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Rate And Regulatory Matters (Tables) | 12 Months Ended
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Dec. 31, 2024
Public Utilities, General Disclosures [Abstract] |
Schedule of Regulatory Frameworks and Significant Recovery Mechanisms | The following table presents the regulatory frameworks and significant regulatory recovery mechanisms for each of Ameren’s rate-regulated businesses, which are discussed in more detail below:
| Ameren Missouri | Ameren Illinois’ electric distribution business | Ameren Illinois’ natural gas delivery business | Ameren Illinois’ and ATXI’s electric transmission businesses
Regulatory framework | •Historical test year ratemaking •Natural gas revenues for residential customers adjusted for sales volume deviations resulting from weather through the WNAR | •MYRP •Initial rates based on future test years •Revenues decoupled from sales volumes and wholesale and miscellaneous revenues through the RBA | •Future test year ratemaking •Revenues for residential and small nonresidential customers decoupled from sales volumes through the VBA | •Formula ratemaking •Initial rates based on future test year •Revenues decoupled from sales volumes
Regulatory mechanisms | •PISA Riders: •RESRAM •FAC •Rush Island Securitization •MEEIA •PGA •WNAR Trackers: •Pension and postretirement benefit costs •Certain excess deferred income taxes •Renewable energy standard costs •Property taxes •Production and investment tax credits or proceeds from the sale of certain tax credits allowed under the IRA | •Electric distribution service and energy-efficiency revenue requirement reconciliation adjustments(a) Riders: •RBA •Power procurement •Transmission services •Renewable energy credit compliance •Zero emission credits •Customer generation rebate program costs •Certain environmental costs •Bad debt write-offs •Costs of certain asbestos-related claims | Riders: •PGA •VBA •Energy-efficiency program costs •Certain environmental costs •Bad debt write-offs •Invested capital taxes | •Revenue requirement reconciliation adjustment
(a)Reconciliation adjustments under an MYRP are subject to a reconciliation cap which limits annual adjustment to 105%. See below for additional information regarding the reconciliation cap.
Schedule of Solar Projects | The following table provides information with respect to each agreement:
| Agreement type | Facility size | Status of MoPSC CCN | Status of FERC approval of acquisition | In-service date(a)
Huck Finn Solar Project(b)(c) | Build-transfer | 200-MW | Approved February 2023 | Received March 2023 | December 2024
Boomtown Solar Project(c)(d) | Build-transfer | 150-MW | Approved April 2023 | Received October 2023 | December 2024
Cass County Solar Project(c)(d) | Development-transfer | 150-MW | Approved June 2024 | Not applicable | December 2024
Vandalia Solar Project(e)(f) | Self-build | 50-MW | Approved March 2024 | Not applicable | Fourth quarter 2025
Bowling Green Solar Project(e)(f) | Self-build | 50-MW | Approved March 2024 | Not applicable | First quarter 2026
Split Rail Solar Project(e)(f) | Build-transfer | 300-MW | Approved March 2024 | Received November 2024 | Mid-2026
Castle Bluff Natural Gas Project(e) | Self-build | 800-MW | Approved October 2024(g) | Not applicable | Fourth quarter 2027
(a)In-service dates are dependent on the timing of construction completion, among other things. The assets of the Huck Finn, Boomtown, and Cass County solar projects were placed in service in December 2024. (b)The Huck Finn Solar Project is expected to support Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Investments in the project are eligible for recovery under the RESRAM. (c)Ameren Missouri acquired the Cass County, Boomtown, and Huck Finn solar projects in June 2024, September 2024, and October 2024, respectively, and placed the assets of the projects, totaling $1 billion, in service in December 2024. (d)The Boomtown and Cass County solar projects are expected to support Ameren Missouri’s transition to renewable energy generation and serve customers under the Renewable Solutions Program, which allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. (e)These projects collectively represent approximately $1.7 billion of expected capital expenditures. (f)These solar projects are expected to support Ameren Missouri’s transition to renewable energy generation. (g)For additional information see Castle Bluff Natural Gas Project CCN and Post-Construction Cost Deferral below.
Schedule of MYRP details | The following table presents the approved revenue requirements and average annual rate base in the ICC’s December 2024 MYRP order and the ICC’s June 2024 rehearing order:
Year | Revenue Requirement (in millions) |  |  | Average Annual Rate Base (in billions)
ICC’s December 2024 MYRP Order(a): |  |  |  |
2024 | $1,206 |  |  | $4.2
2025 | $1,287 |  |  | $4.4
2026 | $1,367 |  |  | $4.6
2027 | $1,422 |  |  | $4.8
ICC’s June 2024 Rehearing Order(a): |  |  |  |
2024 | $1,196 |  |  | $4.0
2025 | $1,282 |  |  | $4.3
2026 | $1,350 |  |  | $4.5
2027 | $1,397 |  |  | $4.7
(a)Based on an allowed ROE of 8.72% and a capital structure composed of 50% common equity. The ROE is under appeal, as discussed above. New rates became effective in December 2024.
Schedule Of Regulatory Assets And Liabilities | The following table presents our regulatory assets and regulatory liabilities at December 31, 2024 and 2023:
|  | 2024 |  |  | 2023
|  | Ameren Missouri |  | Ameren Illinois |  | Ameren |  |  | Ameren Missouri |  | Ameren Illinois |  | Ameren
Regulatory assets: |  |  |  |  |  |  |  |  |  |  |  |  |
Under-recovered FAC(a) |  | $ | 41 |  |  | $ | — |  |  | $ | 41 |  |  |  | $ | 72 |  |  | $ | — |  |  | $ | 72 |
MTM derivative losses(b) |  | 15 |  |  | 88 |  |  | 103 |  |  |  | 25 |  |  | 143 |  |  | 168 |
IEIMA revenue requirement reconciliation adjustment(c)(d) |  | — |  |  | 139 |  |  | 139 |  |  |  | — |  |  | 239 |  |  | 239 |
MYRP revenue requirement reconciliation adjustment(d)(e) |  | — |  |  | 24 |  |  | 24 |  |  |  | — |  |  | — |  |  | — |
Under-recovered RBA(f) |  | — |  |  | 22 |  |  | 22 |  |  |  | — |  |  | — |  |  | — |
FERC revenue requirement reconciliation adjustment(g) |  | — |  |  | 55 |  |  | 90 |  |  |  | — |  |  | 25 |  |  | 54 |
Under-recovered VBA(h) |  | — |  |  | 49 |  |  | 49 |  |  |  | — |  |  | 49 |  |  | 49 |
Income taxes(i) |  | 237 |  |  | 81 |  |  | 322 |  |  |  | 126 |  |  | 78 |  |  | 207 |
Bad debt rider(j) |  | — |  |  | 25 |  |  | 25 |  |  |  | — |  |  | 43 |  |  | 43 |
Callaway refueling and maintenance outage costs(k) |  | 13 |  |  | — |  |  | 13 |  |  |  | 37 |  |  | — |  |  | 37 |
Unamortized loss on reacquired debt(l) |  | 42 |  |  | 5 |  |  | 47 |  |  |  | 45 |  |  | 5 |  |  | 50 |
Environmental cost riders(m) |  | — |  |  | 43 |  |  | 43 |  |  |  | — |  |  | 50 |  |  | 50 |
Storm costs(d)(n) |  | — |  |  | 18 |  |  | 18 |  |  |  | — |  |  | 27 |  |  | 27 |
Customer generation rebate program(d)(o) |  | — |  |  | 89 |  |  | 89 |  |  |  | — |  |  | 54 |  |  | 54 |
PISA(d)(p) |  | 464 |  |  | — |  |  | 464 |  |  |  | 386 |  |  | — |  |  | 386 |
Rush Island Energy Center securitization(q) |  | 465 |  |  | — |  |  | 465 |  |  |  | — |  |  | — |  |  | — |
RESRAM(r) |  | 51 |  |  | — |  |  | 51 |  |  |  | 48 |  |  | — |  |  | 48 |
Certain Meramec Energy Center costs(s) |  | 26 |  |  | — |  |  | 26 |  |  |  | 39 |  |  | — |  |  | 39 |
Energy-efficiency rider(d)(t) |  | — |  |  | 576 |  |  | 576 |  |  |  | — |  |  | 500 |  |  | 500 |
Property tax tracker(u) |  | 22 |  |  | — |  |  | 22 |  |  |  | 13 |  |  | — |  |  | 13 |
Other |  | 56 |  |  | 78 |  |  | 134 |  |  |  | 65 |  |  | 74 |  |  | 139 |
Total regulatory assets |  | $ | 1,432 |  |  | $ | 1,292 |  |  | $ | 2,763 |  |  |  | $ | 856 |  |  | $ | 1,287 |  |  | $ | 2,175 |
Less: current regulatory assets |  | (66) |  |  | (281) |  |  | (366) |  |  |  | (101) |  |  | (252) |  |  | (365) |
Noncurrent regulatory assets |  | $ | 1,366 |  |  | $ | 1,011 |  |  | $ | 2,397 |  |  |  | $ | 755 |  |  | $ | 1,035 |  |  | $ | 1,810 |
Regulatory liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |
Over-recovered Illinois electric power costs(v) |  | — |  |  | 34 |  |  | 34 |  |  |  | — |  |  | 36 |  |  | 36 |
Over-recovered PGA(v) |  | 2 |  |  | 33 |  |  | 35 |  |  |  | 7 |  |  | 33 |  |  | 40 |
MTM derivative gains(b) |  | 10 |  |  | 6 |  |  | 16 |  |  |  | 19 |  |  | 3 |  |  | 22 |
Income taxes(i) |  | 1,040 |  |  | 679 |  |  | 1,804 |  |  |  | 999 |  |  | 724 |  |  | 1,809 |
Cost of removal(w) |  | 1,118 |  |  | 1,115 |  |  | 2,294 |  |  |  | 1,098 |  |  | 1,038 |  |  | 2,186 |
AROs(x) |  | 691 |  |  | — |  |  | 691 |  |  |  | 524 |  |  | — |  |  | 524 |
Pension and postretirement benefit costs(y) |  | 202 |  |  | 156 |  |  | 358 |  |  |  | 202 |  |  | 144 |  |  | 346 |
Pension and postretirement benefit costs tracker(z) |  | 70 |  |  | — |  |  | 70 |  |  |  | 111 |  |  | — |  |  | 111 |
Renewable energy credits and zero emission credits(aa) |  | — |  |  | 586 |  |  | 586 |  |  |  | — |  |  | 489 |  |  | 489 |
Certain Rush Island Energy Center costs(ab) |  | 66 |  |  | — |  |  | 66 |  |  |  | — |  |  | — |  |  | — |
Other |  | 14 |  |  | 43 |  |  | 63 |  |  |  | 14 |  |  | 22 |  |  | 36 |
Total regulatory liabilities |  | $ | 3,213 |  |  | $ | 2,652 |  |  | $ | 6,017 |  |  |  | $ | 2,974 |  |  | $ | 2,489 |  |  | $ | 5,599 |
Less: current regulatory liabilities |  | (37) |  |  | (79) |  |  | (120) |  |  |  | (15) |  |  | (71) |  |  | (87) |
Noncurrent regulatory liabilities |  | $ | 3,176 |  |  | $ | 2,573 |  |  | $ | 5,897 |  |  |  | $ | 2,959 |  |  | $ | 2,418 |  |  | $ | 5,512 |
(a)Under-recovered fuel and purchased power costs to be recovered through the FAC. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months. (b)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information. (c)The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the IEIMA performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. The under-recovery will be recovered from customers with a return at the applicable WACC within two years. (d)These assets earn a return at the applicable WACC. (e)The difference between Ameren Illinois' actual electric distribution revenue requirement, as adjusted for certain cost variations, and the ICC-approved revenue requirement, subject to a reconciliation cap. The under-recovery will be recovered from customers with a return at the applicable WACC within two years. (f)Under-recovered electric distribution service revenue caused by sales volume and/or wholesale and miscellaneous revenue deviations from the related revenue requirement approved by the ICC for a given year. The under-recovery will be recovered from customers within two years. (g)Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years. (h)Under-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in rate regulatory reviews. Each year’s amount will be recovered from customers from April through December of the following year. (i)The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction, the securitization of the Rush Island Energy Center, and the effects of tax rate increases. The regulatory liabilities represent amounts that will be refunded to customers for excess deferred income taxes related to depreciation differences caused by a decrease in the statutory rates, other tax liabilities, and amounts related to the unamortized portion of investment tax credits. Amounts associated with the equity component of allowance for funds used during construction, the securitization of the Rush Island Energy Center, and amounts related to the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 39, 30, and 46 years. In addition, the regulatory liabilities for Ameren Missouri include a regulatory recovery mechanism for the difference between production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA and the level of such tax credits included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. The amortization period will be determined in a future regulatory rate review. (j)A rider for the difference between the level of bad debt write-offs, net of any subsequent recoveries, incurred by Ameren Illinois and the level of such costs included in electric distribution and natural gas delivery service rates. Under-recovered or over-recovered costs for each year are collected from, or refunded to, customers over a twelve-month period beginning in June of the following year. (k)Maintenance expenses related to scheduled refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. Amounts are amortized over the period between refueling and maintenance outages, which has historically been approximately 18 months. (l)Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued. (m)The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information. (n)Storm costs from 2020 through 2023 deferred in accordance with the IEIMA and MYRP. These costs are being amortized over five-year periods beginning in the year the storm occurred. (o)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid. (p)Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on 85% of investments in certain property, plant, and equipment placed in service and not included in base rates. Accumulated PISA deferrals, which also earn a return at the applicable WACC, are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review. (q)In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance costs related to the accelerated retirement of the Rush Island Energy Center, which includes the remaining unrecovered net plant balance associated with the facility, among other costs. Ameren Missouri will collect the amounts necessary to repay the securitized utility tariff bonds over approximately 15 years beginning in December 2024. (r)Under-recovered costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Under-recovered or over-recovered costs are aggregated over a twelve-month period beginning each August and are amortized over a twelve-month period beginning in February of the following year. (s)Certain costs associated with the Meramec Energy Center, which were authorized for recovery by a December 2021 MoPSC electric rate order. These costs are being collected over five years beginning in February 2022. (t)The electric energy-efficiency investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from two to 12 years. (u)A regulatory recovery mechanism for the difference between actual property taxes incurred by Ameren Missouri and the related taxes included in customer rates. The period of recovery, or refund, varies based on MoPSC approval in a regulatory rate review. Amounts accumulated through 2022 are being collected over two years beginning July 2023. The amortization period for amounts accumulated after 2022 will be determined in a future regulatory rate review. (v)Over-recovered costs from utility customers. Amounts will be refunded to customers within one year of the deferral. (w)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment when retired from service, net of salvage. (x)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,342 million and $1,150 million at December 31, 2024 and 2023, respectively), net of recoverable removal costs for AROs ($651 million and $626 million at December 31, 2024 and 2023, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations and Removal Costs. (y)Over-recovered costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information. (z)A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For electric and natural gas related costs incurred prior to 2023 and 2022, respectively, the weighted-average remaining amortization period is two years. For electric and natural gas related costs incurred after 2023 and 2022, respectively, the amortization period will be determined in a future regulatory rate review. (aa)Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to an annual reconciliation proceeding, the latest of which was approved by the ICC in January 2025 and did not result in refunds to customers. (ab)Funds collected from the issuance of securitized utility tariff bonds by AMF primarily to pay for the decommissioning of the Rush Island Energy Center. The amortization period for the difference between the estimated costs and the actual costs incurred will be determined in a future regulatory rate review.

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