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Rate And Regulatory Matters | 12 Months Ended
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Dec. 31, 2023
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(a) •Initial rates based on future test years •Revenues decoupled from sales volumes | •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 •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(b) Riders: •Power procurement •Transmission services •Renewable energy credit compliance •Zero emission credits •Certain environmental costs •Bad debt write-offs •Costs of certain asbestos-related claims | Riders: •QIP(c) •PGA •VBA •Energy-efficiency program costs •Certain environmental costs •Bad debt write-offs •Invested capital taxes | •Revenue requirement reconciliation adjustment
(a)Ameren Illinois used the IEIMA performance-based formula ratemaking framework to establish annual electric distribution customer rates effective through 2023. In December 2023, the ICC approved an MYRP to establish rates effective 2024 through 2027. See below for additional information regarding the MYRP approved in December 2023. (b)Reconciliation adjustments under an MYRP are subject to a reconciliation cap which limits annual adjustment to 105%. See below for additional information regarding the reconciliation cap. (c)The QIP expired in December 2023. Reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP from 2020 to 2023 are ongoing. 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, 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 uncertain income tax positions, 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 Renewable and Atchison Renewable 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 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. The rate increase approved by the June 2023 MoPSC electric rate order discussed below did not exceed the rate increase limitation applicable through 2023. Pursuant to a Missouri law that became effective in August 2022, 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 will be 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 federal production and investment tax credits, with Missouri’s renewable energy standard and the amount set in base rates. Effective February 28, 2022, all sales from the High Prairie Renewable and Atchison Renewable energy centers are included in the RESRAM. Previously, 95% of these sales were included in the FAC and 5% were 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 billed 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 expires 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 either billed 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. The MEEIA permits Ameren Missouri to recover customer energy-efficiency program costs, the related lost electric margins, 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 natural gas margins, 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 billed 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 billed 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. Ameren Illinois used the IEIMA formula framework to establish annual customer electric distribution service rates effective through 2023. Under the framework, Ameren Illinois is allowed to reconcile its revenue requirement for customer rates established through 2023. Ameren Illinois’ 2021, 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 and 2023 revenue requirement reconciliation adjustments will be collected from customers within two years from the end of the reconciled year. By law, the decoupling provisions extend beyond 2023, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. 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. Ameren Illinois’ electric distribution service business has riders for power procurement and transmission services incurred on behalf of its customers, renewable energy credit compliance, zero emission credits, 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. Pursuant to the CEJA, Ameren Illinois may elect to establish electric distribution service rates through either an MYRP or a traditional regulatory rate review for 2024 and beyond. See below for additional information regarding the MYRP approved by the ICC in December 2023, which established rates effective 2024 through 2027. Under the MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. 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. Ameren Illinois’ existing riders remain effective and electric distribution service revenues continue to be decoupled from sales volumes under the MYRP. 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. Subject to the reconciliation cap, if a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. 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’ 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 2023, 2022, and 2021, 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 natural gas margins, 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 billed 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 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 QIP expired in December 2023. Previously, it provided Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that were placed in service between regulatory rate reviews. Infrastructure investments under the QIP earned a return at the applicable WACC. Eligible natural gas investments included projects to improve safety and reliability and modernization investments, such as smart meters. The deferrals were recorded as a regulatory asset, with recovery beginning two months after the qualifying natural gas plant was placed in service and continuing until such plant was included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP was subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. Ameren Illinois did not exceed the rate impact limitation in 2023. Upon issuance of a natural gas delivery service rate order, QIP rate base was transferred to base rates and the QIP was reset to zero. Reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP are still ongoing. See below for additional information on the recovery of capital investments that were made during 2020. 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 June 2023 MoPSC Electric Rate Order In June 2023, the MoPSC issued an order in Ameren Missouri’s 2022 electric service regulatory rate review, approving a nonunanimous stipulation and agreement. The order resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The approved revenue requirement was based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to 2030. The order did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard compliance costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker. It also includes 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 Renewable and Atchison Renewable energy centers, are not eligible for tracking under this mechanism as they are included in the RESRAM. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. 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 approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023. Solar Generation Facilities During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities, which, if placed in-service, would be eligible for recovery under the PISA. The following table provides information with respect to each agreement:
| Huck Finn Solar Project(a)(b) | Boomtown Solar Project(b)(c) | Split Rail Solar Project(d) | Cass County Solar Project(c) | Vandalia Solar Project(d) | Bowling Green Solar Project(d)
Agreement type | Build-transfer | Build-transfer | Build-transfer(e) | Development-transfer(e)(f) | Self-build(e)(g) | Self-build(e)(g)
Facility size | 200-MW | 150-MW | 300-MW | 150-MW | 50-MW | 50-MW
Status of MoPSC CCN | Approved February 2023 | Approved April 2023 | Filed June 2023(h) | Filed June 2023(h) | Filed June 2023(h) | Filed June 2023(h)
Status of FERC approval of acquisition | Received March 2023 | Received October 2023 | Expect to request by mid-2024 | Not applicable | Not applicable | Not applicable
Earliest completion date(i) | Fourth quarter 2024 | Fourth quarter 2024 | Mid-2026 | Fourth quarter 2024 | Fourth quarter 2025 | First quarter 2026
(a)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 will be eligible for recovery under the RESRAM. (b)These projects collectively represent approximately $0.65 billion of expected capital expenditures. (c)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 discussed below. (d)These solar projects are expected to support Ameren Missouri’s transition to renewable energy generation. (e)These projects, and applicable agreements, are subject to the issuance of a CCN by the MoPSC. (f)Ameren Missouri entered into an agreement to acquire the Cass County Solar Project, which includes project design, land rights, and engineering, procurement, and construction agreements for a solar generation facility. Ameren Missouri will construct the facility after obtaining a CCN from the MoPSC and acquiring the project. Acquisition of the project is expected by mid-2024. (g)Ameren Missouri entered into engineering, procurement, and construction agreements to construct these solar projects. (h)In February 2024, Ameren Missouri, the MoPSC staff, and the MoOPC filed a nonunanimous stipulation and agreement requesting the MoPSC approve Ameren Missouri’s requests for CCNs for the Split Rail, Vandalia, and Bowling Green solar projects. The stipulation and agreement also requests MoPSC approval of the CCN request for the Cass County Solar Project conditioned upon the facility supporting the Renewable Solutions Program discussed below and full subscription of the portion of the program supported by this facility, subject to certain other terms and conditions. The remaining intervenors did not object to the agreement. Ameren Missouri expects a decision by the MoPSC in March 2024. (i)Expected completion dates are dependent on the timing of regulatory approvals, among other things. Renewable Solutions Program The April 2023 MoPSC order approving the CCN for the Boomtown Solar Project also approved Ameren Missouri’s Renewable Solutions Program and a tariff related to participation in the program. The program allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. Separate enrollment occurs for each renewable resource serving customers under the program. Collection under the tariff will not begin until the Boomtown Solar Project is placed in service. MoPSC Staff Review of Planned Rush Island Energy Center Retirement In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center as a result of the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies. The MoPSC staff’s review includes potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. Ameren Missouri is unable to predict the results of this matter. Results of the review could be used in the securitization proceeding discussed below, which could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri if Ameren Missouri is not allowed to recover Rush Island costs through securitization. Securitization of Rush Island Energy Center Costs In November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed 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 were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews 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. Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding. MEEIA In August 2023, the MoPSC issued an order approving a nonunanimous stipulation and agreement to extend Ameren Missouri’s MEEIA 2019 program for an additional year through 2024. For 2024, the order approved the establishment of a portfolio of customer energy-efficiency programs and performance incentives that will provide Ameren Missouri an opportunity to earn revenues, including $12 million of performance incentive revenues if Ameren Missouri achieves certain program spending goals. In 2024, Ameren Missouri expects to invest $76 million in energy-efficiency programs. In December 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 orders issued in August 2022 and September 2021, Ameren Missouri recognized performance incentive revenues of $12 million, $22 million, and $9 million in 2023, 2022, and 2021, respectively. In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA. This filing proposed a three-year plan, which includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding. 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 order became effective in January 2024. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The ICC will be under no deadline to act on the revised Grid Plan when filed. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027, using the 2022 year-end rate base approved by the ICC in its 2022 electric distribution service revenue requirement reconciliation adjustment order discussed below. This rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement. In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end 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. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements and annual rate base amounts to reflect a base level of investments to maintain grid reliability for 2024 through 2027. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District. The following table presents the approved revenue requirements, ROE, capital structure common equity percentage, and annual rate base in the ICC’s December 2023 order, as well as the proposed revenue requirements and annual rate base amounts in Ameren Illinois’ February 2024 rehearing request filing:
Year | Revenue Requirement (in millions) | ROE | Capital Structure Common Equity Percentage | Annual Rate Base (in billions)
ICC’s December 2023 MYRP Order: |  |  |  |
2024 | $1,162 | 8.72% | 50% | $3.9
2025 | $1,210 | 8.72% | 50% | $3.9
2026 | $1,242 | 8.72% | 50% | $3.9
2027 | $1,255 | 8.72% | 50% | $3.9
Ameren Illinois’ February 2024 Rehearing Request Filing: |  |  |  |
2024 | $1,214 | (a) | 50% | $4.2
2025 | $1,300 | (a) | 50% | $4.5
2026 | $1,371 | (a) | 50% | $4.7
2027 | $1,420 | (a) | 50% | $4.9
(a)The ROE is under appeal as discussed above. The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase. 2022 Electric Distribution Revenue Requirement Reconciliation Adjustment Order In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $110 million, which reflected Ameren Illinois’ actual 2022 recoverable costs, year-end rate base of $3.9 billion, and a capital structure composed of 50% common equity. The approved reconciliation adjustment will be collected from customers in 2024. In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base. The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025. Electric Customer Energy-Efficiency Investments In November 2023, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $100 million beginning in January 2024, which represents an increase of $24 million from 2023 rates. The order was based on a projected 2024 year-end rate base of $394 million. 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. Subsequently, in January 2024, Ameren Illinois filed an appeal of the November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal. The ICC’s November 2023 natural gas delivery service rate order also required Ameren Illinois to submit a plan outlining how it expects to comply with new PHMSA rules for natural gas transmission pipelines, including proposing a capital expenditures plan necessary to meet the new rules. In February 2024, Ameren Illinois filed its plan with the ICC, which included its proposal of natural gas transmission capital expenditures necessary to achieve compliance with the PHMSA rules. The plan includes delays to certain natural gas transmission capital expenditures from 2024 to subsequent years to align with the November 2023 ICC order. The ICC is under no obligation to issue an order regarding Ameren Illinois’ plan. 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 will be included in this proceeding, which will explore issues involved with 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 expected to be 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. QIP Reconciliation Hearing In March 2021, Ameren Illinois filed a request with the ICC for a reconciliation hearing to determine the accuracy and prudence of natural gas capital investments recovered under the QIP rider during 2020. In October 2023, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow approximately $53 million in natural gas capital investments as improper and imprudent, providing a potential over-recovery of approximately $3 million in 2020. In October 2023, 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. Ameren Illinois cannot predict the ultimate outcome of this regulatory proceeding. RTO Cost-Benefit Study In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from the MISO’s April 2022 capacity auction, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study of continued participation in the MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a period of five to 10 years beginning June 2024. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. Intervenor comments on the study were filed in October 2023 and reply comments were filed in November 2023. In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study. MISO Long-Range Transmission Projects CCN In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed below that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025. Federal MISO Transmission Rate Incentives In July 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 to various utilities, including Ameren. The projects assigned to Ameren are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. In October 2023, the FERC issued an order that approved transmission rate incentives relating to the 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. As a result of the order, ATXI will not capitalize allowance for funds used during construction on the related projects. FERC 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 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 June and July 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. The currently allowed base ROE of 10.02% will remain effective for customer billings, but the transmission rates charged during previous periods and the currently effective rates may be subject to refund if the base ROE is changed by the FERC in a future order. The FERC is under no deadline to issue an order related to these proceedings. A 50-basis-point change in the FERC-allowed ROE would affect Ameren’s and Ameren Illinois’ annual revenue by an estimated $21 million and $15 million, respectively, based on each company’s 2024 projected rate base. Regulatory Assets and Liabilities The following table presents our regulatory assets and regulatory liabilities at December 31, 2023 and 2022:
|  | 2023 |  |  | 2022
|  | Ameren Missouri |  | Ameren Illinois |  | Ameren |  |  | Ameren Missouri |  | Ameren Illinois |  | Ameren
Regulatory assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Under-recovered FAC(a) |  | $ | 72 |  |  | $ | — |  |  | $ | 72 |  |  |  | $ | 140 |  |  | $ | — |  |  | $ | 140 |
Under-recovered Illinois electric power costs(b) |  | — |  |  | 10 |  |  | 10 |  |  |  | — |  |  | 33 |  |  | 33 |
Under-recovered PGA(b)(c) |  | 6 |  |  | — |  |  | 6 |  |  |  | 23 |  |  | — |  |  | 23 |
MTM derivative losses(d) |  | 25 |  |  | 143 |  |  | 168 |  |  |  | 68 |  |  | 68 |  |  | 136 |
IEIMA revenue requirement reconciliation adjustment(e)(f) |  | — |  |  | 239 |  |  | 239 |  |  |  | — |  |  | 134 |  |  | 134 |
FERC revenue requirement reconciliation adjustment(g) |  | — |  |  | 25 |  |  | 54 |  |  |  | — |  |  | 11 |  |  | 33 |
Under-recovered VBA(h) |  | — |  |  | 49 |  |  | 49 |  |  |  | — |  |  | — |  |  | — |
Income taxes(i) |  | 126 |  |  | 78 |  |  | 207 |  |  |  | 111 |  |  | 72 |  |  | 185 |
Bad debt rider(j) |  | — |  |  | 43 |  |  | 43 |  |  |  | — |  |  | 5 |  |  | 5 |
Callaway refueling and maintenance outage costs(k) |  | 37 |  |  | — |  |  | 37 |  |  |  | 33 |  |  | — |  |  | 33 |
Unamortized loss on reacquired debt(l) |  | 45 |  |  | 5 |  |  | 50 |  |  |  | 47 |  |  | 7 |  |  | 54 |
Environmental cost riders(m) |  | — |  |  | 50 |  |  | 50 |  |  |  | — |  |  | 64 |  |  | 64 |
Storm costs(f)(n) |  | — |  |  | 27 |  |  | 27 |  |  |  | — |  |  | 14 |  |  | 14 |
Allowance for funds used during construction for pollution control equipment(f)(o) |  | 10 |  |  | — |  |  | 10 |  |  |  | 11 |  |  | — |  |  | 11 |
Customer generation rebate program(f)(p) |  | — |  |  | 54 |  |  | 54 |  |  |  | — |  |  | 50 |  |  | 50 |
PISA(f)(q) |  | 386 |  |  | — |  |  | 386 |  |  |  | 320 |  |  | — |  |  | 320 |
RESRAM(r) |  | 48 |  |  | — |  |  | 48 |  |  |  | 6 |  |  | — |  |  | 6 |
Certain Meramec Energy Center costs(s) |  | 39 |  |  | — |  |  | 39 |  |  |  | 51 |  |  | — |  |  | 51 |
FEJA energy-efficiency rider(f)(t) |  | — |  |  | 500 |  |  | 500 |  |  |  | — |  |  | 416 |  |  | 416 |
Property tax tracker(u) |  | 13 |  |  | — |  |  | 13 |  |  |  | 3 |  |  | — |  |  | 3 |
Other |  | 49 |  |  | 64 |  |  | 113 |  |  |  | 35 |  |  | 34 |  |  | 69 |
Total regulatory assets |  | $ | 856 |  |  | $ | 1,287 |  |  | $ | 2,175 |  |  |  | $ | 848 |  |  | $ | 908 |  |  | $ | 1,780 |
Less: current regulatory assets |  | (101) |  |  | (252) |  |  | (365) |  |  |  | (254) |  |  | (87) |  |  | (354) |
Noncurrent regulatory assets |  | $ | 755 |  |  | $ | 1,035 |  |  | $ | 1,810 |  |  |  | $ | 594 |  |  | $ | 821 |  |  | $ | 1,426 |
Regulatory liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Over-recovered Illinois electric power costs(b) |  | — |  |  | 36 |  |  | 36 |  |  |  | — |  |  | — |  |  | — |
Over-recovered PGA(b) |  | 7 |  |  | 33 |  |  | 40 |  |  |  | — |  |  | 10 |  |  | 10 |
MTM derivative gains(d) |  | 19 |  |  | 3 |  |  | 22 |  |  |  | 51 |  |  | 40 |  |  | 91 |
Income taxes(i) |  | 999 |  |  | 724 |  |  | 1,809 |  |  |  | 1,095 |  |  | 749 |  |  | 1,931 |
Cost of removal(v) |  | 1,098 |  |  | 1,038 |  |  | 2,186 |  |  |  | 1,064 |  |  | 989 |  |  | 2,091 |
AROs(w) |  | 524 |  |  | — |  |  | 524 |  |  |  | 365 |  |  | — |  |  | 365 |
Bad debt rider(j) |  | — |  |  | 7 |  |  | 7 |  |  |  | — |  |  | 21 |  |  | 21 |
Pension and postretirement benefit costs(x) |  | 202 |  |  | 144 |  |  | 346 |  |  |  | 242 |  |  | 162 |  |  | 404 |
Pension and postretirement benefit costs tracker(y) |  | 111 |  |  | — |  |  | 111 |  |  |  | 60 |  |  | — |  |  | 60 |
Renewable energy credits and zero emission credits(z) |  | — |  |  | 489 |  |  | 489 |  |  |  | — |  |  | 373 |  |  | 373 |
Other |  | 14 |  |  | 15 |  |  | 29 |  |  |  | 64 |  |  | 33 |  |  | 99 |
Total regulatory liabilities |  | $ | 2,974 |  |  | $ | 2,489 |  |  | $ | 5,599 |  |  |  | $ | 2,941 |  |  | $ | 2,377 |  |  | $ | 5,445 |
Less: current regulatory liabilities |  | (15) |  |  | (71) |  |  | (87) |  |  |  | (70) |  |  | (64) |  |  | (136) |
Noncurrent regulatory liabilities |  | $ | 2,959 |  |  | $ | 2,418 |  |  | $ | 5,512 |  |  |  | $ | 2,871 |  |  | $ | 2,313 |  |  | $ | 5,309 |
(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)Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. (c)As a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, for the month of February 2021, Ameren Missouri had under-recovered costs under its PGA clause of $53 million. Pursuant to an October 2021 MoPSC order, the collection period for Ameren Missouri’s cumulative PGA under-recovery as of August 2021, which included the February 2021 under-recovery, was extended from 12 months to 36 months, beginning November 2021. (d)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information. (e)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. (f)These assets earn a return at the applicable WACC. (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 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, other tax liabilities, and the unamortized portion of investment tax credits all recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction and 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 36, 28, and 43 years. (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. These costs are being amortized over five-year periods beginning in the year the storm occurred. (o)The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux Energy Center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux Energy Center, currently through 2030. (p)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid. (q)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 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. (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 three 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)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment when retired from service, net of salvage. (w)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,150 million and $958 million at December 31, 2023 and 2022, respectively), net of recoverable removal costs for AROs ($626 million and $593 million at December 31, 2023 and 2022, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations and Removal Costs. (x)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. (y)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 three 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. (z)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 a reconciliation proceeding, the first of which was initiated in August 2023. Based on amounts collected from customers and renewable energy credit purchases under contract, the August 2023 reconciliation proceeding did not result in refunds to customers.

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