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Rate And Regulatory Matters | 12 Months Ended
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Dec. 31, 2024
Public Utilities, General Disclosures [Abstract] |
Rate and Regulatory Matters | 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:
| 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 •Renewable energy standard costs •Property taxes •Production and investment tax credits or proceeds from the sale of certain tax credits allowed under the IRA | •Electric distribution service and energy-efficiency revenue requirement reconciliation adjustments(a) 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
(a)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 and the revenue requirement established in the review. 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 energy standard 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 and natural gas generating units 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. Pursuant to a Missouri law, Ameren Missouri’s PISA election was extended through December 2028 and an additional extension through December 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things. This law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates, compared to the revenue requirement established in the immediately preceding rate order, due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation is effective for revenue requirements approved by the MoPSC after January 1, 2024. 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 wind generation and other renewables 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, such as the renewable energy standard cost tracker. The renewable energy standard cost tracker allows Ameren Missouri to defer differences between actual costs primarily associated with the Maryland Heights Energy Center and renewable energy credits obtained through a 102-MW power purchase agreement with a wind farm operator, which expired in August 2024, and those costs included in customer rates. 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 June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance $476 million of costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri will collect the amounts necessary to repay the bonds through a rider over approximately 15 years from the date of the December 2024 bond issuance. 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. 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 and the revenue requirement established in the review. 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 revenue requirement, which is subject to final reconciliation and ICC review. 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’ 2022 and 2023 revenues reflected each year’s actual recoverable costs, 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 2022 revenue requirement reconciliation adjustment was collected from customers in 2024, and the 2023 adjustment will be collected 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. 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 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. 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 include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, the allowed ROE on energy-efficiency investments can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings goals. Any adjustments to the allowed ROE for energy-efficiency investments will depend on annual performance for a historical period relative to energy savings goals. In 2024, 2023, and 2022, 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 Missouri 2024 Electric Service Regulatory Rate Review In June 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service. In February 2025, Ameren Missouri filed an updated electric rate increase request seeking approval to increase its annual revenues for electric service by $446 million. The electric rate increase request is based on a 10.25% ROE, a capital structure composed of 52% common equity, a rate base of $13.9 billion, and a test year ended March 31, 2024, with certain pro-forma adjustments through the true-up date of December 31, 2024. Ameren Missouri also requested the continued use of all of its existing riders and trackers. The electric rate increase request reflects the following: •increased infrastructure investments made under Ameren Missouri’s Smart Energy Plan, including increased cost of capital and depreciation expense. Included in these investments are 500 megawatts of solar generation investment for the Boomtown, Cass County and Huck Finn projects along with investments in the Callaway nuclear energy center and other dispatchable generation to support a reliable, low-cost and cleaner mix of energy resources; •decreased costs resulting from the retirement of the Rush Island Energy Center; and •decreased costs related to the extension of the retirement date of the Sioux Energy Center from 2030 to 2032 to ensure reliability. In February 2025, the MoPSC staff recommended an increase to Ameren Missouri's annual electric service revenues of $384 million based on a 9.74% ROE, a capital structure composed of 52% common equity, and a rate base of $13.9 billion. The MoPSC staff’s recommendation includes adjustments for lower off-system sales revenue, production tax credits, and renewable energy credits as a result of the curtailed nighttime operations at the High Prairie Energy Center to limit its impact on protected species. See Note 14 – Commitments and Contingencies for additional information on the curtailed nighttime operations at the High Prairie Energy Center. The MoPSC staff supported the continued use of all of Ameren Missouri’s existing riders and trackers. In December 2024, the MoOPC challenged 25% to 45% of the costs and requested return associated with the High Prairie Energy Center investment included in Ameren Missouri’s requested revenue requirement as a result of the curtailed nighttime operations at the energy center discussed above. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by May 2025 and new rates effective by June 2025. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be continued, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect. 2024 Natural Gas Delivery Service Regulatory Rate Review In September 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for natural gas delivery service by $40 million. The natural gas rate increase request is based on a 10.25% ROE, a capital structure composed of 52% common equity, a rate base of $531 million, and a test year ended March 31, 2024, with certain pro-forma adjustments expected through the true-up date of December 31, 2024. The request includes the continued use of all of Ameren Missouri’s existing riders and trackers. The natural gas rate increase request reflects investments in our existing natural gas infrastructure to ensure the safe delivery of natural gas. The MoPSC proceeding relating to the proposed natural gas delivery service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by August 2025 and new rates effective by September 2025. Ameren Missouri cannot predict the level of any natural gas delivery service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be continued, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect. Generation Facilities Ameren Missouri, and certain subsidiaries of Ameren Missouri, are parties to agreements to acquire and/or construct various generation facilities. The solar generation facilities are eligible for recovery under the PISA. The Castle Bluff Natural Gas Project is eligible for recovery under the post-construction cost deferral discussed below. The following table provides information with respect to each agreement:
| Agreement type | Facility size | Status of MoPSC CCN | Status of FERC approval of acquisition | In-service date(a)
Huck Finn Solar Project(b)(c) | Build-transfer | 200-MW | Approved February 2023 | Received March 2023 | December 2024
Boomtown Solar Project(c)(d) | Build-transfer | 150-MW | Approved April 2023 | Received October 2023 | December 2024
Cass County Solar Project(c)(d) | Development-transfer | 150-MW | Approved June 2024 | Not applicable | December 2024
Vandalia Solar Project(e)(f) | Self-build | 50-MW | Approved March 2024 | Not applicable | Fourth quarter 2025
Bowling Green Solar Project(e)(f) | Self-build | 50-MW | Approved March 2024 | Not applicable | First quarter 2026
Split Rail Solar Project(e)(f) | Build-transfer | 300-MW | Approved March 2024 | Received November 2024 | Mid-2026
Castle Bluff Natural Gas Project(e) | Self-build | 800-MW | Approved October 2024(g) | Not applicable | Fourth quarter 2027
(a)In-service dates are dependent on the timing of construction completion, among other things. The assets of the Huck Finn, Boomtown, and Cass County solar projects were placed in service in December 2024. (b)The Huck Finn Solar Project is expected to support Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Investments in the project are eligible for recovery under the RESRAM. (c)Ameren Missouri acquired the Cass County, Boomtown, and Huck Finn solar projects in June 2024, September 2024, and October 2024, respectively, and placed the assets of the projects, totaling $1 billion, in service in December 2024. (d)The Boomtown and Cass County solar projects are expected to support Ameren Missouri’s transition to renewable energy generation and serve customers under the Renewable Solutions Program, which allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. (e)These projects collectively represent approximately $1.7 billion of expected capital expenditures. (f)These solar projects are expected to support Ameren Missouri’s transition to renewable energy generation. (g)For additional information see Castle Bluff Natural Gas Project CCN and Post-Construction Cost Deferral below. Castle Bluff Natural Gas Project CCN and Post-Construction Cost Deferral In October 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement filed by Ameren Missouri, the MoPSC staff, and other intervenors requesting a CCN for the Castle Bluff Natural Gas Project. The order also includes the use of a post-construction cost deferral related to the Castle Bluff Natural Gas Project, which allows Ameren Missouri to defer and recover depreciation expense, financing costs, and applicable income taxes incurred from the date the project is placed in service to the date when project costs are reflected in updated base rates as a result of a regulatory rate review. The period of deferral would be limited to the earlier of the time the project costs are reflected in base rates or six months. Securitization of Rush Island Energy Center Costs In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance $476 million of costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri will collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. The securitized tariff bonds were issued in December 2024. The financing order also included a determination that the decision to retire the Rush Island Energy Center was reasonable and prudent. The MoPSC did not make a determination regarding the prudency of Ameren Missouri's prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies, however, claims regarding such actions could be considered in future regulatory proceedings. If future regulatory proceedings result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Base rate revenues relating to the recovery of the Rush Island Energy Center are being deferred as a regulatory liability since the October 15, 2024 retirement date of the facility until new rates become effective related to the current electric service regulatory rate review. The amortization period for the regulatory liability will be determined in a future regulatory rate review. See Note 5 – Long-term Debt and Equity Financings for additional information on the securitized tariff bonds issuance. MEEIA In 2024, 2023, and 2022, Ameren Missouri achieved certain energy-efficiency spending goals for the MEEIA 2019 program. As a result of achieving these spending goals and MoPSC order issued in August 2022, Ameren Missouri recognized performance incentive revenues of $13 million, $12 million, and $22 million, respectively. In November 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement for Ameren Missouri’s MEEIA 2025 plan, which includes a portfolio of customer energy-efficiency and demand response programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from customers its actual MEEIA program costs, related lost electric revenues, and performance incentives. Ameren Missouri intends to invest $51 million annually in 2025 and 2026 and $22 million in 2027 for customer energy-efficiency and demand response programs. In addition, the order approved performance incentives applicable to each plan year to earn revenues by achieving certain spending and demand response goals. If 100% of the goals are achieved in 2025, 2026, and 2027, Ameren Missouri would earn performance incentive revenues of $5 million, $5 million, and $2 million, respectively. 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 2024, ATXI filed requests for CCNs, among other things, with the MoPSC related to the MISO long-range transmission projects that it expects to construct within the MoPSC’s jurisdiction. Decisions by the MoPSC are expected in 2025. Illinois MYRP In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding. Rate changes consistent with the December 2023 order became effective in January 2024 and remained effective through late June 2024, when new rates became effective pursuant to the June 2024 ICC rehearing order discussed below. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027 using Ameren Illinois’ previously approved 2022 year-end rate base. In January 2024, the ICC partially denied a rehearing requested by Ameren Illinois to revise the allowed ROE in the December 2023 order and granted Ameren Illinois’ rehearing request to reconsider the rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. In June 2024, the ICC issued an order on Ameren Illinois’ rehearing request, which revised the rate bases for Ameren Illinois’ MYRP test years to include investments for 2023 through 2027, among other things. New rates became effective in late June 2024 and remained effective through late December 2024, when new rates became effective pursuant to the December 2024 ICC order discussed below. For additional information on the ICC’s June 2024 rehearing order, see the table below. In July 2024, Ameren Illinois filed a request for rehearing of the ICC’s June 2024 rehearing order to include an asset associated with other postretirement benefits in the rate base. Subsequently, in August 2024, the ICC denied the rehearing request. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order, including the 8.72% ROE, and subsequently updated the appeal filing in September 2024 to include the June 2024 rehearing order regarding the inclusion of an asset associated with other postretirement benefits in the rate base to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal and Ameren Illinois cannot predict the ultimate outcome of the appeal. In March 2024, pursuant to the December 2023 ICC order discussed above, Ameren Illinois filed a revised Grid Plan and a revised MYRP to update the requested revenue requirements for 2024 through 2027. In December 2024, the ICC issued an order in connection with Ameren Illinois’ revised Grid Plan and revised MYRP for electric distribution service for 2024 through 2027. 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 $309 million. Rate changes consistent with the December 2024 order became effective in December 2024. In January 2025, Ameren Illinois filed a request for rehearing of the ICC’s December 2024 order to revise the allowed ROE and to include an asset associated with other postretirement benefits in the rate base, among other things. Subsequently, in February 2025, the ICC denied the rehearing request. Ameren Illinois intends to file an appeal of the ICC’s December 2024 order and update the appeal filed in September 2024 to the Illinois Appellate Court for the Fifth Judicial District as discussed above. The following table presents the approved revenue requirements and average annual rate base in the ICC’s December 2024 MYRP order and the ICC’s June 2024 rehearing order:
Year | Revenue Requirement (in millions) |  |  | Average Annual Rate Base (in billions)
ICC’s December 2024 MYRP Order(a): |  |  |  |
2024 | $1,206 |  |  | $4.2
2025 | $1,287 |  |  | $4.4
2026 | $1,367 |  |  | $4.6
2027 | $1,422 |  |  | $4.8
ICC’s June 2024 Rehearing Order(a): |  |  |  |
2024 | $1,196 |  |  | $4.0
2025 | $1,282 |  |  | $4.3
2026 | $1,350 |  |  | $4.5
2027 | $1,397 |  |  | $4.7
(a)Based on an allowed ROE of 8.72% and a capital structure composed of 50% common equity. The ROE is under appeal, as discussed above. New rates became effective in December 2024. 2023 Electric Distribution Revenue Requirement Reconciliation Adjustment Order In December 2024, the ICC issued an order approving Ameren Illinois’ 2023 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $158 million, which reflected Ameren Illinois’ actual 2023 recoverable costs, year-end rate base of $4.2 billion, and capital structure composed of 50% common equity. The approved reconciliation adjustment will be collected from customers in 2025. Electric Customer Energy-Efficiency Investments In November 2024, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $126 million beginning in January 2025, which represents an increase of $26 million from 2024 rates. This order was based on a projected 2025 year-end rate base of $434 million. 2025 Natural Gas Delivery Service Rate Review In January 2025, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $140 million. The request is based on a 10.7% ROE, a capital structure composed of 52% common equity, and a rate base of $3.3 billion. Ameren Illinois used a 2026 future test year in this proceeding. A decision by the ICC in this proceeding is required by early December 2025, with new rates expected to be effective in December 2025. Ameren Illinois cannot predict the level of any delivery service rate change the ICC may approve, nor whether any rate change that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on investments when the rate changes go into effect. 2023 Natural Gas Delivery Service Rate Order In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million based on a 9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of approximately $2.85 billion. The order reflected a reduction of approximately $93 million of planned distribution and transmission capital investments included in Ameren Illinois’ requested revenue increase, which used a 2024 future test year. The new rates became effective on November 28, 2023. In December 2023, Ameren Illinois filed a request for rehearing of the ICC's November 2023 order. The filing requested the ICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request, and Ameren Illinois filed an appeal with the Illinois Appellate Court for the Fifth Judicial District. In January 2025, the appellate court ruled on the appeal filed by Ameren Illinois. In that ruling, the court reversed a reduction of planned transmission capital investments of $48 million, but affirmed the ICC-approved 9.44% ROE and the remaining reduction of planned distribution capital investments. Future of Gas Proceeding The ICC’s November 2023 natural gas delivery service rate order discussed above 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 in early 2026 and will be used by the ICC to guide further action, if any. QIP Reconciliation Hearing 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. 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 approximately $30 million in natural gas capital investments as improper and imprudent, resulting in a potential over-recovery of an immaterial amount by Ameren Illinois in 2020. In October 2023, and again in September 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 was within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding. 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 February 2024, Ameren Illinois and ATXI filed a request for a CCN, among other things, with the ICC related to the portion of the MISO long-range transmission projects they will construct within the ICC’s jurisdiction. A decision by the ICC is expected by mid-2025. Federal 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 May 2020, the FERC issued an order, which set the allowed base ROE to 10.02% and required refunds, with interest, for the periods from November 2013 to February 2015 and from late September 2016 forward. Ameren and Ameren Illinois paid these refunds, including interest, by March 31, 2022. In 2020, Ameren Missouri, Ameren Illinois, and ATXI, as well as various customers, petitioned the United States Court of Appeals for the District of Columbia Circuit for review of the May 2020 order, challenging certain aspects of the new ROE methodology established. The petition filed by Ameren Missouri, Ameren Illinois, and ATXI challenged the refunds required for the period from September 2016 to May 2020. In August 2022, the court issued a ruling that granted the customers’ petition for review, vacated the FERC’s previous MISO ROE-determining orders, and remanded the proceedings to the FERC. The court elected not to rule on the issues raised by Ameren Missouri, Ameren Illinois, and ATXI. 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 same periods covered by the May 2020 order. In November 2024, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a request for rehearing with the FERC, arguing, among other things, the FERC should not have ordered refunds back to September 2016 or imposed interest on those refunds. Also in November 2024, another intervenor filed a request for rehearing with the FERC, requesting the FERC correct aspects of the ROE methodology used in the October 2024 order and reconsider its decision in a February 2015 complaint case to deny refunds for the period from February 2015 to May 2016. In December 2024, the FERC issued a notice indicating a future order related to the rehearing requests will be issued but did not specify a timeline. In January 2025, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed an appeal of the October 2024 order to the United States Court of Appeals for the District of Columbia Circuit. As a result of the October 2024 order, Ameren and Ameren Illinois recognized reductions to "Operating Revenues – Electric" on their statements of income of $10 million and $7 million, respectively, and recognized expense of $2 million and $1 million, respectively, in “Interest charges” on their statements of income in 2024. As of December 31, 2024, Ameren and Ameren Illinois had recorded liabilities in "Current regulatory liabilities" on their balance sheets of $12 million and $8 million, respectively, to reflect the expected refunds, including interest, associated with the allowed base ROE set by the October 2024 order. Regulatory Assets and Liabilities The following table presents our regulatory assets and regulatory liabilities at December 31, 2024 and 2023:
|  | 2024 |  |  | 2023
|  | Ameren Missouri |  | Ameren Illinois |  | Ameren |  |  | Ameren Missouri |  | Ameren Illinois |  | Ameren
Regulatory assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Under-recovered FAC(a) |  | $ | 41 |  |  | $ | — |  |  | $ | 41 |  |  |  | $ | 72 |  |  | $ | — |  |  | $ | 72 |
MTM derivative losses(b) |  | 15 |  |  | 88 |  |  | 103 |  |  |  | 25 |  |  | 143 |  |  | 168 |
IEIMA revenue requirement reconciliation adjustment(c)(d) |  | — |  |  | 139 |  |  | 139 |  |  |  | — |  |  | 239 |  |  | 239 |
MYRP revenue requirement reconciliation adjustment(d)(e) |  | — |  |  | 24 |  |  | 24 |  |  |  | — |  |  | — |  |  | — |
Under-recovered RBA(f) |  | — |  |  | 22 |  |  | 22 |  |  |  | — |  |  | — |  |  | — |
FERC revenue requirement reconciliation adjustment(g) |  | — |  |  | 55 |  |  | 90 |  |  |  | — |  |  | 25 |  |  | 54 |
Under-recovered VBA(h) |  | — |  |  | 49 |  |  | 49 |  |  |  | — |  |  | 49 |  |  | 49 |
Income taxes(i) |  | 237 |  |  | 81 |  |  | 322 |  |  |  | 126 |  |  | 78 |  |  | 207 |
Bad debt rider(j) |  | — |  |  | 25 |  |  | 25 |  |  |  | — |  |  | 43 |  |  | 43 |
Callaway refueling and maintenance outage costs(k) |  | 13 |  |  | — |  |  | 13 |  |  |  | 37 |  |  | — |  |  | 37 |
Unamortized loss on reacquired debt(l) |  | 42 |  |  | 5 |  |  | 47 |  |  |  | 45 |  |  | 5 |  |  | 50 |
Environmental cost riders(m) |  | — |  |  | 43 |  |  | 43 |  |  |  | — |  |  | 50 |  |  | 50 |
Storm costs(d)(n) |  | — |  |  | 18 |  |  | 18 |  |  |  | — |  |  | 27 |  |  | 27 |
Customer generation rebate program(d)(o) |  | — |  |  | 89 |  |  | 89 |  |  |  | — |  |  | 54 |  |  | 54 |
PISA(d)(p) |  | 464 |  |  | — |  |  | 464 |  |  |  | 386 |  |  | — |  |  | 386 |
Rush Island Energy Center securitization(q) |  | 465 |  |  | — |  |  | 465 |  |  |  | — |  |  | — |  |  | — |
RESRAM(r) |  | 51 |  |  | — |  |  | 51 |  |  |  | 48 |  |  | — |  |  | 48 |
Certain Meramec Energy Center costs(s) |  | 26 |  |  | — |  |  | 26 |  |  |  | 39 |  |  | — |  |  | 39 |
Energy-efficiency rider(d)(t) |  | — |  |  | 576 |  |  | 576 |  |  |  | — |  |  | 500 |  |  | 500 |
Property tax tracker(u) |  | 22 |  |  | — |  |  | 22 |  |  |  | 13 |  |  | — |  |  | 13 |
Other |  | 56 |  |  | 78 |  |  | 134 |  |  |  | 65 |  |  | 74 |  |  | 139 |
Total regulatory assets |  | $ | 1,432 |  |  | $ | 1,292 |  |  | $ | 2,763 |  |  |  | $ | 856 |  |  | $ | 1,287 |  |  | $ | 2,175 |
Less: current regulatory assets |  | (66) |  |  | (281) |  |  | (366) |  |  |  | (101) |  |  | (252) |  |  | (365) |
Noncurrent regulatory assets |  | $ | 1,366 |  |  | $ | 1,011 |  |  | $ | 2,397 |  |  |  | $ | 755 |  |  | $ | 1,035 |  |  | $ | 1,810 |
Regulatory liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Over-recovered Illinois electric power costs(v) |  | — |  |  | 34 |  |  | 34 |  |  |  | — |  |  | 36 |  |  | 36 |
Over-recovered PGA(v) |  | 2 |  |  | 33 |  |  | 35 |  |  |  | 7 |  |  | 33 |  |  | 40 |
MTM derivative gains(b) |  | 10 |  |  | 6 |  |  | 16 |  |  |  | 19 |  |  | 3 |  |  | 22 |
Income taxes(i) |  | 1,040 |  |  | 679 |  |  | 1,804 |  |  |  | 999 |  |  | 724 |  |  | 1,809 |
Cost of removal(w) |  | 1,118 |  |  | 1,115 |  |  | 2,294 |  |  |  | 1,098 |  |  | 1,038 |  |  | 2,186 |
AROs(x) |  | 691 |  |  | — |  |  | 691 |  |  |  | 524 |  |  | — |  |  | 524 |
Pension and postretirement benefit costs(y) |  | 202 |  |  | 156 |  |  | 358 |  |  |  | 202 |  |  | 144 |  |  | 346 |
Pension and postretirement benefit costs tracker(z) |  | 70 |  |  | — |  |  | 70 |  |  |  | 111 |  |  | — |  |  | 111 |
Renewable energy credits and zero emission credits(aa) |  | — |  |  | 586 |  |  | 586 |  |  |  | — |  |  | 489 |  |  | 489 |
Certain Rush Island Energy Center costs(ab) |  | 66 |  |  | — |  |  | 66 |  |  |  | — |  |  | — |  |  | — |
Other |  | 14 |  |  | 43 |  |  | 63 |  |  |  | 14 |  |  | 22 |  |  | 36 |
Total regulatory liabilities |  | $ | 3,213 |  |  | $ | 2,652 |  |  | $ | 6,017 |  |  |  | $ | 2,974 |  |  | $ | 2,489 |  |  | $ | 5,599 |
Less: current regulatory liabilities |  | (37) |  |  | (79) |  |  | (120) |  |  |  | (15) |  |  | (71) |  |  | (87) |
Noncurrent regulatory liabilities |  | $ | 3,176 |  |  | $ | 2,573 |  |  | $ | 5,897 |  |  |  | $ | 2,959 |  |  | $ | 2,418 |  |  | $ | 5,512 |
(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 will be recovered from customers with a return at the applicable WACC within two years. (d)These assets earn a return at the applicable WACC. (e)The difference between Ameren Illinois' actual 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 rate regulatory 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 39, 30, and 46 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. The amortization period will be determined in a future regulatory 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 2020 through 2023 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 will collect 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 two to 12 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. Amounts accumulated through 2022 are being collected over two years beginning July 2023. The amortization period for amounts accumulated after 2022 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, net of salvage. (x)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,342 million and $1,150 million at December 31, 2024 and 2023, respectively), net of recoverable removal costs for AROs ($651 million and $626 million at December 31, 2024 and 2023, 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 prior to 2023 and 2022, respectively, the weighted-average remaining amortization period is two years. For electric and natural gas related costs incurred after 2023 and 2022, respectively, 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 January 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.

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