insiderdeltaSEC filings, surfaced and scored

CoverageForm 410-K10-Q8-K13D13G13F

Ameren Corp

AEECIK 0001002910 · Every Form 4 filed by insiders at this issuer. See financials →

Annual report (10-K)

Latest 10-K filed Feb 18, 2026. Sentiment + YoY language diff vs prior year. Read sections →

Signal:Neutral

Risk Factors:tone -0.0274Δ+0.001589% similar+42/-45 ¶

MD&A:tone 0.0004Δ+0.001083% similar+208/-228 ¶

Sentiment via Loughran-McDonald lexicon · YoY diff via Jaccard similarity + paragraph set difference.

Recent 8-K announcements

Per-item disclosure feed. Item 2.02 is the earnings release.

May 18, 2026no items parsed May 5, 2026no items parsed Mar 4, 2026no items parsed Feb 27, 2026no items parsed Feb 11, 2026no items parsed

Top insiders

Most active reporters at Ameren Corp

Name	Roles	Filings
Flores Rafael	Director	12
Lyons Martin J	OfficerDirector	12
Nwamu Chonda J	Officer	12
Diya Fadi M	-	11
Birk Mark C	-	9

Showing 6-10 of 37

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Top performers

Insiders ranked by realized 90-day signed return on their open-market trades at Ameren Corp. Minimum 3 scored trades. Returns are signed - a sale followed by a rally counts against the insider.

#	Insider	Trades	Win rate	Avg	Median	Best	Worst
1	Shaw Theresa A	3	67%	+0.5%	+2.7%	+2.9%	-4.1%
2	Baxter Warner L	7	43%	-5.5%	-6.2%	+1.6%	-12.3%
3	Nwamu Chonda J	4	25%	-4.6%	-3.3%	+2.9%	-14.5%
4	Mark Richard J	3	33%	-3.6%	-5.5%	+4.4%	-9.8%
5	Moehn Michael L	14	36%	-2.9%	-0.7%	+12.1%	-12.3%
6	Flores Rafael	7	43%	-2.1%	-0.7%	+7.4%	-17.8%
7	Diya Fadi M	3	33%	-1.7%	-0.3%	+4.0%	-8.8%
8	Lyons Martin J	8	63%	-1.4%	+1.1%	+5.0%	-12.3%
9	Schukar Shawn E	7	71%	-1.1%	+1.7%	+5.0%	-12.3%
10	Lindgren Mark C	8	63%	-0.6%	+2.2%	+5.0%	-12.3%

All filings

245 Form 4 / 4-A filings, newest first

Filed	Insider	Top transaction	Shares	Price	Value
Jun 3, 2026	Arora Ajay K EVP of Subsidiary	AGrant	6,797	$0.00	$0
Jun 3, 2026	Melda Aaron P Chairman and President	AGrant	3,705	$0.00	$0
May 14, 2026	Shaw Theresa A SVP and CATO	SSale	1,500	$109.35	$164,025
May 5, 2026	Moehn Michael L Group President, Utilities	SSale	6,500	$113.63	$738,595
Mar 6, 2026	Brune Catherine S Director	GGift	450	$0.00	$0

Showing 1-5 of 245

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Real-time Form 4 intelligence. Smarter insider tracking.

Filed		Top transaction	Shares	Price	Value

YoY shift: Neutral

Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is 0.13pp more bullish than last year's.

Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.

Tone shift by section

The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.

Risk Factors

+0.15pp

Flat

Net-tone change vs last year's 10-K.

MD&A

+0.10pp

Flat

Net-tone change vs last year's 10-K.

Per-snippet highlights

Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.

Language change vs prior 10-K

Risk Factors (Item 1A) - words with the biggest YoY frequency increase

Negative rising

termination+2
shutdowns+1
negatively+1
against+1
scrutiny+1

Positive rising

satisfaction+2
advances+1
favorable+1
opportunities+1
satisfy+1

Risk Factors (Item 1A)

9,194 words

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 new interpretations of existing regulations, as well as executive orders, 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 presidential administration’s approach to environmental and 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

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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.

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. Pursuant to the PPRA, Ameren Missouri’s natural gas utility rates established in proceedings filed after June 2026 will be allowed to be based on future costs, revenues, and sales volumes, subject to MoPSC approval. 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 experienced higher maintenance costs and capital expenditures to operate their electric, natural gas, and transmission businesses, which has led to increases in customer rates and the related revenue requirements needed to recover such costs and earn a return on investments. This 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.

Beginning 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.

Pursuant to the CEJA, Ameren Illinois has the option to establish electric distribution rates through an MYRP or a traditional regulatory rate review. 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.

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 the PPRA, Ameren Missouri’s PISA election was extended through 2035 and an additional extension through 2040 is allowed if requested by Ameren Missouri and approved by the MoPSC. This law also reduced the 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 annual limit in effect was 2.5% and changed to 2.25%, prorated monthly, for revenue requirements approved by the MoPSC after August 2025. Increased capital expenditures could cause incremental PISA deferrals to exceed the 2.25% limitation, and such amounts exceeding the 2.25% limitation would be excluded from recovery under future revenue requirements. Failure to limit capital investments to an amount which maintains PISA deferrals under the 2.25% limitation could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.

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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; regulate the handling and disposal of hazardous substances and waste materials; establish siting and land use requirements; and protect against 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 and 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 impact the electric utility industry, and compliance obligations could be costly for Ameren Missouri, which operates coal-fired and natural gas-fired energy centers. As of December 31, 2025, Ameren Missouri’s coal-fired energy centers represented 5% and 11% of Ameren’s and Ameren Missouri’s rate base, respectively. Compliance obligations under the Clean Air Act stem from a variety of programs including the NSPS, the MATS, emission allowance programs, 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 SO 2 , particulate matter, NO x , mercury, toxic metals and acid gases, and CO 2 emissions, although the scope of covered pollutants can change. To the extent our operations impact surface water bodies, including wetlands, the Clean Water Act requires permitting as well as evaluation of the ecological and biological impact of those operations. Implementation of requirements under the Clean Air Act and the Clean Water Act typically occurs through the issuance of permits by state regulators or resource agencies, and capital expenditures associated with compliance could be significant. The management and disposal of coal ash from our coal-fired energy centers must comply with federal regulations known as the CCR Rule issued under the Resource Conservation and Recovery Act and require the closure of surface impoundments at our coal-fired energy centers along with groundwater monitoring requirements and the implementations of corrective measures if necessary. The combined effects of compliance with existing and future environmental regulations could result in significant capital expenditures, increased operating costs, and the potential for closure or alteration of operations at some of Ameren Missouri’s energy centers.

Currently as required by the CEJA, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO 2 and NO x . Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the possible 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.

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

There is concern and activism among various external stakeholders, both nationally and internationally, about climate-related risks, 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 have considered initiatives to further restrict greenhouse gases to address global climate-related risks. 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. The United States withdrew from the Paris Agreement and the United Nations Framework Convention on Climate Change in January 2025 and 2026, respectively. The EPA has revised, and has proposed revisions to, compliance requirements under a number of federal environmental regulatory programs related to greenhouse gases; however, differences in energy policy priorities adopted by future presidential 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 CO 2 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-related risks 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.

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 and energy prices; operational performance of low- to zero-carbon resources; new transmission infrastructure; the ability to maintain system reliability; customer demand for energy including carbon-free energy; and constructive energy and economic policies, including those that address investment in energy infrastructure, global climate-related risks, 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, while still meeting load growth opportunities; 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 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 issued 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 interpretations 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.

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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 $33.1 billion (Ameren Missouri – up to $22.2 billion; Ameren Illinois – up to $8.3 billion; ATXI – up to $2.6 billion) of capital expenditures from 2026 through 2030. 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 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.

With respect to the transition of Ameren Missouri’s generation fleet 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 state or federal 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 or battery storage and acquire or construct those resources at a reasonable cost; the ability to enter into natural gas supply agreements at reasonable prices and adequate quantities to power Ameren Missouri’s natural gas-fired energy centers; 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 ability to maintain system reliability; new and/or changes in environmental regulations, including those related to CO 2 and other greenhouse gas emissions; energy prices; and demand. Also, changes to capacity accreditation rules adopted by the MISO could reduce the accredited capacity of renewable generation and battery storage and increase regional capacity prices, potentially requiring additional investment and higher costs to satisfy resource adequacy requirements. In addition, the presidential administration has issued executive orders and taken other actions to increase investment in fossil fuel infrastructure. This change in federal domestic energy policy has created uncertainty regarding the role existing renewable generation will play in supporting the United States’ energy grid and the timing and extent of future renewable generation infrastructure development. Ameren Missouri’s plan could be affected by this change in energy policy.

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;

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• 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, which could potentially increase if new data centers and/or other large primary service customers locate within our service territories;

• 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, 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-related risks, 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;

• the occurrence of catastrophic events such as fires, explosions, acts of sabotage, which in recent years 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, including generative and agentic artificial intelligence; and

• other unanticipated operations and maintenance expenses and liabilities.

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. Approximately 96% 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, 2025, coal inventory was near targeted levels at the Labadie Energy Center and at targeted levels at the Sioux Energy Center. 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;

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• 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;

• increased regulatory scrutiny and oversight resulting from more frequent outages;

• 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 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 could cause additional rate volatility and increases 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.

Realized energy demand from current and potential new customers may differ significantly from forecasts.

The Ameren Companies have historically experienced minimal growth in energy demand for the past two decades. However, current industry projections reflect the potential for significant growth in energy demand over the next decade, primarily arising from data centers and further augmented by onshoring and electrification of manufacturing and an increase in transportation electrification. In addition, in February 2026, Ameren Missouri executed electric service agreements with large load customers under its large load customer rate plan, representing 2.2 gigawatts of demand. The Ameren Companies may or may not experience the energy demand growth currently being forecasted depending on the decisions of potential new customers about whether to locate their operations within our service territories or whether customers that have signed electric service agreements begin operations within the expected timeframes. Also, demand growth may not be realized at the rate, or in the amount, expected if construction of customer facilities is not completed within expected timeframes, which is dependent on the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects. In addition, expected demand growth may not be realized if emerging technologies are not broadly adopted at the rate expected, increased efficiencies in computing or other advances in these technologies reduce energy demand for data centers, or large load customers, such as data centers,

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are not supported by local communities or do not receive necessary approvals by local municipalities. Although customers subject to the large load customer rate plan in Ameren Missouri’s service territory are required to sign agreements for specific term lengths to reasonably ensure rates they are charged reflect a representative share of the costs incurred to serve them, these customers could terminate their agreements early or reduce minimum capacity levels. These agreements include exit fees for early termination and fees for capacity reductions, but these fees may not fully mitigate this risk. Although assets constructed or acquired to serve these customers will also be used to serve other Ameren Missouri customers, early termination or capacity reductions could impact Ameren Missouri’s ability to fully recover its investment in, and return on, those assets. Also, the Ameren Companies may not be able to provide the necessary electric service, including both energy and capacity, within the time periods required by large load customers. The Ameren Companies may need to accelerate the addition of generation resources within current plans, obtain new generation resources, expand transmission or distribution facilities that are not currently within their plans, or purchase additional energy and capacity to meet the increase in demand. In addition, demand for construction services within the utility industry has increased significantly due to growing energy demand and energy transition, creating limited availability of suppliers, contractors, and developers, which could impact the Ameren Companies' ability to timely construct or acquire assets needed to meet forecasted demand. If the Ameren Companies are required to purchase energy and capacity to meet demand, their risk management and liquidity levels may not be effective at mitigating price impacts of such purchases, or there may not be sufficient energy and capacity available, either of which could negatively impact the Ameren Companies’ ability to realize forecasted or other potential demand. The Ameren Companies may not be able to plan, receive regulatory approvals, and execute those plans in a timely manner, which could result in the Ameren Companies not realizing forecasted or other potential demand.

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

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

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

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

• technological advancements that reduce energy consumption and demand;

• 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. 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 is a holding company and files a consolidated income tax return, it is reliant on its subsidiaries to pay the minimum tax once the threshold is exceeded. The payments related to the minimum tax by Ameren Missouri, Ameren Illinois, and ATXI are expected to be recovered, subject to approval by their respective regulators. 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.

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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 strategy focuses on disciplined cost management, including prudently monitoring all of our expenses. Higher than expected inflation levels could put pressure on the prices of labor, services, materials and supplies, and other costs. Higher inflation levels, as well as higher 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 $954 million as of December 31, 2025. 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, 2025, its investment performance in 2025, and its pension funding policy, Ameren expects to make annual contributions of approximately $45 million to $50 million in each of the next five years, with aggregate estimated contributions of $240 million . Ameren Missouri and Ameren Illinois estimate that their portion of the future funding requirements will be 35% and 45%, 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. In addition, rising energy and capacity prices, which are largely outside of our control, could impact customer affordability and satisfaction. Ameren Missouri’s and Ameren Illinois’ recent electric and natural gas regulatory rate reviews have resulted in increases in rates charged to customers which had an adverse impact on customer satisfaction and increased political pressures and media attention.

Our ability to successfully execute our strategic plan, including the transition of Ameren Missouri’s generation fleet 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 increased use of distributed generation by our customers. Any of these consequences could adversely affect our results of operations, financial position, and liquidity.

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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, 2025, approximately 22% 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%, 58%, and 54% of Ameren’s, Ameren Missouri’s and Ameren Illinois’ total employees, respectively. The Ameren Missouri collective bargaining unit contracts expire in 2026 and 2028, and cover 96% and 4% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2027 and 2029, and cover 8% and 92% of represented employees, respectively. Ameren Missouri and Ameren Illinois expect to renew these contracts prior to their expiration, however there can be no guarantee that such renewals will be secured on favorable terms. 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, social engineering 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, including data stored using cloud technologies, operational control, or exploitation of vulnerabilities specific to internally developed systems or to those provided and/or maintained by our suppliers. This also includes attacks arising from or generated by artificial intelligence, among various other attempts to compromise systems that can lead to security breaches. In addition, the increasingly widespread adoption of artificial intelligence technologies, including generative and agentic artificial intelligence, may increase, accelerate, or enhance 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, increasing interest rates, inflation, sanctions, trade restrictions, tariffs or trade wars, government or federal agency shutdowns, political

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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.

Language change vs prior 10-K

MD&A (Item 7) - words with the biggest YoY frequency increase

Negative rising

fired+3
defer+2
disallowances+2
challenged+2
loss+1

Positive rising

efficiency+6
progress+4
favorably+1
innovative+1
satisfy+1

MD&A (Item 7)

24,875 words

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, 2023, including comparisons with the year ended December 31, 2024, is included in Item 7 of our Form 10-K for the year ended December 31, 2024.

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 deliver on opportunities to benefit our customers, communities, and shareholders:

Investing in rate-regulated energy infrastructure

Enhancing regulatory frameworks and advocating for responsible policies

Optimizing operating performance

To deliver on opportunities to benefit our customers, communities, and shareholders

We invest in rate-regulated energy infrastructure and seek to earn competitive returns on our investments. We seek to make prudent investments that benefit our customers. The goal of these investments is to maintain and enhance the reliability of our services, develop and deliver cleaner sources of energy, create economic development opportunities in our region, and provide customers with more options and greater control over their energy usage, among other things. By prudently investing in our businesses, we believe that we deliver superior value to both customers and shareholders.

We seek to partner with our stakeholders, including our customers, communities, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers, communities, and shareholders. We believe enhancing our regulatory frameworks is important to drive investment in our business segments, earn competitive returns on those investments, and realize timely recovery of our costs with the benefits accruing to both customers and shareholders.

Utilizing a continuous improvement mindset, we seek to optimize operating performance for the benefit of our customers. We remain focused on disciplined cost management and strategic capital allocation. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators. We focus on minimizing the gap between allowed and earned ROEs and allocating capital resources to business opportunities that we expect will provide the most benefit to our customers and offer the most attractive risk-adjusted return potential.

Rate Base ($ in billions) (a)

Regulatory Frameworks (c)

Electric Customer Rates (g)

Segment

Regulatory Framework

Ameren

Transmission

Formula ratemaking with initial rates based on a future test year

Allowed ROE of 10.48%

Ameren Illinois

Electric

Distribution

Future test year ratemaking under an MYRP (d) and RBA

Allowed ROE of 8.72% (e)

Ameren Illinois

Natural Gas

Future test year ratemaking and PGA and VBA

Allowed ROE of 9.60%

Ameren

Missouri

Historical test year ratemaking (f) and

PISA, RESRAM, FAC, MEEIA, PGA

Allowed ROE is not specified

(a) Reflects year-end rate base except for Ameren Transmission, which is average rate base. Ameren Illinois Electric Distribution excludes electric energy-efficiency rate base.

(b) Compound annual growth rate.

(d) Ameren Illinois filed appeals of the December 2023, June 2024, and December 2024 orders in its MYRP proceeding. For more information on the MYRP proceeding, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(e) Through 2026, Ameren Illinois’ formula ratemaking framework related to energy-efficiency investments uses an allowed ROE of the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points, subject to performance standards discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(f) Pursuant to the PPRA, Ameren Missouri will be allowed to use a future test year, subject to MoPSC approval, to set natural gas delivery service rates beginning in July 2026. For more information on the PPRA, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(g) Average residential electric prices in cents per kilowatthour. Source: Edison Electric Institute, ‘Typical Bills and Average Rates Report’ for the 12 months ended June 30, 2025.

Key announcements, updates, and regulatory outcomes

The PPRA became effective in August 2025. The law includes certain provisions that affect the regulation of Ameren Missouri’s electric and natural gas businesses. These provisions create modifications to the PISA and integrated resource planning, require electric utilities to submit service tariff schedules for certain large load customers, allow the MoPSC to authorize inclusion of construction work in progress in rate base for new natural gas-fired generation facilities and new generation facilities approved through integrated resource planning, and allow natural gas utilities to file regulatory rate reviews using a future test year, among other things.

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In April 2025, the MoPSC issued an order in Ameren Missouri’s 2024 electric service regulatory rate review, approving nonunanimous stipulations and agreements. The order authorized an increase of $355 million to Ameren Missouri’s annual revenue requirement for electric retail service, effective June 1, 2025. The approved revenue requirement was based on infrastructure investments as of December 31, 2024. The order did not explicitly specify an ROE, capital structure, rate base, or any rate base disallowances. The order provides for the continued use of all existing riders and trackers. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect an increase in “Depreciation and amortization” of approximately $70 million, among other expense changes, on Ameren’s and Ameren Missouri’s consolidated statements of income.

In July 2025, the MoPSC issued an order in Ameren Missouri’s 2024 natural gas delivery service regulatory rate review, approving a unanimous stipulation and agreement. The order authorized an increase of $32 million to Ameren Missouri’s annual revenue requirement for natural gas delivery service, effective September 1, 2025. The order did not explicitly specify an ROE, capital structure, rate base, or any rate base disallowances. The order provides for the continued use of all of Ameren Missouri’s existing riders and trackers.

In November 2025, the MoPSC approved Ameren Missouri’s request to modify its existing large primary service tariff to require customers requesting 75 MWs or more of demand and who are served at transmission level voltage to comply with additional tariff terms. The additional terms include a service term of 12 years plus a ramp period of up to five years to reach peak demand, minimum demand charges of 80% of contracted capacity, customer exit terms and fees, and customer credit and collateral requirements, among other terms. In addition, new customer programs would be available under this tariff, which allow customers to support renewable generation, battery storage, and/or nuclear generation through incremental payments. The MoPSC order also includes an earnings sharing mechanism that would apply if Ameren Missouri’s earned ROE for a calendar year exceeds 9.74%, which can be adjusted by the MoPSC in future electric rate orders. If this were to occur, Ameren Missouri would defer 65% of the return in excess of the 9.74% ROE to a regulatory liability, which would be returned to retail electric customers in a future rate review. In addition, if large load customer revenues were reduced in a calendar year due to certain events, as determined by the MoPSC, Ameren Missouri may defer a portion of the reduced revenues to a regulatory asset to be included in its revenue requirement in the next electric rate review. In February 2026, Ameren Missouri executed electric service agreements with large load customers consistent with the tariff terms discussed above, representing 2.2 gigawatts of demand. Ameren and Ameren Missouri do not expect a material impact to their results of operations, financial position, or liquidity in 2026 related to these agreements.

In August 2025, Ameren Missouri filed for a CCN to construct the Reform Solar Project (250-MW facility). Ameren Missouri expects a decision by the MoPSC in the first half of 2026. In February 2026, the MoPSC issued an order approving a nonunanimous stipulation and agreement related to a requested CCN for the Big Hollow Natural Gas (800-MW facility) and the Big Hollow Battery Energy Storage (400-MW facility) projects. Also in February 2026, Ameren Missouri acquired the Split Rail Solar Project, which includes solar panels, project design, land rights, and engineering, procurement, and construction agreements, for approximately $600 million, and took over construction management of the project, which is expected to be placed in-service in the second quarter of 2026.

In February 2026, 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 2026. 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 $20.8 billion over the five-year period from 2026 through 2030, with expenditures largely recoverable under the PISA. The Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

In December 2024, the ICC issued an order in connection with a revised Grid Plan and a revised MYRP filed by Ameren Illinois in March 2024, approving revenue requirements for electric distribution services for 2024 through 2027 of $1,206 million, $1,287 million, $1,367 million, and $1,421 million, respectively. Rate changes consistent with the December 2024 order became effective in December 2024. In March 2025, Ameren Illinois filed an appeal of the ICC’s December 2024 order to the Illinois Appellate Court for the Fifth Judicial District to revise the allowed ROE and to include an asset associated with other postretirement benefits in the rate base, among other things. In addition, Ameren Illinois filed an appeal related to orders issued by the ICC in December 2023 and June 2024 related to the MYRP proceeding. The appellate court is under no deadline to address the appeals.

In December 2025, the ICC issued an order approving Ameren Illinois’ 2024 electric distribution service revenue requirement reconciliation adjustment filing. This order approved an adjustment increasing the allowed revenue requirement by $48 million, which reflected Ameren Illinois’ actual 2024 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 2026. In February 2026, the ICC denied Ameren Illinois’ rehearing request to include an asset associated with other postretirement benefits in the rate base, among other things. Ameren Illinois is assessing whether to pursue an appeal with the Illinois Appellate Court for the Fifth Judicial District in the first half of 2026.

In November 2025, the ICC issued an order in Ameren Illinois’ annual update filing that approved an electric customer energy-efficiency revenue requirement of $138 million beginning in January 2026, which represents an increase of $12 million from the 2025 revenue requirement. This order was based on a projected 2026 year-end rate base of $474 million .

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In August 2025, the ICC issued an order approving Ameren Illinois’ energy-efficiency plan that includes annual investments in electric energy-efficiency programs of approximately $126 million per year from 2026 through 2029. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs.

In January 2026, the CRGA was enacted and will become effective in June 2026. The law includes certain provisions that affect Ameren Illinois’ electric distribution and transmission businesses. These provisions increase the annual spending cap on energy-efficiency investments beginning in 2027 and modify the ROE component of the return on those investments.

In November 2025, the ICC issued an order in Ameren Illinois’ January 2025 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $79 million based on a 9.60% ROE, a capital structure composed of 50% common equity, a 2026 future test year, and a rate base of $3.2 billion. The order reflected a reduction of $75 million of planned distribution and transmission capital investments included in Ameren Illinois’ future test year request. The new rates became effective December 2025. In January 2026, Ameren Illinois filed an appeal of the ICC’s November 2025 order and the ICC’s January 2026 order rejecting Ameren Illinois’ rehearing request to the Illinois Appellate Court for the Fifth Judicial District. The appeal challenged the inclusion of the non-service cost component of the net periodic benefit income related to other postretirement benefits in the annual revenue requirement and the $75 million reduction of planned capital investments, among other things. The court is under no deadline to address the appeal .

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. In February 2026, Ameren’s board of directors increased the quarterly common stock dividend to 75 cents per share, resulting in an annualized equivalent dividend rate of $3.00 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.

Earnings

Net income attributable to Ameren common shareholders was $1,456 million, or $5.35 per diluted share, for 2025, and $1,182 million, or $4.42 per diluted share, for 2024. Net income was favorably affected in 2025, compared with 2024, by increased base rate revenues at Ameren Missouri effective June 1, 2025, pursuant to the April 2025 MoPSC electric rate order and decreased tax expense at Ameren Transmission, Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas due to the revaluation of excess deferred income tax regulatory liabilities. Earnings were also favorably affected by increased retail electric sales volumes at Ameren Missouri, primarily due to warmer July temperatures and colder winter temperatures in 2025, and by decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, because of the absence in 2025 of an Ameren Missouri charge related to the resolution of outstanding claims in the NSR and Clean Air Act litigation associated with the Rush Island Energy Center. Additionally, earnings were favorably affected by the increased deferral of financing costs related to rate base investments at Ameren Missouri and by increased infrastructure investments at Ameren Transmission and Ameren Illinois Electric Distribution. Net income was unfavorably affected in 2025 compared with 2024 by increased financing costs, primarily resulting from higher interest rates on higher debt balances at Ameren Missouri and Ameren (parent) and by increased 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, primarily due to higher vegetation management costs, higher storm costs, and higher energy center maintenance expenses. Additionally, earnings were unfavorably affected by an increase in the weighted-average basic common shares outstanding, which reduced earnings per diluted share.

Liquidity

At December 31, 2025, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $2.5 billion.

Ameren may offer and sell from time to time common stock, including under its ATM program, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. As of December 31, 2025, Ameren had approximately $1.5 billion of common stock remaining available for sale under the ATM program. As of December 31, 2025, Ameren had multiple forward sale agreements with various counterparties relating to 6.4 million shares of common stock, which it expects to settle in 2026. For information regarding long-term debt issuances and maturities, common stock issuances, and outstanding forward sale agreements, including those 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 2025 capital expenditures by segment and the midpoint of projected cumulative capital expenditures for 2026 through 2030 by segment:

2025 Capital Expenditures by Segment

(Total Ameren – $4.1 billion)

(in billions)

Midpoint of 2026 – 2030 Projected Capital

Expenditures by Segment (Total Ameren – $31.8 billion)

(in billions)

Ameren Missouri (a)

Ameren Illinois Natural Gas

Ameren Illinois Electric Distribution

Ameren Transmission (b)

For 2026 through 2030, Ameren’s cumulative capital expenditures are projected to range from $30.5 billion to $33.1 billion. The following table presents the range of projected spending by segment:

Range (in billions)

Ameren Missouri (a)

Ameren Illinois Electric Distribution

Ameren Illinois Natural Gas

Ameren Transmission (b)

Ameren (a)(b)

(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 .

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, 2025 and 2024:

Net income attributable to Ameren common shareholders

Earnings per common share – diluted

Net income attributable to Ameren common shareholders in 2025 increased $274 million, and $0.93 per diluted share, from 2024. The increase was due to net income increases of $188 million, $92 million, $47 million, and $9 million at Ameren Missouri, Ameren Transmission, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. These increases were partially offset by an increase in net loss of $62 million for activity not reported as part of a segment, primarily at Ameren (parent).

Earnings per diluted share in 2025, compared with 2024, were favorably affected by:

• increased base rate revenues at Ameren Missouri effective June 1, 2025, pursuant to the April 2025 MoPSC electric rate order and a lower base level of expenses, partially offset by financing costs otherwise recoverable under the PISA and RESRAM, depreciation and amortization on property, plant, and equipment previously eligible for deferral under the PISA and RESRAM, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (42 cents per share);

• decreased income tax expense at Ameren Transmission, Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas resulting from the revaluation of excess deferred income tax regulatory liabilities, resulting from TCJA for FERC-regulated and ICC-regulated jurisdictions, related to ratemaking treatment of net operating loss carryforwards by affiliates under a tax allocation agreement, see Note 12 – Income Taxes under Part II, Item 8, of this report for additional information (32 cents per share);

• increased retail electric sales volumes at Ameren Missouri, excluding customer energy-efficiency programs, primarily due to warmer July temperatures and colder winter temperatures, and growth in weather-normalized retail electric sales (estimated at 22 cents per share);

• the absence of a 2024 charge recorded by Ameren Missouri, included in other operation and maintenance expenses, related to a settlement agreement with the United States Department of Justice that 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 additional information (17 cents per share);

• increased base rate revenues at Ameren Missouri for the inclusion of previously deferred interest charges pursuant to the April 2025 MoPSC electric rate order effective June 1, 2025, and higher interest deferrals related to infrastructure investments associated with the PISA and RESRAM (17 cents per share);

• increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution (14 cents per share);

• the absence of the October 2024 FERC order reducing the allowed base ROE for FERC regulated transmission rate base and required refunds for certain prior periods under the MISO tariff, which increased Ameren Transmission earnings (4 cents per share); and

• a higher allowance for equity funds used during construction at Ameren Transmission (4 cents per share).

Earnings per diluted share in 2025, compared with 2024, were unfavorably affected by:

• increased financing costs primarily due to higher interest rates on higher debt balances at Ameren Missouri and Ameren (parent) (24 cents per share);

• increased other operations and maintenance expenses not subject to formula rates, riders, or trackers, excluding a 2024 charge related to the NSR and Clean Air Act litigation discussed above, largely because of higher vegetation management costs, higher storm costs, higher energy center maintenance expense, and higher cloud computing costs at Ameren Missouri (18 cents per share);

• increased weighted-average basic common shares outstanding resulting from issuances of common shares (8 cents per share); and

• increased losses related to equity method investments at Ameren Transmission and Ameren (parent) (4 cents per share).

The cents per share variances above are presented based on the weighted-average basic shares outstanding in 2024 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 2025 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

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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.

Below is Ameren’s table of income statement components by segment for the years ended December 31, 2025 and 2024:

Ameren

Missouri

Ameren

Illinois

Electric

Distribution

Ameren

Illinois

Natural Gas

Ameren

Transmission

Other /

Intersegment

Eliminations

Ameren

Electric revenues

Natural gas revenues

Fuel and purchased power

Natural gas purchased for resale

Other operations and maintenance expenses

Depreciation and amortization

Taxes other than income taxes

Operating income (loss)

Other income, net

Interest charges

Income (taxes) benefit

Net income (loss)

Noncontrolling interests – preferred stock dividends

Net income (loss) attributable to Ameren common shareholders

Electric revenues

Natural gas revenues

Fuel and purchased power

Natural gas purchased for resale

Other operations and maintenance expenses

Depreciation and amortization

Taxes other than income taxes

Operating income (loss)

Other income, net

Interest charges

Income (taxes) benefit

Net income (loss)

Noncontrolling interests – preferred stock dividends

Net income (loss) attributable to Ameren common shareholders

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Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2025 and 2024:

Ameren

Illinois

Electric

Distribution

Ameren

Illinois

Natural Gas

Ameren

Illinois

Transmission

Other /

Intersegment

Eliminations

Ameren Illinois

Electric revenues

Natural gas revenues

Purchased power

Natural gas purchased for resale

Other operations and maintenance expenses

Depreciation and amortization

Taxes other than income taxes

Operating income

Other income, net

Interest charges

Income taxes

Net income

Preferred stock dividends

Net income attributable to common shareholder

Electric revenues

Natural gas revenues

Purchased power

Natural gas purchased for resale

Other operations and maintenance expenses

Depreciation and amortization

Taxes other than income taxes

Operating income

Other income, net

Interest charges

Income taxes

Net income

Preferred stock dividends

Net income attributable to common shareholder

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Operating Revenues

The following table presents the increases (decreases) by Ameren segment for electric and natural gas revenues in 2025, compared with 2024:

2025 versus 2024

Ameren Missouri

Ameren Illinois

Electric Distribution

Ameren Illinois

Natural Gas

Ameren Transmission (a)

Other /Intersegment Eliminations

Ameren

Electric revenue change:

Base rates (estimate) (b)

Effect of weather (estimate) (c)

Retail sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)

RESRAM (d)

Rush Island Energy Center base rate revenue deferral

Securitized utility tariff bond surcharges

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

Ameren Illinois energy-efficiency program investment revenues

Other

Cost recovery mechanisms – offset in fuel and purchased power (e)

Other cost recovery mechanisms (f)

Total electric revenue change

Natural gas revenue change:

Base rates (estimate)

Effect of weather (estimate) (c)

Other

Cost recovery mechanisms – offset in natural gas purchased for resale (e)

Other cost recovery mechanisms (f)

Total natural gas revenue change

(a) Includes an increase in transmission revenues of $73 million in 2025, compared with 2024, 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) Changes in RESRAM revenues are largely offset in “Fuel and purchased power,” “Other operations and maintenance,” “Depreciation and amortization,” “Taxes other than income taxes,” or “Income taxes” on the statement of income.

(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 $41 million was due to changes in Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution (-$41 million). See 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 $1,128 million, or 17%, in 2025, compared with 2024 , due to increased revenues at Ameren Missouri, Ameren Illinois, and Ameren Transmission, as discussed below.

Ameren Transmission

Amer en Transmission’s electric revenues increased $81 million, or 10%, in 2025, compared with 2024. Revenues were favorably affected by higher recoverable expenses (+$47 million) and increased capital investment (+$24 million), as evidenced by a 7% increase in rate base used to calculate the revenue requirement. Additionally, revenues were favorably affected by the absence of the October 2024 FERC order that decreased base ROE for certain historical periods (+$10 million).

Ameren Missouri

Ameren Missouri’s electric revenues increased $784 million , or 20% , in 2025, compared with 2024.

The following items increased Ameren Missouri’s electric revenues in 2025, compared with 2024:

• “Off-system sales, capacity, transmission, and FAC revenues, net” increased $452 million, primarily due to summer capacity prices increasing from $30 per MW-day in 2024 to $667 per MW-day in 2025 pursuant to the April 2025 annual MISO capacity auction.

• Higher electric base rates, excluding the change in base rates for the MEEIA customer energy-efficiency programs and the RESRAM, resulting from the April 2025 MoPSC electric rate order effective June 1, 2025, increased revenues an estimated $249 million . See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the April 2025 MoPSC electric rate order.

• The effect of weather increased revenues an estimated $66 million primarily due to warmer July temperatures and colder winter temperatures.

• Revenues increased $46 million due to surcharges related to the servicing of securitized utility tariff bonds issued in December 2024 to finance costs related to the accelerated retirement of the Rush Island Energy Center. This increase in revenue is offset by increases in interest and amortization expense. See Variable Interest Entities in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.

• Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues increased an estimated $20 million, primarily due to increased retail sales volumes, partially offset by lower realized prices due to changes in customer usage patterns.

The following ite ms decreased Ameren Missouri’s electric revenues in 2025, compared with 2024:

• RESRAM revenues decreased $23 million. The changes in revenue are largely offset by changes in the “Depreciation and amortization” section of the statement of income.

• 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 deferral ended with new rates effective June 1, 2025.

• Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” decreased $12 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.

Ameren Illinois

Ameren Illinois’ electric revenues increased $342 million, or 13%, in 2025, compared with 2024, driven by increased revenues at Ameren Illinois Electric Distribution and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s revenues increased $310 million, or 15%, in 2025, compared with 2024.

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The following items increased Ameren Illinois Electric Distribution’s revenues in 2025, compared with 2024:

• Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $201 million, due to increased purchased power expenses recovered from customers. The increases in electric revenues are fully offset by increases in purchased power expenses under cost recovery mechanisms for purchased power, as discussed below.

• Base rates increased revenues by $96 million, due to higher recoverable non-purchased power expenses (+$76 million), increased capital investment (+$11 million), and the results of the 2024 annual revenue requirement reconciliation proceeding recognized in 2025

(+$9 million).

• Other revenues increased $18 million, primarily due to the recovery of and return on increased customer generation rebates and mutual assistance provided to Ameren Missouri for major storms experienced in 2025 throughout its service territory.

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

Other cost recovery mechanisms decreased revenues by $17 million, primarily due to lower bad debt costs on purchased receivables from alternative retail electric suppliers and environmental remediation revenues that are included in customer rates pursuant to their associated riders.

Ameren Illinois Transmission

Ameren Illinois Transmission’s revenues increased $73 million , or 13% , in 2025, compared with 2024. Base rate revenues were favorably affected by higher recoverable expen ses (+$48 million) and increased capital investment (+$18 million), as e videnced by an 8% increase in rate base used to calculate the revenue requirement . Additionally, revenues were favorably affected by the absence of the October 2024 FERC order that decreased base ROE for certain historical periods (+$7 million).

Natural Gas Revenues

Ameren

Ameren’s natural gas revenues increased $48 million , or 4% , in 2025, compared with 2024, due to increased revenues at Ameren Illinois Natural Gas and Ameren Missouri, as discussed below.

Ameren Missouri

Ameren Missouri’s natural gas revenues increased $18 million, or 12%, in 2025, compared with 2024, primarily due to colder winter temperatures and the effect of higher natural gas base rates as a result of the natural gas rate order effective September 1, 2025.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ revenues increased $30 million, or 3%, in 2025, compared with 2024. “Cost recovery mechanisms – offset in natural gas purchased for resale” increased revenues $23 million, due to a higher collection of natural gas costs previously deferred under the PGA. Changes in natural gas revenues under the PGA are fully offset by changes in natural gas purchased for resale expenses.

Fuel and Purchased Power

The following table presents the increases (decreases) by Ameren segment for fuel and purchased power in 2025, compared with 2024:

2025 versus 2024

Ameren Missouri

Ameren Illinois

Electric Distribution

Ameren Illinois

Natural Gas

Ameren Transmission

Other /Intersegment Eliminations

Ameren

Fuel and purchased power change:

Energy costs (excluding the estimated effect of weather)

Effect of weather (estimate) (a)

Transmission service charges

Other

Cost recovery mechanisms – offset in electric revenue (b)

Total fuel and purchased power change

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

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(b) “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 $41 million was due to changes in Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution (-$41 million). See 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 increased $625 million, or 37%, in 2025, compared with 2024, primarily due to increased fuel and purchased power expenses at Ameren Missouri and Ameren Illinois Electric Distribution, as discussed below.

Ameren Missouri

Ameren Missouri’s fuel and purchased power expenses increased $467 million, or 44%, in 2025, compared with 2024.

The following items increased Ameren Missouri’s fuel and purchased power expense in 2025, compared with 2024:

• Energy costs increased $459 million in 2025, compared with 2024, primarily due to summer capacity prices increasing from $30 per MW-day in 2024 to $667 per MW-day in 2025 pursuant to the April 2025 annual MISO capacity auction. Ameren Missouri’s 5% exposure to net energy cost variances under the FAC of $7 million is the difference between “Off-system sales, capacity, transmission, and FAC revenues, net” in electric revenues and “Energy costs (excluding the estimated effect of weather)”.

• Fuel and purchased power expenses increased an estimated $11 million due to an increase in electric retail sales related to weather.

• Transmission service charges (not included in the FAC) increased $10 million due to higher transmission rates related to increased revenue requirements of other MISO transmission operators.

“Cost recovery mechanisms — offset in electric revenue” decreased $12 million in 2025, compared with 2024, 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 increased $201 million, or 27%, in 2025, compared with 2024, primarily due to summer capacity prices increasing from $30 per MW-day in 2024 to $667 per MW-day in 2025 pursuant to the April 2025 annual MISO capacity auction (+$69 million), increased volumes (+$61 million), primarily due to residential and small commercial customers switching from alternative retail electric suppliers to Ameren Illinois’ supplied power, increases in transmission service charges (+$46 million), and increased energy prices (+$25 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 2025, compared with 2024:

2025 versus 2024

Ameren Missouri

Ameren Illinois

Electric Distribution

Ameren Illinois

Natural Gas

Ameren Transmission

Other /Intersegment Eliminations

Ameren

Natural gas purchased for resale change:

Effect of weather (estimate) (a)

Cost recovery mechanisms – offset in natural gas revenue (b)

Total natural gas purchased for resale change

(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 increased $28 million, or 9%, in 2025, compared with 2024, due to increased natural gas purchased for resale expenses at Ameren Illinois Natural Gas, as discussed below.

Ameren Missouri

Ameren Missouri’s natural gas purchased for resale expenses were comparable in 2025, compared with 2024.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ natural gas purchased for resale expenses increased $23 million, or 9%, in 2025, compared with 2024, due to the amortization of natural gas costs that were previously deferred under the PGA. 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 $5 Million

(a) Includes $74 million and $70 million at Ameren Transmission in 2025 and 2024, respectively, and other/intersegment eliminations of $(18) million and $– million in 2025 and 2024, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Ameren

Other operations and maintenance expenses increased $5 million in 2025, compared with 2024 because of the changes discussed below. In addition to changes by segments discussed below, other operations and maintenance expenses decreased $18 million for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above. This is primarily due to a decrease of $21 million in the elimination of the non-service cost component of net periodic benefit income and other miscellaneous income and expenses. The non-service cost component of net periodic benefit cost or income and other miscellaneous income and expenses at Ameren Services is allocated to the segments and primarily included in the segments’ other operations and maintenance expenses. The decreases are offset by the absence of a gain on the sale of land of $8 million that occurred in 2024.

Ameren Transmission

Other operations and maintenance expenses were comparable between periods.

Ameren Missouri

Other operations and maintenance expenses decreased $21 million in 2025, compared with 2024, primarily due to the following items:

• The absence in 2025 of a $59 million charge, related to the NSR and Clean Air Act litigation associated with the Rush Island Energy Center, see Note 14 - Commitments and Contingencies under Part II, Item 8, of this report for additional information.

• Expenses associated with the MEEIA customer energy-efficiency program decreased $23 million as approved by the MoPSC in November 2024.

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

• Non-nuclear generation operations and maintenance expenses, primarily at Sioux and Labadie energy centers, increased $16 million.

• Increased expense of $13 million for cloud-related software.

• Transmission and distribution expenditures, excluding major storm-related expenses, increased $12 million, largely due to increased vegetation management expenditures.

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• Injuries and damages increased $9 million, primarily due to an increase in claims compared to the prior year.

• Transmission and distribution storm-related expenses increased $8 million, primarily because of the major storms experienced throughout its service territory in 2025.

• Bad debts increased $6 million, primarily because of a decline in collections experience.

Ameren Illinois

Other operations and maintenance expenses increased $39 million at Ameren Illinois in 2025, compared with 2024, as discussed below.

Ameren Illinois Electric Distribution

Other operations and maintenance increased $37 million in 2025, compared with 2024, primarily due to the following items:

• Increased costs of $17 million resulting from expanding programs under CEJA.

• Distribution expenditures increased $10 million, primarily due to increased levels of reliability and other maintenance activity.

• Increased costs associated with customer energy-efficiency investments under formula ratemaking of $10 million, primarily due to amortization of regulatory assets.

• Increased expense of $8 million for cloud-related software.

• Increased costs related to demand response programs of $7 million.

• Injuries and damages increased $6 million, primarily due to an increase in claims compared to the prior year.

The above increases were partially offset by the following items:

• Bad debt costs on purchased receivables decreased $17 million, primarily because of a lower base level of expenses included in customer rates pursuant to the associated rider.

• Reduction in environmental remediation rider costs of $8 million.

Ameren Illinois Natural Gas

Other operations and maintenance costs were comparable between periods.

Ameren Illinois Transmission

Other operations and maintenance costs were comparable between periods.

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Depreciation and Amortization Expenses

Total by Segment (a)

Increase (Decrease) by Segment

Overall Ameren Decrease of $22 Million

(a) Includes other/intersegment eliminations of $8 million and $8 million in 2025 and 2024, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Depreciation and amortization expenses decreased $22 million and $57 million at Ameren and Ameren Missouri, respectively, and increased $33 million at Ameren Illinois. Ameren Illinois depreciation and amortization expenses increased primarily because of additional property, plant, and equipment investments. 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 absence of a 2024 deferral to a regulatory liability associated with production tax credits allowed under the IRA applicable to the Callaway Energy Center and the related amortization in 2025, which decreased depreciation and amortization expenses by $100 million.

• The higher net under-recovery of RESRAM eligible expenses and lower amortization of prior deferrals decreased depreciation and amortization expenses by $37 million.

• The absence of depreciation expense associated with the retirement of Ameren Missouri’s Rush Island Energy Center in 2024 decreased expenses by $27 million.

• Increased depreciation and amortization of $36 million due to the inclusion in base rates of property, plant, and equipment previously eligible for deferral to a regulatory asset under the PISA and RESRAM effective June 1, 2025, pursuant to the April 2025 MoPSC electric rate order.

• The amortization of a regulatory asset associated with the securitization of Ameren Missouri’s Rush Island Energy Center increased depreciation and amortization expenses by $22 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. Base rates were updated to include the eligible property, plant, and equipment in-service through December 31, 2024, when new customer rates became effective on June 1, 2025, pursuant to the April 2025 MoPSC electric rate order. The effect of rebasing PISA and increased amortization of prior PISA deferrals, increased depreciation and amortization by $14 million.

• Increased amortization and lower deferral pursuant to a tracker related to certain excess deferred income taxes, which increased depreciation and amortization expenses by $13 million.

• Depreciation and amortization rate changes effective June 1, 2025, pursuant to the April 2025 MoPSC electric rate order, which increased depreciation and amortization expenses by $9 million.

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Taxes Other Than Income Taxes

Total by Segment (a)

Increase (Decrease) by Segment

Overall Ameren Increase of $30 Million

(a) Includes $9 million and $9 million at Ameren Transmission in 2025 and 2024, respectively, and other/intersegment eliminations of $11 million and $13 million in 2025 and 2024, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Taxes other than income taxes increased $30 million in 2025, compared with 2024, primarily because of an increase of $21 million, $7 million, and $4 million at Ameren Missouri, Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively. Taxes other than income taxes increased primarily due to an increase in gross receipts taxes of $20 million, $6 million, and $4 million at Ameren Missouri, Ameren Illinois Natural Gas, and Ameren Illinois Electric Distribution, respectively, resulting from increased retail electric and natural gas sales.

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Other Income, Net

Total by Segment

Decrease by Segment

Overall Ameren Decrease of $70 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, decreased $70 million in 2025, compared with 2024. In addition to the changes discussed below, other income, net, decreased $36 million for activity not reported as part of a segment, due to a decrease of $20 million in the non-service cost component of net periodic benefit income and a decrease of $6 million in income from equity method investments, primarily associated with investments to advance innovative energy technologies.

Ameren Transmission

Other income, net, decreased $2 million in 2025, compared with 2024, primarily due to a $9 million impairment of an equity method investment and a decreas e of $5 million for individually insignificant items. These decreases were offset by a $12 million increase in the allowance for equity funds used during construction, primarily resulting from a decreased level of short-term borrowings included in the calculation and higher average construction work in progress balances.

Ameren Missouri

Other income, net, decreased $16 million in 2025, compared with 2024, primarily due to a decrease of $13 million in the reduction in non-service cost component of net periodic benefit income and an increase of $5 million in charitable donations.

Ameren Illinois

Other income, net, decreased $11 million in 2025, compared with 2024, primarily due to a decrease of $24 million in the non-service cost component of net periodic benefit income, largely at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas. The decreases are partially offset by a $13 million increase in the allowance for equity funds used during construction, largely at Ameren Illinois Transmission.

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Interest Charges

Total by Segment

Increase by Segment

Overall Ameren Increase of $113 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 $113 million in 2025, compared with 2024. In addition to changes by segments discussed below, interest charges increased $46 million at Ameren (parent), because of increased levels of short-term borrowings that increased interest charges by $20 million. Additionally, interest charges increased $25 million at Ameren (parent), due to a long-term debt issuance in March 2025, partially offset by the repayment of a senior unsecured note in September 2024.

Ameren Transmission

Interest charges were comparable between periods.

Ameren Missouri

Interest charges increased $53 million in 2025, compared with 2024, primarily due to the issuances of long-term debt in April 2024, October 2024, and April 2025 which increased interest by $45 million. Interest charges also increased by $22 million due to the December 2024 issuance of securitized utility tariff bonds associated with the retirement of the Rush Island Energy Center, see Note 5 - Long-Term Debt and Equity Financing under Part II, Item 8, in this report for more information. Additionally, the amount of interest charges included in base rates for PISA and RESRAM was updated when new customer rates became effective on June 1, 2025, pursuant to the April 2025 MoPSC electric rate order. Lower deferrals due to the inclusion in base rates of interest associated with certain property, plant, and equipment previously deferred under the PISA and RESRAM increased interest charges by $30 million.

The above increases were partially offset by interest charges that reflected a deferral to a regulatory asset of interest associated with investments in eligible property, plant and equipment not yet reflected in rates pursuant to PISA and RESRAM, which decreased interest charges by $44 million.

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Ameren Illinois

Interest charges increased $19 million in 2025, compared with 2024, primarily due to the following:

Ameren Illinois Transmission

Interest charges increased by $8 million, p rimarily because of issuances of long-term debt in March and September 2025 and June 2024, which increased interest expense by $14 million. The increases were partially offset by $3 million due to a lower interest rate on decreased levels of borrowing on short-term debt and by $3 million due to the maturity of a senior secured note in June 2025.

Ameren Illinois Electric Distribution

Interest charges increased by $9 million, primarily because of issuances of long-term debt in March and September 2025 and June 2024, which increased interest expense by $16 million. The increases were partially offset by $3 million due to the maturity of a senior secured note in June 2025 and by $2 million due to a lower interest rate on decreased levels of borrowing on short-term debt.

Ameren Illinois Natural Gas

Interest charges were comparable between periods.

Income Taxes

The following table presents effective income tax rates for the years ended December 31, 2025 and 2024:

Ameren

Ameren Missouri

Ameren Illinois

Ameren Illinois Electric Distribution

Ameren Illinois Natural Gas

Ameren Illinois Transmission

Ameren Transmission

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

The effective tax rate was lower at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, Ameren Illinois Transmission, and Ameren Transmission compared with the prior year due to a revaluation of excess deferred income tax regulatory liabilities in 2025. In 2024, the IRS issued a series of private letter rulings to another taxpayer, which provided guidance on applying IRS normalization rules to the calculation of tax benefits applicable to the ratemaking treatment related to net operating loss carryforwards. The rulings concluded that, for ratemaking purposes, net operating loss carryforwards should be reflected on a separate company basis and should not be reduced by payments received for the utilization of losses by other affiliates under a tax allocation agreement. In 2025, the FERC issued an order reflecting implementation of the rules for the other taxpayer who had a similar fact pattern as Ameren Illinois and ATXI. In addition, in 2025, the ICC issued orders in Ameren Illinois’ 2024 electric distribution service revenue requirement reconciliation adjustment proceeding and in its January 2025 natural gas rate review addressing the impacts of the private letter rulings. Accordingly, in 2025, Ameren and Ameren Illinois decreased income tax expense by $86 million and $61 million, respectively, to reflect the revaluation of excess deferred income tax regulatory liabilities resulting from TCJA for FERC-regulated and ICC-regulated jurisdictions pursuant to IRS guidance and recent FERC and ICC orders.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash provided by operating activities, we use available cash, drawings under committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). In addition, to support a portion of its fuel requirements for generation, Ameren Missouri has entered into various long-term commitments to meet these requirements. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. Ameren’s, Ameren Missouri’s, and Ameren Illinois’ estimated minimum purchase obligations associated with these commitments totaled $2.1 billion, $1.0 billion, and, $1.1 billion, respectively, which include $0.8 billion, $0.3 billion, and $0.5 billion,

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respectively, in 2026. Further, for additional information about Ameren’s and Ameren Missouri’s obligations associated with operating leases, see Note 15 – Supplemental Information.

We expect to make significant capital expenditures over the next five years, as discussed in the Capital Expenditures sections below, supported by a combination of long-term debt and equity, as we invest in our electric and natural gas utility infrastructure to support expected increases in demand, overall system reliability, grid modernization, renewable energy target requirements, and other improvements. For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2030. Additionally, Ameren may offer and sell from time to time common stock, including under its ATM program, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. During 2025, Ameren issued a total of 5.8 million shares of common stock and received aggregate proceeds of $530 million under the ATM program. As of December 31, 2025, Ameren had multiple forward sale agreements with various counterparties relating to 6.4 million shares of common stock, which it expects to settle in 2026. Ameren’s equity financing plan is estimated to be approximately $4 billion from 2026 to 2030. This plan includes equity issuances under forward sales agreements, the DRPlus, and employee benefit plans, and could include issuances of hybrid debt securities. Ameren expects the financing plans to be aligned with the timing of generation investments. In August 2025, Ameren increased the amount of common stock available for sale under the ATM program by $1.25 billion to a total of $3 billion. As of December 31, 2025, Ameren had approximately $1.5 billion of common stock remaining available for sale under the ATM program. The Ameren Companies expect their equity to total capitalization and cash flow metrics to support solid investment-grade credit ratings. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the ATM program and forward sale agreements relating to common stock, including those under the ATM program.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the years ended December 31, 2025 and 2024:

Net Cash Provided By

Operating Activities

Net Cash Used In

Investing Activities

Net Cash Provided By

Financing Activities

Variance

Ameren

Ameren Missouri

Ameren Illinois

(a) Both Ameren and Ameren Illinois’ cash provided by operating activities included cash outflows of $123 million and $125 million for the electric energy-efficiency rider and $54 million and $39 million for the customer generation rebate program in 2025 and 2024, respectively.

Cash Flows from Operating Activities

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

Ameren

Ameren’s cash provided by operating activities increased $590 million in 2025, compared with 2024. The following items contributed to the increase:

• A $636 million increase resulting from higher customer collections primarily from higher electric and natural gas sales volumes due to warmer July temperatures and colder winter temperatures in 2025, increased base rates at Ameren Missouri effective June 1, 2025, pursuant to the April 2025 MoPSC electric rate order, and at Ameren Illinois, electric distribution and transmission base rate increases and higher customer collections under cost recovery mechanisms.

• A $219 million increase due to the transfer of production and investment tax credits to unrelated parties.

• A $27 million increase due to the timing of payments for spent nuclear fuel storage and reimbursements from the DOE.

• A $24 million increase due to the timing of payments for accounts payable.

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

• A $144 million increase in interest payments, primarily due to higher average outstanding debt and interest rates on long-term debt.

• A $43 million increase in payments for the spring 2025 refueling and maintenance outage at the Callaway Energy Center. There was no outage in 2024.

• A $29 million increase in gross receipts tax payments due to an increase in sales in 2025 compared to 2024.

• A $25 million increase in payments for coal deliveries, primarily due to increased generation at Ameren Missouri’s coal-fired energy centers in 2025.

• A $23 million increase in payments to contractors at Ameren Illinois, primarily related to higher levels of reliability and other maintenance activity and costs to comply with the CEJA.

• A $22 million decrease due to the absence of insurance proceeds received in 2024 related to workers’ compensation claims at Ameren Illinois.

• Ameren Missouri paid $19 million during 2025 to fund mitigation programs ordered in the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

• A $14 million increase in restoration expenses related to major storms in 2025.

• A $10 million increase in the cost of natural gas held in storage, primarily at Ameren Illinois, due to changes in the market price of natural gas.

Ameren Missouri

Ameren Missouri’s cash provided by operating activities increased $280 million in 2025, compared with 2024. The following items contributed to the increase:

• A $219 million increase due to the transfer of production and investment tax credits to unrelated parties.

• A $218 million increase resulting from higher customer collections primarily from higher electric sales volumes due to warmer July temperatures and colder winter temperatures in 2025 and increased base rates effective June 1, 2025, pursuant to the April 2025 MoPSC electric rate order, partially offset by lower customer collections under cost recovery mechanisms.

• A $27 million increase due to the timing of payments for spent nuclear fuel storage and reimbursements from the DOE.

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

• A $68 million increase in interest payments, primarily due to higher average outstanding debt and interest rates on long-term debt.

• A $43 million increase in payments for the spring 2025 refueling and maintenance outage at the Callaway Energy Center. There was no outage in 2024.

• A $25 million increase in payments for coal deliveries, primarily due to increased generation at coal-fired energy centers in 2025.

• Payments of $19 million during 2025 to fund mitigation programs ordered in the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

• A $17 million increase in gross receipts tax payments due to an increase in sales in 2025 compared to 2024.

• An $11 million decrease due to the timing of payments for accounts payable.

• An $8 million increase in restoration expenses related to major storms in 2025.

Ameren Illinois

Ameren Illinois’ cash provided by operating activities increased $129 million in 2025, compared with 2024 primarily due to a $410 million increase resulting from higher customer collections primarily from higher electric and natural gas distribution sales volumes due to warmer July temperatures and colder winter temperatures in 2025, electric distribution and transmission base rate increases, and higher customer collections under cost recovery mechanisms.

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

• A $164 million increase in income tax payments to Ameren (parent), pursuant to the tax allocation agreement, primarily due to higher taxable income compared to 2024. Taxable income was lower in 2024 due to the adoption of IRS guidance that provided a safe harbor method of accounting for the capitalization or deduction of certain expenditures to maintain, repair, replace, or improve natural gas distribution property. The adoption of this guidance resulted in an adjustment for all years prior to 2024.

• A $29 million increase in interest payments, primarily due to higher average outstanding long-term debt and interest rates on long-term debt.

• A $23 million increase in payments to contractors, primarily related to higher levels of reliability and other maintenance activity and costs to comply with the CEJA.

• A $22 million decrease due to the absence of insurance proceeds received in 2024 related to workers’ compensation claims.

• A $12 million increase in gross receipts tax payments due to an increase in sales in 2025 compared to 2024.

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• A $9 million increase in the cost of natural gas held in storage due to changes in the market price of natural gas.

• A $6 million increase in restoration expenses related to major storms in 2025.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities decreased $311 million during 2025, compared with 2024, primarily as a result of a $191 million decrease in capital expenditures, largely resulting from the completion of the Cass County, Boomtown, and Huck Finn energy centers at Ameren Missouri in 2024. In addition, Ameren’s cash used in investing activities also decreased by $54 million due to a withdrawal of funds related to the cash surrender value of COLI and by $45 million due to the timing of nuclear fuel expenditures at Ameren Missouri.

Ameren Missouri’s cash used in investing activities decreased $369 million during 2025, compared with 2024, primarily as a result of a $210 million decrease in capital expenditures, largely resulting from the completion of the Cass County, Boomtown, and Huck Finn energy centers in 2024. Ameren Missouri’s cash used in investing activities also decreased as a result of an $86 million decrease in money pool advances, net, and $45 million due to the timing of nuclear fuel expenditures.

Ameren Illinois’ cash used in investing activities increased $18 million during 2025, compared with 2024, due to an increase in capital expenditures, largely resulting from increased expenditures for natural gas and electric distribution infrastructure upgrades as well as increased expenditures related to major storms, partially offset by decreased expenditures for electric transmission infrastructure.

Capital Expenditures

The following charts present our capital expenditures for the years ended December 31, 2025 and 2024:

2025 – Total Ameren $4,128 (a)

2024 – Total Ameren $4,319 (a)

Ameren Missouri

Ameren Illinois Natural Gas

ATXI and other electric transmission subsidiaries

Ameren Illinois Electric Distribution

Ameren Illinois Transmission

(a) Includes Other capital expenditures of $(9) million and $6 million for the years ended December 31, 2025 and 2024, respectively, which includes amounts for the elimination of intercompany transfers.

Ameren’s 2025 capital expenditures consisted of expenditures made by its subsidiaries, including $154 million by ATXI and other electric transmission subsidiaries. Ameren’s 2024 capital expenditures consisted of expenditures made by its subsidiaries, including $134 million by ATXI and other electric transmission subsidiaries. In both years, capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects.

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The following table presents Ameren’s estimate of capital expenditures that will be incurred from 2026 through 2030, including construction expenditures and allowance for funds used during construction:

Total

Ameren Missouri

Ameren Illinois Electric Distribution

Ameren Illinois Natural Gas

Ameren Illinois Transmission

ATXI and other electric transmission subsidiaries

Other

Ameren

Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, primarily renewable and natural gas generation and battery storage, consistent with the 2025 Change to the 2023 PRP. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments.

Ameren Missouri continually reviews its generation portfolio and expected power needs, including estimates of future load growth. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments within and outside our service territories. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, future rate orders, and our ability and willingness to pursue transmission investments, as well as our ability to obtain necessary regulatory approvals, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.

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 2024 in advance of transmission line construction, which is expected to begin in spring 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. Also in 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. The remaining competitive bid projects that have not been awarded are estimated to cost $4.4 billion, which includes projects located in Illinois that are estimated to cost $1.7 billion, based on the MISO’s cost estimate. The competitive bid process is expected to continue through 2026.

Environmental Capital Expenditures

Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO 2 , NO x , CO 2 , and mercury emissions from its coal-fired energy centers and compliance with the CCR Rule. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws that affect, or may affect, our facilities and capital expenditures to comply with such laws.

Cash Flows from Financing Activities

Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the level of dividends, and our long-term debt maturities, among other things.

Ameren’s cash provided by financing activities decreased $865 million during 2025, compared with 2024. During 2025, Ameren utilized net proceeds from the issuance of long-term debt of $2.0 billion for general corporate purposes and to repay $300 million of long-term debt maturities and then-outstanding short-term debt. During 2025, Ameren also repaid net short-term debt of $499 million. In addition, Ameren

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utilized aggregate cash proceeds of $574 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, along with cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2024, Ameren utilized net proceeds of $2.5 billion from the issuance of long-term debt for capital expenditures, to repay then-outstanding short-term debt, to repay $49 million of maturities of long-term debt at ATXI, and to finance energy transition 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. In addition, during 2024, Ameren utilized proceeds from net commercial paper issuances of $607 million , aggregate cash proceeds of $273 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and cash provided by operating activities to repay $800 million of long-term debt maturities at Ameren (parent) and Ameren Missouri, and to fund, in part, capital expenditures. During 2025, Ameren paid common stock dividends of $768 million, compared with $714 million in dividend payments in 2024.

Ameren Missouri’s cash provided by financing activities decreased $605 million during 2025, compared with 2024. During 2025, Ameren Missouri utilized net proceeds of $500 million from the issuance of long-term debt to repay then-outstanding short-term debt. In addition, during 2025, Ameren Missouri utilized proceeds from net commercial paper issuances of $471 million and cash provided by operating activities to fund, in part, capital expenditures. I n comparison, in 2024, Ameren Missouri utilized net proceeds of $1.8 billion from the issuance of long-term debt for capital expenditures and to repay then-outstanding short-term debt, and to finance energy transition 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 . In addition, during 2024, Ameren Missouri repaid $350 million of long-term debt maturities, $170 million of net commercial paper borrowings, and $306 million of money pool borrowings. During 2024 , Ameren Missouri also utilized capital contributions from Ameren (parent) of $476 million along with cash provided by operating activities to fund, in part, capital expenditures. During 2025, Ameren Missouri also paid common stock dividends of $196 million.

Ameren Illinois’ cash provided by financing activities decreased $137 million during 2025, compared with 2024. During 2025, Ameren Illinois utilized net proceeds of $711 million from the issuance of long-term debt to repay $300 million of long-term debt maturities and then-outstanding short-term debt. Ameren Illinois also repaid net commercial paper borrowings of $71 million and money pool borrowings of $37 million. In comparison, in 2024, Ameren Illinois utilized net proceeds of $624 million from the issuance of long-term debt to repay then-outstanding short-term debt. In addition, Ameren Illinois repaid net commercial paper borrowings of $277 million and money pool borrowings of $98 million. During 2024 , Ameren Illinois also utilized capital contributions from Ameren (parent) of $36 million along with cash provided by operating activities to fund, in part, capital expenditures. During 2025, Ameren Illinois paid common stock dividends of $265 million, compared with $110 million in dividend payments in 2024.

Short-term Debt and Liquidity

The liquidity needs of the Ameren Companies are supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, commercial paper issuances, Ameren’s money pool arrangements and related borrowings, and relevant interest rates.

The following table presents Ameren’s consolidated net available liquidity as of December 31, 2025:

Available at

December 31, 2025

Ameren (parent) and Ameren Missouri (a) :

Missouri Credit Agreement – borrowing capacity

Less: Ameren (parent) commercial paper outstanding

Less: Ameren Missouri commercial paper outstanding

Less: Letters of credit

Missouri Credit Agreement – subtotal

Ameren (parent) and Ameren Illinois (b) :

Illinois Credit Agreement – borrowing capacity

Less: Ameren (parent) commercial paper outstanding

Less: Ameren Illinois commercial paper outstanding

Less: Letters of credit

Illinois Credit Agreement – subtotal

Subtotal

Cash and cash equivalents

Net available liquidity (c)

(a) The maximum aggregate amount available to both Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $1.6 billion.

(b) The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the Illinois Credit Agreement is $800 million and $1.1 billion, respectively.

(c) Does not include Ameren’s forward equity sale agreements. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.

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In December 2025, the Credit Agreements, which were scheduled to mature in December 2028, were extended and now mature in December 2030. The Credit Agreements provide $3.2 billion of credit through December 2030. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on the Credit Agreements. During the year ended December 31, 2025, Ameren (parent), Ameren Missouri, and Ameren Illinois each issued commercial paper. Borrowings under the Credit Agreements and commercial paper issuances are based upon available interest rates at that time of the borrowing or issuance.

Ameren has a money pool agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option has the lowest interest rates.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval under the Federal Power Act. In January 2025, the FERC issued orders authorizing ATXI to issue up to $500 million of short-term debt securities through January 2027. In December 2025, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to issue up to $1.6 billion and $1.1 billion, respectively, of short-term debt securities through December 2027.

The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements for changing business conditions. When business conditions warrant, changes may be made to the existing Credit Agreements or to other borrowing arrangements, or other arrangements may be made.

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Long-term Debt and Equity

The following table presents Ameren’s issuances (net of any issuance premiums or discounts) of long-term debt and equity, as well as redemptions and maturities of long-term debt for the years ended December 31, 2025 and 2024. For additional information related to the terms and uses of these issuances and effective registration statements, and Ameren’s forward sale agreements relating to common stock, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. For information on capital contributions received by Ameren Missouri and Ameren Illinois from Ameren (parent), see Note 13 – Related-party Transactions under Part II, Item 8, of this report.

Month Issued, Redeemed, Repurchased, or Matured

Issuances of Long-term Debt

Ameren:

5.375% Senior unsecured notes due 2035

March

Ameren Missouri:

5.25% First mortgage bonds due 2054

January

5.25% First mortgage bonds due 2035

April

5.20% First mortgage bonds due 2034

April

5.125% First mortgage bonds due 2055

October

4.85% Securitized utility tariff bonds due 2039 (a)

December

Ameren Illinois:

5.625% First mortgage bonds due 2055

March

5.55% First mortgage bonds due 2054

June

5.625% First mortgage bonds due 2055

September

ATXI:

5.17% Senior unsecured notes due 2039

August

5.42% Senior unsecured notes due 2053

August

Total Ameren long-term debt issuances

Issuances of Common Stock

Ameren:

DRPlus and 401(k) (b)(c)

Various

ATM program (d)

Various

Total Ameren common stock issuances (e)

Maturities of Long-term Debt

Ameren:

2.50% Senior unsecured notes due 2024

September

Ameren Missouri:

3.50% Senior secured notes due 2024

April

4.85% Securitized utility tariff bonds due 2039 (a)

October

Ameren Illinois:

3.25% First mortgage bonds due 2025

June

ATXI:

3.43% Senior unsecured notes due 2050

August

Total Ameren long-term debt maturities

(a) These securitized utility tariff bonds were issued by AMF. The securitized tariff bondholders have no recourse to Ameren Missouri.

(b) Ameren issued a total of 0.4 million and 0.5 million shares of common stock under its DRPlus and 401(k) plan in 2025 and 2024, respectively.

(d) Ameren issued 5.8 million and 2.9 million shares of common stock under the ATM program in 2025 and 2024, respectively.

(e) Excludes 0.3 million and 0.2 million shares of common stock valued at $25 million and $16 million issued for no cash consideration in connection with stock-based compensation in 2025 and 2024, respectively.

(f) Excludes Ameren (parent)’s 2025 and 2024 purchases of senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois for $24 million and $44 million in the aggregate, respectively.

The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

At December 31, 2025, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings

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under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreements.

We consider access to short-term and long-term capital and credit markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital and credit markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital and credit markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital and credit markets or make access to the capital and credit markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital and credit markets.

Dividends

Ameren paid to its shareholders common stock dividends totaling $768 million, or $2.84 per share, in 2025 and $714 million, or $2.68 per share, in 2024. The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 50% and 60% of earnings over the next few years. On February 6, 2026, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 75 cents per share, payable on March 31, 2026, to shareholders of record on March 10, 2026.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances.

Ameren Illinois’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions with respect to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in the capital structure at Ameren Illinois.

Ameren Missouri and Ameren Illinois, as well as certain other nonregistrant Ameren subsidiaries, are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and from retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on their respective stock unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.

At December 31, 2025, the amount of restricted net assets of Ameren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $4.6 billion.

The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren subsidiaries to their parent, Ameren:

Ameren

Ameren Missouri

Ameren Illinois

ATXI

Ameren Missouri and Ameren Illinois each have issued preferred stock, which provide for cumulative dividends. Each company’s board of directors considers the declaration of preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.

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Credit Ratings

Our credit ratings affect our liquidity, our access to the capital and credit markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.

The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:

Moody’s

Ameren:

Issuer/corporate credit rating

Baa1

BBB+

Senior unsecured debt

Baa1

BBB

Commercial paper

Ameren Missouri:

Issuer/corporate credit rating

Baa1

BBB+

Secured debt

Commercial paper

AMF securitized utility tariff bonds

Aaa

AAA

Ameren Illinois:

Issuer/corporate credit rating

BBB+

Secured debt

Commercial paper

ATXI:

Issuer credit rating

Not Rated

Senior unsecured debt

Not Rated

A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

Collateral Postings

Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties were immaterial and cash collateral posted by external parties was $70 million for Ameren and Ameren Illinois at December 31, 2025. A sub-investment-grade issuer or senior unsecured debt rating (below “Baa3” from Moody’s or below “BBB-” from S&P) at December 31, 2025, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade and contractual obligations amounting to $1.2 billion, $1.1 billion, and $57 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2025, if market prices were 15% higher or lower than December 31, 2025 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade and contractual obligations.

Environmental Matters

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; regulate the handling and disposal of hazardous substances and waste materials; establish siting and land use requirements; and protect against ecological impacts. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws, including those that relate to climate-related risks, that affect, or may affect, our facilities, operations, and capital expenditures to comply with such laws. The combined effects of compliance with existing and future environmental regulations could result in significant capital expenditures, increased operating costs, and the potential for closure or alteration of operations at some of Ameren Missouri’s energy centers.

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

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increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius. The United States withdrew from the Paris Agreement and the United Nations Framework Convention on Climate Change in January 2025 and 2026, respectively. The EPA has revised, and has proposed revisions to, compliance requirements under a number of federal environmental regulatory programs related to greenhouse gases; however, differences in energy policy priorities adopted by future presidential administrations could result in additional greenhouse gas reduction requirements in the United States.

OUTLOOK

Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2026 and beyond. For additional information regarding recent rate orders, lawsuits, and pending requests filed with state and federal regulatory commissions, including those discussed below, see Note 2 – Rate and Regulatory Matters and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

Operations

• The PPRA became effective in August 2025. The law made modifications to integrated resource planning, which requires Missouri electric utilities to file plans for meeting their customers' long-term energy needs. By August 2027, the MoPSC will publish a schedule for Missouri electric utilities to file integrated resource plans every four years. The MoPSC will be required to issue an order on the plans and shall determine whether the electric utility has submitted sufficient documentation and selected preferred resource plans representing a reasonable and prudent means of serving the utility's load obligations at just and reasonable rates. In making this determination, the MoPSC shall consider whether the plans appropriately balance specific factors described in the law. If the MoPSC approves the plans, requests for CCNs for new generation facilities to be constructed or acquired as a part of the approved plans shall be deemed necessary and convenient and the scope of the CCN proceedings to review projects will be limited. The approved generation facilities will also be eligible to include construction work in progress in rate base, subject to MoPSC approval, which would improve the timeliness of cash recovery. Utilities are not allowed to capitalize allowance for funds used during construction on amounts included in rate base under this provision. The amount of construction work in progress to be included in rate base is limited to prudently incurred expenditures made within the construction period for the facility. Separately, outside of the integrated resource planning process discussed above, the law allows a Missouri electric utility to request that the MoPSC authorize the inclusion of construction work in progress for new natural gas-fired generation facilities in rate base, subject to the same restrictions discussed above. The provisions allowing for the inclusion of construction work in progress on natural gas-fired generation in rate base expire in December 2035, unless Ameren Missouri requests and receives MoPSC approval of an extension through 2045. Also, beginning in July 2026 the law allows natural gas utilities to file regulatory rate reviews using a future test year, subject to MoPSC approval. If a natural gas utility is allowed to use a future test year, a reconciliation of the actual rate base and certain forecasted costs will be performed 45 days after the end of the test year. If a given year’s actual revenue requirement is less than the revenue requirement approved by the MoPSC due to changes in rate base or certain other costs, an adjustment is made to reduce natural gas operating revenues with an offset to a regulatory liability to reflect that test year’s amounts. The regulatory liability will then be refunded to customers in the next regulatory rate review and will accrue carrying costs at the applicable WACC. The law also made modifications to the PISA and requires electric utilities to submit service tariff schedules for certain large load customers as discussed below.

• The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense for investments in qualifying property, plant, and equipment placed in service and not included in base rates. Investments not eligible for recovery under the PISA include amounts related to new nuclear generation facilities and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on 85% of rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC until added to rate base prospectively. Ameren Missouri recognizes an offset to “Interest Charges” on its consolidated statement of income for its carrying cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its carrying cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service to comply with Missouri’s renewable energy standard. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases caused by the inclusion of incremental PISA deferrals in the revenue requirement. Pursuant to the PPRA discussed above, Ameren Missouri’s PISA election was extended through 2035 and an additional extension through 2040 is allowed if requested by Ameren Missouri and approved by the MoPSC. This law also reduced the 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

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revenue requirement. The annual limit in effect was 2.5% and changed to 2.25%, prorated monthly, for revenue requirements approved by the MoPSC after August 2025. Ameren Missouri expects significantly higher investments in infrastructure eligible for PISA and AFUDC in 2026, compared to 2025.

• In April 2025, the MoPSC issued an order that authorized an increase of $355 million to Ameren Missouri’s annual revenue requirement for electric retail service, effective June 1, 2025. The order changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect an increase in “Depreciation and amortization” of approximately $70 million, among other expense changes, on Ameren’s and Ameren Missouri’s consolidated statements of income. As a result of this order, Ameren Missouri expects a year-over-year increase to 2026 earnings, compared to 2025, of approximately $30 million.

• In July 2025, the MoPSC issued an order in Ameren Missouri’s 2024 natural gas delivery service regulatory rate review, approving a unanimous stipulation and agreement. The order authorized an increase of $32 million to Ameren Missouri’s annual revenue requirement for natural gas delivery service, effective September 1, 2025.

• The PPRA requires an electric utility to develop and submit to the MoPSC schedules that include its service tariff applicable to certain large load customers. These schedules must reasonably ensure that such high-demand customers’ rates reflect a representative share of the costs incurred to serve them and must prevent other lower-demand customer rates from reflecting any unjust or unreasonable costs arising from service provided to these high-demand customers. In November 2025, the MoPSC approved Ameren Missouri’s request to modify its existing large primary service tariff to require customers requesting 75 MWs or more of demand and who are served at transmission level voltage to comply with additional tariff terms. The additional terms include a service term of 12 years plus a ramp period of up to five years to reach peak demand, minimum demand charges of 80% of contracted capacity, customer exit terms and fees, and customer credit and collateral requirements, among other terms. In addition, new customer programs would be available under this tariff, which allow customers to support renewable generation, battery storage, and/or nuclear generation through incremental payments. The MoPSC order also includes an earnings sharing mechanism that would apply if Ameren Missouri’s earned ROE for a calendar year exceeds 9.74%, which can be adjusted by the MoPSC in future electric rate orders. If this were to occur, Ameren Missouri would defer 65% of the return in excess of the 9.74% ROE to a regulatory liability, which would be returned to retail electric customers in a future rate review. In addition, if large load customer revenues were reduced in a calendar year due to certain events, as determined by the MoPSC, Ameren Missouri may defer a portion of the reduced revenues to a regulatory asset to be included in its revenue requirement in the next electric rate review. In February 2026, Ameren Missouri executed electric service agreements with large load customers consistent with the tariff terms discussed above, representing 2.2 gigawatts of demand. Ameren and Ameren Missouri do not expect a material impact to their results of operations, financial position, or liquidity in 2026 related to these agreements.

• Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base and the currently allowed 10.48% ROE, which includes a 50-basis-point incentive adder for participation in an RTO, the revenue requirements that will be included in 2026 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $685 million and $265 million, respectively. These revenue requirements represent increases in Ameren Illinois’ and ATXI’s revenue requirements of $42 million and $33 million, respectively, from the revenue requirements reflected in 2025 rates, primarily due to higher expected rate base. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2026, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2026 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the FERC formula ratemaking framework.

• In 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which proposed to increase the incentive ROE for participation in an RTO to 100 basis points from the current 50 basis points and revised the parameters for awarding incentives, while limiting the overall incentives to a cap of 250 basis points, among other things. In 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking, which proposed to modify the Notice of Proposed Rulemaking’s incentive for participation in an RTO by limiting this incentive for utilities that join an RTO to 50 basis points and only allowing them to earn the incentive for three years, among other things. If this proposal is included in a final rule, Ameren Illinois and ATXI would no longer be eligible for the 50 basis point RTO incentive adder, prospectively. The FERC is under no deadline to issue a final rule on this matter. Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy. A 50-basis-point change in the FERC-allowed ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $19 million and $14 million, respectively, based on each company’s 2026 projected rate base.

• Pursuant to the CEJA, Ameren Illinois may file an MYRP with the ICC to establish base rates for electric distribution service to be charged to customers for each calendar year of a four-year period. The base rates for a particular calendar year are based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ forecasted average annual rate base using a forecasted capital structure, with a common equity ratio of up to 50% being deemed prudent and reasonable by law and a higher equity ratio requiring specific ICC approval. The ROE determined by the ICC for each calendar year of the four-year period is subject to annual

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adjustments based on certain performance incentives and penalties. An MYRP allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to a reconciliation cap and adjustments to the ROE. Under the MYRP discussed below, Ameren Illinois’ 2026 electric distribution service revenues will be based on its 2026 actual recoverable costs, 2026 year-end rate base, and an ROE of 8.72%, as adjusted for any performance incentives or penalties, provided the actual revenue requirement does not exceed the reconciliation cap. If a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the applicable annual period. Additionally, the RBA ensures electric distribution service revenues are decoupled from sales volumes and wholesale and miscellaneous revenue differences from those assumed in the revenue requirement approved by the ICC. The RBA remains effective whether Ameren Illinois elects to file an MYRP or a traditional regulatory rate review. In December 2025, the ICC issued an order approving Ameren Illinois’ 2024 electric distribution service revenue requirement reconciliation adjustment filing. This order approved an adjustment increasing the allowed revenue requirement by $48 million, which will be collected from customers in 2026. In February 2026, the ICC denied Ameren Illinois’ rehearing request to include an asset associated with other postretirement benefits in the rate base, among other things. Ameren Illinois is assessing whether to pursue an appeal with the Illinois Appellate Court for the Fifth Judicial District in the first half of 2026.

• In December 2024, the ICC issued an order in connection with a revised Grid Plan and a revised MYRP filed by Ameren Illinois in March 2024, approving revenue requirements for electric distribution services for 2024 through 2027 of $1,206 million, $1,287 million, $1,367 million, and $1,421 million, respectively. Using the 2023 revenue requirement as a starting point, the approved revenue requirements in the ICC’s December 2024 order represent a cumulative four-year increase of $308 million. Rate changes consistent with the December 2024 order became effective in December 2024. In March 2025, Ameren Illinois filed an appeal of the ICC’s December 2024 order to the Illinois Appellate Court for the Fifth Judicial District to revise the allowed ROE and to include an asset associated with other postretirement benefits in the rate base, among other things. The appellate court is under no deadline to address the appeal, and Ameren Illinois cannot predict the ultimate outcome of the appeal.

• In January 2026, the CRGA was enacted and will become effective in June 2026. The law includes certain provisions that affect Ameren Illinois’ annual investments in energy-efficiency programs, and the related return on those investments. Under the law, the annual spending cap for energy-efficiency investments will increase to $178 million, $222 million, and $256 million for 2027, 2028, and 2029, respectively. In addition, beginning in 2027, the ROE component of the applicable WACC used to calculate Ameren Illinois’ return on energy-efficiency investments for the year will be that year’s ICC-approved ROE for Ameren Illinois’ electric distribution service. The allowed ROE can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings and demand goals.

• Pursuant to Illinois law, Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the applicable WACC. Through 2026, the ROE component of the applicable WACC is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Pursuant to the CRGA discussed above, beginning in 2027, the ROE component of the applicable WACC for a given year will be that year’s ICC approved ROE for Ameren Illinois’ electric distribution service. The allowed ROE on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings and demand goals. While the ICC has approved a plan for Ameren Illinois to invest approximately $126 million per year in electric energy-efficiency programs through 2029, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. Pursuant to the CRGA, Ameren Illinois is required to file an updated energy-efficiency plan for 2027 through 2029 by June 1, 2026 to reflect the spending cap increases discussed above.

• In November 2025, the ICC issued an order in Ameren Illinois’ January 2025 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $79 million. The order reflected a reduction of $75 million of planned distribution and transmission capital investments included in Ameren Illinois’ future test year request. The new rates became effective December 2025. In January 2026, Ameren Illinois filed an appeal of the ICC’s November 2025 order and the ICC’s January 2026 order rejecting Ameren Illinois’ rehearing request to the Illinois Appellate Court for the Fifth Judicial District. The appeal challenged the inclusion of the non-service cost component of the net periodic benefit income related to other postretirement benefits in the annual revenue requirement and the $75 million reduction of planned capital investments, among other things. The court is under no deadline to address the appeal, and Ameren Illinois cannot predict the ultimate outcome of the appeal.

• A November 2023 ICC order directed the ICC staff to develop a plan for a future of gas proceeding. All of the Illinois natural gas utilities subject to ICC regulation are included in this proceeding, which is exploring issues involving the decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA. Some of the issues being addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others. A final ICC staff report is expected by the end of 2026 and will be used by the ICC to guide further action, if any.

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• Ameren Missouri’s next refueling and maintenance outage at the Callaway Energy Center is scheduled for the fall of 2026. During a scheduled refueling, which occurs every 18 months, maintenance expenses are deferred as a regulatory asset and amortized until the completion of the next refueling and maintenance outage. During an outage, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri may incur increased non-nuclear energy center maintenance costs in non-outage years.

• In late 2024 three turbines at the High Prairie Energy Center collapsed, resulting in significantly reduced operation of the energy center. While the investigation into the cause of the collapse is ongoing, a large majority of the turbines at the energy center have returned to operation, and work is ongoing to restore the remaining turbines.

• Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek increases to electric and natural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, regulatory and legislative solutions to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, higher cost of debt, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective advancements in innovative energy technologies, including private generation and battery storage. We expect a net increase in demand resulting from the electrification of the economy, including in the transportation sector. In addition, several entities in various industries, including data center, healthcare, manufacturing, distribution, warehousing, alternative energy, fabrication, and food production, are considering either locating or expanding their operations within our service territories. In February 2026, Ameren Missouri executed electric service agreements with large load customers under the modified tariff as discussed above, representing 2.2 gigawatts of demand. Construction agreements have been signed with developers representing 3.4 gigawatts of demand, which includes the executed electric service agreements. Serving these new loads will require increased investments, including future investments for system reliability improvements and new generation sources, that will result in rate base growth.

Liquidity and Capital Resources

• In 2025 and 2026, the presidential administration took executive action to impose additional foreign trade tariffs on various goods imported from numerous countries, and several of these countries imposed retaliatory foreign trade tariffs in response. Some of these foreign trade tariffs have been modified several times and/or paused for specific periods of time. The Ameren Companies have not experienced material impacts on their results of operations, financial position, or liquidity to date, however the foreign trade tariffs may have future impacts. The Ameren Companies will continue to assess the impact of such foreign trade tariffs or other potential presidential administrative action and take actions to mitigate risks associated with costs and project timelines.

• As discussed above, several entities in various industries, including data center and manufacturing, are considering either locating or expanding their operations within Ameren Missouri’s service territory. In order to address these load growth opportunities and ensure reliability, Ameren Missouri filed a notice of change in its September 2023 preferred resource plan with the MoPSC in February 2025. Ameren is continuing to target 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. Achieving these goals will be dependent on a variety of factors, including cost-effective advancements in innovative energy technologies and constructive federal and state energy and economic policies. The 2025 Change to the 2023 PRP includes, among other things, the following:

• estimated total load growth of 1.5 gigawatts by 2032 and 2.5 gigawatts by 2040;

• adding 1,600 MWs of natural gas-fired simple-cycle generation by 2030, which will be achieved through the natural gas generation projects discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and an additional 1,200 MWs by 2043;

• adding 2,100 MWs of natural gas-fired combined-cycle generation by 2035 and an additional 1,200 MWs by 2040;

• adding 3,200 MWs of renewable generation by 2030, which includes the solar generation projects discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and an additional 1,500 MWs by 2035;

• adding 1,000 MWs of battery storage by 2030, which includes the Big Hollow Battery Energy Storage Project discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and an additional 800 MWs by 2042;

• adding 1,500 MWs of nuclear generation by 2040;

• retiring all of Ameren Missouri’s coal-fired energy centers by 2042;

• retiring 1,800 MWs of Ameren Missouri’s natural gas-fired energy centers by 2040 to comply with Illinois law;

• the continued implementation of customer energy-efficiency and demand response programs; and

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• the expectation that Ameren Missouri will seek and receive NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date.

Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required state or federal 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 or battery storage and acquire or construct those resources at a reasonable cost; the ability of suppliers, contractors, and developers to meet contractual commitments and complete projects timely, which is dependent upon the availability of necessary labor, materials, and equipment, geopolitical conflict, or government actions, among other things; changes in the scope and timing of projects; the ability to enter into natural gas supply agreements at reasonable prices and adequate quantities to power Ameren Missouri’s natural gas-fired energy centers; the continued existence and ability to qualify for, and use or transfer, federal production or investment tax credits; the ability to maintain system reliability; new and/or changes in environmental regulations, including those related to CO 2 and other greenhouse gas emissions; energy prices; and demand; Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion; the ability to earn an adequate return on invested capital; and the ability to raise capital on reasonable terms. Also, changes to capacity accreditation rules adopted by the MISO could reduce the accredited capacity of renewable generation and battery storage and increase regional capacity prices, potentially requiring additional investment and higher costs to satisfy resource adequacy requirements. In addition, the presidential administration has issued executive orders and taken other actions to increase investment in fossil fuel infrastructure. This change in federal domestic energy policy has created uncertainty regarding the role existing renewable generation will play in supporting the United States’ energy grid and the timing and extent of future renewable generation infrastructure development. Ameren Missouri’s plan could be affected by this change in energy policy. Ameren Missouri expects to file its next preferred resource plan in September 2026.

• Through 2030, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems, as well as generation and battery storage facilities that align with the 2025 Change to the 2023 PRP discussed above. We estimate that we will invest up to $33.1 billion (Ameren Missouri – up to $22.2 billion; Ameren Illinois – up to $8.3 billion; ATXI – up to $2.6 billion) of capital expenditures during the period from 2026 through 2030. These estimates include the MISO long-range transmission projects assigned to Ameren, as well as the first tranche competitive projects awarded to ATXI discussed below.

• 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 2024 in advance of transmission line construction, which is expected to begin in spring 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. Also in 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. The remaining competitive bid projects that have not been awarded are estimated to cost $4.4 billion, which includes projects located in Illinois that are estimated to cost $1.7 billion, based on the MISO’s cost estimate. The competitive bid process is expected to continue through 2026. Separately, in July 2025, the FERC approved transmission rate incentives relating to the second tranche projects assigned to Ameren. The incentives will allow construction work in progress to be included in rate base for projects constructed by ATXI, thereby improving the timeliness of cash recovery, and would allow recovery of prudently incurred costs, subject to FERC approval, for any portion of the projects if they are abandoned for reasons beyond the control of Ameren. ATXI will not capitalize allowance for funds used during construction on the related projects.

• In 2025, the presidential administration issued several executive orders on environmental regulations and enforcement. Many of these actions require further implementation by the EPA, and some of these actions will likely be subject to further judicial review. Grid reliability, environmental, or other regulations, including those related to CO 2 or other emissions, or other executive orders or actions taken by federal or state regulators, including federal orders related to planned retirements of coal-fired power plants, could result in significant changes in capital expenditures and operating costs. Regulations can be reviewed and repealed, and replacement or alternative regulations can be proposed or adopted by the regulatory agencies, including the EPA. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, for additional information on environmental matters. The ultimate implementation of any of these new regulations, as well as the timing of any such implementation, is uncertain. Ameren Missouri’s operating costs and capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances, as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity.

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Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.

• The Ameren Companies have multiyear Credit Agreements that cumulatively provide $3.2 billion of credit through December 2030, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $4.0 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for outstanding forward sale agreements, issuances and maturities of long-term debt through the date of this report, and maturities of long-term debt from 2026 to 2030 and beyond at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI. Ameren (parent) entered into interest rate swaps to hedge a portion of its interest rate risk on cash flows related to certain forecasted debt issuances to occur in 2026 and 2027. The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments at the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2025, for Ameren and Ameren Missouri. Ameren, Ameren Missouri, and Ameren Illinois each believe that their liquidity is adequate given their respective expected operating cash flows, capital expenditures, and financing plans, and expect to continue to have access to the capital and credit markets on reasonable terms when needed. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

• Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2030. Additionally, Ameren may offer and sell from time to time common stock, including under its ATM program, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. As of December 31, 2025, Ameren had multiple forward sale agreements with various counterparties relating to 6.4 million shares of common stock, which it expects to settle in 2026. Ameren’s equity financing plan is estimated to be approximately $4 billion from 2026 to 2030. This plan includes equity issuances under forward sales agreements, the DRPlus, and employee benefit plans, and could include issuances of hybrid debt securities. Ameren expects the financing plans to be aligned with the timing of generation investments. In August 2025, Ameren increased the amount of common stock available for sale under the ATM program by $1.25 billion to a total of $3 billion. As of December 31, 2025, Ameren had approximately $1.5 billion of common stock remaining available for sale under the ATM program. The Ameren Companies expect their equity to total capitalization and cash flow metrics to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, cash provided by operating activities, and/or capital contributions from Ameren (parent).

• The IRA was enacted in 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects that began construction through 2024 and creates production and investment tax credits and nuclear production tax credits for projects beginning construction after 2024, subject to the phase out provisions established by the OBBBA as discussed below. The law allows for transferability, subject to revisions made by the OBBBA discussed below, to an unrelated party for cash of up to 100% of certain tax credits generated after 2022.

• The OBBBA was enacted in July 2025 and includes various income tax provisions, among other things. The OBBBA modified provisions of the IRA related to production and investment tax credits. The new law maintains production and investment tax credits for solar and wind projects that begin construction within one year of the OBBBA’s enactment and are placed in-service by the end of 2030. Projects that begin construction after one year from enactment of the OBBBA but are placed in service by the end of 2027 also remain eligible. The law provides investment tax credits for battery storage projects that begin construction by the end of 2033, which phase out by the end of 2035. Renewable energy projects that begin construction in 2026 and beyond that use a certain threshold percentage of materials from prohibited foreign entities, as defined in the OBBBA, are not eligible for the tax credits. Production tax credits associated with nuclear generation remain unchanged from the IRA and phase out by the end of 2032. Furthermore, the new law continues to allow for transferability of the production and investment tax credits to an unrelated party for cash but such credits are restricted from being transferred to specified foreign entities, as defined in the OBBBA. Ameren did not have any material impacts on its results of operations, financial position, and liquidity in 2025 related to the OBBBA. Implementation of the OBBBA provisions is subject to additional guidance, regulations, interpretations, amendments, or technical corrections that may be issued by the IRS or United States Department of Treasury. Ameren will continue to monitor and assess any impacts related to the OBBBA.

• Pursuant to the IRA and the OBBBA discussed above, Ameren Missouri expects to transfer production and investment tax credits to unrelated parties in an aggregate amount of approximately $1.8 billion from 2026 to 2030. Proceeds from these transfers are included in Ameren Missouri’s tracker related to production and investment tax credits allowed under the IRA and the OBBBA or the RESRAM and are ultimately refunded to customers.

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• As of December 31, 2025, Ameren had $178 million in tax benefits from federal and state income tax credit carryforwards, $165 million in tax benefits from federal and state net operating loss carryforwards, and $22 million in tax receivables, which will be utilized in future periods. Future expected income tax payments are based on expected taxable income, available income tax credit and net operating loss carryforwards, and current tax law. Expected taxable income is affected by expected capital expenditures, when property, plant, and equipment is placed in-service or retired, and the timing of regulatory reviews, among other things. Ameren expects annual federal income tax payments to be immaterial through 2030.

The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.

REGULATORY MATTERS

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

ACCOUNTING MATTERS

Critical Accounting Estimates

Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are the most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

Accounting Estimate

Uncertainties Affecting Application

Regulatory Mechanisms and Cost Recovery

We defer costs and recognize revenues that we intend to collect in future rates.

• Regulatory environment and external regulatory decisions and requirements

• Anticipated future regulatory decisions and our assessment of their impact

• The impact of prudence reviews, complaint cases, limitations on electric rate increases in Missouri and Illinois, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments

• Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under the MYRP process, which includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap

• Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks

• Ameren Missouri’s estimate of revenue recovery under the MEEIA plans

Basis for Judgment

The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory

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commissions, enacted legislation, or historical experience, as well as discussions with legal counsel. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers. We also recognize revenues for alternative revenue programs authorized by our regulators that allow for an automatic rate adjustment, are probable of recovery or refund, and are collected or refunded within 24 months following the end of the annual period in which they are recognized. Under the MYRP, Ameren Illinois' base rates for a particular calendar year are based on the forecasts of recoverable costs, average annual rate base, and capital structure. An ICC-determined ROE is applied to determine the base rates for a particular calendar year. Ameren Illinois reconciles its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Orders by the ICC can result in a subsequent change in Ameren Illinois’ resulting estimated regulatory assets or liabilities. Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated annually and become effective each January with forecasted information. The formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed ROE. Variations in investments made or orders by the FERC or courts can result in a subsequent change in Ameren Illinois’ and ATXI’s estimated regulatory assets or liabilities. Ameren Missouri estimates lost electric revenues resulting from its MEEIA customer energy-efficiency programs, which are subsequently recovered through the MEEIA rider. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a description of our regulatory mechanisms and quantification of these assets or liabilities for each of the Ameren Companies.

The following table reflects the gain and other comprehensive income, which would be offset by the removal of regulatory assets and liabilities and an increase in accumulated other comprehensive income, that would have resulted if accounting guidance for rate-regulated businesses had been eliminated as of December 31, 2025:

Ameren

Missouri

Ameren

Illinois

Gains

Other comprehensive income (before taxes) - pension and other postretirement benefit plan activity

Accounting Estimate

Uncertainties Affecting Application

Benefit Plan Accounting

Based on actuarial calculations, we accrue postretirement costs of providing future employee benefits for the benefit plans we offer our employees. See Note 10 – Retirement Benefits under Part II, Item 8, of this report.

• Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable

• Discount rate

• Cash balance plan interest crediting rate on certain plans

• Future compensation increase

• Health care cost trend rates

• The timing of employee retirements, terminations, benefit payments, and mortality

• Ability to recover certain benefit plan costs from our customers

• Changing market conditions that may affect investment and interest rate environments

• Future rate of return on pension and other plan assets

Basis for Judgment

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. Our ultimate selection of the discount rate, health care trend rate, future compensation, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies, including our review of available historical, current, and projected rates, as applicable.

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The following table reflects the sensitivity of Ameren’s pension and postretirement plans to potential changes in key assumptions for the year ended December 31, 2025:

Pension Benefits

Postretirement Benefits

Net Periodic

Benefit Cost

Projected Pension Benefit Obligation

Net Periodic

Benefit Cost

Projected Postretirement Benefit

Obligation

0.25% decrease in discount rate

0.25% decrease in return on assets

(a) Not applicable.

Accounting Estimate

Uncertainties Affecting Application

Accounting for Contingencies

We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.

• Estimating expected financial impact of future events

• Estimating likelihood of various potential outcomes

• Regulatory and political environments and requirements

• Outcome of legal proceedings, settlements, or other factors

• Changes in regulation, legislation, expected scope of work, technology, or timing of environmental remediation

Basis for Judgment

The determination of a loss contingency requires significant judgment as to the expected outcome of the contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider the nature of the litigation, the claim or assessment, opinions or views of legal counsel, and the expected outcome of potential litigation, among other things. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. The amount recorded for any contingency may differ from actual costs incurred when the contingency is ultimately resolved. Contingencies are normally resolved over long periods of time. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. 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 for information on the Ameren Companies’ contingencies.

Accounting Estimate

Uncertainties Affecting Application

Accounting for Income Taxes

We record a provision for income taxes, deferred tax assets and liabilities, and a valuation allowance against net deferred tax assets, if any. See Note 12 – Income Taxes under Part II, Item 8, of this report.

• Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations

• Estimates of the amount and character of future taxable income and forecasted use of our tax credit carryforwards

• Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled

• Effectiveness of implementing tax planning strategies

• Changes in income tax laws, including amounts subject to income tax, and the regulatory treatment of any tax reform changes

• Results of audits and examinations by taxing authorities

• Ability to forecast and transfer production and investment tax credits

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Basis for Judgment

The reporting of tax-related assets and liabilities requires the use of estimates and significant management judgment. Deferred tax assets and liabilities are recorded to represent future effects on income taxes for temporary differences between the basis of assets for financial reporting and tax purposes. Although management believes that current estimates for deferred tax assets and liabilities are reasonable, actual results could differ from these estimates for a variety of reasons, including: a change in forecasted financial condition and/or results of operations; changes in income tax laws, enacted tax rates or amounts subject to income tax; the form, structure, and timing of asset or stock sales or dispositions; changes in the regulatory treatment of any tax reform benefits; and changes resulting from audits and examinations by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken, or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At each period end, and as new developments occur, management reevaluates its tax positions. Additional interpretations, regulations, amendments, or technical corrections related to the federal income tax code as a result of the OBBBA and the IRA, may impact the estimates for income taxes discussed above. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information on the OBBBA, the IRA, and the amount of deferred income taxes recorded at December 31, 2025.

Accounting Estimate

Uncertainties Affecting Application

Accounting for Asset Retirement Obligations

We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

• Discount rates

• Cost escalation rates

• Changes in regulation, expected scope of work, technology, or timing of environmental remediation

• Estimates as to the probability, timing, or amount of cash expenditures associated with AROs

Basis for Judgment

We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs for accretion and changes in the estimated fair values of the obligations, with a corresponding increase or decrease in the asset book value for the fair value changes. We estimate the fair value of our AROs using present value techniques, in which we make various assumptions about discount rates and cost escalation rates. In addition, these estimates include assumptions of the probability, timing, and amount of cash expenditures to settle the ARO, and are based on currently available technology. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with decommissioning of Ameren Missouri’s Callaway and wind renewable energy centers, certain Ameren Missouri solar energy centers, CCR facilities, and river structures at certain energy centers used for unloading coal and circulating water systems. Additionally, Ameren, Ameren Missouri, and Ameren Illinois have recorded AROs for retirement costs associated with asbestos removal and the disposal of certain transformers. See Note 15 – Supplemental Information under Part II, Item 8, of this report for the amount of AROs recorded at December 31, 2025.

A significant portion of Ameren’s and Ameren Missouri’s AROs relate to the decommissioning of Ameren Missouri’s Callaway Energy Center. Changes in key assumptions could materially affect the decommissioning obligation. The following table reflects the sensitivity of potential changes in key assumptions to Ameren Missouri’s Callaway Energy Center decommissioning obligation as of December 31, 2025:

Change in Callaway Energy Center’s Key ARO Assumptions

Increase (Decrease) to ARO

Discount rate decreased by 0.25%

Cost escalation rate increased by 0.25%

Increase in the estimated decommissioning costs by 10%

Two-year deferral in timing of cash expenditures

Impact of New Accounting Pronouncements

See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

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Ameren Corp

Annual report (10-K)

Recent 8-K announcements

Top insiders

Top performers

All filings

Tone shift by section

Language change vs prior 10-K

Risk Factors (Item 1A)

Language change vs prior 10-K

MD&A (Item 7)

External resources

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