Ameren Missouri

Ameren Illinois’ electric distribution business

Ameren Illinois’ natural gas delivery business

Ameren Illinois’ and ATXI’s electric transmission businesses

Regulatory framework

•Historical test year ratemaking

•Natural gas revenues for residential customers adjusted for sales volume deviations resulting from weather through the WNAR

•MYRP

•Initial rates based on future test years

•Revenues decoupled from sales volumes and wholesale and miscellaneous revenues through the RBA

•Future test year ratemaking

•Revenues for residential and small nonresidential customers decoupled from sales volumes through the VBA

•Formula ratemaking

•Initial rates based on future test year

•Revenues decoupled from sales volumes

Regulatory mechanisms

•PISA

Riders:

•RESRAM

•FAC

•Rush Island securitization

•MEEIA

•PGA

•WNAR

Trackers:

•Pension and postretirement benefit costs

•Certain excess deferred income taxes

•Property taxes

•Production and investment tax credits or proceeds from the sale of certain tax credits allowed under the IRA

•Renewable solutions program revenues and costs(a)

•Electric distribution service and energy-efficiency revenue requirement reconciliation adjustments(b)

Riders:

•RBA

•Power procurement

•Transmission services

•Renewable energy credit compliance

•Zero emission credits

•Customer generation rebate program costs

•Certain environmental costs

•Bad debt write-offs

•Costs of certain asbestos-related claims

Riders:

•PGA

•VBA

•Energy-efficiency program costs

•Certain environmental costs

•Bad debt write-offs

•Invested capital taxes

•Revenue requirement reconciliation adjustment

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.

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.

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.

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.

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.

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.

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, 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.

Agreement type

Facility size

Status of MoPSC CCN

In-service date(a)

Vandalia Solar Project(b)

Self-build

50-MW

Approved March 2024

December 2025

Bowling Green Solar Project(b)

Self-build

50-MW

Approved March 2024

First quarter 2026

Split Rail Solar Project

Build-transfer(c)

300-MW

Approved March 2024

Second quarter 2026

Castle Bluff Natural Gas Project(d)

Self-build

800-MW

Approved October 2024

Fourth quarter 2027

Big Hollow Battery Energy Storage Project(e)

Self-build

400-MW

Approved February 2026

Second quarter 2028

Big Hollow Natural Gas Project(e)

Self-build

800-MW

Approved February 2026

Third quarter 2028

Reform Solar Project

Self-build

250-MW

Filed August 2025(f)

Fourth quarter 2028

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.

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.

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.

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 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.

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.

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.

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.

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.

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.

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.


	2025						2024
	Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren
Regulatory assets:
Under-recovered FAC(a)	$	137	$	—	$	137	$	41	$	—	$	41


MTM derivative losses(b)	15		111		126		15		88		103

IEIMA revenue requirement reconciliation adjustment(c)(d)	—		—		—		—		139		139
MYRP revenue requirement reconciliation adjustment(d)(e)	—		74		74		—		24		24
Under-recovered RBA(f)	—		29		29		—		22		22
FERC revenue requirement reconciliation adjustment(g)	—		45		73		—		55		90
Under-recovered VBA(h)	—		21		21		—		49		49

Income taxes(i)	282		91		376		237		81		322


Bad debt rider(j)	—		13		13		—		25		25

Callaway refueling and maintenance outage costs(k)	32		—		32		13		—		13
Unamortized loss on reacquired debt(l)	40		4		44		42		5		47
Environmental cost riders(m)	—		46		46		—		43		43
Storm costs(d)(n)	—		15		15		—		18		18





Customer generation rebate program(d)(o)	—		141		141		—		89		89


PISA(d)(p)	558		—		558		464		—		464
Rush Island Energy Center securitization(q)	443		—		443		465		—		465
RESRAM(r)	44		—		44		51		—		51
Certain Meramec Energy Center costs(s)	14		—		14		26		—		26
Energy-efficiency rider(d)(t)	—		624		624		—		576		576
Property tax tracker(u)	18		—		18		22		—		22

Other	48		34		83		56		78		134
Total regulatory assets	$	1,631	$	1,248	$	2,911	$	1,432	$	1,292	$	2,763
Less: current regulatory assets	(181)		(189)		(387)		(66)		(281)		(366)
Noncurrent regulatory assets	$	1,450	$	1,059	$	2,524	$	1,366	$	1,011	$	2,397
Regulatory liabilities:

Over-recovered Illinois electric power costs(v)	—		85		85		—		34		34
Over-recovered PGA(v)	3		39		42		2		33		35

MTM derivative gains(b)	12		4		16		10		6		16





Income taxes(i)	963		546		1,587		1,040		679		1,804



Cost of removal(w)	1,203		1,230		2,511		1,118		1,115		2,294
AROs(x)	841		—		841		691		—		691


Pension and postretirement benefit costs(y)	230		237		467		202		156		358
Pension and postretirement benefit costs tracker(z)	9		—		9		70		—		70


Renewable energy credits and zero emission credits(aa)	—		699		699		—		586		586



Certain Rush Island Energy Center costs(ab)	31		—		31		66		—		66
Rush Island Energy Center base rate revenue deferral(ac)	31		—		31		13		—		13
Other	24		67		94		1		43		50
Total regulatory liabilities	$	3,347	$	2,907	$	6,413	$	3,213	$	2,652	$	6,017
Less: current regulatory liabilities	(23)		(132)		(158)		(37)		(79)		(120)
Noncurrent regulatory liabilities	$	3,324	$	2,775	$	6,255	$	3,176	$	2,573	$	5,897

(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.

(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.

(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.