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.

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:

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.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.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.EarningsNet 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.LiquidityAt 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.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 GasAmeren Illinois Electric DistributionAmeren 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: [Table with ~5 rows, ~10 numbers, and 187 characters.] (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 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: [Table with ~2 rows, ~6 numbers, and 119 characters.] 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 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: [Table with ~30 rows, ~149 numbers, and 1656 characters.] Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2025 and 2024: [Table with ~30 rows, ~102 numbers, and 1313 characters.]

Operating Revenues

The following table presents the increases (decreases) by Ameren segment for electric and natural gas revenues in 2025, compared with 2024: [Table with ~21 rows, ~50 numbers, and 1226 characters.] (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.

Electric Revenues

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

Ameren 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’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 items 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’ 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.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 expenses (+$48 million) and increased capital investment (+$18 million), as evidenced 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’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’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: [Table with ~8 rows, ~18 numbers, and 505 characters.] (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.(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 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’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.

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: [Table with ~5 rows, ~9 numbers, and 377 characters.] (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 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’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.

Other Operations and Maintenance Expenses

Total by Segment(a)Increase (Decrease) by SegmentOverall 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 MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionOther 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. 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.•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.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.

Depreciation and Amortization Expenses

Total by Segment(a)Increase (Decrease) by SegmentOverall Ameren Decrease of $22 Million

(a)Includes other/intersegment eliminations of $8 million and $8 million in 2025 and 2024, respectively.Ameren MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionDepreciation 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.

Taxes Other Than Income Taxes

Total by Segment(a)Increase (Decrease) by SegmentOverall 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 MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionTaxes 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.

Other Income, Net

Total by SegmentDecrease by SegmentOverall Ameren Decrease of $70 Million

Ameren MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionSee 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.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 decrease 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.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. 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.

Interest Charges

Total by SegmentIncrease by SegmentOverall Ameren Increase of $113 Million

Ameren MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionSee 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. 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.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. Interest charges increased $19 million in 2025, compared with 2024, primarily due to the following:

Ameren Illinois Transmission

Interest charges increased by $8 million, primarily 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: [Table with ~7 rows, ~16 numbers, and 196 characters.] 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, 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: [Table with ~3 rows, ~33 numbers, and 365 characters.] (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’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.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’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’ 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.•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:

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 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: [Table with ~2 rows, ~6 numbers, and 119 characters.] 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 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: [Table with ~30 rows, ~149 numbers, and 1656 characters.] Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2025 and 2024: [Table with ~30 rows, ~102 numbers, and 1313 characters.]

Operating Revenues

The following table presents the increases (decreases) by Ameren segment for electric and natural gas revenues in 2025, compared with 2024: [Table with ~21 rows, ~50 numbers, and 1226 characters.] (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.

Electric Revenues

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

Ameren 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’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 items 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’ 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.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 expenses (+$48 million) and increased capital investment (+$18 million), as evidenced 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’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’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: [Table with ~8 rows, ~18 numbers, and 505 characters.] (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.(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 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’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.

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: [Table with ~5 rows, ~9 numbers, and 377 characters.] (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 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’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.

Other Operations and Maintenance Expenses

Total by Segment(a)Increase (Decrease) by SegmentOverall 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 MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionOther 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. 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.•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.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.

Depreciation and Amortization Expenses

Total by Segment(a)Increase (Decrease) by SegmentOverall Ameren Decrease of $22 Million

(a)Includes other/intersegment eliminations of $8 million and $8 million in 2025 and 2024, respectively.Ameren MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionDepreciation 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.

Taxes Other Than Income Taxes

Total by Segment(a)Increase (Decrease) by SegmentOverall 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 MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionTaxes 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.

Other Income, Net

Total by SegmentDecrease by SegmentOverall Ameren Decrease of $70 Million

Ameren MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionSee 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.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 decrease 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.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. 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.

Interest Charges

Total by SegmentIncrease by SegmentOverall Ameren Increase of $113 Million

Ameren MissouriAmeren Illinois Natural GasOther/Intersegment EliminationsAmeren Illinois Electric DistributionAmeren TransmissionSee 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. 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.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. Interest charges increased $19 million in 2025, compared with 2024, primarily due to the following:

Ameren Illinois Transmission

Interest charges increased by $8 million, primarily 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: [Table with ~7 rows, ~16 numbers, and 196 characters.] 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, 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: [Table with ~3 rows, ~33 numbers, and 365 characters.] (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’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.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’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’ 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.•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 MissouriAmeren Illinois Natural GasATXI and other electric transmission subsidiariesAmeren Illinois Electric DistributionAmeren 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.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: [Table with ~7 rows, ~37 numbers, and 404 characters.] 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.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.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 SO2, NOx, CO2, 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 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. In 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: [Table with ~15 rows, ~14 numbers, and 636 characters.] (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. 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.

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. [Table with ~33 rows, ~45 numbers, and 1248 characters.] (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.(c)    Excludes a $7 million and $7 million receivable at December 31, 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 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: [Table with ~4 rows, ~9 numbers, and 77 characters.] 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.

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: [Table with ~16 rows, ~14 numbers, and 395 characters.] 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 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 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 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.•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•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 CO2 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 CO2 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. 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.•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. [Table with ~3 rows, ~0 numbers, and 1226 characters.] 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 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: [Table with ~2 rows, ~6 numbers, and 169 characters.] [Table with ~3 rows, ~1 numbers, and 851 characters.] 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.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: [Table with ~2 rows, ~8 numbers, and 259 characters.] [Table with ~3 rows, ~0 numbers, and 793 characters.] 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. [Table with ~3 rows, ~1 numbers, and 975 characters.] 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. [Table with ~3 rows, ~1 numbers, and 537 characters.] 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: [Table with ~5 rows, ~7 numbers, and 267 characters.]

Impact of New Accounting Pronouncements

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

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.Our risk management objectives are to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by the risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight.

Interest Rate Risk

We are exposed to market risk through changes in interest rates associated with:•short-term variable-rate debt;•fixed-rate debt;•United States Treasury bonds; and•the discount rate applicable to AROs, goodwill, and defined pension and postretirement benefit plans.We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio, by monitoring the effects of market changes on interest rates, and by entering into interest rate swaps to hedge a portion of our interest rate risk on cash flows related to certain forecasted debt issuances. For defined pension and postretirement benefit plans, we control the duration and the portfolio mix of our plan assets. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information related to AROs, goodwill, and the defined pension and postretirement benefit plans.The estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 100 basis points on variable-rate debt outstanding at December 31, 2025 is immaterial.Through 2026, the allowed ROE under Ameren Illinois’ electric energy-efficiency investments formula ratemaking recovery mechanisms is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual ROE for its electric energy-efficiency investments is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. Interest rate levels also influence the ROE allowed by our regulators in our other ratemaking jurisdictions, as well as the carrying costs associated with certain regulatory assets and liabilities.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and carry only a nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 7 – Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2025.Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments subject to credit risk primarily consist of trade accounts receivables and executory contracts with market risk exposures. Credit risk associated with trade receivables is mitigated by our diversified customer base. At December 31, 2025, no nonaffiliated customer represented more than 10% of our accounts receivable. Additionally, Ameren Illinois faces risks associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois may be required to purchase the supplier’s receivables relating to Ameren Illinois’ distribution customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers to reflect charges for electric distribution and purchased receivables from the alternative retail electric supplier. As of December 31, 2025, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $47 million. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rider that allows Ameren Illinois to recover the difference between its actual net bad debt write-offs under GAAP and the amount of net bad debt write-offs included in its base rates. Ameren Missouri and Ameren Illinois continue to monitor the impact of economic conditions, including inflationary pressures, on customer collections and customer account balances. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

Investment Price Risk

Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and COLI contracts include equity and debt securities. The equity securities are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates.Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide benefits at the time they are payable, while also maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class are estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjust the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns, and for the effect of expenses paid from plan assets. Contributions to the plans and future costs could increase materially if we do not achieve pension and postretirement asset portfolio investment returns equal to or in excess of our 2026 assumed return on plan assets of 6.75%.Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2025, this fund was invested in domestic equity securities (67%) and debt securities (32%). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the trust assets to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.Additionally, Ameren and Ameren Illinois have COLI contracts with net cash surrender values of $102 million and $9 million, respectively, as of December 31, 2025. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest. As of December 31, 2025, that separate account is comprised of approximately 40% equity securities and 60% debt securities. To the extent not recovered through customer rates, changes in the market values of these contracts are reflected in earnings.

Commodity Price Risk

Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businesses’ exposure to changing market prices for commodities is in large part mitigated because there are cost recovery mechanisms in place. These cost recovery mechanisms allow Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and natural gas supply.Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their customers. 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. This projected growth could create volatility for the prices of purchased power and capacity. The effects of price volatility cannot be eliminated. However, procurement and sales strategies involve risk management techniques and instruments, as well as the management of physical assets.Ameren Missouri has a FAC that allows it to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional regulatory rate review, subject to MoPSC prudence reviews. Ameren Missouri remains exposed to the remaining 5% of such changes.Ameren Illinois has cost recovery mechanisms for power purchased, capacity, zero emission credit, and renewable energy credit costs. Ameren Illinois is required to serve as the provider of last resort for electric customers in its service territory who have not chosen an alternative retail electric supplier. In 2025, Ameren Illinois procured power on behalf of its customers for 28% of its total kilowatthour sales. Ameren Illinois purchases energy and capacity through bilateral contracts resulting from IPA procurement events, with any remaining needs procured through the MISO marketplace. Ameren Illinois has purchased approximately 55% of its summer 2026, 46% of its fall 2026, 40% of its winter 2026/27 and 61% of its spring 2027 capacity needs bilaterally, however, this percentage beyond May 2027 will be dependent on the results of future IPA procurement events. Daily energy balancing is also handled through the MISO marketplace. Through the IPA's development and filing of the 2026 Electricity Procurement Plan, the ICC has approved the plan's proposal for multiple IPA procurement events over the following year. These events will procure portions of Ameren Illinois' energy and capacity forecasted requirements for forward delivery years through May 2029. Ameren Illinois has also entered into ICC-approved contracts for zero emission credits through May 2027 and for renewable energy credits with various terms, including contracts with 20-year terms ending 2032, and contracts entered into beginning in 2018 through 2025 with 15- to 20-year terms. Pursuant to Illinois law, Ameren Illinois is required to enter into these contracts to comply with Illinois’ renewable energy and zero emission standards. These contracts, with the exception of certain contracts entered into in 2010, do not serve to meet Ameren Illinois’ energy and capacity needs.Ameren Illinois does not generate earnings based on the resale of power or purchase of zero emission credits or renewable energy credits but rather on the delivery of the energy.Ameren Missouri and Ameren Illinois have PGA clauses that permit costs incurred for natural gas to be recovered directly from utility customers without a traditional regulatory rate review, subject to prudence reviews.The following table presents, as of December 31, 2025, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri’s coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway Energy Center, natural gas for Ameren Missouri’s and Ameren Illinois’ retail distribution, and purchased power for Ameren Illinois that are price-hedged over the period 2026 through 2030. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for electricity and natural gas supplied by us and inventory levels, as well as Ameren Missouri’s generation output, among other matters. [Table with ~14 rows, ~36 numbers, and 404 characters.] (a)Ameren Missouri has agreements in place to purchase and transport coal to its energy centers. While Ameren Missouri has minimum purchase obligations associated with these agreements, the majority of these agreements are not associated with any specific coal-fired energy center.(b)Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2026 represents January 2026 through March 2026. The year 2027 represents November 2026 through March 2027. This continues each successive year through March 2030.(c)Represents the percentage of purchased power price-hedged for fixed-price residential and nonresidential customers with less than 150 kilowatts of demand.Our exposure to commodity price risk for construction and maintenance activities is related to changes in market prices for metal commodities and to labor availability.

Commodity Supplier Risk

The use of low-sulfur coal is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has agreements with multiple suppliers to purchase low-sulfur coal through 2030 to comply with environmental regulations. Disruptions to the deliveries of low-sulfur coal from a supplier could compromise Ameren Missouri’s ability to operate in compliance with emission standards. The suppliers of low-sulfur coal are limited. If Ameren Missouri were to experience a temporary disruption of low-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of low-sulfur coal were not available, Ameren Missouri would have to use its existing emission allowances, purchase emission allowances, and reduce generation to achieve compliance with environmental regulations. Ameren Missouri would then need to purchase power necessary to meet demand.Currently, the Callaway Energy Center has one NRC-licensed supplier able to provide fuel assemblies to the Callaway Energy Center.

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholdersof Ameren Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statement of income and comprehensive income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation

As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2025, there were approximately $2.9 billion of regulatory assets and approximately $6.4 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized./s/ PricewaterhouseCoopers LLPSt. Louis, MissouriFebruary 18, 2026We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholdersof Union Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Union Electric Company and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statement of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation

As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2025, there were approximately $1.6 billion of regulatory assets and approximately $3.3 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel and (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator.Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation and (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities./s/ PricewaterhouseCoopers LLPSt. Louis, MissouriFebruary 18, 2026We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholdersof Ameren Illinois Company

Opinion on the Financial Statements

We have audited the accompanying balance sheet of Ameren Illinois Company (the “Company”) as of December 31, 2025 and 2024, and the related statement of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation

As described in Notes 1 and 2 to the financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2025, there were approximately $1.2 billion of regulatory assets and approximately $2.9 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized./s/ PricewaterhouseCoopers LLPSt. Louis, MissouriFebruary 18, 2026We have served as the Company’s auditor since 1998.

Environmental Capital Expenditures

Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO2, NOx, CO2, 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 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. In 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: [Table with ~15 rows, ~14 numbers, and 636 characters.] (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. 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.

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. [Table with ~33 rows, ~45 numbers, and 1248 characters.] (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.(c)    Excludes a $7 million and $7 million receivable at December 31, 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 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: [Table with ~4 rows, ~9 numbers, and 77 characters.] 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.

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: [Table with ~16 rows, ~14 numbers, and 395 characters.] 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 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 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 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.•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•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 CO2 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 CO2 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. 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.•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. [Table with ~3 rows, ~0 numbers, and 1226 characters.] 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 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: [Table with ~2 rows, ~6 numbers, and 169 characters.] [Table with ~3 rows, ~1 numbers, and 851 characters.] 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.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: [Table with ~2 rows, ~8 numbers, and 259 characters.] [Table with ~3 rows, ~0 numbers, and 793 characters.] 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. [Table with ~3 rows, ~1 numbers, and 975 characters.] 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. [Table with ~3 rows, ~1 numbers, and 537 characters.] 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: [Table with ~5 rows, ~7 numbers, and 267 characters.]

Impact of New Accounting Pronouncements

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

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.Our risk management objectives are to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by the risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight.

Interest Rate Risk

We are exposed to market risk through changes in interest rates associated with:•short-term variable-rate debt;•fixed-rate debt;•United States Treasury bonds; and•the discount rate applicable to AROs, goodwill, and defined pension and postretirement benefit plans.We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio, by monitoring the effects of market changes on interest rates, and by entering into interest rate swaps to hedge a portion of our interest rate risk on cash flows related to certain forecasted debt issuances. For defined pension and postretirement benefit plans, we control the duration and the portfolio mix of our plan assets. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information related to AROs, goodwill, and the defined pension and postretirement benefit plans.The estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 100 basis points on variable-rate debt outstanding at December 31, 2025 is immaterial.Through 2026, the allowed ROE under Ameren Illinois’ electric energy-efficiency investments formula ratemaking recovery mechanisms is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual ROE for its electric energy-efficiency investments is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. Interest rate levels also influence the ROE allowed by our regulators in our other ratemaking jurisdictions, as well as the carrying costs associated with certain regulatory assets and liabilities.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and carry only a nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 7 – Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2025.Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments subject to credit risk primarily consist of trade accounts receivables and executory contracts with market risk exposures. Credit risk associated with trade receivables is mitigated by our diversified customer base. At December 31, 2025, no nonaffiliated customer represented more than 10% of our accounts receivable. Additionally, Ameren Illinois faces risks associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois may be required to purchase the supplier’s receivables relating to Ameren Illinois’ distribution customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers to reflect charges for electric distribution and purchased receivables from the alternative retail electric supplier. As of December 31, 2025, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $47 million. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rider that allows Ameren Illinois to recover the difference between its actual net bad debt write-offs under GAAP and the amount of net bad debt write-offs included in its base rates. Ameren Missouri and Ameren Illinois continue to monitor the impact of economic conditions, including inflationary pressures, on customer collections and customer account balances. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

Investment Price Risk

Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and COLI contracts include equity and debt securities. The equity securities are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates.Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide benefits at the time they are payable, while also maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class are estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjust the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns, and for the effect of expenses paid from plan assets. Contributions to the plans and future costs could increase materially if we do not achieve pension and postretirement asset portfolio investment returns equal to or in excess of our 2026 assumed return on plan assets of 6.75%.Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2025, this fund was invested in domestic equity securities (67%) and debt securities (32%). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the trust assets to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.Additionally, Ameren and Ameren Illinois have COLI contracts with net cash surrender values of $102 million and $9 million, respectively, as of December 31, 2025. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest. As of December 31, 2025, that separate account is comprised of approximately 40% equity securities and 60% debt securities. To the extent not recovered through customer rates, changes in the market values of these contracts are reflected in earnings.

Commodity Price Risk

Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businesses’ exposure to changing market prices for commodities is in large part mitigated because there are cost recovery mechanisms in place. These cost recovery mechanisms allow Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and natural gas supply.Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their customers. 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. This projected growth could create volatility for the prices of purchased power and capacity. The effects of price volatility cannot be eliminated. However, procurement and sales strategies involve risk management techniques and instruments, as well as the management of physical assets.Ameren Missouri has a FAC that allows it to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional regulatory rate review, subject to MoPSC prudence reviews. Ameren Missouri remains exposed to the remaining 5% of such changes.Ameren Illinois has cost recovery mechanisms for power purchased, capacity, zero emission credit, and renewable energy credit costs. Ameren Illinois is required to serve as the provider of last resort for electric customers in its service territory who have not chosen an alternative retail electric supplier. In 2025, Ameren Illinois procured power on behalf of its customers for 28% of its total kilowatthour sales. Ameren Illinois purchases energy and capacity through bilateral contracts resulting from IPA procurement events, with any remaining needs procured through the MISO marketplace. Ameren Illinois has purchased approximately 55% of its summer 2026, 46% of its fall 2026, 40% of its winter 2026/27 and 61% of its spring 2027 capacity needs bilaterally, however, this percentage beyond May 2027 will be dependent on the results of future IPA procurement events. Daily energy balancing is also handled through the MISO marketplace. Through the IPA's development and filing of the 2026 Electricity Procurement Plan, the ICC has approved the plan's proposal for multiple IPA procurement events over the following year. These events will procure portions of Ameren Illinois' energy and capacity forecasted requirements for forward delivery years through May 2029. Ameren Illinois has also entered into ICC-approved contracts for zero emission credits through May 2027 and for renewable energy credits with various terms, including contracts with 20-year terms ending 2032, and contracts entered into beginning in 2018 through 2025 with 15- to 20-year terms. Pursuant to Illinois law, Ameren Illinois is required to enter into these contracts to comply with Illinois’ renewable energy and zero emission standards. These contracts, with the exception of certain contracts entered into in 2010, do not serve to meet Ameren Illinois’ energy and capacity needs.Ameren Illinois does not generate earnings based on the resale of power or purchase of zero emission credits or renewable energy credits but rather on the delivery of the energy.Ameren Missouri and Ameren Illinois have PGA clauses that permit costs incurred for natural gas to be recovered directly from utility customers without a traditional regulatory rate review, subject to prudence reviews.The following table presents, as of December 31, 2025, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri’s coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway Energy Center, natural gas for Ameren Missouri’s and Ameren Illinois’ retail distribution, and purchased power for Ameren Illinois that are price-hedged over the period 2026 through 2030. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for electricity and natural gas supplied by us and inventory levels, as well as Ameren Missouri’s generation output, among other matters. [Table with ~14 rows, ~36 numbers, and 404 characters.] (a)Ameren Missouri has agreements in place to purchase and transport coal to its energy centers. While Ameren Missouri has minimum purchase obligations associated with these agreements, the majority of these agreements are not associated with any specific coal-fired energy center.(b)Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2026 represents January 2026 through March 2026. The year 2027 represents November 2026 through March 2027. This continues each successive year through March 2030.(c)Represents the percentage of purchased power price-hedged for fixed-price residential and nonresidential customers with less than 150 kilowatts of demand.Our exposure to commodity price risk for construction and maintenance activities is related to changes in market prices for metal commodities and to labor availability.

Commodity Supplier Risk

The use of low-sulfur coal is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has agreements with multiple suppliers to purchase low-sulfur coal through 2030 to comply with environmental regulations. Disruptions to the deliveries of low-sulfur coal from a supplier could compromise Ameren Missouri’s ability to operate in compliance with emission standards. The suppliers of low-sulfur coal are limited. If Ameren Missouri were to experience a temporary disruption of low-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of low-sulfur coal were not available, Ameren Missouri would have to use its existing emission allowances, purchase emission allowances, and reduce generation to achieve compliance with environmental regulations. Ameren Missouri would then need to purchase power necessary to meet demand.Currently, the Callaway Energy Center has one NRC-licensed supplier able to provide fuel assemblies to the Callaway Energy Center.

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholdersof Ameren Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statement of income and comprehensive income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation

As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2025, there were approximately $2.9 billion of regulatory assets and approximately $6.4 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized./s/ PricewaterhouseCoopers LLPSt. Louis, MissouriFebruary 18, 2026We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholdersof Union Electric Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Union Electric Company and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statement of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation

As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2025, there were approximately $1.6 billion of regulatory assets and approximately $3.3 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel and (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator.Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation and (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities./s/ PricewaterhouseCoopers LLPSt. Louis, MissouriFebruary 18, 2026We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholdersof Ameren Illinois Company

Opinion on the Financial Statements

We have audited the accompanying balance sheet of Ameren Illinois Company (the “Company”) as of December 31, 2025 and 2024, and the related statement of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation

As described in Notes 1 and 2 to the financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2025, there were approximately $1.2 billion of regulatory assets and approximately $2.9 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized./s/ PricewaterhouseCoopers LLPSt. Louis, MissouriFebruary 18, 2026We have served as the Company’s auditor since 1998.

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (Consolidated) (d/b/a Ameren Missouri)

AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)

COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2025

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2025

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

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. Ameren’s principal subsidiaries are listed below. Ameren also has other subsidiaries that conduct other activities, such as providing shared services.•Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri. Ameren Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri, which includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.3 million customers and natural gas service to 0.1 million customers.•Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois. Ameren Illinois was incorporated in Illinois in 1923 and is the successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to a 43,700 square mile area in central and southern Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 0.8 million customers.•ATXI operates a FERC rate-regulated electric transmission business in the MISO. ATXI was incorporated in Illinois in 2006. 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.Note 1 – Summary of Significant Accounting Policies applies to the Ameren Companies. The remaining notes to the consolidated financial statements apply to the registrants as indicated in each footnote disclosure. Registrants are named specifically for their related activities and disclosures.Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.

Regulation

Our customer rates are regulated by the MoPSC, the ICC, and the FERC. We defer certain costs as assets pursuant to actions of rate regulators or because of expectations that we will be able to recover such costs in future rates charged to customers. We also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on our regulatory frameworks, regulatory recovery mechanisms, and regulatory assets and liabilities recorded at December 31, 2025 and 2024.We periodically assess the recoverability of our regulatory assets and probability of refund of our regulatory liabilities. Regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that refunds to customers related to regulatory liabilities are eliminated by the regulator or are no longer probable, the amounts are credited to earnings.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents include short-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash. See Note 15 – Supplemental Information for a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows.

Allowance for Doubtful Accounts Receivable

The allowance for doubtful accounts represents our estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. We estimate future collections success using loss factors such as account aging, customer-specific considerations, and forecasted economic conditions. Accounts receivables are written off when all reasonable collection efforts have been completed. Ameren Illinois has bad debt riders that adjust rates for net write-offs of customer accounts receivable above or below those being collected in rates.

Inventories

Inventories are recorded at the lower of weighted-average cost or net realizable value. Inventories are charged to expense or capitalized to property, plant and equipment when issued, as appropriate, using the weighted-average cost method. See Note 15 – Supplemental Information for the components of inventories.

Property, Plant, and Equipment, Net

We capitalize the cost of additions to, and betterments of, units of property, plant, and equipment. The cost includes labor, material, overheads, and applicable taxes. An allowance for funds used during construction, as discussed below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures are expensed as incurred unless subject to regulatory deferral. When units of depreciable tangible property are retired, the original costs, and the associated removal cost, net of salvage, are charged to accumulated depreciation. If environmental expenditures are related to assets currently in use, as in the case of the installation of pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset. See Asset Retirement Obligations and Removal Costs section below and Note 3 – Property, Plant, and Equipment, Net for additional information.Ameren Missouri’s cost of nuclear fuel is capitalized as a part of “Property, Plant, and Equipment, Net” on Ameren and Ameren Missouri’s balance sheets and then amortized to “Operating Expenses – Fuel and purchased power” in their respective statements of income on a unit-of-production basis. Nuclear fuel amortization is reflected as a part of “Amortization of nuclear fuel” on their respective statements of cash flows.When it becomes probable an asset will be retired significantly in advance of its previously expected useful life and in the near term, the Ameren Companies must assess the probability of recovery of the remaining net book value of the asset to be abandoned. We recognize a loss on abandonment when it becomes probable that all or part of the cost of an asset, including a return at the applicable WACC, will be disallowed from recovery either through customer rates or through the issuance of securitized utility tariff bonds and such amount is reasonably estimable.In addition, the Ameren Companies must assess the likelihood of a disallowance that part of the cost of a plant under construction or a recently completed plant will be disallowed for ratemaking purposes. Factors can include our own recent rate orders, as well as recent rate orders of other regulated entities in similar jurisdictions. If a disallowance becomes probable and reasonably estimable, we record an impairment charge in the period in which we determine the plant has met the criteria.We also evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets to the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount by which the carrying value exceeds the estimated fair value of the assets. In the period in which we determine that an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its estimated fair value less cost to sell. We did not identify any material events or changes in circumstances that indicated that the carrying value of long-lived assets may not be recoverable in 2025, 2024, or 2023.

Depreciation

Depreciation is recognized over the estimated lives of the many classes of depreciable tangible property by applying composite rates on a straight-line basis to the original cost of such property. The composite rates include a provision for the estimated removal cost of property, plant, and equipment retired from service, net of salvage. See Asset Retirement Obligation and Removal Costs section below for additional information. The provision for depreciation for the Ameren Companies in 2025, 2024, and 2023 ranged from 3% to 4% of the average depreciable cost. See Note 3 – Property, Plant, and Equipment, Net for additional information on estimated depreciable lives.

Allowance for Funds Used During Construction

As a part of “Property, Plant, and Equipment, Net” on the balance sheet, we capitalize allowance for funds used during construction, which is the cost of borrowed funds and the cost of equity funds (preferred and common shareholders’ equity) applicable to eligible rate-regulated construction work in progress, in accordance with the utility industry’s accounting practice and GAAP. The amount of allowance for funds used during construction is calculated using a FERC-prescribed formula based on a rate, which incorporates the average cost of short-term debt, the average cost of long-term debt, and the cost of equity funds. The portion attributable to borrowed funds is recorded as a reduction of “Interest Charges” on the statements of income. The portion attributable to equity funds is recorded within “Other Income, Net” on the statements of income. This accounting practice offsets the effect on earnings of the cost of financing during construction. See Note 15 – Supplemental Information for the amount of allowance for funds used during construction capitalized and the average rate applied to eligible construction work in progress.Allowance for funds used during construction does not represent a current source of cash funds. Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Ameren and Ameren Illinois had goodwill of $411 million at December 31, 2025 and 2024. Ameren has four reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois has three reporting units: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission had goodwill of $238 million, $80 million, and $93 million, respectively, at December 31, 2025 and 2024. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 2025 and 2024.Ameren and Ameren Illinois evaluate goodwill for impairment in each of their reporting units as of October 31 each year, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of their reporting units below their carrying amounts. To determine whether the fair value of a reporting unit is more likely than not greater than its carrying amount, Ameren and Ameren Illinois can elect to perform either a qualitative assessment or to bypass the qualitative assessment and perform a quantitative test.Ameren and Ameren Illinois elected to perform a qualitative assessment for their annual goodwill impairment test conducted as of October 31, 2025. As part of this qualitative assessment, Ameren and Ameren Illinois evaluated, among other things, macroeconomic conditions, industry and market considerations such as observable industry market multiples, regulatory frameworks, cost factors, overall financial performance, and entity-specific events. The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was more likely than not that the fair value of each reporting unit exceeded its carrying value as of October 31, 2025, resulting in no impairment of Ameren’s or Ameren Illinois’ goodwill.

Variable Interest Entities

Variable Interest Entities that are Consolidated

AMF was formed in 2024, for the purpose of issuing and servicing securitized utility tariff bonds related to costs for the accelerated retirement of the Rush Island Energy Center. Ameren Missouri is the primary beneficiary of this entity because it has the power to direct the activities that most significantly impact the economic performance of the entity, as well as the obligation to absorb losses or the right to receive benefits from the entity. The entity is considered a variable interest entity primarily because its equity capitalization is insufficient to support its operations. The entity’s primary assets and liabilities are comprised of regulatory assets related to the unrecovered net plant balance associated with the retired energy center, among other costs, and long-term debt. Ameren and Ameren Missouri consolidate AMF, which Ameren Missouri wholly owns, and both manages and controls the entity’s operating activities. For additional information on the securitization of the Rush Island Energy Center costs, see Note 2 – Rate and Regulatory Matters. For additional information on the securitized tariff bond issuance, see Note 5 – Long-term Debt and Equity Financings. The following table presents the carrying values of AMF’s assets and liabilities included on Ameren’s and Ameren Missouri’s consolidated balance sheets as of December 31, 2025 : [Table with ~7 rows, ~14 numbers, and 241 characters.] (a)Assets may be used only to meet AMF’s obligations and commitments.(b)Included in “Restricted cash” on Ameren Missouri’s balance sheet.(c)The securitized tariff bondholders have no recourse to Ameren Missouri.(d)Included in “Other current liabilities” on Ameren Missouri’s balance sheet.

Variable Interest Entities that are not Consolidated

As of December 31, 2025 and 2024, Ameren had unconsolidated variable interests in various equity method investments, primarily to advance innovative energy technologies, totaling $64 million and $74 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Any earnings or losses related to these investments are included in “Other Income, Net” on Ameren’s consolidated statement of income and comprehensive income. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of December 31, 2025, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $64 million plus associated outstanding funding commitments of $28 million.

Variable Interest Entities that are Consolidated

AMF was formed in 2024, for the purpose of issuing and servicing securitized utility tariff bonds related to costs for the accelerated retirement of the Rush Island Energy Center. Ameren Missouri is the primary beneficiary of this entity because it has the power to direct the activities that most significantly impact the economic performance of the entity, as well as the obligation to absorb losses or the right to receive benefits from the entity. The entity is considered a variable interest entity primarily because its equity capitalization is insufficient to support its operations. The entity’s primary assets and liabilities are comprised of regulatory assets related to the unrecovered net plant balance associated with the retired energy center, among other costs, and long-term debt. Ameren and Ameren Missouri consolidate AMF, which Ameren Missouri wholly owns, and both manages and controls the entity’s operating activities. For additional information on the securitization of the Rush Island Energy Center costs, see Note 2 – Rate and Regulatory Matters. For additional information on the securitized tariff bond issuance, see Note 5 – Long-term Debt and Equity Financings. The following table presents the carrying values of AMF’s assets and liabilities included on Ameren’s and Ameren Missouri’s consolidated balance sheets as of December 31, 2025 : [Table with ~7 rows, ~14 numbers, and 241 characters.] (a)Assets may be used only to meet AMF’s obligations and commitments.(b)Included in “Restricted cash” on Ameren Missouri’s balance sheet.(c)The securitized tariff bondholders have no recourse to Ameren Missouri.(d)Included in “Other current liabilities” on Ameren Missouri’s balance sheet.

Variable Interest Entities that are not Consolidated

As of December 31, 2025 and 2024, Ameren had unconsolidated variable interests in various equity method investments, primarily to advance innovative energy technologies, totaling $64 million and $74 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Any earnings or losses related to these investments are included in “Other Income, Net” on Ameren’s consolidated statement of income and comprehensive income. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of December 31, 2025, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $64 million plus associated outstanding funding commitments of $28 million.

Environmental Costs

Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is probable that the costs will be recovered from customers in future rates. See Note 14 – Commitments and Contingencies for additional information on liabilities for environmental costs.

Asset Retirement Obligations and Removal Costs

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. Asset book values, reflected within “Property, Plant, and Equipment, Net” on the balance sheet, are depreciated over the remaining useful life of the related asset. Depreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $7 million, $2 million, and $9 million for the years ended December 31, 2025, 2024, and 2023, respectively, which was deferred as a reduction to the net regulatory liability. The net regulatory liability also reflects a deferral for the nuclear decommissioning trust fund balance for the Callaway Energy Center. The depreciation deferred to the regulatory asset at Ameren Illinois was immaterial in each respective period. Uncertainties as to the probability, timing, or amount of cash expenditures associated with AROs affect our estimates of fair value. 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 for a reconciliation of the beginning and ending carrying amounts of AROs.Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment retired from service, represent a cost of removal regulatory liability. See the cost of removal regulatory liability balance in Note 2 – Rate and Regulatory Matters.

COLI

Ameren (parent) and Ameren Illinois have COLI, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of December 31, 2025, the cash surrender value of COLI at Ameren and Ameren Illinois was $219 million (December 31, 2024 – $260 million) and $126 million (December 31, 2024 – $118 million), respectively, while total borrowings against the policies were $117 million (December 31, 2024 – $110 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest.

COLI

Ameren (parent) and Ameren Illinois have COLI, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of December 31, 2025, the cash surrender value of COLI at Ameren and Ameren Illinois was $219 million (December 31, 2024 – $260 million) and $126 million (December 31, 2024 – $118 million), respectively, while total borrowings against the policies were $117 million (December 31, 2024 – $110 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest.

Operating Revenues

We record revenues from contracts with customers for various electric and natural gas services, which primarily consist of retail distribution, electric transmission, and off-system arrangements. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price.Electric and natural gas retail distribution revenues are earned when the commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service provided but unbilled at the end of each accounting period. Electric transmission revenues are earned as electric transmission services are provided. Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the sale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. Capacity and ancillary service revenues are earned as services are provided.Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers are equal to the amounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the end of each accounting period. Customers are billed at least monthly, and payments are due less than one month after goods and/or services are provided. See Note 16 – Segment Information for disaggregated revenue information.For certain regulatory recovery mechanisms that are alternative revenue programs rather than revenues from contracts with customers, we recognize revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected from customers within two years from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, the MEEIA, the RBA, the VBA, and the WNAR. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to alternative revenue program revenues.As of December 31, 2025 and 2024, our remaining performance obligations were immaterial. The Ameren Companies elected not to disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less.

Accounting for MISO Transactions

MISO-related purchase and sale transactions are recorded by Ameren, Ameren Missouri, and Ameren Illinois using settlement information provided by the MISO. Ameren Missouri records these purchase and sale transactions on a net hourly position. Ameren Missouri records net purchases in a single hour in “Operating Expenses – Fuel and purchased power” and net sales in a single hour in “Operating Revenues – Electric” in its statement of income. Ameren Illinois records net purchases in “Operating Expenses – Fuel and purchased power” in its statement of income to reflect all of its MISO transactions relating to the procurement of power for its customers.

Stock-based Compensation

Stock-based compensation cost is measured at the grant date based on the fair value of the award, net of an assumed forfeiture rate. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite vesting period. To the extent that actual forfeitures differ from estimated forfeitures, such differences are accounted for as an adjustment to compensation expense and recorded in the period that estimates are revised. Compensation cost is ultimately recognized only for awards for which the requisite service was provided. See Note 11 – Stock-based Compensation for additional information.

Unamortized Debt Discounts, Premiums, and Issuance Costs

Long-term debt discounts, premiums, and issuance costs are amortized over the lives of the related issuances. Credit agreement fees are amortized over the term of the agreement.

Income Taxes

Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.We expect that regulators will reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in certain excess deferred tax liabilities that were recorded because of decreases in the statutory rate have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery through future customer rates of tax benefits related to the equity component of allowance for funds used during construction, as well as the effects of tax rate increases. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes caused by a change in the statutory rate is recorded as a regulatory asset or liability on the balance sheet and will be collected from, or refunded to, customers. For deferred tax balances not included in rate base, the revaluation of deferred taxes caused by a change in the statutory rate is recorded as an adjustment to income tax expense on the income statement.Tax credits other than investment tax credits are recognized as a reduction to income tax expense when earned and realizable. The benefits for investment tax credits not transferred under the IRA are amortized over the book depreciable lives of the related property. For production and other tax credits otherwise eligible to be recognized when earned and for investment tax credits transferred under the IRA, Ameren considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory liabilities. See Note 2 – Rate and Regulatory Matters for additional information on Ameren Missouri’s production and investment tax credit tracker and the RESRAM. Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren (parent) that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each subsidiary be allocated an amount of tax using a stand-alone calculation ratio to the total amount of tax owed by the consolidated group. Any net benefit attributable to Ameren (parent) is reallocated to the other subsidiaries. This reallocation is treated as a capital contribution to the subsidiary receiving the benefit. See Note 13 – Related-party Transactions for information regarding capital contributions under the tax allocation agreement.

Accounting and Reporting Developments

Improvements to the Accounting for Internal-Use Software

In September 2025, the FASB issued authoritative guidance that made targeted improvements to the accounting for internal-use software. The guidance requires an entity to capitalize internal-use software costs when management has authorized and committed to funding the software project, and it is probable that the project will be completed and the software will be used to perform its intended function. This guidance will be effective for the Ameren Companies in the first quarter of 2028. We are currently assessing the impacts of this guidance on our results of operations, financial position, and liquidity.

Accounting for Government Grants Received by Business Entities

In December 2025, the FASB issued authoritative guidance that established requirements for the recognition, measurement, presentation, and disclosure of government grants received by business entities. The guidance applies to transfers of monetary or tangible nonmonetary assets from a government to a business entity, excluding income tax credits, below-market loans, and government guarantees. Under this guidance, government grants are recognized when it is probable that a business entity will comply with the grant’s conditions and will receive the grant. This guidance will be effective for the Ameren Companies in the first quarter of 2029. We are currently assessing the impacts of this guidance on our results of operations, financial position, and liquidity.

NOTE 2 – RATE AND REGULATORY MATTERS

Below is a summary of our regulatory frameworks and significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.

Regulatory Frameworks

The following table presents the regulatory frameworks and significant regulatory recovery mechanisms for each of Ameren’s rate-regulated businesses, which are discussed in more detail below: [Table with ~2 rows, ~0 numbers, and 1578 characters.] (a)Ameren Missouri’s renewable solutions program allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. (b)Reconciliation adjustments under an MYRP are subject to a reconciliation cap which limits annual adjustment to 105%. See below for additional information regarding the reconciliation cap.

Improvements to the Accounting for Internal-Use Software

In September 2025, the FASB issued authoritative guidance that made targeted improvements to the accounting for internal-use software. The guidance requires an entity to capitalize internal-use software costs when management has authorized and committed to funding the software project, and it is probable that the project will be completed and the software will be used to perform its intended function. This guidance will be effective for the Ameren Companies in the first quarter of 2028. We are currently assessing the impacts of this guidance on our results of operations, financial position, and liquidity.

Accounting for Government Grants Received by Business Entities

In December 2025, the FASB issued authoritative guidance that established requirements for the recognition, measurement, presentation, and disclosure of government grants received by business entities. The guidance applies to transfers of monetary or tangible nonmonetary assets from a government to a business entity, excluding income tax credits, below-market loans, and government guarantees. Under this guidance, government grants are recognized when it is probable that a business entity will comply with the grant’s conditions and will receive the grant. This guidance will be effective for the Ameren Companies in the first quarter of 2029. We are currently assessing the impacts of this guidance on our results of operations, financial position, and liquidity.

NOTE 2 – RATE AND REGULATORY MATTERS

Below is a summary of our regulatory frameworks and significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.

Regulatory Frameworks

The following table presents the regulatory frameworks and significant regulatory recovery mechanisms for each of Ameren’s rate-regulated businesses, which are discussed in more detail below: [Table with ~2 rows, ~0 numbers, and 1578 characters.] (a)Ameren Missouri’s renewable solutions program allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. (b)Reconciliation adjustments under an MYRP are subject to a reconciliation cap which limits annual adjustment to 105%. See below for additional information regarding the reconciliation cap.

Missouri

The MoPSC regulates rates and other matters for Ameren Missouri’s electric service and natural gas distribution businesses. The rates Ameren Missouri charges customers for these services are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a historical test year. Pursuant to the PPRA discussed below, beginning in July 2026, Ameren Missouri will be allowed to file regulatory rate reviews for natural gas delivery service using a future test year, subject to MoPSC approval.Ameren Missouri has recovery mechanisms, including the RESRAM, FAC, MEEIA, PGA, and WNAR, as well as a rider related to the securitization of the Rush Island Energy Center, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, along with the PISA, each described in more detail below, partially mitigate the effects of regulatory lag. Ameren Missouri also employs other recovery mechanisms, including a renewable solutions program revenue and cost tracker, as well as electric and natural gas trackers for certain excess deferred income taxes, property taxes, and pension and postretirement benefit costs. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability, with the difference expected to be reflected in base rates in a subsequent MoPSC rate order. Ameren Missouri also employs a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. Production and investment tax credits produced by renewable energy centers that support compliance with the state of Missouri’s renewable energy standard, such as the High Prairie, Atchison, and Huck Finn energy centers, are not eligible for tracking under this mechanism as they are included in the RESRAM. Ameren Missouri’s cost recovery under any of its recovery mechanisms is subject to MoPSC prudence reviews.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. The RESRAM deferrals are a regulatory asset until they are included in customer rates and collected in a subsequent period. 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 below, 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.The RESRAM permits Ameren Missouri to recover or refund, through customer rates, the difference between the cost of compliance, net of production and investment tax credits, with Missouri’s renewable energy standard and the amount set in base rates. All sales from the High Prairie, Atchison, and Huck Finn energy centers are included in the RESRAM. Customer rates are adjusted for the RESRAM on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. The difference between actual compliance costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either collected from, or refunded to, customers in a subsequent period. RESRAM regulatory assets earn carrying costs at short-term interest rates. The RESRAM permits Ameren Missouri to recover investments in renewable generation related to compliance with Missouri’s renewable energy standard, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism.The FAC permits Ameren Missouri to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional regulatory rate review, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. As such, Ameren Missouri’s results of operations are affected by the 5% not recovered or refunded under the FAC. The 95% variance in net energy costs in a given period is deferred as a regulatory asset or liability, and is either collected from, or refunded to, customers in a subsequent period. FAC regulatory assets earn carrying costs at short-term interest rates. Ameren Missouri’s base rates for electric service are required to be reset at least every four years to allow for continued use of the FAC.In 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance $476 million of costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri is collecting the amounts necessary to repay the bonds through a rider over approximately 15 years beginning in December 2024.The MEEIA permits Ameren Missouri to recover customer energy-efficiency and demand response program costs, the related lost electric revenues, and any performance incentive through the MEEIA without a traditional regulatory rate review, subject to MoPSC prudence reviews. MEEIA assets earn carrying costs at short-term interest rates.Ameren Missouri is a member of the MISO, and its transmission rate is calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. The FERC regulates the rates charged and the terms and conditions for wholesale electric transmission service. The transmission rate update each June is based on Ameren Missouri’s actual historical cost from the prior calendar year. This rate is not directly charged to Missouri retail customers because, in Missouri, the revenue requirement used to set bundled retail base rates includes an amount for transmission-related costs and revenues.The PGA allows Ameren Missouri to recover costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review, subject to MoPSC prudence reviews. These pass-through purchased gas costs do not affect Ameren Missouri’s net income, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either collected from, or refunded to, customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The WNAR allows Ameren Missouri to adjust natural gas delivery service rates charged to residential customers without a traditional regulatory rate review when deviations from normal weather conditions cause natural gas revenues to vary from the related revenue requirement approved by the MoPSC in the previous regulatory rate review. The impact of deviations from normal weather on natural gas delivery service revenues billed to residential customers in a given period are deferred as a regulatory asset or liability. WNAR regulatory assets earn carrying costs at short-term interest rates. The deferred amount is either collected from, or refunded to, residential customers in a subsequent period.

Illinois

The ICC regulates rates and other matters for Ameren Illinois’ electric distribution service and natural gas distribution businesses. Pursuant to the CEJA, Ameren Illinois may elect to establish electric distribution service rates through either an MYRP or a traditional regulatory rate review based on a future test year. See below for additional information regarding the MYRP approved by the ICC, which established rates effective for 2024 through 2027. The rates Ameren Illinois charges customers for natural gas distribution service are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a future test year.Ameren Illinois’ electric distribution service has cost recovery mechanisms in place that allow customer rates to be adjusted without an MYRP or a traditional regulatory rate review. This includes the RBA, which is described in more detail below, and riders for power procurement and transmission services incurred on behalf of its customers, renewable energy credit compliance, zero emission credits, customer generation rebate program costs, and certain environmental costs, as well as bad debt write-offs and the costs of certain asbestos-related claims not recovered in base rates. These pass-through costs do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews. 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, such as those described above and the electric energy-efficiency rider discussed below, among others. 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 did not exceed the reconciliation cap for the 2024 and 2025 revenue requirements. The 2025 revenue requirement is subject to final reconciliation and ICC review. Ameren Illinois expects to file the 2025 reconciliation with the ICC by May 2026. Subject to the reconciliation cap, if a given year’s actual revenue requirement 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. Regulatory assets applicable to the MYRP earn a return at the applicable WACC. However, Ameren Illinois recognizes the carrying cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates. Ameren Illinois’ existing riders continue to be effective under the MYRP.The RBA allows Ameren Illinois to adjust electric distribution service rates charged to customers under an MYRP or a traditional regulatory rate review when electric distribution revenues vary from the related revenue requirement approved by the ICC in the previous MYRP or traditional regulatory rate review. If a given year’s actual revenue billed to customers varies from the approved revenue requirement as a result of sales volumes and/or wholesale and miscellaneous revenue, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue. RBA regulatory assets do not earn carrying costs or a return. The regulatory balance is either collected from, or refunded to, customers within two years from the end of the applicable annual period.Ameren Illinois used the IEIMA formula framework to establish annual customer electric distribution service rates effective through 2023. Under the framework, Ameren Illinois was allowed to reconcile its revenue requirement for customer rates established through 2023. Ameren Illinois’ 2023 revenues reflected 2023 actual recoverable costs, 2023 year-end rate base, and a return at the applicable WACC, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The 2023 revenue requirement reconciliation adjustment was collected from customers in 2025.Ameren Illinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for its electric energy-efficiency investments, the revenue requirements are based on recoverable costs, year-end rate base, and a year-end ratemaking capital structure, and earn a return at the applicable WACC. Through 2026, the ROE component of the applicable WACC will continue to be based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points and any performance-related basis-point adjustments, described in more detail below. Therefore, Ameren Illinois’ annual ROE for its electric energy-efficiency investments is directly correlated to the yields on such bonds through 2026. Pursuant to the CRGA discussed below, 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. Regulatory assets applicable to formula ratemaking for electric energy-efficiency investments earn a return at the applicable WACC. However, Ameren Illinois recognizes the carrying cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates. Ameren Illinois’ electric distribution service business is also subject to performance metrics. Failure to achieve the metrics would result in a reduction in the company’s allowed ROE calculated under the MYRP. In 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points under the MYRP, allocated among seven performance metrics. These performance metrics apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, the allowed ROE on energy-efficiency investments can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings and demand goals. Any adjustments to the allowed ROE for energy-efficiency investments will depend on annual performance for a historical period relative to energy savings goals. In 2025, 2024, and 2023, there were no performance-related basis-point adjustments that materially affected financial results.Ameren Illinois’ natural gas distribution business has recovery mechanisms, including the PGA and VBA, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, described in more detail below, mitigate the effects of regulatory lag. Ameren Illinois employs other riders for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt write-offs and invested capital taxes not recovered in base rates. Pass-through costs under the riders do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.The PGA allows Ameren Illinois to recover costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review, subject to ICC prudence reviews. These pass-through purchased gas costs do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either collected from, or refunded to, customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The VBA ensures recoverability of the natural gas distribution service revenue requirement that is dependent on sales volumes for residential and small nonresidential customers. For these rate classes, the VBA allows Ameren Illinois to adjust natural gas distribution service rates without a traditional regulatory rate review when changes occur in sales volumes from those volumes approved by the ICC in a previous regulatory rate review. The difference between allowed sales revenues and amounts billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either collected from, or refunded to, customers in a subsequent period. VBA regulatory assets for a given year that are not fully collected by the end of the following year begin earning carrying costs at short-term interest rates.

Federal

The FERC regulates rates and other matters for Ameren Illinois’ transmission business and ATXI, as well as for Ameren Missouri. See the discussion above related to Ameren Missouri. Both Ameren Illinois and ATXI are members of the MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. 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. If a given year’s revenue requirement varies from the amount collected from customers, 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, independent of actual sales volumes. The regulatory balance is collected from, or refunded to, customers within two years from the end of the year. FERC revenue requirement reconciliation adjustment regulatory assets earn carrying costs at each company’s short-term interest rates. In addition, the FERC has approved transmission rate incentives, including a 50-basis-point incentive adder to the allowed base ROE for Ameren Illinois and ATXI for participation in an RTO.

Proceedings and Updates

Proceedings and Updates

Missouri

####### PPRA The PPRA became effective in August 2025. Pursuant to the law, the PISA has been modified to include new natural gas generating units placed in service after the effective date of the law as qualifying property, plant, and equipment eligible for deferral and recovery of 85% of the related depreciation expense. These new natural gas generating units will also be included in the 85% of rate base allowed to earn a return at the applicable WACC under the PISA. The 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. Furthermore, the PISA's expiration date has been extended through 2035, unless Ameren Missouri requests and receives MoPSC approval of an extension through 2040. The law also 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 addition, 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.Further, 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. Under this provision, utilities are not allowed to capitalize allowance for funds used during construction on projects approved to include construction work in progress in rate base. 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. 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.

April 2025 MoPSC Electric Rate Order

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.

July 2025 MoPSC Natural Gas Rate Order

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.

Large Load Customer Rate Plan

In November 2025, the MoPSC approved Ameren Missouri’s request to modify its existing large primary service tariff, pursuant to the PPRA, 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.

Generation and Storage Facilities

Ameren Missouri is party to agreements to acquire and/or construct various generation and storage facilities that are consistent with the 2025 Change to the 2023 PRP. The generation and storage facilities are eligible for recovery under the PISA. The following table provides information with respect to each facility: [Table with ~7 rows, ~21 numbers, and 659 characters.] (a)In-service dates are dependent on the timing of regulatory approvals and construction completion, among other things.(b)These projects collectively represent approximately $0.2 billion of capital expenditures.(c)Ameren Missouri received FERC approval for the acquisition in November 2024. 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 $0.6 billion, and took over construction management of the project.(d)This project represents approximately $0.9 billion of capital expenditures.(e)These projects represent approximately $2 billion of capital expenditures.(f)Ameren Missouri expects a decision by the MoPSC in the first half of 2026. ####### MEEIA In 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement for Ameren Missouri’s MEEIA 2025 plan, which includes a portfolio of customer energy-efficiency and demand response programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from customers its actual MEEIA program costs, related lost electric revenues, and performance incentives. Ameren Missouri intends to invest $51 million in 2026 and $22 million in 2027 for customer energy-efficiency and demand response programs. In addition, the order approved an immaterial amount of performance incentives applicable to each plan year to earn revenues by achieving certain spending and demand response goals.

MISO Long-Range Transmission Projects CCN

In 2022, the MISO approved the first tranche of projects related to a preliminary long-range transmission planning roadmap of projects through 2039. A portion of these projects were assigned or awarded via a competitive bid process to various utilities, including Ameren. In July and December 2025, the MoPSC issued orders approving requests filed by ATXI for CCNs, among other things, related to the portion of the MISO long-range transmission projects it will construct within the MoPSC’s jurisdiction.

PPRA

The PPRA became effective in August 2025. Pursuant to the law, the PISA has been modified to include new natural gas generating units placed in service after the effective date of the law as qualifying property, plant, and equipment eligible for deferral and recovery of 85% of the related depreciation expense. These new natural gas generating units will also be included in the 85% of rate base allowed to earn a return at the applicable WACC under the PISA. The 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. Furthermore, the PISA's expiration date has been extended through 2035, unless Ameren Missouri requests and receives MoPSC approval of an extension through 2040. The law also 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 addition, 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.Further, 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. Under this provision, utilities are not allowed to capitalize allowance for funds used during construction on projects approved to include construction work in progress in rate base. 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. 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.

April 2025 MoPSC Electric Rate Order

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.

July 2025 MoPSC Natural Gas Rate Order

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.

Large Load Customer Rate Plan

In November 2025, the MoPSC approved Ameren Missouri’s request to modify its existing large primary service tariff, pursuant to the PPRA, 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.

Generation and Storage Facilities

Ameren Missouri is party to agreements to acquire and/or construct various generation and storage facilities that are consistent with the 2025 Change to the 2023 PRP. The generation and storage facilities are eligible for recovery under the PISA. The following table provides information with respect to each facility: [Table with ~7 rows, ~21 numbers, and 659 characters.] (a)In-service dates are dependent on the timing of regulatory approvals and construction completion, among other things.(b)These projects collectively represent approximately $0.2 billion of capital expenditures.(c)Ameren Missouri received FERC approval for the acquisition in November 2024. 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 $0.6 billion, and took over construction management of the project.(d)This project represents approximately $0.9 billion of capital expenditures.(e)These projects represent approximately $2 billion of capital expenditures.(f)Ameren Missouri expects a decision by the MoPSC in the first half of 2026. ####### MEEIA In 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement for Ameren Missouri’s MEEIA 2025 plan, which includes a portfolio of customer energy-efficiency and demand response programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from customers its actual MEEIA program costs, related lost electric revenues, and performance incentives. Ameren Missouri intends to invest $51 million in 2026 and $22 million in 2027 for customer energy-efficiency and demand response programs. In addition, the order approved an immaterial amount of performance incentives applicable to each plan year to earn revenues by achieving certain spending and demand response goals.

MISO Long-Range Transmission Projects CCN

In 2022, the MISO approved the first tranche of projects related to a preliminary long-range transmission planning roadmap of projects through 2039. A portion of these projects were assigned or awarded via a competitive bid process to various utilities, including Ameren. In July and December 2025, the MoPSC issued orders approving requests filed by ATXI for CCNs, among other things, related to the portion of the MISO long-range transmission projects it will construct within the MoPSC’s jurisdiction.

Illinois

####### MYRP 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. 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, and Ameren Illinois cannot predict the ultimate outcome of the appeals.

2024 Electric Distribution Service Revenue Requirement Reconciliation Adjustment Order

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.

Electric Customer Energy-Efficiency Investments

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.

Grid Plan

In January 2026, Ameren Illinois filed its Grid Plan for the years 2028 through 2031. The Grid Plan will be used to align capital expenditures to operational needs and will impact rate base for future rate reviews under an MYRP or traditional rate review. An order from the ICC is expected in December 2026.

Electric Energy Efficiency Plan

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. 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 below. ####### CRGA 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.

2025 Natural Gas Delivery Service Rate Order

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, and Ameren Illinois cannot predict the ultimate outcome of the appeal.

QIP Reconciliation Hearing

Pursuant to Illinois law, 2014 was the first year of the QIP. In 2021, Ameren Illinois filed a request with the ICC to initiate a reconciliation proceeding of natural gas capital investments recovered under the QIP rider during 2020. Ameren Illinois recovered similar investments in each of the 2014 to 2019 annual reconciliations. In September 2024, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow $30 million in natural gas capital investments as imprudent, unsupported, or ineligible to be recovered through the QIP resulting in a potential over-recovery of an immaterial amount by Ameren Illinois in 2020. In 2023, and again in 2024, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2020. Ameren Illinois’ 2020 QIP rate recovery request under review by the ICC is within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding. Ameren Illinois included $529 million of eligible natural gas capital investments in the QIP from 2021 to 2023. In addition, 2021 through 2023 reconciliation proceedings are still ongoing. Ameren Illinois cannot predict the ultimate outcome of these regulatory proceedings.

MISO Long-Range Transmission Projects CCN

In 2022, the MISO approved the first tranche of projects related to a preliminary long-range transmission planning roadmap of projects through 2039. A portion of these projects were assigned or awarded via a competitive bidding process to various utilities, including Ameren. In July 2025, the ICC issued an order approving a request filed by Ameren Illinois and ATXI for a CCN, among other things, related to the portion of the MISO long-range transmission projects they will construct within the ICC’s jurisdiction.

MYRP

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. 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, and Ameren Illinois cannot predict the ultimate outcome of the appeals.

2024 Electric Distribution Service Revenue Requirement Reconciliation Adjustment Order

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.

Electric Customer Energy-Efficiency Investments

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.

Grid Plan

In January 2026, Ameren Illinois filed its Grid Plan for the years 2028 through 2031. The Grid Plan will be used to align capital expenditures to operational needs and will impact rate base for future rate reviews under an MYRP or traditional rate review. An order from the ICC is expected in December 2026.

Electric Energy Efficiency Plan

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. 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 below. ####### CRGA 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.

2025 Natural Gas Delivery Service Rate Order

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, and Ameren Illinois cannot predict the ultimate outcome of the appeal.

QIP Reconciliation Hearing

Pursuant to Illinois law, 2014 was the first year of the QIP. In 2021, Ameren Illinois filed a request with the ICC to initiate a reconciliation proceeding of natural gas capital investments recovered under the QIP rider during 2020. Ameren Illinois recovered similar investments in each of the 2014 to 2019 annual reconciliations. In September 2024, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow $30 million in natural gas capital investments as imprudent, unsupported, or ineligible to be recovered through the QIP resulting in a potential over-recovery of an immaterial amount by Ameren Illinois in 2020. In 2023, and again in 2024, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2020. Ameren Illinois’ 2020 QIP rate recovery request under review by the ICC is within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding. Ameren Illinois included $529 million of eligible natural gas capital investments in the QIP from 2021 to 2023. In addition, 2021 through 2023 reconciliation proceedings are still ongoing. Ameren Illinois cannot predict the ultimate outcome of these regulatory proceedings.

MISO Long-Range Transmission Projects CCN

In 2022, the MISO approved the first tranche of projects related to a preliminary long-range transmission planning roadmap of projects through 2039. A portion of these projects were assigned or awarded via a competitive bidding process to various utilities, including Ameren. In July 2025, the ICC issued an order approving a request filed by Ameren Illinois and ATXI for a CCN, among other things, related to the portion of the MISO long-range transmission projects they will construct within the ICC’s jurisdiction.

Federal

MISO Transmission Rate Incentives

In 2024, the MISO approved a first set of second tranche projects related to its preliminary long-range transmission planning roadmap of projects through 2039. 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. 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.

FERC ROE Complaint Cases

Since November 2013, the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff has been subject to customer complaint cases and has been changed by various FERC orders. In October 2024, the FERC issued an order, which decreased the allowed base ROE from 10.02% to 9.98% and required refunds, with interest, for the periods from November 2013 to February 2015 and from late September 2016 forward. In January and April 2025, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed appeals of the October 2024 order and a March 2025 FERC order that rejected all rehearing requests to the United States Court of Appeals for the District of Columbia Circuit. The appellate court is under no deadline to address the appeals.

Regulatory Assets and Liabilities

The following table presents our regulatory assets and regulatory liabilities at December 31, 2025 and 2024: [Table with ~41 rows, ~188 numbers, and 2133 characters.] (a)Under-recovered fuel and purchased power costs to be recovered through the FAC. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.(b)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.(c)The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the IEIMA performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. The under-recovery was recovered from customers with a return at the applicable WACC in 2025.(d)These assets earn a return at the applicable WACC.(e)The difference between Ameren Illinois' actual annual electric distribution revenue requirement, as adjusted for certain cost variations, and the ICC-approved revenue requirement, subject to a reconciliation cap. The under-recovery will be recovered from customers with a return at the applicable WACC within two years. (f)Under-recovered electric distribution service revenue caused by sales volume and/or wholesale and miscellaneous revenue deviations from the related revenue requirement approved by the ICC for a given year. The under-recovery will be recovered from customers within two years.(g)Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years.(h)Under-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in regulatory rate reviews. Each year’s amount will be recovered from customers from April through December of the following year.(i)The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction, the securitization of the Rush Island Energy Center, and the effects of tax rate increases. The regulatory liabilities represent amounts that will be refunded to customers for excess deferred income taxes related to depreciation differences caused by a decrease in the statutory rates, other tax liabilities, and amounts related to the unamortized portion of investment tax credits. Amounts associated with the equity component of allowance for funds used during construction, the securitization of the Rush Island Energy Center, and amounts related to the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 38, 30, and 44 years. In addition, the regulatory liabilities for Ameren Missouri include a regulatory recovery mechanism for the difference between production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA and the level of such tax credits included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. Amounts included in the accumulation period approved in the April 2025 MoPSC electric rate order, discussed above, are being amortized over five years beginning June 2025. An amortization period for subsequent accumulations will be established in a future rate review.(j)A rider for the difference between the level of bad debt write-offs, net of any subsequent recoveries, incurred by Ameren Illinois and the level of such costs included in electric distribution and natural gas delivery service rates. Under-recovered or over-recovered costs for each year are collected from, or refunded to, customers over a twelve-month period beginning in June of the following year.(k)Maintenance expenses related to scheduled refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. Amounts are amortized over the period between refueling and maintenance outages, which has historically been approximately 18 months.(l)Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued.(m)The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information.(n)Storm costs from 2021 through 2025 deferred in accordance with the IEIMA and MYRP. These costs are being amortized over five-year periods beginning in the year the storm occurred.(o)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid.(p)Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on 85% of investments in certain property, plant, and equipment placed in service and not included in base rates. Accumulated PISA deferrals, which also earn a return at the applicable WACC, are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.(q)In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance costs related to the accelerated retirement of the Rush Island Energy Center, which includes the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri is collecting the amounts necessary to repay the securitized utility tariff bonds over approximately 15 years beginning in December 2024.(r)Under-recovered costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Under-recovered or over-recovered costs are aggregated over a twelve-month period beginning each August and are amortized over a twelve-month period beginning in February of the following year.(s)Certain costs associated with the Meramec Energy Center, which were authorized for recovery by a December 2021 MoPSC electric rate order. These costs are being collected over five years beginning in February 2022.(t)The electric energy-efficiency investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from one to 13 years.(u)A regulatory recovery mechanism for the difference between actual property taxes incurred by Ameren Missouri and the related taxes included in customer rates. The period of recovery, or refund, varies based on MoPSC approval in a regulatory rate review. Electric amounts accumulated through 2024 are being amortized over three years beginning June 2025. Gas amounts accumulated through 2024 are being amortized over five years beginning September 2025. For electric and natural gas related costs incurred subsequent to 2024, the amortization period will be determined in a future regulatory rate review.(v)Over-recovered costs from utility customers. Amounts will be refunded to customers within one year of the deferral.(w)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment when retired from service.(x)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,526 million and $1,342 million at December 31, 2025 and 2024, respectively), net of recoverable removal costs for AROs ($685 million and $651 million at December 31, 2025 and 2024, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations and Removal Costs.(y)Over-recovered costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information.(z)A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For electric and natural gas related costs incurred through 2024, the weighted-average remaining amortization period is four years. For electric and natural gas related costs incurred subsequent to 2024, the amortization period will be determined in a future regulatory rate review.(aa)Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to an annual reconciliation proceeding, the latest of which was approved by the ICC in May 2025 and did not result in refunds to customers.(ab)Funds collected from the issuance of securitized utility tariff bonds by AMF primarily to pay for the decommissioning of the Rush Island Energy Center. The amortization period for the difference between the estimated costs and the actual costs incurred will be determined in a future regulatory rate review. (ac)Base rate revenues related to the Rush Island Energy Center collected after the energy center was retired in October 2024, which is being refunded to customers over three years beginning June 2025.

NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET

The following table presents components of “Property, plant, and equipment, net” at December 31, 2025 and 2024: [Table with ~32 rows, ~92 numbers, and 1248 characters.] (a)The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydroelectric generating assets, which have useful lives of up to 150 years; 20 to 80 years for electric distribution; 50 to 75 years for electric transmission; 15 to 80 years for natural gas; and 2 to 55 years for other.(b)Includes $30 million of oil-fired generation at December 31, 2025 and 2024.(c)Renewable includes hydroelectric, wind, solar, and methane gas generation facilities.(d)Other property, plant, and equipment includes assets used to support electric distribution, electric transmission, and natural gas services. Capitalized software costs are classified within “Property, Plant, and Equipment, Net” on the balance sheet and are amortized on a straight-line basis over the expected period of benefit, ranging from 2 to 15 years, with the amortization expense included in “Depreciation and amortization” on the statement of income. Deferred cloud implementation costs are classified within “Other Assets” on the balance sheet and are amortized on a straight-line basis over the term of the associated hosting arrangement, ranging from 5 to 15 years, with the amortization expense included in “Other operations and maintenance” on the statement of income. The following table presents the amortization expense, gross carrying value, and related accumulated amortization of capitalized software and deferred cloud implementation costs by year: [Table with ~8 rows, ~49 numbers, and 403 characters.] Annual amortization expense for capitalized software classified as in service as of December 31, 2025, is estimated to be as follows: [Table with ~3 rows, ~20 numbers, and 107 characters.]

NOTE 4 – 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.

MISO Transmission Rate Incentives

In 2024, the MISO approved a first set of second tranche projects related to its preliminary long-range transmission planning roadmap of projects through 2039. 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. 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.

FERC ROE Complaint Cases

Since November 2013, the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff has been subject to customer complaint cases and has been changed by various FERC orders. In October 2024, the FERC issued an order, which decreased the allowed base ROE from 10.02% to 9.98% and required refunds, with interest, for the periods from November 2013 to February 2015 and from late September 2016 forward. In January and April 2025, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed appeals of the October 2024 order and a March 2025 FERC order that rejected all rehearing requests to the United States Court of Appeals for the District of Columbia Circuit. The appellate court is under no deadline to address the appeals.

Regulatory Assets and Liabilities

The following table presents our regulatory assets and regulatory liabilities at December 31, 2025 and 2024: [Table with ~41 rows, ~188 numbers, and 2133 characters.] (a)Under-recovered fuel and purchased power costs to be recovered through the FAC. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.(b)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.(c)The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the IEIMA performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. The under-recovery was recovered from customers with a return at the applicable WACC in 2025.(d)These assets earn a return at the applicable WACC.(e)The difference between Ameren Illinois' actual annual electric distribution revenue requirement, as adjusted for certain cost variations, and the ICC-approved revenue requirement, subject to a reconciliation cap. The under-recovery will be recovered from customers with a return at the applicable WACC within two years. (f)Under-recovered electric distribution service revenue caused by sales volume and/or wholesale and miscellaneous revenue deviations from the related revenue requirement approved by the ICC for a given year. The under-recovery will be recovered from customers within two years.(g)Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years.(h)Under-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in regulatory rate reviews. Each year’s amount will be recovered from customers from April through December of the following year.(i)The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction, the securitization of the Rush Island Energy Center, and the effects of tax rate increases. The regulatory liabilities represent amounts that will be refunded to customers for excess deferred income taxes related to depreciation differences caused by a decrease in the statutory rates, other tax liabilities, and amounts related to the unamortized portion of investment tax credits. Amounts associated with the equity component of allowance for funds used during construction, the securitization of the Rush Island Energy Center, and amounts related to the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 38, 30, and 44 years. In addition, the regulatory liabilities for Ameren Missouri include a regulatory recovery mechanism for the difference between production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA and the level of such tax credits included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. Amounts included in the accumulation period approved in the April 2025 MoPSC electric rate order, discussed above, are being amortized over five years beginning June 2025. An amortization period for subsequent accumulations will be established in a future rate review.(j)A rider for the difference between the level of bad debt write-offs, net of any subsequent recoveries, incurred by Ameren Illinois and the level of such costs included in electric distribution and natural gas delivery service rates. Under-recovered or over-recovered costs for each year are collected from, or refunded to, customers over a twelve-month period beginning in June of the following year.(k)Maintenance expenses related to scheduled refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. Amounts are amortized over the period between refueling and maintenance outages, which has historically been approximately 18 months.(l)Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued.(m)The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information.(n)Storm costs from 2021 through 2025 deferred in accordance with the IEIMA and MYRP. These costs are being amortized over five-year periods beginning in the year the storm occurred.(o)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid.(p)Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on 85% of investments in certain property, plant, and equipment placed in service and not included in base rates. Accumulated PISA deferrals, which also earn a return at the applicable WACC, are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.(q)In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance costs related to the accelerated retirement of the Rush Island Energy Center, which includes the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri is collecting the amounts necessary to repay the securitized utility tariff bonds over approximately 15 years beginning in December 2024.(r)Under-recovered costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Under-recovered or over-recovered costs are aggregated over a twelve-month period beginning each August and are amortized over a twelve-month period beginning in February of the following year.(s)Certain costs associated with the Meramec Energy Center, which were authorized for recovery by a December 2021 MoPSC electric rate order. These costs are being collected over five years beginning in February 2022.(t)The electric energy-efficiency investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from one to 13 years.(u)A regulatory recovery mechanism for the difference between actual property taxes incurred by Ameren Missouri and the related taxes included in customer rates. The period of recovery, or refund, varies based on MoPSC approval in a regulatory rate review. Electric amounts accumulated through 2024 are being amortized over three years beginning June 2025. Gas amounts accumulated through 2024 are being amortized over five years beginning September 2025. For electric and natural gas related costs incurred subsequent to 2024, the amortization period will be determined in a future regulatory rate review.(v)Over-recovered costs from utility customers. Amounts will be refunded to customers within one year of the deferral.(w)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment when retired from service.(x)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,526 million and $1,342 million at December 31, 2025 and 2024, respectively), net of recoverable removal costs for AROs ($685 million and $651 million at December 31, 2025 and 2024, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations and Removal Costs.(y)Over-recovered costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information.(z)A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For electric and natural gas related costs incurred through 2024, the weighted-average remaining amortization period is four years. For electric and natural gas related costs incurred subsequent to 2024, the amortization period will be determined in a future regulatory rate review.(aa)Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to an annual reconciliation proceeding, the latest of which was approved by the ICC in May 2025 and did not result in refunds to customers.(ab)Funds collected from the issuance of securitized utility tariff bonds by AMF primarily to pay for the decommissioning of the Rush Island Energy Center. The amortization period for the difference between the estimated costs and the actual costs incurred will be determined in a future regulatory rate review. (ac)Base rate revenues related to the Rush Island Energy Center collected after the energy center was retired in October 2024, which is being refunded to customers over three years beginning June 2025.

NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET

The following table presents components of “Property, plant, and equipment, net” at December 31, 2025 and 2024: [Table with ~32 rows, ~92 numbers, and 1248 characters.] (a)The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydroelectric generating assets, which have useful lives of up to 150 years; 20 to 80 years for electric distribution; 50 to 75 years for electric transmission; 15 to 80 years for natural gas; and 2 to 55 years for other.(b)Includes $30 million of oil-fired generation at December 31, 2025 and 2024.(c)Renewable includes hydroelectric, wind, solar, and methane gas generation facilities.(d)Other property, plant, and equipment includes assets used to support electric distribution, electric transmission, and natural gas services. Capitalized software costs are classified within “Property, Plant, and Equipment, Net” on the balance sheet and are amortized on a straight-line basis over the expected period of benefit, ranging from 2 to 15 years, with the amortization expense included in “Depreciation and amortization” on the statement of income. Deferred cloud implementation costs are classified within “Other Assets” on the balance sheet and are amortized on a straight-line basis over the term of the associated hosting arrangement, ranging from 5 to 15 years, with the amortization expense included in “Other operations and maintenance” on the statement of income. The following table presents the amortization expense, gross carrying value, and related accumulated amortization of capitalized software and deferred cloud implementation costs by year: [Table with ~8 rows, ~49 numbers, and 403 characters.] Annual amortization expense for capitalized software classified as in service as of December 31, 2025, is estimated to be as follows: [Table with ~3 rows, ~20 numbers, and 107 characters.]

NOTE 4 – 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.

Short-Term Borrowings

In December 2025, the Credit Agreements, which were scheduled to mature in December 2028, were extended and amended. The Credit Agreements now mature in December 2030. The Credit Agreements provide $3.2 billion of credit cumulatively through maturity. The total facility size of the Missouri Credit Agreement and Illinois Credit Agreement is $1.9 billion and $1.3 billion, respectively. The maturity date of each Credit Agreement may be extended for an additional one-year period upon the mutual consent of the respective borrowers and the lenders. Credit available under the agreements is provided by 20 international, national, and regional lenders, with no single lender providing more than $208 million of lending capacity across both agreements in the aggregate.The obligations of each borrower under the respective Credit Agreements to which it is a party are several and not joint. Except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective Credit Agreements are not guaranteed by Ameren (parent) or any other subsidiary of Ameren. The following table presents the maximum aggregate amount available to each borrower under each facility: [Table with ~3 rows, ~4 numbers, and 122 characters.] The borrowers have the option to seek additional commitments from existing or new lenders to increase the total facility size of the Credit Agreements to a maximum of $2.4 billion for the Missouri Credit Agreement and $1.6 billion for the Illinois Credit Agreement. Ameren (parent) borrowings are due and payable no later than the maturity date of the Credit Agreements. Ameren Missouri and Ameren Illinois borrowings under the applicable Credit Agreement are due and payable no later than the earlier of the maturity date or 364 days after the date of the borrowing.The obligations of the borrowers under the Credit Agreements are unsecured. Loans are available on a revolving basis under each of the Credit Agreements. Funds borrowed may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate plus the margin applicable to the particular borrower and/or the eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower’s long-term unsecured credit ratings or, if no such ratings are in effect, the borrower’s corporate/issuer ratings then in effect. The borrowers have received commitments from the lenders to issue letters of credit up to $120 million under each of the Credit Agreements. In addition, the issuance of letters of credit is subject to the $3.2 billion overall combined facility borrowing limitations of the Credit Agreements.The borrowers will use the proceeds from any borrowings under the Credit Agreements for general corporate purposes. The Missouri Credit Agreement and the Illinois Credit Agreement are available to support issuances under Ameren (parent)’s, Ameren Missouri’s and Ameren Illinois’ commercial paper programs, respectively, subject to borrowing sublimits, as well as to support issuance of letters of credit for the borrowers. Ameren (parent), Ameren Missouri and Ameren Illinois’ use letters of credit to provide financial guarantees for certain operating obligations. As of December 31, 2025, there were $33 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value. As of December 31, 2025, based on credit capacity available under the Credit Agreements, along with cash and cash equivalents, the net liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $2.5 billion. The following table summarizes the activity and relevant interest rates for Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper issuances under the Credit Agreements in the aggregate for the years ended December 31, 2025 and 2024: [Table with ~12 rows, ~41 numbers, and 631 characters.] (a)    The timing of peak outstanding commercial paper issuances and borrowings under the Credit Agreements varies by company. Therefore, the sum of individual company peak amounts may not equal the Ameren consolidated peak amount for the period.

Indebtedness Provisions and Other Covenants

The information below is a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants.The Credit Agreements contain conditions for borrowings and issuances of letters of credit. These conditions include the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation, and the absence of any notice of violation, liability, or requirement under any environmental laws that could have a material adverse effect), and obtaining required regulatory authorizations. In addition, it is a condition for any Ameren Illinois borrowing that, at the time of and after giving effect to such borrowing, Ameren Illinois not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation.The Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur certain liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The Credit Agreements require each of Ameren, Ameren Missouri, and Ameren Illinois to maintain consolidated indebtedness of not more than 67.5%, 65%, and 65%, respectively, of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of December 31, 2025, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 59%, 49%, and 45%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The Credit Agreements contain default provisions that apply separately to each borrower. However, a default of Ameren Missouri or Ameren Illinois under the applicable credit agreement is also deemed to constitute a default of Ameren (parent) under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries, nonmaterial subsidiaries, and certain special purposes entities contemplated in the Credit Agreements) in excess of $150 million in the aggregate (including under the other credit agreement). However, under the default provisions of the Credit Agreements, any default of Ameren (parent) under either credit agreement that results solely from a default of Ameren Missouri or Ameren Illinois does not result in a cross-default of Ameren (parent) under the other credit agreement. Further, the Credit Agreements default provisions provide that an Ameren (parent) default under either of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.None of the Credit Agreements or financing agreements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. The Ameren Companies were in compliance with the provisions and covenants of the Credit Agreements at December 31, 2025.

Money Pools

Ameren (parent) has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the money pool from participants. The primary sources of external funds for the utility money pool are the Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but it is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2025, was 4.39% (2024 – 5.19%).See Note 13 – Related-party Transactions for the amount of interest income and expense from the utility money pool agreement recorded by Ameren Missouri and Ameren Illinois for the years ended December 31, 2025, 2024, and 2023.

NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS

The following table presents long-term debt outstanding, including maturities due within one year, as of December 31, 2025 and 2024: [Table with ~43 rows, ~108 numbers, and 1855 characters.] [Table with ~36 rows, ~88 numbers, and 1509 characters.] (a)These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2055 maturity date of the 5.125% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (d) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.(b)These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. They are secured by substantially all Ameren Missouri property and franchises.(c)These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes.(d)Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions.(e)These bonds were issued by AMF. The bondholders of AMF have no recourse to Ameren Missouri’s assets. Ameren Missouri collects securitization surcharges to cover the principal and interest on the bonds as well as certain other qualified costs. The surcharges collected by Ameren Missouri on behalf of AMF are remitted to AMF and are not available to creditors of Ameren Missouri. Principal and interest payments on these bonds are payable semiannually on April 1 and October 1 of each year, which began on October 1, 2025, with final principal and interest payment due October 1, 2039.(f)These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2055 maturity date of the 5.625% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.(g)These bonds are first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises.

(h)

The following table presents the principal maturities schedule for the 2.45% senior unsecured notes due 2036: [Table with ~4 rows, ~5 numbers, and 68 characters.] (i)The following table presents the principal maturities schedule for the 3.43% senior unsecured notes due 2050: [Table with ~8 rows, ~13 numbers, and 117 characters.] (j)The following table presents the principal maturities schedule for the 2.96% senior unsecured notes due 2052: [Table with ~4 rows, ~5 numbers, and 64 characters.] The following table presents the aggregate maturities of long-term debt, including current maturities, at December 31, 2025: [Table with ~7 rows, ~34 numbers, and 269 characters.] (a)Excludes unamortized discount, premium, and debt issuance costs of $19 million, $77 million, $54 million, and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI, respectively. In November and December 2024, Ameren (parent) purchased senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois for $44 million in the aggregate. In June 2025, Ameren (parent) purchased senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois for $24 million in the aggregate. On a consolidated basis, Ameren (parent)’s repurchase of these senior secured notes and first mortgage bonds were accounted for as a debt extinguishment and resulted in a pre-tax gain of $8 million and $16 million for the years ended December 31, 2025 and 2024, respectively, which is reflected in “Other Income, Net” on Ameren’s consolidated statement of income. Interest expense related to the repurchased bonds was $3 million and less than $1 million for the years ended December 31, 2025 and 2024, respectively. The following table presents Ameren Missouri’s and Ameren Illinois’ “Long-term Debt, Net - Related Parties” as of December 31, 2025 and 2024: [Table with ~14 rows, ~32 numbers, and 544 characters.] All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends, have voting rights, and are not subject to mandatory redemption. The preferred stock of Ameren’s subsidiaries is included in “Noncontrolling Interests” on Ameren’s consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois, which is redeemable at the option of the issuer, at the prices shown below as of December 31, 2025 and 2024: [Table with ~25 rows, ~100 numbers, and 952 characters.] (a)In the event of voluntary liquidation, $105.50. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no such shares outstanding. Ameren Missouri has 7.5 million shares of $1 par value preference stock authorized, with no such shares outstanding. Ameren Illinois has 2.6 million shares of no par value preferred stock authorized, with no such shares outstanding.

NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS

The following table presents long-term debt outstanding, including maturities due within one year, as of December 31, 2025 and 2024: [Table with ~43 rows, ~108 numbers, and 1855 characters.] [Table with ~36 rows, ~88 numbers, and 1509 characters.] (a)These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2055 maturity date of the 5.125% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (d) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.(b)These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. They are secured by substantially all Ameren Missouri property and franchises.(c)These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes.(d)Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions.(e)These bonds were issued by AMF. The bondholders of AMF have no recourse to Ameren Missouri’s assets. Ameren Missouri collects securitization surcharges to cover the principal and interest on the bonds as well as certain other qualified costs. The surcharges collected by Ameren Missouri on behalf of AMF are remitted to AMF and are not available to creditors of Ameren Missouri. Principal and interest payments on these bonds are payable semiannually on April 1 and October 1 of each year, which began on October 1, 2025, with final principal and interest payment due October 1, 2039.(f)These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2055 maturity date of the 5.625% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.(g)These bonds are first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises.

(h)

The following table presents the principal maturities schedule for the 2.45% senior unsecured notes due 2036: [Table with ~4 rows, ~5 numbers, and 68 characters.] (i)The following table presents the principal maturities schedule for the 3.43% senior unsecured notes due 2050: [Table with ~8 rows, ~13 numbers, and 117 characters.] (j)The following table presents the principal maturities schedule for the 2.96% senior unsecured notes due 2052: [Table with ~4 rows, ~5 numbers, and 64 characters.] The following table presents the aggregate maturities of long-term debt, including current maturities, at December 31, 2025: [Table with ~7 rows, ~34 numbers, and 269 characters.] (a)Excludes unamortized discount, premium, and debt issuance costs of $19 million, $77 million, $54 million, and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI, respectively. In November and December 2024, Ameren (parent) purchased senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois for $44 million in the aggregate. In June 2025, Ameren (parent) purchased senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois for $24 million in the aggregate. On a consolidated basis, Ameren (parent)’s repurchase of these senior secured notes and first mortgage bonds were accounted for as a debt extinguishment and resulted in a pre-tax gain of $8 million and $16 million for the years ended December 31, 2025 and 2024, respectively, which is reflected in “Other Income, Net” on Ameren’s consolidated statement of income. Interest expense related to the repurchased bonds was $3 million and less than $1 million for the years ended December 31, 2025 and 2024, respectively. The following table presents Ameren Missouri’s and Ameren Illinois’ “Long-term Debt, Net - Related Parties” as of December 31, 2025 and 2024: [Table with ~14 rows, ~32 numbers, and 544 characters.] All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends, have voting rights, and are not subject to mandatory redemption. The preferred stock of Ameren’s subsidiaries is included in “Noncontrolling Interests” on Ameren’s consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois, which is redeemable at the option of the issuer, at the prices shown below as of December 31, 2025 and 2024: [Table with ~25 rows, ~100 numbers, and 952 characters.] (a)In the event of voluntary liquidation, $105.50. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no such shares outstanding. Ameren Missouri has 7.5 million shares of $1 par value preference stock authorized, with no such shares outstanding. Ameren Illinois has 2.6 million shares of no par value preferred stock authorized, with no such shares outstanding.

Ameren

Under the DRPlus and its 401(k) plan, Ameren issued 0.4 million, 0.5 million, and 0.6 million shares of common stock in 2025, 2024, and 2023, respectively, received proceeds of $37 million, $33 million, and $39 million for the respective years, and had a receivable of $7 million and $7 million as of December 31, 2025 and 2024. In addition, Ameren issued 0.3 million, 0.2 million, and 0.5 million shares of common stock valued at $25 million, $16 million, and $40 million in 2025, 2024, 2023, respectively, for no cash consideration in connection with stock-based compensation.In May 2023, Ameren filed a Form S-3 registration statement with the SEC, authorizing the offering of 3 million additional shares of its common stock under the DRPlus, which expires in May 2026. Shares of common stock sold under the DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated contracts.In October 2023, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuance of an unspecified amount of certain types of securities. This registration statement expires in October 2026.In May 2022, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 7.5 million additional shares of its common stock under its 401(k) plan. Shares of common stock issuable under the 401(k) plan are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated contracts.Ameren has entered into an equity distribution sales agreement pursuant to which Ameren may offer and sell from time to time its common stock through an ATM program, which includes the ability to enter into forward sale agreements. 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. Under the ATM, Ameren issued 5.8 million, 2.9 million, and 3.2 million shares of common stock and received proceeds of $530 million, $233 million, and $299 million in 2025, 2024 and 2023, respectively. These proceeds were net of $5 million, $2 million and $3 million, respectively, in compensation paid to selling agents. As of December 31, 2025, Ameren had approximately $1.5 billion of common stock remaining available for sale under the ATM program.In May 2025, Ameren entered into forward sale agreements separate from the ATM program with multiple counterparties relating to 6.4 million shares of common stock, with an initial forward sale price for the agreements of $91.89. The forward sale agreements can be settled at Ameren’s discretion on or prior to January 15, 2027. On a settlement date or dates, if Ameren elects to physically settle a forward sale agreement, Ameren will issue shares of common stock to the counterparties at the then-applicable forward sale price. Each initial forward sale price is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the forward sale agreements by specified amounts related to expected dividends on shares of the common stock during the term of the forward sale agreements. If the overnight bank funding rate is less than or more than the spread on any day, the interest rate factor will result in a reduction or an increase, respectively, of the forward sale price. The forward sale agreements will be physically settled unless Ameren elects to settle in cash or to net share settle.At December 31, 2025, Ameren could have settled the forward sale agreements with physical delivery of 6.4 million shares of common stock to the respective counterparties in exchange for cash of $585 million. Alternatively, the forward sale agreements could have also been settled at December 31, 2025, with delivery of approximately $52 million of cash or approximately 0.5 million shares of common stock to the counterparties. In connection to the forward sale agreements, the various counterparties, or their affiliates, borrowed from third parties and sold 6.4 million shares of common stock. The gross sales price of these shares totaled $600 million. Ameren does not receive any proceeds from such sales of borrowed shares. The forward sale agreements have been classified as equity transactions.In February 2026, $350 million principal amount of Ameren (parent)’s 3.65% senior unsecured notes matured and was repaid with commercial paper borrowings.In March 2025, Ameren (parent) issued $750 million of 5.375% senior unsecured notes due March 2035, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2025. Net proceeds from this issuance were used for general corporate purposes, including the repayment of short-term debt. In September 2024, $450 million principal amount of Ameren (parent)’s 2.50% senior unsecured notes matured and was repaid with commercial paper borrowings.

Ameren Missouri

In April 2025, Ameren Missouri issued $500 million of 5.25% first mortgage bonds due April 2035, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2025. Net proceeds from this issuance were used to repay short-term debt. In January 2024, Ameren Missouri issued $350 million of 5.25% first mortgage bonds due January 2054, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2024. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.In April 2024, Ameren Missouri issued $500 million of 5.20% first mortgage bonds due April 2034, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2024. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.In April 2024, $350 million principal amount of Ameren Missouri’s 3.50% senior secured notes matured and was repaid with cash on hand.In October 2024, Ameren Missouri issued $450 million of 5.125% first mortgage bonds due March 2055, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2025. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.In December 2024, AMF issued $476 million of 4.85% securitized utility tariff bonds due October 2039, with principal and interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2025. Net proceeds from this issuance were used 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, and to repay short-term debt. See Note 2 – Rate and Regulatory Matters for additional information on the securitization of Rush Island Energy Center costs.For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.In March and September 2025, Ameren Illinois issued $350 million and $350 million, respectively, of 5.625% first mortgage bonds due March 2055, with interest payable semiannually on March 1 and September 1 of each year, beginning September 1, 2025 and March 1, 2026, respectively. Net proceeds from the March 2025 issuance were used to repay $300 million principal amount of its 3.25% senior secured notes that matured in March 2025, and net proceeds of both issuances were used to repay a portion of its short-term debt.In June 2024, Ameren Illinois issued $625 million of 5.55% first mortgage bonds due July 2054, with interest payable semiannually on January 1 and July 1 of each year, beginning January 1, 2025. Net proceeds from this issuance were used to repay short-term debt.For information on Ameren Illinois’ capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.

ATXI

In August 2024, ATXI issued $70 million of 5.17% senior unsecured notes due September 2039 and $70 million of 5.42% senior unsecured notes due September 2053, pursuant to an August 2024 note purchase agreement. Both series of senior unsecured notes have interest payable semiannually on March 1 and September 1 of each year, which began on March 1, 2025, and were issued through a private placement offering exempt from registration under the Securities Act of 1933, as amended. Net proceeds from these issuances were used to repay a $49 million principal payment of ATXI’s 3.43% senior unsecured notes at maturity and to repay short-term debt.

ATXI

In August 2024, ATXI issued $70 million of 5.17% senior unsecured notes due September 2039 and $70 million of 5.42% senior unsecured notes due September 2053, pursuant to an August 2024 note purchase agreement. Both series of senior unsecured notes have interest payable semiannually on March 1 and September 1 of each year, which began on March 1, 2025, and were issued through a private placement offering exempt from registration under the Securities Act of 1933, as amended. Net proceeds from these issuances were used to repay a $49 million principal payment of ATXI’s 3.43% senior unsecured notes at maturity and to repay short-term debt.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges, dividend coverage ratios, and bonds and preferred stock issuable as of December 31, 2025, at an assumed interest rate of 7% and dividend rate of 8%. [Table with ~2 rows, ~12 numbers, and 249 characters.] (a)Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.(b)Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $895 million and $1,093 million at Ameren Missouri and Ameren Illinois, respectively.(c)Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.(d)Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation. Ameren’s indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million, or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including borrowings under the Credit Agreements or the Ameren commercial paper program, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.Ameren Missouri and Ameren Illinois and 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 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.Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois has made a commitment to the FERC to maintain a minimum 30% ratio of common stock equity to total capitalization. As of December 31, 2025, using the FERC-agreed upon calculation method, Ameren Illinois’ ratio of common stock equity to total capitalization was 55%.ATXI’s note purchase agreements includes financial covenants that require ATXI not to permit at any time (1) debt to exceed 70% of total capitalization or (2) secured debt to exceed 10% of total assets.At December 31, 2025, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements. In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable requirements in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At December 31, 2025, none of the Ameren Companies had any material off-balance-sheet financing arrangements, other than their investments in variable interest entities, letters of credit, and the forward sale agreements relating to common stock. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.

NOTE 6 – OTHER INCOME, NET

The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the years ended December 31, 2025, 2024, and 2023: [Table with ~29 rows, ~71 numbers, and 1040 characters.] (a)For the years ended December 31, 2025, 2024, and 2023, the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $(53) million, $(41) million, and $27 million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates. See Note 10 – Retirement Benefits for additional information. (b)See Note 5 – Long-term Debt and Equity Financings for additional information on Ameren (parent)’s repurchase of Ameren Missouri’s senior secured notes and first mortgage bonds and Ameren Illinois’ first mortgage bonds that were accounted for as a debt extinguishment.

NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas, power, and interest rates, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:•an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;•market values of natural gas that differ from the cost of this commodity in inventory;•actual cash outlays for interest expense and the purchase of commodities that differ from anticipated cash outlays; and•actual off-system sales revenues that differ from anticipated revenues.The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty. All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 – Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery. The following disclosures exclude NPNS contracts and other non-derivative commodity contracts that are accounted for under the accrual method of accounting.If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of December 31, 2025 and 2024, all commodity contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Interest rate hedges entered into by Ameren (parent) and discussed below do not receive regulatory deferral and were included in accumulated OCI as Ameren (parent) is not a rate-regulated entity. The cash flows from our derivative financial instruments follow the cash flow classification of the hedged item.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 interest rate swaps are designated as cash flow hedges and the corresponding changes in fair value each period are initially recorded on the balance sheet in “Accumulated other comprehensive income” and reclassified into earnings when the debt is issued and the corresponding interest payments affect earnings during the debt term. As of December 31, 2025, and 2024, Ameren had interest rate swaps with notional amounts of $820 million and $140 million, respectively. Ameren recorded an unrealized gain, net of income taxes, on the change in fair value of interest rate swaps of $3 million and $3 million to "Accumulated other comprehensive income" for the years ended December 31, 2025 and 2024. The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2025 and 2024. As of December 31, 2025, these contracts extended through October 2029, October 2031, and May 2032 for fuel oils, natural gas, and power, respectively. [Table with ~4 rows, ~16 numbers, and 240 characters.] The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments because all qualify for regulatory deferral, as of December 31, 2025 and 2024: [Table with ~6 rows, ~57 numbers, and 606 characters.] The Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement at the gross amounts on the balance sheet. However, if the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at December 31, 2025 and 2024.

NOTE 6 – OTHER INCOME, NET

The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the years ended December 31, 2025, 2024, and 2023: [Table with ~29 rows, ~71 numbers, and 1040 characters.] (a)For the years ended December 31, 2025, 2024, and 2023, the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $(53) million, $(41) million, and $27 million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates. See Note 10 – Retirement Benefits for additional information. (b)See Note 5 – Long-term Debt and Equity Financings for additional information on Ameren (parent)’s repurchase of Ameren Missouri’s senior secured notes and first mortgage bonds and Ameren Illinois’ first mortgage bonds that were accounted for as a debt extinguishment.

NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas, power, and interest rates, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:•an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;•market values of natural gas that differ from the cost of this commodity in inventory;•actual cash outlays for interest expense and the purchase of commodities that differ from anticipated cash outlays; and•actual off-system sales revenues that differ from anticipated revenues.The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty. All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 – Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery. The following disclosures exclude NPNS contracts and other non-derivative commodity contracts that are accounted for under the accrual method of accounting.If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of December 31, 2025 and 2024, all commodity contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Interest rate hedges entered into by Ameren (parent) and discussed below do not receive regulatory deferral and were included in accumulated OCI as Ameren (parent) is not a rate-regulated entity. The cash flows from our derivative financial instruments follow the cash flow classification of the hedged item.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 interest rate swaps are designated as cash flow hedges and the corresponding changes in fair value each period are initially recorded on the balance sheet in “Accumulated other comprehensive income” and reclassified into earnings when the debt is issued and the corresponding interest payments affect earnings during the debt term. As of December 31, 2025, and 2024, Ameren had interest rate swaps with notional amounts of $820 million and $140 million, respectively. Ameren recorded an unrealized gain, net of income taxes, on the change in fair value of interest rate swaps of $3 million and $3 million to "Accumulated other comprehensive income" for the years ended December 31, 2025 and 2024. The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2025 and 2024. As of December 31, 2025, these contracts extended through October 2029, October 2031, and May 2032 for fuel oils, natural gas, and power, respectively. [Table with ~4 rows, ~16 numbers, and 240 characters.] The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments because all qualify for regulatory deferral, as of December 31, 2025 and 2024: [Table with ~6 rows, ~57 numbers, and 606 characters.] The Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement at the gross amounts on the balance sheet. However, if the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at December 31, 2025 and 2024.

Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. As of December 31, 2025, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held. Certain of our derivative instruments contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded below investment grade, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered and (2) those counterparties with rights to do so requested collateral. As of December 31, 2025, the aggregate fair value of derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require were each immaterial to Ameren, Ameren Missouri, and Ameren Illinois.

NOTE 8 – FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:Level 1 (quoted prices in active markets for identical assets or liabilities): Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives, cash and cash equivalents, and listed equity securities.The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants, and the trustee and investment managers. The S&P 500 index comprises stocks of large-capitalization companies.Level 2 (significant other observable inputs): Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including United States Treasury and agency securities, corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.Fixed income securities are valued by using prices from independent industry-recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed-income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices.Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the bid/ask spreads to the midpoints. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoints. The value of natural gas derivative contracts is based upon exchange closing prices without significant unobservable adjustments. The value of power derivative contracts is based upon exchange closing prices or the use of multiple forward prices provided by third parties. Level 3 (significant other unobservable inputs): Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, such as certain internal assumptions, quotes or prices from outside sources not supported by a liquid market, or trend rates.We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by considering any credit enhancements (e.g., collateral). Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in 2025, 2024, or 2023. At December 31, 2025 and 2024, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois. The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2025 and 2024: [Table with ~8 rows, ~127 numbers, and 1463 characters.] (a)Balance excludes $12 million and $9 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2025 and 2024, respectively.(b)See the Ameren Missouri and Ameren Illinois sections of the table for the fair value of Ameren’s derivative assets and liabilities by type of commodity.(c)See the Ameren Missouri section of the table for Ameren’s nuclear decommissioning trust fund by investment type. See Note 10 – Retirement Benefits for tables that set forth, by level within the fair value hierarchy, Ameren’s pension and postretirement plan assets as of December 31, 2025 and 2024. Level 3 natural gas derivative contract assets and liabilities measured at fair value on a recurring basis were immaterial for all periods presented. The following table presents the fair value reconciliation of Level 3 power derivative contract assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2025 and 2024: [Table with ~5 rows, ~35 numbers, and 418 characters.] All gains or losses related to our Level 3 derivative commodity contracts are expected to be recovered or returned through customer rates; therefore, there is no impact to either net income or OCI resulting from changes in the fair value of these instruments. The following table describes the valuation techniques and significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of December 31, 2025 and 2024: [Table with ~2 rows, ~14 numbers, and 396 characters.] (a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.(b)Unobservable inputs were weighted by relative fair value.(c)Valuations use visible forward prices adjusted for nodal-to-hub basis differentials. The following table sets forth the carrying amount and, by level within the fair value hierarchy, the fair value of long-term debt (including current portion), disclosed, but not recorded, at fair value as of December 31, 2025 and 2024: [Table with ~7 rows, ~24 numbers, and 356 characters.] (a)Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $136 million, $62 million, and $56 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2025. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $129 million, $62 million, and $51 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2024.(b)Amount excludes Ameren (parent)’s repurchase of Ameren Missouri’s senior secured notes and first mortgage bonds and Ameren Illinois’ first mortgage bonds that were accounted for as a debt extinguishment. See Note 5 – Long-term Debt and Equity Financings for additional information. (c)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.(d)Amount includes Ameren Missouri’s senior secured notes and first mortgage bonds and Ameren Illinois’ first mortgage bonds that were repurchased by Ameren (parent) in 2025 and 2024. The Ameren Companies’ carrying amounts of cash, cash equivalents, and restricted cash approximate fair value and are considered Level 1 in the fair value hierarchy. The Ameren Companies’ short-term borrowings approximate fair value because of the short-term nature of these instruments and are considered Level 2 in the fair value hierarchy.

NOTE 9 – CALLAWAY ENERGY CENTER

NOTE 8 – FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:Level 1 (quoted prices in active markets for identical assets or liabilities): Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives, cash and cash equivalents, and listed equity securities.The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants, and the trustee and investment managers. The S&P 500 index comprises stocks of large-capitalization companies.Level 2 (significant other observable inputs): Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including United States Treasury and agency securities, corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.Fixed income securities are valued by using prices from independent industry-recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed-income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices.Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the bid/ask spreads to the midpoints. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoints. The value of natural gas derivative contracts is based upon exchange closing prices without significant unobservable adjustments. The value of power derivative contracts is based upon exchange closing prices or the use of multiple forward prices provided by third parties. Level 3 (significant other unobservable inputs): Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, such as certain internal assumptions, quotes or prices from outside sources not supported by a liquid market, or trend rates.We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by considering any credit enhancements (e.g., collateral). Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in 2025, 2024, or 2023. At December 31, 2025 and 2024, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois. The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2025 and 2024: [Table with ~8 rows, ~127 numbers, and 1463 characters.] (a)Balance excludes $12 million and $9 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2025 and 2024, respectively.(b)See the Ameren Missouri and Ameren Illinois sections of the table for the fair value of Ameren’s derivative assets and liabilities by type of commodity.(c)See the Ameren Missouri section of the table for Ameren’s nuclear decommissioning trust fund by investment type. See Note 10 – Retirement Benefits for tables that set forth, by level within the fair value hierarchy, Ameren’s pension and postretirement plan assets as of December 31, 2025 and 2024. Level 3 natural gas derivative contract assets and liabilities measured at fair value on a recurring basis were immaterial for all periods presented. The following table presents the fair value reconciliation of Level 3 power derivative contract assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2025 and 2024: [Table with ~5 rows, ~35 numbers, and 418 characters.] All gains or losses related to our Level 3 derivative commodity contracts are expected to be recovered or returned through customer rates; therefore, there is no impact to either net income or OCI resulting from changes in the fair value of these instruments. The following table describes the valuation techniques and significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of December 31, 2025 and 2024: [Table with ~2 rows, ~14 numbers, and 396 characters.] (a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.(b)Unobservable inputs were weighted by relative fair value.(c)Valuations use visible forward prices adjusted for nodal-to-hub basis differentials. The following table sets forth the carrying amount and, by level within the fair value hierarchy, the fair value of long-term debt (including current portion), disclosed, but not recorded, at fair value as of December 31, 2025 and 2024: [Table with ~7 rows, ~24 numbers, and 356 characters.] (a)Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $136 million, $62 million, and $56 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2025. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $129 million, $62 million, and $51 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2024.(b)Amount excludes Ameren (parent)’s repurchase of Ameren Missouri’s senior secured notes and first mortgage bonds and Ameren Illinois’ first mortgage bonds that were accounted for as a debt extinguishment. See Note 5 – Long-term Debt and Equity Financings for additional information. (c)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.(d)Amount includes Ameren Missouri’s senior secured notes and first mortgage bonds and Ameren Illinois’ first mortgage bonds that were repurchased by Ameren (parent) in 2025 and 2024. The Ameren Companies’ carrying amounts of cash, cash equivalents, and restricted cash approximate fair value and are considered Level 1 in the fair value hierarchy. The Ameren Companies’ short-term borrowings approximate fair value because of the short-term nature of these instruments and are considered Level 2 in the fair value hierarchy.

NOTE 9 – CALLAWAY ENERGY CENTER

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, as amended, the DOE is responsible for disposing of spent nuclear fuel from the Callaway Energy Center and other commercial nuclear energy centers. As required by the act, Ameren Missouri and other utilities have entered into standard contracts with the DOE, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998. However, the DOE failed to fulfill its disposal obligations, and Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri’s lawsuit against the DOE resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. Ameren Missouri received immaterial reimbursements from the DOE in the years ended December 31, 2025, 2024, and 2023. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel. The DOE’s delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway Energy Center is not expected to adversely affect the continued operations of the energy center.

Decommissioning

Electric rates charged to customers provide for the recovery of the Callaway Energy Center’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over the expected life of the nuclear energy center. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway Energy Center’s decommissioning. It is assumed that the Callaway Energy Center site will be decommissioned after its retirement through the immediate dismantlement method and removed from service. The Callaway Energy Center’s operating license currently expires in 2044. Ameren and Ameren Missouri have recorded an ARO for the Callaway Energy Center decommissioning costs at fair value. Annual decommissioning costs of $7 million have historically been included in the costs used to establish electric rates for Ameren Missouri’s customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway Energy Center. An updated cost study and funding analysis was filed with the MoPSC in December 2023 and reflected within the ARO. In May 2025, the MoPSC issued an order that approved a non-unanimous stipulation and agreement between Ameren Missouri and the MoPSC staff that reduced annual customer contributions for funding the Callaway Energy Center decommissioning costs from $7 million to zero, as the trust fund level exceeded the estimated present value of future decommissioning costs at the time of the agreement. This MoPSC order removed Ameren Missouri’s funding obligation effective in June 2025. Ameren and Ameren Missouri have classified the investments in debt and equity securities that are held in the nuclear decommissioning trust fund as available for sale, and have recorded all such investments at their fair market value at December 31, 2025 and 2024. Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities.The fair value of the trust fund for Ameren Missouri’s Callaway Energy Center is reported as “Nuclear decommissioning trust fund” in Ameren’s and Ameren Missouri’s balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the regulatory liability related to AROs. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. See Note 2 – Rate and Regulatory Matters for the regulatory liability recorded at December 31, 2025. If the assumed return on trust assets is not earned, Ameren Missouri believes that it is probable that any additional funding requirements resulting from such earnings deficiency will be recovered in customer rates. The following table presents proceeds from the sales and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2025, 2024, and 2023: [Table with ~3 rows, ~12 numbers, and 117 characters.] The following table presents the cost and fair value of investments in debt and equity securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2025 and 2024: [Table with ~13 rows, ~34 numbers, and 357 characters.] (a)Represents net receivables and payables relating to pending securities sales, interest, and securities purchases. The following table presents the costs and fair values of investments in debt securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2025: [Table with ~4 rows, ~11 numbers, and 108 characters.]

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway Energy Center at January 1, 2026: [Table with ~8 rows, ~12 numbers, and 363 characters.] (a)Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.(b)Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $500 million in the event of an incident at any licensed United States commercial reactor, payable at $25 million per year.(c)Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors.(d)NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $0.7 billion in property damage insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events.(e)All NEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.(f)Accidental outage insurance provides for lost sales in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $291 million. The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in October 2023. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act. Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share the limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination, resulting from terrorist attacks. The EMANI policies are not subject to industrywide aggregates in the event of terrorist attacks on nuclear facilities.If losses from a nuclear incident at the Callaway Energy Center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.

NOTE 10 – RETIREMENT BENEFITS

The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren has defined benefit pension plans covering substantially all of its employees and has a postretirement benefit plan covering non-union employees hired before October 2015 and union employees hired before January 2020. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. All non-union employees participate in a cash balance pension plan. Ameren Missouri union employees hired after June 2013, and Ameren Illinois union employees hired after mid-October 2012, participate in a cash balance pension plan. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Ameren also has an unfunded nonqualified pension plan, the Ameren Supplemental Retirement Plan, which is available to provide certain non-union employees and retirees with a supplemental benefit when their qualified pension plan benefits are capped in compliance with Internal Revenue Code limitations. Only Ameren subsidiaries participate in the plans listed above.Ameren’s pension and other postretirement benefit plans were overfunded by $954 million and $734 million in the aggregate as of December 31, 2025 and 2024, respectively. These net assets are recorded in “Pension and other postretirement benefits,” “Other current liabilities,” and “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. The increase in the overfunded pension and postretirement benefit plans during 2025 was primarily the result of an increase in the actual return on plan assets of the pension and postretirement trusts and a 5-basis-point increase in the pension discount rate used to determine the present value of the obligation. The overfunded pension and other postretirement benefit plans also resulted in regulatory liabilities on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets. The following table presents the net benefit liability/(asset) recorded on the balance sheets as of December 31, 2025 and 2024: [Table with ~3 rows, ~8 numbers, and 85 characters.] (a)Liabilities associated with pension and other postretirement benefits are recorded in “Other current liabilities” and “Other deferred credits and liabilities” on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets. In December 2025, Ameren, completed a contract transfer transaction with a third-party insurance company that transferred approximately $240 million of plan assets and plan obligations of the Ameren Retirement Plan, associated with approximately 4,200 former Ameren Missouri, Ameren Illinois, and Ameren Services employees, that will assume future and full responsibility to fund and administer their benefit payments. The transaction is designed to reduce potential volatility with the pension plan assets and liabilities and administrative costs. There was no change to the pension benefits for any participants because of the transfer. The transaction was funded by pension plan assets and resulted in an actuarial gain of $15 million, which will be amortized in net periodic benefit cost (income) over 10 years through the actuarial (gain) loss component beginning in 2026. Ameren recognizes the overfunded and underfunded status of its pension and postretirement plans as an asset or a liability on its consolidated balance sheet, with offsetting entries to accumulated OCI and regulatory assets or liabilities. The following table presents the funded status of Ameren’s pension and postretirement benefit plans as of December 31, 2025 and 2024. It also provides the amounts included in regulatory assets or liabilities and accumulated OCI at December 31, 2025 and 2024, that have not been recognized in net periodic benefit costs. [Table with ~31 rows, ~89 numbers, and 1371 characters.] (b)Includes a $15 million gain from the contract transfer of defined benefit pension obligations and related plan assets to a third-party insurance company in December 2025 as described above.(c)Represents the contract transfer of defined benefit pension obligations and related plan assets to a third-party insurance company in December 2025 as described above. (d)Included in “Other current liabilities” on Ameren’s consolidated balance sheet.(e)Included in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. The following table presents the assumptions used to determine our benefit obligations at December 31, 2025 and 2024: [Table with ~5 rows, ~16 numbers, and 328 characters.] (b)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants was 2.50% at December 31, 2025 and 2024.(c)Initial medical cost trend rates of 7.50% and 7.00% for both pre-Medicare plan participants and post-Medicare plan participants at December 31, 2025 and 2024, respectively, trend down to the ultimate rate by 2036 and 2033, respectively, with a 3.00% upward adjustment to the post-Medicare trend rate in 2024. Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan’s projected benefit payments. The settlement portfolio of bonds is selected from a pool of high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan’s benefit payments that equates to the market value of the selected bonds. In 2025, Ameren elected to continue to use the Society of Actuaries mortality table and the Society of Actuaries 2020 Mortality Improvement Scale.

NOTE 10 – RETIREMENT BENEFITS

The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren has defined benefit pension plans covering substantially all of its employees and has a postretirement benefit plan covering non-union employees hired before October 2015 and union employees hired before January 2020. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. All non-union employees participate in a cash balance pension plan. Ameren Missouri union employees hired after June 2013, and Ameren Illinois union employees hired after mid-October 2012, participate in a cash balance pension plan. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Ameren also has an unfunded nonqualified pension plan, the Ameren Supplemental Retirement Plan, which is available to provide certain non-union employees and retirees with a supplemental benefit when their qualified pension plan benefits are capped in compliance with Internal Revenue Code limitations. Only Ameren subsidiaries participate in the plans listed above.Ameren’s pension and other postretirement benefit plans were overfunded by $954 million and $734 million in the aggregate as of December 31, 2025 and 2024, respectively. These net assets are recorded in “Pension and other postretirement benefits,” “Other current liabilities,” and “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. The increase in the overfunded pension and postretirement benefit plans during 2025 was primarily the result of an increase in the actual return on plan assets of the pension and postretirement trusts and a 5-basis-point increase in the pension discount rate used to determine the present value of the obligation. The overfunded pension and other postretirement benefit plans also resulted in regulatory liabilities on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets. The following table presents the net benefit liability/(asset) recorded on the balance sheets as of December 31, 2025 and 2024: [Table with ~3 rows, ~8 numbers, and 85 characters.] (a)Liabilities associated with pension and other postretirement benefits are recorded in “Other current liabilities” and “Other deferred credits and liabilities” on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets. In December 2025, Ameren, completed a contract transfer transaction with a third-party insurance company that transferred approximately $240 million of plan assets and plan obligations of the Ameren Retirement Plan, associated with approximately 4,200 former Ameren Missouri, Ameren Illinois, and Ameren Services employees, that will assume future and full responsibility to fund and administer their benefit payments. The transaction is designed to reduce potential volatility with the pension plan assets and liabilities and administrative costs. There was no change to the pension benefits for any participants because of the transfer. The transaction was funded by pension plan assets and resulted in an actuarial gain of $15 million, which will be amortized in net periodic benefit cost (income) over 10 years through the actuarial (gain) loss component beginning in 2026. Ameren recognizes the overfunded and underfunded status of its pension and postretirement plans as an asset or a liability on its consolidated balance sheet, with offsetting entries to accumulated OCI and regulatory assets or liabilities. The following table presents the funded status of Ameren’s pension and postretirement benefit plans as of December 31, 2025 and 2024. It also provides the amounts included in regulatory assets or liabilities and accumulated OCI at December 31, 2025 and 2024, that have not been recognized in net periodic benefit costs. [Table with ~31 rows, ~89 numbers, and 1371 characters.] (b)Includes a $15 million gain from the contract transfer of defined benefit pension obligations and related plan assets to a third-party insurance company in December 2025 as described above.(c)Represents the contract transfer of defined benefit pension obligations and related plan assets to a third-party insurance company in December 2025 as described above. (d)Included in “Other current liabilities” on Ameren’s consolidated balance sheet.(e)Included in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. The following table presents the assumptions used to determine our benefit obligations at December 31, 2025 and 2024: [Table with ~5 rows, ~16 numbers, and 328 characters.] (b)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants was 2.50% at December 31, 2025 and 2024.(c)Initial medical cost trend rates of 7.50% and 7.00% for both pre-Medicare plan participants and post-Medicare plan participants at December 31, 2025 and 2024, respectively, trend down to the ultimate rate by 2036 and 2033, respectively, with a 3.00% upward adjustment to the post-Medicare trend rate in 2024. Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan’s projected benefit payments. The settlement portfolio of bonds is selected from a pool of high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan’s benefit payments that equates to the market value of the selected bonds. In 2025, Ameren elected to continue to use the Society of Actuaries mortality table and the Society of Actuaries 2020 Mortality Improvement Scale.

Funding

Pension benefits are based on the employees’ years of service, age, and compensation. Ameren’s pension plans are funded in compliance with income tax regulations, federal funding requirements, and other regulatory requirements. As a result, 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. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense. The following table presents the cash contributions made to our defined benefit retirement plans and to our postretirement plan during 2025, 2024, and 2023: [Table with ~4 rows, ~29 numbers, and 173 characters.]

Investment Strategy and Policies

Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, which includes members of senior management, approves and implements investment strategy and asset allocation guidelines for the plan assets. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable; and second, to maximize total return on plan assets and to minimize expense volatility consistent with its tolerance for risk. Ameren delegates the task of investment management to specialists in each asset class. As appropriate, Ameren provides each investment manager with guidelines that specify allowable and prohibited investment types. The investment committee regularly monitors manager performance and compliance with investment guidelines.The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we reviewed the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. Ameren will use an expected return on plan assets for its pension and postretirement plan assets of 6.75% in 2026. Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate), duration, market capitalization, country, style (growth or value), and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk.Ameren’s investment committee developed and implemented a liability hedging investment strategy for its qualified pension plan designed to reduce interest rate risk as part of an objective for its long-term investment strategy. The plan invests in derivative instruments mainly consisting of interest rate futures intended to extend the duration of the pension plan assets so that the assets are more closely aligned with the duration of the liabilities. In addition, part of Ameren’s investment strategy includes participation in a securities lending program, which allows it to lend eligible securities to third party borrowers. All loans are collateralized by at least 103% of the loaned asset’s market value and the collateral is invested in the form of cash, government obligations, and U.S. agency obligations. Ameren’s fair value of securities loaned was $517 million and $454 million as of December 31, 2025 and 2024, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2025 and 2024. The following table presents our target allocations and our pension and postretirement plans’ asset categories as of December 31, 2025 and 2024: [Table with ~25 rows, ~57 numbers, and 753 characters.] (a)Includes interest rate futures derivative instruments.(b)Less than 1% of plan assets. In general, the United States large-capitalization equity investments are passively managed or indexed, whereas the international, global, United States small-capitalization, and United States mid-capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed-income vehicles. Debt security investments in high-yield securities and non-United-States-dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Diversified credit investments include but are not limited to, sub-investment grade rated bonds and loans, securitized credit, and emerging market debt. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. In addition to the derivative investments included in the liability hedging investment strategy described above, Ameren’s investment committee also allows investment managers to use derivatives, such as index futures, foreign exchange futures, and options, in certain situations to increase or to reduce market exposure in an efficient and timely manner.

Fair Value Measurements of Plan Assets

Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2025. Fair value is defined as the price that would be received for an asset in the principal or most advantageous market for the asset in an orderly transaction between market participants on the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the measurement date or, if that is not a business day, on the last business day before that date. Securities traded in over-the-counter markets are valued by quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Investments measured under NAV as a practical expedient are based on the fair values of the underlying assets provided by the funds and their administrators. The fair value of real estate investments is based on NAV; it is determined by annual appraisal reports prepared by an independent real estate appraiser. Investments measured at NAV often provide for daily, monthly, or quarterly redemptions with 60 or less days of notice depending on the fund. For some funds, redemption may also require approval from the fund’s board of directors. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information. The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pension plans’ assets measured at fair value and NAV as of December 31, 2025 and 2024: [Table with ~17 rows, ~68 numbers, and 776 characters.] (a)Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation.(b)Net of receivables related to pending securities sales and payables related to pending securities purchases. The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans’ assets measured at fair value and NAV as of December 31, 2025 and 2024: [Table with ~13 rows, ~52 numbers, and 593 characters.] (a)Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.(b)Net of receivables related to pending securities sales and payables related to pending securities purchases.

Net Periodic Benefit Cost

The following table presents the components of the net periodic benefit cost (income) of Ameren’s pension and postretirement benefit plans during 2025, 2024, and 2023: [Table with ~9 rows, ~45 numbers, and 464 characters.] (a)Service cost, net of capitalization, is reflected in “Operating Expenses - Other operations and maintenance” on Ameren’s statement of income.(b)Prior service cost (credit) is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. Net actuarial gains or losses subject to amortization are amortized on a straight-line basis over 10 years. Expected return on plan assets is based on a market-related value of assets that recognizes asset (gains) losses over 4 years.(c)Non-service cost components are reflected in “Other Income, Net” on Ameren’s consolidated statement of income. See Note 6 – Other Income, Net for additional information.(d)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in rates. The Ameren Companies are responsible for their share of the pension and postretirement benefit costs (income). The following table presents the pension and postretirement benefit costs (income) incurred for the years ended December 31, 2025, 2024, and 2023: [Table with ~4 rows, ~28 numbers, and 201 characters.] (a)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in customer rates. The expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, as of December 31, 2025, are as follows: [Table with ~6 rows, ~30 numbers, and 244 characters.] The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2025, 2024, and 2023: [Table with ~6 rows, ~30 numbers, and 446 characters.] (a)Increase in future compensation is 4.00% for the year ended December 31, 2025, 4.00% for 2024 and 3.50% thereafter for the year ended December 31, 2024, and 4.50% for 2023, 4.00% for 2024, and 3.50% thereafter for the year ended December 31, 2023.(b)Cash balance pension plan interest crediting rate is 5.20% for 2025 and 5.50% thereafter for the year ended December 31, 2025, was 6.42% for 2024, and 5.50% thereafter for the year ended December 31, 2024, and 5.50% for 2023 and 2024, and 5.00% thereafter for the year ended December 31, 2023.(c)Not applicable.(d)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 2.50% for the years ended December 31, 2025, 2024, and 2023.(e)Initial medical cost trend rates of 7.00% for pre-Medicare plan participants and 7.00% for post-Medicare plan participants trend down to the ultimate rate by 2033 with a 3.00% upward adjustment to the post-Medicare trend rate in 2025.(f)Initial medical cost trend rates of 6.93% for pre-Medicare plan participants and 6.50% for post-Medicare plan participants trend down to the ultimate rate by 2030, with a 3.00% upward adjustment to the post-Medicare trend rate in 2025.(g)Initial medical cost trend rates of 7.25% for pre-Medicare plan participants and 6.75% for post-Medicare plan participants trend down to the ultimate rate by 2030, with a 3.00% upward adjustment to the post-Medicare trend rate in 2025.

Other

Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible Ameren employees at December 31, 2025. The plan allows employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matches a percentage of the employee contributions up to certain limits. The following table presents the portion of the matching contribution to the Ameren 401(k) plan attributable to each of the Ameren Companies for the years ended December 31, 2025, 2024, and 2023: [Table with ~4 rows, ~15 numbers, and 91 characters.]

NOTE 11 – STOCK-BASED COMPENSATION

The 2022 Omnibus Incentive Compensation Plan is Ameren’s long-term incentive plan available for eligible employees and directors. It provides for a maximum of 8.8 million common shares to be available for grant to eligible employees and directors. At December 31, 2025, there were 7.3 million common shares remaining for grant. Awards may be restricted stock, restricted stock units, stock options (incentive stock options and nonqualified stock options), stock appreciation rights, performance awards, cash-based awards and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2025, 2024, and 2023, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2026. The following table summarizes Ameren’s outstanding performance share unit and restricted stock unit activity for the year ended December 31, 2025: [Table with ~6 rows, ~38 numbers, and 658 characters.] (a)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions. Compensation cost on nonforfeited awards is recognized regardless of whether Ameren achieves the specified market conditions.(b)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. Compensation cost is recognized ratably over the requisite service period only for awards for which it is probable that the performance condition will be satisfied.(c)Outstanding awards include awards that vest on a pro-rata basis due to attainment of retirement eligibility by employees, but have not yet been distributed. In these cases, the pro-rata basis awards have not yet been distributed as the entire performance period has not been completed. The number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.(d)Dividend equivalents represent the right to receive shares measured by the dividend payable with respect to the corresponding number of outstanding share units. Dividend equivalents will accrue and be reinvested in additional share units throughout the performance period.

Performance Share Units – Market Condition

A market condition performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions.The fair value of each share unit is based on a Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on Ameren’s TSR for a three-year performance period relative to the designated peer group beginning January 1st of the award year. The simulation can produce a greater or lesser fair value for the share unit than the applicable closing common share price because it includes the weighted payout scenarios in which an increase or decrease in the share price has occurred and/or in which the payout is above 100% due to Ameren’s projected TSR performance. The key assumptions used to calculate fair value also include a three-year risk-free rate, Ameren’s common stock volatility, and volatility for the peer group. The following table presents the fair value of each share unit along with the significant assumptions used to calculate the fair value of each share unit for the years ended December 31, 2025, 2024, and 2023: [Table with ~4 rows, ~15 numbers, and 213 characters.] (a)Based on a historical period that is equal to the remaining term of the performance period as of the grant date. In addition to the market condition performance share units described above, there are an immaterial number of market condition performance share units with different vesting conditions and target payout percentages.

Performance Share Units – Performance Condition

A performance condition share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has met the specified performance condition and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual performance conditions achieved. The specified performance condition in each award year is based on Ameren’s clean energy transition. The grant-date fair value for an individual outcome of a performance condition is determined by Ameren’s closing common share price on the grant date.

Restricted Stock Units

Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date.

Stock-Based Compensation Expense

The following table presents the stock-based compensation expense for the years ended December 31, 2025, 2024, and 2023: [Table with ~6 rows, ~21 numbers, and 167 characters.] (a)Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above. Ameren settled performance share units and restricted stock units of $38 million, $24 million, and $60 million for the years ended December 31, 2025, 2024, and 2023, respectively. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2025, 2024, and 2023. As of December 31, 2025, total compensation cost of $43 million related to outstanding awards not yet recognized is expected to be recognized over a weighted-average period of 23 months.For the years ended December 31, 2025, 2024, and 2023, excess tax benefits (deficiencies) associated with the settlement of stock-based compensation awards reduced (increased) income tax expense by $1 million, $(1) million, and $6 million, respectively.

NOTE 12 – INCOME TAXES

####### IRA The IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates production and investment tax credits for projects beginning construction after 2024. The production and investment tax credits will apply to renewable energy production and investments, along with certain nuclear energy production. See the OBBBA below for additional information on revisions to the production and investment tax credits. 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. In addition, the law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for 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. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the IRA have been and are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren. ####### OBBBA 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. The following table presents the principal reasons for the difference between the effective income tax expense and rate and the federal statutory corporate income tax expense and rate for the years ended December 31, 2025, 2024, and 2023: [Table with ~38 rows, ~127 numbers, and 1725 characters.] (a)State taxes in Missouri and Illinois made up the majority of the tax effect in this category for Ameren, Ameren Missouri, and Ameren Illinois. (b)The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM. The benefit of the credits associated with the production and investment tax credit tracker will be refunded to customers based on MoPSC approval in a regulatory rate review.(c)Reflects the amortization of a regulatory liability resulting from the revaluation of accumulated deferred income taxes subject to regulatory ratemaking, which are being refunded to customers.(d)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. The following table presents the components of income tax expense (benefit) for the years ended December 31, 2025, 2024, and 2023: [Table with ~30 rows, ~79 numbers, and 889 characters.] The following table presents the accumulated deferred income tax assets and liabilities recorded as a result of temporary differences and accumulated deferred production and investment tax credits at December 31, 2025 and 2024: [Table with ~20 rows, ~64 numbers, and 1002 characters.] The following table presents the components of accumulated deferred income tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2025 and 2024: [Table with ~18 rows, ~41 numbers, and 529 characters.] (a)No expiration date.(b)Will expire between 2039 and 2047.(c)Will expire between 2032 and 2045.(d)Will expire between 2026 and 2030. The following table presents the total income taxes paid, net of refunds, including production and investment tax credit sale proceeds, for the years ended December 31, 2025, 2024, and 2023: [Table with ~6 rows, ~39 numbers, and 270 characters.] (a)Amounts represent income tax paid, net of refunds, to Ameren (parent), pursuant to the tax allocation agreement. See Note 1 – Summary of Significant Accounting Policies – Income Taxes for additional information.(b)Includes production and investment tax credit sale proceeds for Ameren and Ameren Missouri of $314 million, $95 million, and $49 million for the years ended December 31, 2025, 2024, and 2023, respectively.

Uncertain Tax Positions

As of December 31, 2025 and 2024, the Ameren Companies did not record any uncertain tax positions.Ameren is a part of the IRS’s compliance assurance process program, which involves real-time review of compliance with federal income tax law. State income tax returns are generally subject to examination for a period of three years after filing. The state impact of any federal changes remains subject to examination by various states for up to one year after formal notification to the states. Ameren’s federal tax return for the 2024 tax year is open, but, at the time of this filing, the Ameren Companies do not have material income tax issues under examination, administrative appeals, or litigation.

NOTE 13 – RELATED-PARTY TRANSACTIONS

In the normal course of business, Ameren Missouri and Ameren Illinois engage in affiliate transactions. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. Below are the material related-party agreements.

NOTE 11 – STOCK-BASED COMPENSATION

The 2022 Omnibus Incentive Compensation Plan is Ameren’s long-term incentive plan available for eligible employees and directors. It provides for a maximum of 8.8 million common shares to be available for grant to eligible employees and directors. At December 31, 2025, there were 7.3 million common shares remaining for grant. Awards may be restricted stock, restricted stock units, stock options (incentive stock options and nonqualified stock options), stock appreciation rights, performance awards, cash-based awards and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2025, 2024, and 2023, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2026. The following table summarizes Ameren’s outstanding performance share unit and restricted stock unit activity for the year ended December 31, 2025: [Table with ~6 rows, ~38 numbers, and 658 characters.] (a)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions. Compensation cost on nonforfeited awards is recognized regardless of whether Ameren achieves the specified market conditions.(b)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. Compensation cost is recognized ratably over the requisite service period only for awards for which it is probable that the performance condition will be satisfied.(c)Outstanding awards include awards that vest on a pro-rata basis due to attainment of retirement eligibility by employees, but have not yet been distributed. In these cases, the pro-rata basis awards have not yet been distributed as the entire performance period has not been completed. The number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.(d)Dividend equivalents represent the right to receive shares measured by the dividend payable with respect to the corresponding number of outstanding share units. Dividend equivalents will accrue and be reinvested in additional share units throughout the performance period.

Performance Share Units – Market Condition

A market condition performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions.The fair value of each share unit is based on a Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on Ameren’s TSR for a three-year performance period relative to the designated peer group beginning January 1st of the award year. The simulation can produce a greater or lesser fair value for the share unit than the applicable closing common share price because it includes the weighted payout scenarios in which an increase or decrease in the share price has occurred and/or in which the payout is above 100% due to Ameren’s projected TSR performance. The key assumptions used to calculate fair value also include a three-year risk-free rate, Ameren’s common stock volatility, and volatility for the peer group. The following table presents the fair value of each share unit along with the significant assumptions used to calculate the fair value of each share unit for the years ended December 31, 2025, 2024, and 2023: [Table with ~4 rows, ~15 numbers, and 213 characters.] (a)Based on a historical period that is equal to the remaining term of the performance period as of the grant date. In addition to the market condition performance share units described above, there are an immaterial number of market condition performance share units with different vesting conditions and target payout percentages.

Performance Share Units – Performance Condition

A performance condition share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has met the specified performance condition and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual performance conditions achieved. The specified performance condition in each award year is based on Ameren’s clean energy transition. The grant-date fair value for an individual outcome of a performance condition is determined by Ameren’s closing common share price on the grant date.

Restricted Stock Units

Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date.

Stock-Based Compensation Expense

The following table presents the stock-based compensation expense for the years ended December 31, 2025, 2024, and 2023: [Table with ~6 rows, ~21 numbers, and 167 characters.] (a)Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above. Ameren settled performance share units and restricted stock units of $38 million, $24 million, and $60 million for the years ended December 31, 2025, 2024, and 2023, respectively. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2025, 2024, and 2023. As of December 31, 2025, total compensation cost of $43 million related to outstanding awards not yet recognized is expected to be recognized over a weighted-average period of 23 months.For the years ended December 31, 2025, 2024, and 2023, excess tax benefits (deficiencies) associated with the settlement of stock-based compensation awards reduced (increased) income tax expense by $1 million, $(1) million, and $6 million, respectively.

NOTE 12 – INCOME TAXES

####### IRA The IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates production and investment tax credits for projects beginning construction after 2024. The production and investment tax credits will apply to renewable energy production and investments, along with certain nuclear energy production. See the OBBBA below for additional information on revisions to the production and investment tax credits. 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. In addition, the law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for 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. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the IRA have been and are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren. ####### OBBBA 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. The following table presents the principal reasons for the difference between the effective income tax expense and rate and the federal statutory corporate income tax expense and rate for the years ended December 31, 2025, 2024, and 2023: [Table with ~38 rows, ~127 numbers, and 1725 characters.] (a)State taxes in Missouri and Illinois made up the majority of the tax effect in this category for Ameren, Ameren Missouri, and Ameren Illinois. (b)The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM. The benefit of the credits associated with the production and investment tax credit tracker will be refunded to customers based on MoPSC approval in a regulatory rate review.(c)Reflects the amortization of a regulatory liability resulting from the revaluation of accumulated deferred income taxes subject to regulatory ratemaking, which are being refunded to customers.(d)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. The following table presents the components of income tax expense (benefit) for the years ended December 31, 2025, 2024, and 2023: [Table with ~30 rows, ~79 numbers, and 889 characters.] The following table presents the accumulated deferred income tax assets and liabilities recorded as a result of temporary differences and accumulated deferred production and investment tax credits at December 31, 2025 and 2024: [Table with ~20 rows, ~64 numbers, and 1002 characters.] The following table presents the components of accumulated deferred income tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2025 and 2024: [Table with ~18 rows, ~41 numbers, and 529 characters.] (a)No expiration date.(b)Will expire between 2039 and 2047.(c)Will expire between 2032 and 2045.(d)Will expire between 2026 and 2030. The following table presents the total income taxes paid, net of refunds, including production and investment tax credit sale proceeds, for the years ended December 31, 2025, 2024, and 2023: [Table with ~6 rows, ~39 numbers, and 270 characters.] (a)Amounts represent income tax paid, net of refunds, to Ameren (parent), pursuant to the tax allocation agreement. See Note 1 – Summary of Significant Accounting Policies – Income Taxes for additional information.(b)Includes production and investment tax credit sale proceeds for Ameren and Ameren Missouri of $314 million, $95 million, and $49 million for the years ended December 31, 2025, 2024, and 2023, respectively.

Uncertain Tax Positions

As of December 31, 2025 and 2024, the Ameren Companies did not record any uncertain tax positions.Ameren is a part of the IRS’s compliance assurance process program, which involves real-time review of compliance with federal income tax law. State income tax returns are generally subject to examination for a period of three years after filing. The state impact of any federal changes remains subject to examination by various states for up to one year after formal notification to the states. Ameren’s federal tax return for the 2024 tax year is open, but, at the time of this filing, the Ameren Companies do not have material income tax issues under examination, administrative appeals, or litigation.

NOTE 13 – RELATED-PARTY TRANSACTIONS

In the normal course of business, Ameren Missouri and Ameren Illinois engage in affiliate transactions. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. Below are the material related-party agreements.

Electric Power Supply Agreements

Ameren Illinois must acquire capacity and energy sufficient to meet its obligations to customers. Ameren Illinois uses periodic RFP processes, administered by the IPA and approved by the ICC, to contract capacity and energy on behalf of its customers. Ameren Missouri participates in the RFP process and has been a winning supplier for certain periods.

Capacity Supply Agreements

In procurement events in 2021, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $2 million from June 2022 through May 2023.

Energy Product Agreements

Based on the outcome of an IPA-administered procurement event in 2021, Ameren Missouri and Ameren Illinois have entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 136,000 MWhs at an average price of $37 per MWh from January 2022 through September 2023.

Capacity Supply Agreements

In procurement events in 2021, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $2 million from June 2022 through May 2023.

Energy Product Agreements

Based on the outcome of an IPA-administered procurement event in 2021, Ameren Missouri and Ameren Illinois have entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 136,000 MWhs at an average price of $37 per MWh from January 2022 through September 2023.

Interconnection Agreements

Ameren Missouri and Ameren Illinois are parties to an interconnection agreement that governs the connection of their respective transmission lines and other facilities used for the distribution of power. These agreements have no contractual expiration date, but may be terminated by either party with three years’ notice.Ameren Missouri and ATXI are parties to an interconnection agreement that governs the connection of the High Prairie Energy Center to an ATXI transmission line that allows Ameren Missouri to distribute power generated from the High Prairie Energy Center.Ameren Missouri and Ameren Illinois are parties to interconnection agreements that govern the connection of the Cass County and Boomtown energy centers to Ameren Illinois transmission lines that allows Ameren Missouri to distribute power generated from the Cass County and Boomtown energy centers.

Support Services Agreements

Ameren Services provides support services to its affiliates. The costs of support services including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The support services agreement can be terminated at any time by the mutual agreement of Ameren Services and that affiliate or by either party with 60 days’ notice before the end of a calendar year.In addition, Ameren Missouri and Ameren Illinois provide affiliates with access to their facilities for administrative purposes and with use of other assets. The costs of the rent and facility services and other assets are based on, or are an allocation of, actual costs incurred.Ameren Missouri and Ameren Illinois also provide storm-related and miscellaneous support services to each other on an as-needed basis.Ameren Missouri and Ameren Illinois had long-term receivables included in “Other assets” from Ameren Services of $36 million and $38 million, respectively, as of December 31, 2025, and $29 million and $32 million, respectively, as of December 31, 2024, related to Ameren Services’ allocated portion of Ameren’s pension and postretirement benefit plans.

Transmission Services

Ameren Missouri and Ameren Illinois each receives transmission services from ATXI for their respective retail loads.

Electric Transmission Maintenance and Construction Agreements

ATXI entered into separate agreements with Ameren Missouri and Ameren Illinois in which Ameren Missouri or Ameren Illinois, as applicable, may perform certain maintenance and construction services related to ATXI’s electric transmission assets.

Money Pool

See Note 4 – Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.

Long-Term Debt, Net - Related Parties

In November 2024, December 2024, and June 2025, Ameren (parent) purchased senior secured notes and first mortgage bonds issued by Ameren Missouri, and first mortgage bonds issued by Ameren Illinois. See Note 5 – Long-term Debt and Equity Financings for additional information.

Tax Allocation Agreement

See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreement. The following table presents the affiliate balances related to income taxes for Ameren Missouri and Ameren Illinois as of December 31, 2025 and 2024: [Table with ~2 rows, ~7 numbers, and 160 characters.] (a)Included in “Accounts payable – affiliates” on the balance sheet. (b)Included in “Accounts receivable – affiliates” on the balance sheet.

Capital Contributions

The following table presents cash capital contributions received from Ameren (parent) by Ameren Missouri and Ameren Illinois for the years ended December 31, 2025, 2024, and 2023: [Table with ~2 rows, ~8 numbers, and 67 characters.] (a)Includes capital contributions made as a result of the tax allocation agreement.

Effects of Related-party Transactions on the Statement of Income

The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the years ended December 31, 2025, 2024, and 2023. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 – Short-term Debt and Liquidity. [Table with ~25 rows, ~94 numbers, and 1417 characters.] (b)Amount less than $1 million.

NOTE 14 – COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, Note 13 – Related-party Transactions, and Note 15 – Supplemental Information in this report.

NOTE 14 – COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, Note 13 – Related-party Transactions, and Note 15 – Supplemental Information in this report.

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. 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.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. 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 SO2, particulate matter, NOx, mercury, toxic metals and acid gases, and CO2 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. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.Additionally, Ameren Missouri’s wind generation facilities may be subject to operating restrictions to limit the impact on protected species. Since 2021, Ameren Missouri’s High Prairie Energy Center has curtailed nighttime operations from April through October to limit impacts on protected species during the critical biological season. Ameren Missouri does not anticipate these operating curtailments will have a material impact on its results of operations, financial position, or liquidity. In 2026, Ameren Missouri plans to apply for a new federal permit to operate the High Prairie Energy Center which, if approved, would reduce restrictions limiting the energy center’s impact on protected species for 30 years. The application will also propose various mitigation measures and operating curtailments based on Ameren Missouri’s assessment of mitigation technologies. Ameren Missouri’s current permit expires in May 2027.Due to various actions taken by the EPA, which are discussed below, Ameren and Ameren Missouri have revised capital expenditure estimates necessary to comply with environmental regulations to a range of $70 million to $100 million from 2026 through 2030. Additional capital expenditures beyond 2030 could be required. This estimate includes surface impoundment closure and corrective action measures required by the 2015 CCR Rule and modifications to cooling water intake structures at existing power plants under Clean Water Act rules in place prior to 2024, all of which are discussed below. The EPA could review and revise compliance requirements. In addition to planned retirements of coal-fired energy centers that were included in Ameren Missouri’s 2025 Change to the 2023 PRP and with respect to the Illinois emissions standards discussed below, Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning low-sulfur coal and optimizing existing air pollution control equipment. Accordingly, the actual amount of capital expenditures required to comply with existing environmental regulations could vary from the above estimates because of uncertainty as to revisions to regulatory requirements by the EPA and/or state regulators and their timing and varying cost of potential compliance strategies, among other things.The following sections describe the significant environmental statutes and regulations and environmental enforcement and remediation matters that affect or could affect our operations. The EPA could ultimately revise all or part of such federal regulations.

Clean Air Act

Federal and state laws, including the CSAPR, regulate emissions of SO2 and NOx through the reduction of emissions at their source and the use and retirement of emission allowances available for state budgets. In 2022, the EPA proposed the Good Neighbor Rule to reduce the transport of ozone from power plants by reducing the amount of CSAPR NOx allowances available for compliance. The EPA subsequently rejected state implementation plans proposed by Missouri and other states to comply with the Good Neighbor Rule and issued a federal implementation plan. The disapprovals for some state implementation plans, including Missouri’s, were stayed by multiple appellate courts, and in 2024, the United States Supreme Court issued a stay of the federal implementation plan. In January 2026, the EPA issued a proposed rule to reconsider the Good Neighbor Rule. Ameren Missouri complies with the current CSAPR requirements by minimizing emissions with low-sulfur coal, operation of two scrubbers at its Sioux Energy Center, and optimization of existing NOx air pollution control equipment. If a final rule is issued similar to the proposed rule, Ameren Missouri would not expect additional NOx controls at its coal-fired energy centers to be necessary.

CO2 Emissions Standards

In April 2024, the EPA issued a final rule that sets CO2 emission standards for existing coal-fired and new natural gas-fired power plants based on the emissions expected from adoption of carbon capture technology and/or natural gas co-firing for coal-fired power plants and carbon capture technology for new natural gas-fired power plants. Affected power plants are required to comply with the rule through a phased-in approach or retire. In June 2025, the EPA issued a proposed rule to repeal all greenhouse gas emissions standards for fossil fuel-fired power plants, including the April 2024 rule. The EPA expects to issue a final rule in the first half of 2026. In addition, in February 2026, the EPA issued a final rule rescinding its 2009 Endangerment Finding for greenhouse gas emissions, which was the basis for implementing greenhouse gas emissions standards. Ameren and Ameren Missouri are assessing the final rule and, at this time, cannot predict the final impacts on their results of operations, financial position, and liquidity. ####### MATS In April 2024, the EPA revised the MATS by establishing a more stringent standard for emissions of particulate matter, as well as requiring the use of continuous emissions monitoring systems. In April 2025, the presidential administration issued a proclamation through which it granted owners of coal-fired energy centers, including Ameren Missouri, a two-year extension of the compliance deadline. As such, the compliance deadline for the Labadie and Sioux energy centers is now set for July 2029. In June 2025, the EPA issued a proposed rule to repeal the April 2024 revisions to the MATS. The EPA expects to issue a final rule in 2026. ####### NSPS In January 2026, the EPA issued a final rule that established NOx emission standards for several subcategories of natural gas-fired stationary CTs that began construction after December 13, 2024, based on size, utilization, design efficiency, and fuel type. Ameren and Ameren Missouri are assessing the final rule and, at this time, cannot predict the final impacts on their results of operations, financial position, and liquidity.

NSR and Clean Air Act Litigation

In December 2024, the United States District Court for the Eastern District of Missouri issued an order resolving all outstanding claims related to a complaint filed against Ameren Missouri by the United States Department of Justice that alleged certain projects performed at the coal-fired Rush Island Energy Center violated provisions of the Clean Air Act. The order requires Ameren Missouri to fund a program to provide electric buses and charging stations to schools within its service territory and a program to provide air purifiers to eligible electric residential customers. Ameren and Ameren Missouri each had liabilities of $36 million in “Other current liabilities” on their consolidated balance sheets as of December 31, 2025 and had liabilities of $40 million and $24 million in “Other current liabilities” and “Other deferred credits and liabilities”, respectively, on their consolidated balance sheets as of December 31, 2024. In addition, Ameren and Ameren Missouri each recorded charges of $59 million in “Other operations and maintenance” on their consolidated statements of income in 2024 related to the cost of these programs.

Clean Water Act

All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to Clean Water Act requirements to identify measures for reducing the number of aquatic organisms impinged on a power plant’s cooling water intake screens or entrained through the plant’s cooling water system. Cooling water intake requirements are implemented by state regulators through the permit renewal process of each power plant’s water discharge permit. Permits for Ameren Missouri’s coal-fired and nuclear energy centers have been issued or are in the process of renewal.

CCR Management

The EPA’s 2015 CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and has resulted in the closure of surface impoundments at Ameren Missouri’s energy centers, with closures of surface impoundments in process at its Sioux Energy Center and retired Meramec Energy Center. Ameren Missouri plans to substantially complete the closures of remaining surface impoundments by the end of 2026. Ameren Missouri’s CCR management compliance plan includes installation of groundwater monitoring equipment and groundwater treatment facilities. In April 2024, the EPA revised the CCR Rule to impose groundwater monitoring, and corrective action, closure, and post-closure requirements on certain active and inactive CCR surface impoundments and disposal units not previously included in the 2015 CCR Rule. Ameren and Ameren Missouri had AROs of $56 million associated with CCR storage facilities recorded on their respective balance sheets as of December 31, 2025. This amount includes an immaterial incremental ARO related to the 2024 CCR Rule, which may be revised as additional site studies are performed. The EPA could reconsider aspects of the 2015 and 2024 CCR rules. Ameren and Ameren Missouri are monitoring the ongoing legal challenges and regulatory developments but, at this time, cannot predict the final impacts of the 2024 CCR Rule on their results of operations, financial position, and liquidity.

Remediation

The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site.As of December 31, 2025, Ameren Illinois has remediated the majority of the 44 former MGP sites in Illinois with an estimated remaining obligation primarily related to three of these former MGP sites at $45 million to $90 million. Ameren and Ameren Illinois recorded a liability of $45 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate. Ameren and Ameren Illinois cannot estimate the completion dates of the estimated remaining obligation due to site accessibility, among other things. The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the actual costs, including unanticipated underground structures, the degree to which groundwater is impacted, regulatory changes, local ordinances, and site accessibility. The actual costs and timing of completion may vary substantially from these estimates.The ICC allows Ameren Illinois to recover MGP remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders that are subject to annual prudence reviews by the ICC.Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. Such historical practices may result in future environmental commitments, including additional or more stringent cleanup standards. We are unable to determine whether such historical practices will affect our results of operations, financial position, or liquidity.

Illinois Emission Standards

Currently as required by the CEJA, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the 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.

NOTE 15 – SUPPLEMENTAL INFORMATION

Clean Air Act

Federal and state laws, including the CSAPR, regulate emissions of SO2 and NOx through the reduction of emissions at their source and the use and retirement of emission allowances available for state budgets. In 2022, the EPA proposed the Good Neighbor Rule to reduce the transport of ozone from power plants by reducing the amount of CSAPR NOx allowances available for compliance. The EPA subsequently rejected state implementation plans proposed by Missouri and other states to comply with the Good Neighbor Rule and issued a federal implementation plan. The disapprovals for some state implementation plans, including Missouri’s, were stayed by multiple appellate courts, and in 2024, the United States Supreme Court issued a stay of the federal implementation plan. In January 2026, the EPA issued a proposed rule to reconsider the Good Neighbor Rule. Ameren Missouri complies with the current CSAPR requirements by minimizing emissions with low-sulfur coal, operation of two scrubbers at its Sioux Energy Center, and optimization of existing NOx air pollution control equipment. If a final rule is issued similar to the proposed rule, Ameren Missouri would not expect additional NOx controls at its coal-fired energy centers to be necessary.

CO2 Emissions Standards

In April 2024, the EPA issued a final rule that sets CO2 emission standards for existing coal-fired and new natural gas-fired power plants based on the emissions expected from adoption of carbon capture technology and/or natural gas co-firing for coal-fired power plants and carbon capture technology for new natural gas-fired power plants. Affected power plants are required to comply with the rule through a phased-in approach or retire. In June 2025, the EPA issued a proposed rule to repeal all greenhouse gas emissions standards for fossil fuel-fired power plants, including the April 2024 rule. The EPA expects to issue a final rule in the first half of 2026. In addition, in February 2026, the EPA issued a final rule rescinding its 2009 Endangerment Finding for greenhouse gas emissions, which was the basis for implementing greenhouse gas emissions standards. Ameren and Ameren Missouri are assessing the final rule and, at this time, cannot predict the final impacts on their results of operations, financial position, and liquidity. ####### MATS In April 2024, the EPA revised the MATS by establishing a more stringent standard for emissions of particulate matter, as well as requiring the use of continuous emissions monitoring systems. In April 2025, the presidential administration issued a proclamation through which it granted owners of coal-fired energy centers, including Ameren Missouri, a two-year extension of the compliance deadline. As such, the compliance deadline for the Labadie and Sioux energy centers is now set for July 2029. In June 2025, the EPA issued a proposed rule to repeal the April 2024 revisions to the MATS. The EPA expects to issue a final rule in 2026. ####### NSPS In January 2026, the EPA issued a final rule that established NOx emission standards for several subcategories of natural gas-fired stationary CTs that began construction after December 13, 2024, based on size, utilization, design efficiency, and fuel type. Ameren and Ameren Missouri are assessing the final rule and, at this time, cannot predict the final impacts on their results of operations, financial position, and liquidity.

NSR and Clean Air Act Litigation

In December 2024, the United States District Court for the Eastern District of Missouri issued an order resolving all outstanding claims related to a complaint filed against Ameren Missouri by the United States Department of Justice that alleged certain projects performed at the coal-fired Rush Island Energy Center violated provisions of the Clean Air Act. The order requires Ameren Missouri to fund a program to provide electric buses and charging stations to schools within its service territory and a program to provide air purifiers to eligible electric residential customers. Ameren and Ameren Missouri each had liabilities of $36 million in “Other current liabilities” on their consolidated balance sheets as of December 31, 2025 and had liabilities of $40 million and $24 million in “Other current liabilities” and “Other deferred credits and liabilities”, respectively, on their consolidated balance sheets as of December 31, 2024. In addition, Ameren and Ameren Missouri each recorded charges of $59 million in “Other operations and maintenance” on their consolidated statements of income in 2024 related to the cost of these programs.

Clean Water Act

All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to Clean Water Act requirements to identify measures for reducing the number of aquatic organisms impinged on a power plant’s cooling water intake screens or entrained through the plant’s cooling water system. Cooling water intake requirements are implemented by state regulators through the permit renewal process of each power plant’s water discharge permit. Permits for Ameren Missouri’s coal-fired and nuclear energy centers have been issued or are in the process of renewal.

CCR Management

The EPA’s 2015 CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and has resulted in the closure of surface impoundments at Ameren Missouri’s energy centers, with closures of surface impoundments in process at its Sioux Energy Center and retired Meramec Energy Center. Ameren Missouri plans to substantially complete the closures of remaining surface impoundments by the end of 2026. Ameren Missouri’s CCR management compliance plan includes installation of groundwater monitoring equipment and groundwater treatment facilities. In April 2024, the EPA revised the CCR Rule to impose groundwater monitoring, and corrective action, closure, and post-closure requirements on certain active and inactive CCR surface impoundments and disposal units not previously included in the 2015 CCR Rule. Ameren and Ameren Missouri had AROs of $56 million associated with CCR storage facilities recorded on their respective balance sheets as of December 31, 2025. This amount includes an immaterial incremental ARO related to the 2024 CCR Rule, which may be revised as additional site studies are performed. The EPA could reconsider aspects of the 2015 and 2024 CCR rules. Ameren and Ameren Missouri are monitoring the ongoing legal challenges and regulatory developments but, at this time, cannot predict the final impacts of the 2024 CCR Rule on their results of operations, financial position, and liquidity.

Remediation

The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site.As of December 31, 2025, Ameren Illinois has remediated the majority of the 44 former MGP sites in Illinois with an estimated remaining obligation primarily related to three of these former MGP sites at $45 million to $90 million. Ameren and Ameren Illinois recorded a liability of $45 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate. Ameren and Ameren Illinois cannot estimate the completion dates of the estimated remaining obligation due to site accessibility, among other things. The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the actual costs, including unanticipated underground structures, the degree to which groundwater is impacted, regulatory changes, local ordinances, and site accessibility. The actual costs and timing of completion may vary substantially from these estimates.The ICC allows Ameren Illinois to recover MGP remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders that are subject to annual prudence reviews by the ICC.Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. Such historical practices may result in future environmental commitments, including additional or more stringent cleanup standards. We are unable to determine whether such historical practices will affect our results of operations, financial position, or liquidity.

Illinois Emission Standards

Currently as required by the CEJA, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the 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.

NOTE 15 – SUPPLEMENTAL INFORMATION

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of December 31, 2025 and 2024: [Table with ~6 rows, ~26 numbers, and 429 characters.] Restricted cash included in “Other current assets” represents funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets, funds held in an escrow account for programs established as a result of a 2024 court order resolving outstanding claims in the NSR and Clean Air Act litigation on Ameren’s and Ameren Missouri’s balance sheets, and AMF’s restricted cash for payments for securitized utility tariff bonds on Ameren’s and Ameren Missouri’s balance sheets. Restricted cash included in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets primarily represents amounts collected under a cost recovery rider restricted for use in the procurement of renewable energy credits and amounts in a trust fund restricted for the use of funding certain asbestos-related claims.

Accounts Receivable

“Accounts receivable – trade” on Ameren’s and Ameren Illinois’ balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At December 31, 2025 and 2024, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $47 million and $43 million, respectively. The following table provides a reconciliation of the beginning and ending amount of the allowance for doubtful accounts for the years ended December 31, 2025 and 2024: [Table with ~5 rows, ~32 numbers, and 330 characters.] (a)Ameren Illinois has rate-adjustment mechanisms that allow it to recover the difference between its actual net bad debt write-offs under GAAP, including those associated with receivables purchased from alternative retail electric suppliers, and the amount of net bad debt write-offs included in its base rates.(b)Amounts associated with the allowance for doubtful accounts related to receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.

Leases

Ameren and Ameren Missouri have lease agreements primarily relating to rail cars and land related to solar generation facilities. The land leases are related to the Cass County, Boomtown, and Huck Finn energy centers. Rail cars are leased for the transportation of coal to its energy centers. For rail car leases, we account for the lease and non-lease components as a single lease component, and for the land leases related to solar generation projects, we account for the components separately for each agreement. Certain of the land leases related to the acquisitions of the Cass County, Boomtown, and Huck Finn energy centers have options to renew or terminate those leases. Termination and renewal options are not expected to be exercised and are not included in any of the lease measurements used to record the leased assets and liabilities in the tables below. The following table provides supplemental balance sheet information related to operating leases as of December 31, 2025 and 2024: [Table with ~5 rows, ~22 numbers, and 319 characters.] (a)As an implicit rate is not readily determinable under most of our lease agreements, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. We use an implicit rate when readily determinable. The following table presents Ameren’s and Ameren Missouri’s remaining maturities of operating lease liabilities as of December 31, 2025: [Table with ~9 rows, ~23 numbers, and 150 characters.]

Inventories

The following table presents the components of inventories for each of the Ameren Companies at December 31, 2025 and 2024: [Table with ~4 rows, ~24 numbers, and 282 characters.] (a)Consists of coal, oil, and propane.

Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years ended December 31, 2025 and 2024: [Table with ~6 rows, ~30 numbers, and 398 characters.] (a)Balance included $5 million and $5 million in “Other current liabilities” on the balance sheet as of December 31, 2025 and 2024, respectively.(b)Included in “Other deferred credits and liabilities” on the balance sheet.(c)In 2024, Ameren and Ameren Missouri recorded an ARO related to decommissioning for the Cass County, Boomtown, and Huck Finn energy centers. In addition, as a result of the 2024 CCR Rule, Ameren and Ameren Missouri recorded an increase to their AROs associated with CCR storage facilities. See Note 14 – Commitments and Contingencies for additional information.(d)Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.(e)The balance included an ARO related to the decommissioning of the Callaway Enter Center of $678 million and $648 million as of December 31, 2025 and 2024, respectively.

Deferred Compensation

As of December 31, 2025, and 2024, the present value of benefits to be paid for deferred compensation obligations was $79 million and $79 million, respectively, which was primarily reflected in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. Deferred compensation obligations are primarily recorded on the balance sheet of Ameren (parent).

Excise Taxes

Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the sale or distribution of natural gas and electricity. The following table presents the excise taxes recorded on a gross basis in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income for the years ended December 31, 2025, 2024, and 2023: [Table with ~3 rows, ~12 numbers, and 89 characters.]

Allowance for Funds Used During Construction

The following table presents the average rate that was applied to eligible construction work in progress and the amounts of allowance for funds used during construction capitalized in 2025, 2024, and 2023: [Table with ~15 rows, ~36 numbers, and 579 characters.]

Earnings per Share

Earnings per basic and diluted share are computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of basic and diluted common shares outstanding, respectively, during the applicable period. The weighted-average shares outstanding for earnings per diluted share includes the incremental effects resulting from performance share units, restricted stock units, and forward sale agreements relating to common stock when the impact would be dilutive, as calculated using the treasury stock method. For information regarding performance share units and restricted stock units, see Note 11 – Stock-based Compensation. For information regarding forward sale agreements, see Note 5 – Long-term Debt and Equity Financings. The following table reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2025, 2024, and 2023: [Table with ~4 rows, ~14 numbers, and 288 characters.] (a)There was an immaterial number of anti-dilutive securities excluded from the earnings per diluted share calculations as calculated using the treasury stock method for the years ended December 31, 2025, 2024, and 2023 related to performance share units and restricted stock units. Outstanding forward sale agreements as of December 31, 2025 and 2024 that were anti-dilutive for the years ended December 31, 2025 and 2024, respectively, were excluded from the earnings per diluted share calculation as calculated using the treasury stock method. The outstanding forward sale agreements as of December 31, 2023, were anti-dilutive for the year ended December 31, 2023, and excluded from the earnings per diluted share calculation as calculated using the treasury stock method. For additional information about the outstanding forward sale agreements, see Note 5 – Long-term Debt and Equity Financings.

Supplemental Cash Flow Information

The following table provides noncash financing and investing activity excluded from the statements of cash flows for the years ended December 31, 2025, 2024, and 2023: [Table with ~9 rows, ~28 numbers, and 674 characters.] (a)In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri.

NOTE 16 – SEGMENT INFORMATION

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. The category called Other primarily includes Ameren (parent) activities and Ameren Services.Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri, Ameren Illinois, and ATXI.Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois in each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution, other retail electric suppliers, and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.The CODMs for Ameren, Ameren Missouri, and Ameren Illinois are the Chief Executive Officer of Ameren, the Group President of Ameren Utilities of Ameren, and the Chief Financial Officer of Ameren. The CODMs use net income to evaluate income generated from the segments to make decisions about resources allocated to each segment and assess segment performance. Net income is also used to monitor budget versus actual results when assessing segment performance. The following tables present information about the reported revenue and specified items reflected in net income attributable to common shareholders and capital expenditures by segment at Ameren and Ameren Illinois for the years ended December 31, 2025, 2024, and 2023. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

NOTE 16 – SEGMENT INFORMATION

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. The category called Other primarily includes Ameren (parent) activities and Ameren Services.Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri, Ameren Illinois, and ATXI.Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois in each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution, other retail electric suppliers, and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.The CODMs for Ameren, Ameren Missouri, and Ameren Illinois are the Chief Executive Officer of Ameren, the Group President of Ameren Utilities of Ameren, and the Chief Financial Officer of Ameren. The CODMs use net income to evaluate income generated from the segments to make decisions about resources allocated to each segment and assess segment performance. Net income is also used to monitor budget versus actual results when assessing segment performance. The following tables present information about the reported revenue and specified items reflected in net income attributable to common shareholders and capital expenditures by segment at Ameren and Ameren Illinois for the years ended December 31, 2025, 2024, and 2023. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

Ameren

[Table with ~34 rows, ~171 numbers, and 1872 characters.] [Table with ~17 rows, ~86 numbers, and 1008 characters.] (a)Significant segment expense that is regularly provided to the CODMs. Intersegment expenses are included within the amounts shown.(b)Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent). [Table with ~34 rows, ~111 numbers, and 1520 characters.] [Table with ~17 rows, ~56 numbers, and 834 characters.] (a)Significant segment expense that is regularly provided to the CODMs. Intersegment expenses are included within the amounts shown. The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the years ended December 31, 2025, 2024, and 2023. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system sales and capacity revenues.

Ameren

[Table with ~36 rows, ~129 numbers, and 1327 characters.] (a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the years ended December 31, 2025, 2024, and 2023: [Table with ~9 rows, ~30 numbers, and 548 characters.] (a)Includes net realized gains and losses on derivative power contracts. [Table with ~18 rows, ~60 numbers, and 621 characters.] (a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the years ended December 31, 2025, 2024, and 2023: [Table with ~9 rows, ~24 numbers, and 474 characters.]