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

•Performance-based formula ratemaking(a)

•Initial rates based on historical test year and expected net plant additions for the year before rates become effective

•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

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

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(b)

•PGA

•VBA

•Energy-efficiency program costs

•Certain environmental costs

•Bad debt write-offs

•Invested capital taxes

•Revenue requirement reconciliation adjustment

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’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 for its cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its 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. Under Missouri law, as a result of the PISA election, additional provisions apply to Ameren Missouri. These provisions include limiting Ameren Missouri’s rate increases to a 2.85% compound annual growth rate in the average overall customer rate

per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in a July 2018 MoPSC order. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the 2.85% rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review would be subject to the rate cap. Any deferred overages approved for recovery would be recovered in a manner consistent with costs recovered under the PISA. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the amount of deferred overage that would cause customer rates to exceed the 2.85% rate cap until new rates are established in the next regulatory rate review. Ameren Missouri did not incur a penalty related to the rate cap in 2022. The current rate cap is effective through 2023. As discussed below, Missouri Senate Bill 745 was enacted in June 2022 and established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates 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, and will be based on the revenue requirement established in the immediately preceding rate order. The PISA is effective through December 2028. Missouri law provides for the ability to use the PISA, if Ameren Missouri requests and receives MoPSC approval for extension, through December 2033.

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 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.

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, subject to MoPSC prudence reviews, 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. The WNAR was approved by a December 2021 MoPSC natural gas rate order and became effective February 28, 2022, replacing a rate-adjustment mechanism that had decoupled natural gas revenues from actual sales volumes.

The ICC regulates rates and other matters for Ameren Illinois’ electric distribution service and natural gas distribution businesses. The rates Ameren Illinois charges customers for electric distribution service are calculated under a performance-based formula ratemaking framework pursuant to the IEIMA. Pursuant to the IETL and December 2022 and March 2021 ICC orders, Ameren Illinois used the IEIMA formula framework to establish annual customer rates effective through 2023 and filed an MYRP in January 2023 for rates that will become effective beginning in 2024. The orders also allow Ameren Illinois to reconcile its revenue requirement for customer rates established for 2022 and 2023. Pursuant to the orders, Ameren Illinois’ 2022 revenues reflected, and its 2023 revenues will reflect, 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 revenue requirement reconciliation adjustment would be collected from, or refunded to, customers within two years from the end of the reconciled year. By law, the decoupling provisions extend beyond the end of existing performance-based formula ratemaking, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. See below for additional information regarding the MYRP filed in January 2023. 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’ election to use the electric distribution service performance-based formula ratemaking framework allowed by state law, described below, permits Ameren Illinois to adjust customer rates to recover the cost of electric distribution service on an annual basis. Ameren Illinois’ electric distribution service also has other cost recovery mechanisms in place that allow customer rates to be adjusted without 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.

Ameren Illinois’ electric distribution service performance-based formula ratemaking framework under the IEIMA allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis. 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 then collected from, or refunded to, customers within two years from the end of the year. In addition, 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 both its electric distribution service and 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 distribution business is directly correlated to the yields on such bonds. In addition, regulatory assets applicable to formula ratemaking for both electric distribution service and electric energy-efficiency investments earn a return at the applicable WACC. However, Ameren Illinois recognizes the 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. As discussed above, Ameren Illinois filed an MYRP to establish electric distribution service rates beginning in 2024. Ameren Illinois will continue to use formula ratemaking to establish annual customer rates related to its electric energy-efficiency investments beyond 2023.

Ameren Illinois’ electric distribution service business is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed ROE calculated under the formula ratemaking recovery mechanism. The performance standards applicable to electric distribution service under the IEIMA include improvements in service reliability to reduce both the frequency and duration of outages, a reduction in the number of estimated bills, a reduction of consumption from inactive meters, and a reduction in bad debt expense. The 2023 allowed ROE for electric distribution service is subject to the performance standards related to reduced estimated bills and bad debt expense, and may be decreased for penalties up to 10 basis points if these performance standards are not met. 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 2022, 2021, and 2020, there were no performance-related basis point adjustments that materially affected financial results.

Ameren Illinois’ natural gas distribution business has recovery mechanisms, including the QIP, 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

The QIP provides Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that are placed in service between regulatory rate reviews. Infrastructure investments under the QIP earn a return at the applicable WACC. Eligible natural gas investments include projects to improve safety and reliability and modernization investments, such as smart meters. The deferrals are recorded as a regulatory asset, with recovery beginning two months after the qualifying natural gas plant is placed in service and continuing until such plant is included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP is 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%. If the rate impact limitation was met in a particular year, the amount of rate base causing the QIP rate to exceed the limitation would be exposed to regulatory lag until a year when that amount could be recovered under QIP or is added to rate base as a part of a regulatory rate review. Upon issuance of a natural gas delivery service rate order, QIP rate base is transferred to base rates and the QIP is reset to zero, which mitigates the risk that the QIP will exceed its statutory limitations in future years and ensures timely recovery of capital investments. Without legislative action, the QIP will expire after December 2023.

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 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.

In August 2022, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $316 million. The electric rate increase request is based on a 10.2% ROE, a capital structure composed of 51.93% common equity, a rate base of $11.6 billion, and a test year ended March 31, 2022, with certain pro-forma adjustments expected through an anticipated true-up date of December 31, 2022. Ameren Missouri’s request includes 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 costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker allowed under Missouri Senate Bill 745 discussed below. In October 2022, Ameren Missouri also requested the use of a tracker for variances between actual income tax benefits and costs resulting from the IRA and those amounts included in customer rates, which would be considered for recovery or refund in a future electric regulatory rate review. For additional information regarding the IRA, see Note 12 – Income Taxes. The electric rate increase request reflects the following:

In connection with the planned accelerated retirement of the Rush Island Energy Center, Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute. As such, Ameren Missouri did not request a change in the depreciation rates related to the Rush Island Energy Center in this electric service regulatory rate review.

In January 2023, the MoPSC staff recommended an increase to Ameren Missouri's annual electric service revenues of $199 million based on a 9.59% ROE, a capital structure composed of 51.84% common equity, and a rate base as of June 30, 2022, of $10.5 billion. Ameren Missouri expects the MoPSC staff will update its rate base estimate through the anticipated true-up date of December 31, 2022. The MoPSC staff’s recommendation of $199 million includes an adjustment to annual electric service revenues of $128 million for estimated true-up items from June 30, 2022, to December 31, 2022, including the impacts of any investments made during that period. Their recommendation also 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, and a lower rate base for the Rush Island Energy Center due to its reduced operation in compliance with a system support resource agreement approved by the FERC in October 2022, among other things. See Note 14 – Commitments and Contingencies for additional information on the curtailed nighttime operations at the High Prairie Energy Center and the Rush Island Energy Center system support resource agreement. The MoPSC staff supported the authorization of a tracker for future production tax credits and proceeds from the sale of tax credits allowed under the IRA, but did not recommend tracking investment tax credits or costs resulting from the IRA, including the 15% minimum tax on adjusted financial statement income imposed by the law. The MoPSC staff also recommended that deferrals under the electric property tax tracker discussed below should begin on the effective date of new rates established by this proceeding, rather than the effective date of the enactment of Missouri Senate Bill 745.

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 June 2023 and new rates effective by July 2023. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be approved, 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.

Missouri Senate Bill 745 became effective on August 28, 2022. The law extended Ameren Missouri’s PISA election through December 2028 and allows for an additional extension through December 2033 if requested by Ameren Missouri and approved by the MoPSC, among other things. The law established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates 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, and will be based on the revenue requirement established in the immediately preceding rate order. The law also established electric and natural gas property tax trackers that allow Ameren Missouri to defer the difference between actual property taxes incurred and related taxes included in customer rates as a regulatory asset or regulatory liability, with the difference expected to be reflected in rate base in a subsequent rate order. Upon the effective date of the law, Ameren Missouri began deferring amounts under these trackers. The deferrals were immaterial as of December 31, 2022.

In February 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, the Boomtown Solar Project, a 150-MW solar generation facility, which is expected to support Ameren Missouri’s transition to renewable energy generation and serve customers under the Renewable Solutions Program discussed below, if approved by the MoPSC. In June 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, the Huck Finn Solar Project, a 200-MW solar generation facility, which is expected to support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of retail sales from renewable energy sources, of which 2% must be derived from solar energy sources. Both acquisitions are aligned with the 2022 Change to the 2020 IRP, which Ameren Missouri filed with the MoPSC in June 2022, and are subject to certain


	Boomtown Solar Project	Huck Finn Solar Project
Agreement date	February 2022	June 2022
Facility size	150-MW	200-MW
Location	Southeastern Illinois	Central Missouri
Status of MoPSC certificate of convenience and necessity	Requested in July 2022(a)	Approved February 2023(b)
Status of FERC approval of acquisition	Expect to request by mid-2023	Requested in November 2022
Expected completion date(c)	As early as fourth quarter 2024	As early as fourth quarter 2024

In July 2022, Ameren Missouri filed a request with the MoPSC seeking approval of its Renewable Solutions Program and a tariff related to participation in the program. The program would allow certain commercial, industrial, and governmental customers to receive up to 100% of their energy from renewable resources. Based on customer contracts, the program would enable Ameren Missouri to supply renewable solar energy generated by the Boomtown Solar Project discussed above to customers that enroll in the program. Ameren Missouri expects a decision from the MoPSC by April 2023.

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 other MoPSC proceedings, which could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

In August 2022, the MoPSC issued an order approving Ameren Missouri’s energy savings results for the 2021 program year of the MEEIA 2019 program. In December 2022, Ameren Missouri achieved certain energy-efficiency spending goals for the 2022 program year of the MEEIA 2019 program. As a result of this order, achieving the spending goals for the 2022 program year, and MoPSC orders issued in September 2021 and August 2020, Ameren Missouri recognized revenues of $22 million, $9 million, and $6 million in 2022, 2021, and 2020, respectively.

The electric order resulted in an increase of $220 million to Ameren Missouri’s annual revenue requirement for electric retail service. The approved revenue requirement is based on a rate base of $10.2 billion, infrastructure investments as of September 30, 2021, and a change in the depreciable lives of the Sioux and Rush Island energy centers’ assets consistent with Ameren Missouri’s 2020 IRP. The order did not specify an ROE, but specified that Ameren Missouri’s September 30, 2021 capital structure, which was composed of 51.97% common equity, will be used in the PISA and RESRAM. The order changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in depreciation and amortization of $140 million and other operating and maintenance expenses of $40 million.

In January 2023, Ameren Illinois filed an MYRP with the ICC to be used in setting electric distribution service rates for 2024 through 2027. Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of the four-year period. The following table includes the forecasted revenue requirement, the requested ROE, the requested capital structure common equity percentage, and the forecasted average annual rate base for 2024 through 2027, as reflected in Ameren Illinois’ MYRP:

Under an MYRP, the IETL permits any initial rate increase to be phased in, with at least 50% of the first annual period’s approved rate increase reflected in rates in the first annual period, with the remaining portion deferred as a regulatory asset that earns a return at the applicable WACC and is collected from customers over a period not to exceed two years beginning within one year after the second annual period’s rates are effective. Ameren Illinois’ MYRP filing utilizes this phase-in provision and proposes to defer 50% of the requested 2024 rate increase of $175 million as a regulatory asset to be collected from customers in 2026. Ameren Illinois recognizes revenues when amounts are expected to be collected from customers within two years from the end of an applicable year. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024. Ameren Illinois cannot predict the level of any electric distribution service rate change the ICC may approve, or whether any rate change that may eventually be approved will be sufficient for Ameren Illinois to recover its costs to the extent those costs are subject to and exceed the reconciliation cap discussed below and earn a reasonable return on its investments when the rate change goes into effect.

The MYRP also allows Ameren Illinois to 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 would be 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 through riders outside of base rates, such as riders for electric energy-efficiency investments, power procurement and transmission services, renewable energy credit compliance, zero emission credits, certain environmental costs, and bad debt write-offs, among others. Ameren Illinois’ existing riders will remain effective and electric distribution service revenues will continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year would incorporate Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. Excluding the phase-in of the initial rate increase discussed above, and subject to the reconciliation cap, if a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment would be 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 would then be collected from, or refunded to, customers within two years from the end of the applicable annual period.

Under the MYRP, the ROE approved by the ICC will be subject to annual adjustments during the four-year period based on seven performance metrics. In September 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points, allocated among the 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 and the ROE incentives and penalties will 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 December 2022, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $61 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2023. This order reflected an increase to the annual performance-based formula rate based on 2021 actual recoverable costs and expected net plant additions for 2022, an increase to include the 2021 revenue requirement reconciliation adjustment including a capital structure composed of 50% common equity, and a decrease for the conclusion of the 2020 revenue requirement reconciliation adjustment, which was fully collected from customers in 2022, consistent with the ICC’s December 2021 annual update filing order.

In June 2022, the ICC issued an order approving Ameren Illinois’ revised energy-efficiency plan that includes annual investments in electric energy-efficiency programs of approximately $120 million per year through 2025, which reflects the increased level of annual investments allowed under the IETL. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not recovered through the electric distribution service performance-based formula ratemaking framework.

In January 2023, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $160 million, which included an estimated $77 million of annual revenues that would otherwise be recovered under the QIP and other riders. The request is based on a 10.7% allowed ROE, a capital structure composed of 53.99% common equity, and a rate base of $2.9 billion. In an attempt to reduce regulatory lag, Ameren Illinois used a 2024 future test year in this proceeding. A decision by the ICC in this proceeding is required by late November 2023, with new rates expected to be effective in early December 2023. 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.

The IETL contains other provisions in addition to the ratemaking impacts discussed in the MYRP section above. The law permits Ameren Illinois to invest up to $20 million in each of two solar generation and battery storage pilot projects in Illinois. The first of these projects was placed in service in December 2022. Additionally, the law increased the existing customer surcharge for renewable energy resources, which funds IPA renewable energy credit procurement events. As a result, Ameren Illinois began collecting additional annual revenues of approximately $100 million, beginning in February 2022, under the rider for the procurement of renewable energy credits. It also established an Energy Transition Assistance Fund to support economic and workforce development programs designed to assist the state of Illinois with its transition to clean energy sources. The fund is subsidized through customer surcharges collected by electric utilities operating in the state, including Ameren Illinois, and is remitted in the month following collection to an Illinois state agency, with no impact to results of operations. In May 2022, Illinois Senate Bill 3866 was enacted and became effective. This legislation makes certain amendments to the IETL, including amendments to increase the allowed level of funding for the Energy Transition Assistance Fund. Ameren Illinois expects to collect approximately $25 million annually related to this fund, beginning in January 2023, which could be increased to up to $50 million in future years. Pursuant to the IETL, Ameren Illinois is required to file a multi-year integrated grid plan with the ICC every four years. In January 2023, Ameren Illinois filed its first multi-year integrated grid plan for the years 2023 to 2027. The plan outlines how Ameren Illinois expects to operate and invest in electric distribution infrastructure in order to support grid modernization, clean energy, energy efficiency, and the state of Illinois’ renewable energy, equity, climate, electrification, and environmental goals, while providing safe, secure, reliable, and resilient electric distribution service to customers. Ameren Illinois’ next multi-year integrated grid plan is required by mid-January 2026.

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. The cost-benefit study will examine 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 ICC order requires Ameren Illinois to file the study by July 2023. A 30-day comment period will follow. The ICC is under no obligation to issue an order related to the cost-benefit study.

In February 2020, the MISO, on behalf of Ameren Missouri, Ameren Illinois, and ATXI, filed requests with the FERC to revise each company’s transmission formula rate calculations with respect to the calculation used for materials and supplies inventories included in rate base. In May 2020, the FERC issued orders approving the revisions prospectively. In addition, the FERC declined to order refunds for earlier periods, as requested by intervenors in Ameren Illinois’ filing, but directed its audit staff to review historical rate recovery in connection with an ongoing FERC audit. Separately, in March 2021, the FERC issued an order related to an intervenor challenge to Ameren Illinois’ 2020 transmission formula rate update. As a result of this order, in March 2021, Ameren Illinois recorded a regulatory liability of $9 million, largely as a reduction of electric operating revenues, to reflect expected refunds, including interest, primarily related to the historical rate recovery of materials and supplies inventories included in rate base. The refund amount was reflected in rates as of January 2022 and fully refunded to customers by the end of 2022. Ameren Missouri, Ameren Illinois, and ATXI filed appeals of the FERC’s May 2020 and March 2021 orders, and related FERC orders denying requests for rehearing, to the United States Court of Appeals for the District of Columbia Circuit, which appeals were denied in January 2023. The impact of the May 2020 and March 2021 orders was not material to Ameren’s, Ameren Missouri’s, or Ameren Illinois’ results of operations, financial position, or liquidity.

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 did not rule on the petition filed by Ameren Missouri, Ameren Illinois, and ATXI. The currently allowed base ROE of 10.02% will remain effective for customer billings, but 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 $19 million and $13 million, respectively, based on each company’s 2023 projected rate base.


	2022						2021
	Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois		Ameren
Regulatory assets:
Under-recovered FAC(a)	$	140	$	—	$	140	$	47	$	—	$	47
Under-recovered Illinois electric power costs(b)	—		33		33		—		3		3
Under-recovered PGA(b)(c)	23		—		23		49		114		163
MTM derivative losses(d)	68		68		136		77		125		202

IEIMA revenue requirement reconciliation adjustment(e)(f)	—		134		134		—		42		42
FERC revenue requirement reconciliation adjustment(g)	—		11		33		—		18		43
Under-recovered VBA(h)	—		—		—		—		17		17

Income taxes(i)	111		72		185		115		69		185




Callaway refueling and maintenance outage costs(j)	33		—		33		14		—		14
Unamortized loss on reacquired debt(k)	47		7		54		50		13		63
Environmental cost riders(l)	—		64		64		—		70		70
Storm costs(f)(m)	—		14		14		—		17		17




Allowance for funds used during construction for pollution control equipment(f)(n)	11		—		11		13		—		13
Customer generation rebate program(f)(o)	—		50		50		—		47		47


PISA(f)(p)	320		—		320		244		—		244

Certain Meramec Energy Center costs(q)	51		—		51		—		—		—
FEJA energy-efficiency rider(f)(r)	—		416		416		—		350		350
Other	44		39		83		41		47		88
Total regulatory assets	$	848	$	908	$	1,780	$	650	$	932	$	1,608
Less: current regulatory assets	(254)		(87)		(354)		(127)		(180)		(319)
Noncurrent regulatory assets	$	594	$	821	$	1,426	$	523	$	752	$	1,289
Regulatory liabilities:
Over-recovered FAC(a)	$	4	$	—	$	4	$	19	$	—	$	19
Over-recovered Illinois electric power costs(b)	—		—		—		—		13		13
Over-recovered PGA(b)	—		10		10		—		1		1

MTM derivative gains(d)	51		40		91		50		41		91





Income taxes(i)	1,095		749		1,931		1,208		770		2,066



Cost of removal(s)	1,064		989		2,091		1,028		929		1,988
AROs(t)	365		—		365		603		—		603

Bad debt rider(u)	—		21		21		—		19		19
Pension and postretirement benefit costs(v)	242		162		404		399		392		791
Pension and postretirement benefit costs tracker(w)	60		—		60		28		—		28


Renewable energy credits and zero emission credits(x)	—		373		373		—		246		246

RESRAM(y)	2		—		2		19		—		19
Excess income taxes collected in 2018(z)	7		—		7		25		—		25
Other	51		33		86		32		17		52
Total regulatory liabilities	$	2,941	$	2,377	$	5,445	$	3,411	$	2,428	$	5,961
Less: current regulatory liabilities	(70)		(64)		(136)		(57)		(54)		$	(113)
Noncurrent regulatory liabilities	$	2,871	$	2,313	$	5,309	$	3,354	$	2,374	$	5,848

(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 and Ameren Illinois had under-recovered costs under their PGA clauses of $53 million and $221 million, respectively. Pursuant to an October 2021 MoPSC order, the collection period for Ameren Missouri’s cumulative PGA under-recovery as of August 2021, which includes the February 2021 under-recovery, was extended from 12 months to 36 months, beginning November 2021. Ameren Illinois collected its February 2021 PGA under-recovery over 18 months beginning April 2021.

(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 deferred income taxes related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits 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 38, 31, and 44 years.

(n)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 2028. Ameren Missouri’s electric rate increase request discussed above reflects extending the retirement date of the Sioux Energy Center from 2028 to 2030.

(w)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 costs incurred prior to 2022, the weighted-average remaining amortization period is four years. For costs incurred during 2022, the amortization period will be determined the 2022 electric service regulatory rate review discussed above.