved all outstanding claims in the NSR and Clean Air Act litigation related to the Rush Island Energy Center, see Note 14 - Commitments and Contingencies under Part II, Item 8, of this report for more information.

•The absence in 2024 of the recognition of regulatory assets for previously expensed costs approved for recovery pursuant to the June 2023 MoPSC rate order increased expenses $15 million.

•Individually insignificant increases of $7 million in various other operations and maintenance expenses, including other labor, cloud computing costs, and a decrease in the cash surrender value of COLI.

•The absence of previously deferred expenses increased expense by $7 million.

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•Legal and administrative expenses increased by $6 million, primarily related to environmental matters.

•Costs for injuries and damages increased $4 million, primarily due to an increase in claims.

•Renewable development costs increased $3 million, primarily due to the absence in 2024 of the MoPSC order approving CCNs for the Boomtown and Huck Finn energy centers in the first half of 2023 that led to increased capitalization of renewable development costs pursuant to anticipated recovery from customers.

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

•Pension and benefit costs decreased $20 million because of a lower base level of expenses, subject to a tracker, included in customer rates pursuant to the June 2023 MoPSC electric rate order. See Note 10 - Retirement Benefits under Part II, Item 8, of this report for more information.

•Energy center maintenance decreased $17 million, primarily because of lower amortization of Callaway Energy Center refueling and maintenance costs resulting from cost saving initiatives in the fall 2023 outage, compared to the spring 2022 outage, and lower headcount.

•Transmission and distribution storm-related costs decreased $10 million because of the major storms experienced throughout the service territory in July and August 2023.

•Transmission and distribution expenditures, excluding major storm-related costs, decreased $8 million, primarily due to reduced levels of vegetation management expenditures and lower inspection costs from decreased use of contractors, and lower headcount.

Ameren Illinois

Other operations and maintenance expenses increased $88 million at Ameren Illinois in 2024, compared with 2023, as discussed below.

Ameren Illinois Electric Distribution

Other operations and maintenance increased $87 million in 2024, compared with 2023, was primarily due to the following items:

•Bad debt costs increased $52 million, primarily because of a higher base level of expenses included in customer rates pursuant to the associated rider.

•Amortization of previous deferrals associated with bad debt costs on purchased receivables increased $15 million, primarily because of a higher base level of expenses included in customer rates pursuant to the associated rider.

•Increased costs associated with customer energy-efficiency investments under formula ratemaking of $13 million, primarily due to amortization of regulatory assets.

•Benefit costs increased $6 million, primarily due to an increase in medical benefit claims related to active plan participants.

•Increased labor expense of $5 million, primarily caused by reduced capital expenditures due to steps taken to align operations with the MYRP orders, resulting in more maintenance activities.

•Absence of major storm-related cost deferrals in 2024 increased expense by $4 million.

•Vegetation management costs increased by $4 million due to increased activity.

•Labor expense increased by $3 million due to assistance provided to other utilities to aid in storm recovery efforts, primarily caused by hurricane damage.

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

•Reduction in environmental remediation rider costs of $14 million.

•Technology-related expenditures decreased $3 million resulting from lower levels of software licenses and rentals.

Ameren Illinois Natural Gas

Other operations and maintenance costs decreased $7 million in 2024, compared with 2023, primarily due to a decrease of $6 million in contractor service costs and a $4 million decrease in labor expense due to steps taken to align operations with the November 2023 ICC natural gas rate order. These decreases were partially offset by an increase of $2 million in cloud computing costs.

Ameren Illinois Transmission

Other operations and maintenance expenses increased $8 million in 2024, compared with 2023, primarily because of increased costs related to ATXI’s operations control center, which was placed in service in December 2023. ATXI provides affiliates with access to this facility. The rent expense associated with this facility is an affiliate transaction and eliminated in consolidation for purposes of Ameren’s consolidated financial statements. See Note 13 - Related-party Transactions under Part II, Item 8, of this report for additional information.

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Depreciation and Amortization Expenses

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $203 Million

(a)Includes other/intersegment eliminations of $8 million and $7 million in 2024 and 2023, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Depreciation and amortization expenses increased $203 million, $134 million, and $63 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment investments across their respective segments. In addition, Ameren’s and Ameren Missouri’s depreciation and amortization expenses were affected by the following items, which include the effect of the additional investments at Ameren Missouri:

•The deferral to a regulatory liability related to production tax credits allowed under the IRA associated with the Callaway Energy Center that increased expenses by $90 million.

•Increased depreciation and amortization of $40 million due to the inclusion in base rates of amounts previously deferred under the PISA and RESRAM effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order.

•Increased amortization of prior deferrals and the lower net under-recovery of RESRAM eligible expenses increased depreciation and amortization expenses by $33 million.

•Depreciation and amortization rate changes pursuant to the electric rate order noted above, which increased depreciation and amortization expenses by $4 million.

•Depreciation and amortization expenses reflected a deferral to a regulatory asset of depreciation associated with investments in eligible property, plant, and equipment not yet included in base rates, pursuant to PISA and RESRAM. Base rates were updated to include the eligible property, plant, and equipment in-service through December 31, 2022, when new customer rates became effective on July 9, 2023, pursuant to the June 2023 MoPSC electric rate order. The effect of rebasing PISA and RESRAM, partially offset by increased amortization of prior PISA deferrals, decreased depreciation and amortization by $30 million.

•The higher net deferral pursuant to a tracker related to certain excess deferred income taxes, which decreased depreciation and amortization expenses by $5 million.

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Taxes Other Than Income Taxes

Total by Segment(a) Increase by Segment

Overall Ameren Increase of $25 Million

(a)Includes $9 million and $8 million at Ameren Transmission in 2024 and 2023, respectively, and other/intersegment eliminations of $13 million and $12 million in 2024and2023, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

Taxes other than income taxes increased $25 million in 2024, compared with 2023, primarily because of an increase of $7 million and $2 million at Ameren Missouri and Ameren Illinois Electric Distribution, respectively, due to the absence in 2024 of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act; a $9 million increase at Ameren Illinois Natural Gas due to an increase in excise taxes, primarily resulting from higher invested capital taxes; and a $3 million increase in gross receipts taxes at Ameren Missouri, primarily due to increased retail electric sales.

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Other Income, Net

Total by Segment Increase (Decrease) by Segment

Overall Ameren Increase of $69 Million

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

See Note 6 – Other Income, Net under Part II, Item 8, of this report for additional information. See Note 5 – Long-term Debt and Equity Financings and Note 10 – Retirement Benefits under Part II, Item 8, for additional information on the debt extinguishment and the non-service cost components of net periodic benefit income.

Ameren

Other income, net, increased $69 million in 2024, compared with 2023. In addition to changes discussed below, other income, net, increased $14 million for activity not reported as part of a segment, primarily due to lower charitable contributions of $18 million at Ameren (parent) and a gain of $16 million for Ameren (parent)’s repurchase of senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois. These increases were partially offset by a decrease of $13 million due to the non-service cost component of net periodic benefit income for activity not reported as part of a segment and $7 million in intersegment eliminations.

Ameren Transmission

Other income, net, decreased $2 million in 2024, compared with 2023 due to a decrease of $5 million in lower allowance for equity funds used during construction, primarily related to lower average construction work in progress balances and a decrease of $2 million in the non-service cost component of net periodic benefit income. These decreases were partially offset by the increase of $4 million in other interest income on regulatory balances.

Ameren Missouri

Other income, net, increased $66 million in 2024, compared with 2023, primarily because of an increase of $42 million in the non-service cost component of net periodic benefit income because of changes in the base level of pension and postretirement costs pursuant to the June 2023 MoPSC electric rate order. Other income, net, also increased $28 million because of a higher allowance for equity funds used during construction resulting from higher average construction work in progress balances. These increases were offset by a decrease of $2 million in other interest income on regulatory balances.

Ameren Illinois

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Other income, net, decreased $9 million in 2024, compared with 2023. Other income, net, decreased primarily because of a decrease of $12 million and $6 million in the non-service cost component of net periodic benefit income at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively. Other income, net decreased $2 million in the allowance of equity funds used during construction, largely at Ameren Illinois Electric Distribution. These decreases were partially offset by the increase in other interest income on regulatory balances of $11 million, largely at Ameren Illinois Electric Distribution.

Interest Charges

Total by Segment Increase by Segment

Overall Ameren Increase of $97 Million

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Ameren Illinois Electric Distribution Ameren Transmission

See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report and the Long-term Debt and Equity section below for additional information on short-term borrowings and long-term debt, respectively.

Ameren

Interest charges increased $97 million in 2024, compared with 2023. In addition to changes by segments discussed below, interest charges increased $42 million for activity not reported as part of a segment, primarily at Ameren (parent), because of issuances of long-term debt in November and December of 2023, which collectively increased interest charges by $64 million. The net proceeds from these issuances were used to repay short-term borrowings, which decreased short-term interest expense by $23 million, compared with 2023.

Ameren Transmission

Interest charges increased $21 million in 2024, compared with 2023, primarily due to issuances of long-term debt in May 2023, June 2024 and August 2024, which collectively increased interest charges by $9 million. Additionally, an increase on long-term debt and a higher interest rate on an increased level of short-term borrowings increased interest charges by $8 million and $2 million, respectively.

Ameren Missouri

Interest charges increased $17 million in 2024, compared with 2023, primarily due to issuances of long-term debt in March 2023, January 2024, April 2024, and October 2024, which collectively increased interest charges by $48 million.

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The following items partially offset the above increase in interest charges between years:

•Increase in the borrowed funds capitalized as part of the allowance for funds used during construction of $12 million, primarily due to higher average construction work in progress balances.

•Interest charges decreased by $9 million due to the maturity of $350 million senior secured notes bearing a 3.5% interest rate in April 2024 that were repaid with cash on hand.

•Interest charges reflected a deferral to a regulatory asset of interest associated with investments in eligible property, plant, and equipment not yet included in base rates, pursuant to PISA and RESRAM. Base rates were updated to include the eligible property, plant, and equipment in-service through December 31, 2022, when new customer rates became effective on July 9, 2023, pursuant to the June 2023 MoPSC electric rate order. This update to base rates resulted in a higher deferral of interest in 2024 pursuant to PISA and RESRAM that decreased interest charges by $5 million.

•Lower levels of short-term borrowings decreased interest charges by $4 million.

Ameren Illinois

Interest charges increased $37 million in 2024, compared with 2023, primarily due to the following:

Ameren Illinois Transmission