NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren also has other subsidiaries that conduct other activities, such as providing shared services.
•Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri. Ameren Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri, which includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 0.1 million customers.
•Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois. Ameren Illinois was incorporated in Illinois in 1923 and is the successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to a 43,700 square mile area in central and southern Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 0.8 million customers.
•Ameren Transmission Company of Illinois, doing business as ATXI, operates a FERC rate-regulated electric transmission business in the MISO. ATXI was incorporated in Illinois in 2006. In December 2020, ATXI completed construction of the ninth and final line segment of the Illinois Rivers transmission line, a MISO-approved electric transmission line. ATXI also operates the Spoon River and Mark Twain transmission lines, which were placed in service in February 2018 and December 2019, respectively.
The COVID-19 pandemic continues to affect our results of operations, financial position, and liquidity. While our electric sales volumes, excluding the estimated effects of weather and customer energy-efficiency programs, increased in 2021, compared to 2020, and total sales volume levels were more comparable to pre-pandemic levels, there has been a shift in sales volumes by customer class, with an increase in residential sales, and a decrease in commercial and industrial sales. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions.
We continue to assess the impacts the COVID-19 pandemic is having on our businesses, including but not limited to impacts on our liquidity; demand for residential, commercial, and industrial electric and natural gas services; changes in deferred payment arrangements for customers; bad debt expense; supply chain operations; the availability of our employees and contractors; counterparty credit; capital construction; infrastructure operations and maintenance; and pension valuations. While the revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission businesses are decoupled from changes in sales volumes, earnings at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers are exposed to such changes. Regarding uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri has not experienced and does not expect a material impact to earnings from increases in bad debt expense. Our customers’ payment for our services has been impacted by the COVID-19 pandemic, resulting in a decrease to cash from operations. For information regarding Ameren Illinois’ suspension and subsequent reinstatement of customer disconnections and late fee charges for nonpayment and Ameren Missouri’s accounting authority orders related to the COVID-19 pandemic, see Note 2 – Rate and Regulatory Matters below.
Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated, except as disclosed in Note 13 – Related-party Transactions. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Our customer rates are regulated by the MoPSC, the ICC, and the FERC. We defer certain costs as assets pursuant to actions of rate regulators or because of expectations that we will be able to recover such costs in future rates charged to customers. We also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on our regulatory frameworks, regulatory recovery mechanisms, and regulatory assets and liabilities recorded at December 31, 2021 and 2020.
We continually assess the recoverability of our respective regulatory assets. Regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that reductions in customers’ rates or refunds to customers related to regulatory liabilities are no longer probable, the amounts are credited to earnings.
Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents include short-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash. See Note 15 – Supplemental Information for a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has bad debt riders that adjust rates for net write-offs of customer accounts receivable above or below those being collected in rates. In 2020, the rider for electric distribution allowed for recovery of bad debt expense recognized under GAAP.
Inventories
Inventories are recorded at the lower of weighted-average cost or net realizable value. Inventories are capitalized when purchased and then expensed as consumed or capitalized as property, plant, and equipment when installed, as appropriate. See Note 15 – Supplemental Information for the components of inventories.
Property, Plant, and Equipment, Net
We capitalize the cost of additions to, and betterments of, units of property, plant, and equipment. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures are expensed as incurred. Beginning in 2020, maintenance expenses related to scheduled Callaway nuclear refueling and maintenance outages, which were previously expensed as incurred, are deferred and amortized over the number of expected months until the completion of the next refueling outage, which historically has been approximately 18 months. When units of depreciable property are retired, the original costs, and the associated removal cost, net of salvage, are charged to accumulated depreciation. If environmental expenditures are related to assets currently in use, as in the case of the installation of pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset. See Asset Retirement Obligations section below and Note 3 – Property, Plant, and Equipment, Net for additional information.
Ameren Missouri’s cost of nuclear fuel is capitalized as a part of “Property, Plant, and Equipment, Net” on the balance sheet and then amortized to “Operating Expenses – Fuel” in the statement of income on a unit-of-production basis.
Plant to be Abandoned, Net
When it becomes probable an asset will be retired significantly in advance of its previously expected useful life and in the near term, the Ameren Companies must assess the probability of full recovery of the remaining net book value of the asset to be abandoned. We recognize a loss on abandonment when it becomes probable that all or part of the cost of an asset, including a return at the applicable WACC, will be disallowed from recovery either through customer rates or through the issuance of securitized utility tariff bonds and such amount is reasonably estimable. An abandonment loss, if any, would equal the difference between the remaining net book value of the asset and the present value of the expected future cash flows. If the asset is still in service, the net book value is classified as plant to be abandoned, net,
within “Property, Plant, and Equipment, Net” on the balance sheet. The net book value will be classified as a regulatory asset on the balance sheet when the asset is no longer in service or as required by a rate order.
In relation to the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies, in December 2021, Ameren Missouri filed a motion with the United States District Court for the Eastern District of Missouri to modify a previously issued remedy order to allow the retirement of the Rush Island Energy Center in lieu of installing a flue gas desulfurization system. As of December 31, 2021, Ameren and Ameren Missouri determined that the Rush Island Energy Center met the criteria to be considered probable of abandonment and have classified its remaining net book value as plant to be abandoned, net, within “Property, Plant, and Equipment, Net” on Ameren’s and Ameren Missouri’s balance sheets. See Note 3 – Property, Plant, and Equipment, Net for our plant to be abandoned balance as of December 31, 2021. Ameren Missouri is currently allowed a full recovery of and a full return on its investment in Rush Island Energy Center and has concluded that no abandonment loss was required as of December 31, 2021. As part of the assessment of any potential future abandonment loss, consideration will be given to rate and securitization orders issued by the MoPSC to Ameren Missouri and to orders issued to other Missouri utilities with similar facts.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The composite rates include a provision for the estimated removal cost of property, plant, and equipment retired from service, net of salvage. The provision for depreciation for the Ameren Companies in 2021, 2020, and 2019 ranged from 3% to 4% of the average depreciable cost. See Note 3 – Property, Plant, and Equipment, Net for additional information on estimated depreciable lives.
Allowance for Funds Used During Construction
As a part of “Property, Plant, and Equipment, Net” on the balance sheet, we capitalize allowance for funds used during construction, which is the cost of borrowed funds and the cost of equity funds (preferred and common shareholders’ equity) applicable to eligible rate-regulated construction work in progress, in accordance with the utility industry’s accounting practice and GAAP. The amount of allowance for funds used during construction is calculated using a FERC-prescribed formula based on a rate, which incorporates the average cost of short-term debt, the average cost of long-term debt, and the cost of equity funds. The portion attributable to borrowed funds is recorded as a reduction of “Interest Charges” on the statements of income. The portion attributable to equity funds is recorded within “Other Income, Net” on the statements of income. This accounting practice offsets the effect on earnings of the cost of financing during construction. See Note 15 – Supplemental Information for the amount of allowance for funds used during construction capitalized and the average rate applied to eligible construction work in progress.
Allowance for funds used during construction does not represent a current source of cash funds. Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates.
Goodwill
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Ameren and Ameren Illinois had goodwill of $411 million at December 31, 2021 and 2020. Ameren has four reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois has three reporting units: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission had goodwill of $238 million, $80 million, and $93 million, respectively, at December 31, 2021 and 2020. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 2021 and 2020.
Ameren and Ameren Illinois evaluate goodwill for impairment in each of their reporting units as of October 31 each year, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of their reporting units below their carrying amounts. To determine whether the fair value of a reporting unit is more likely than not greater than its carrying amount, Ameren and Ameren Illinois elect to perform either a qualitative assessment or to bypass the qualitative assessment and perform a quantitative test.
Ameren and Ameren Illinois elected to perform a qualitative assessment for their annual goodwill impairment test conducted as of October 31, 2021. As part of this qualitative assessment, Ameren and Ameren Illinois evaluated, among other things, macroeconomic conditions, industry and market considerations such as observable industry market multiples, regulatory frameworks, cost factors, overall financial performance, and entity-specific events. The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was
more likely than not that the fair value of each reporting unit exceeded its carrying value as of October 31, 2021, resulting in no impairment of Ameren’s or Ameren Illinois’ goodwill.
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets to the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount by which the carrying value exceeds the estimated fair value of the assets. In the period in which we determine that an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its estimated fair value less cost to sell. We did not identify any events or changes in circumstances that indicated that the carrying value of long-lived assets may not be recoverable in 2021, 2020 or 2019.
Variable Interest Entities
As of December 31, 2021 and 2020, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, primarily to advance clean and resilient energy technologies, totaling $56 million and $37 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Any earnings or losses related to these investments are included in “Other Income, Net” on Ameren’s consolidated statement of income and comprehensive income. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of December 31, 2021, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $56 million plus associated outstanding funding commitments of $28 million.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. See Note 14 – Commitments and Contingencies for additional information on liabilities for environmental costs.
Asset Retirement Obligations and Removal Costs
We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs for accretion and changes in the estimated fair values of the obligations, with a corresponding increase or decrease in the asset book value for the fair value changes. Asset book values, reflected within “Property, Plant, and Equipment, Net” on the balance sheet, are depreciated over the remaining useful life of the related asset. Due to regulatory recovery, that depreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $14 million, $28 million, and $18 million for the years ended December 31, 2021, 2020, and 2019, respectively, which was deferred as a reduction to the net regulatory liability. The net regulatory liability also reflects a deferral for the nuclear decommissioning trust fund balance for the Callaway Energy Center. The depreciation deferred to the regulatory asset at Ameren Illinois was immaterial in each respective period. Uncertainties as to the probability, timing, or amount of cash expenditures associated with AROs affect our estimates of fair value. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with decommissioning of Ameren Missouri’s Callaway and wind renewable energy centers, certain Ameren Missouri solar energy centers, CCR facilities, and river structures at certain energy centers used for unloading coal and circulating water systems. Additionally, Ameren, Ameren Missouri, and Ameren Illinois have recorded AROs for retirement costs associated with asbestos removal and the disposal of certain transformers. See Note 15 – Supplemental Information for a reconciliation of the beginning and ending carrying amounts of AROs.
Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment retired from service, net of salvage, represent a cost of removal regulatory liability. See the cost of removal regulatory liability balance in Note 2 – Rate and Regulatory Matters.
Company-owned Life Insurance
Ameren and Ameren Illinois have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of December 31, 2021, the cash surrender value of company-owned life insurance at Ameren and Ameren Illinois was $278 million (December 31, 2020 – $272 million) and $117 million (December 31, 2020 – $115 million), respectively, while total borrowings against the policies were $109 million (December 31, 2020 – $107 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance
sheets. The net cash surrender value of Ameren’s company-owned life insurance is affected by the investment performance of a separate account in which Ameren holds a beneficial interest.
Operating Revenues
We record revenues from contracts with customers for various electric and natural gas services, which primarily consist of retail distribution, electric transmission, and off-system arrangements. When more than one performance obligation exists in a contract, the consideration under the contract is allocated to the performance obligations based on the relative standalone selling price.
Electric and natural gas retail distribution revenues are earned when the commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service provided but unbilled at the end of each accounting period. Electric transmission revenues are earned as electric transmission services are provided. Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the sale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. Capacity and ancillary service revenues are earned as services are provided.
Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers are equal to the amounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the end of each accounting period. Customers are billed at least monthly, and payments are due less than one month after goods and/or services are provided. See Note 16 – Segment Information for disaggregated revenue information.
For certain regulatory recovery mechanisms that are alternative revenue programs rather than revenues from contracts with customers, we recognize revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected from customers within two years from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, the MEEIA, the VBA, and the WNAR. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to alternative revenue program revenues.
As of December 31, 2021 and 2020, our remaining performance obligations were immaterial. The Ameren Companies elected not to disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, Ameren Missouri, and Ameren Illinois using settlement information provided by the MISO. Ameren Missouri records these purchase and sale transactions on a net hourly position. Ameren Missouri records net purchases in a single hour in “Operating Expenses – Purchased power” and net sales in a single hour in “Operating Revenues – Electric” in its statement of income. Ameren Illinois records net purchases in “Operating Expenses – Purchased power” in its statement of income to reflect all of its MISO transactions relating to the procurement of power for its customers. On occasion, Ameren Missouri’s and Ameren Illinois’ prior-period transactions will be resettled outside the routine settlement process because of a change in the MISO’s tariff or a material interpretation thereof. In these cases, Ameren Missouri and Ameren Illinois recognize revenues and expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated. There were no material MISO resettlements in 2021, 2020, or 2019.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date based on the fair value of the award, net of an assumed forfeiture rate. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite vesting period. To the extent that actual forfeitures differ from estimated forfeitures, such differences are accounted for as a cumulative adjustment to compensation expense and recorded in the period that estimates are revised. Compensation cost is ultimately recognized only for awards for which the requisite service was provided. See Note 11 – Stock-based Compensation for additional information.
Unamortized Debt Discounts, Premiums, and Issuance Costs
Long-term debt discounts, premiums, and issuance costs are amortized over the lives of the related issuances. Credit agreement fees are amortized over the term of the agreement.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We expect that regulators will reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in certain deferred tax liabilities that were recorded because of decreases in the statutory rate have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery through future customer rates of tax benefits related to the equity component of allowance for funds used during construction, as well as the effects of tax rate increases. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes is recorded as a regulatory asset or liability on the balance sheet and will be collected from, or refunded to, customers. For deferred tax balances not included in rate base, the revaluation of deferred taxes is recorded as an adjustment to income tax expense on the income statement. See Note 12 – Income Taxes for further information regarding the revaluation of deferred taxes related to Missouri state corporate income tax rate changes.
Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren (parent) that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax using a stand-alone calculation, which is similar to what would be owed or refunded had the party been separately subject to tax without considering the impact of consolidation. Any net benefit attributable to Ameren (parent) is reallocated to the other parties. This reallocation is treated as a capital contribution to the party receiving the benefit. See Note 13 – Related-party Transactions for information regarding capital contributions under the tax allocation agreement.
NOTE 2 – 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 service business | Ameren Illinois’ and ATXI’s electric transmission business |
| 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 •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 | •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 •PGA •VBA •Energy-efficiency program costs •Certain environmental costs •Bad debt write-offs •Invested capital taxes | •Revenue requirement reconciliation adjustment |
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 pension and postretirement benefit cost tracker, an uncertain income tax position tracker, a tracker on certain excess deferred income taxes, and a renewable energy standard cost tracker. 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 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. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC, with all approved PISA deferrals added to rate base prospectively and 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. Ameren Missouri defers its cost of debt relating to PISA eligible investments as an offset to interest charges with the difference between the applicable WACC and its cost of debt recognized in revenues when recovery of such deferrals is reflected in customer rates. 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. Ameren Missouri did not incur a penalty related to the rate cap in 2021. Both the rate increase limitation and the PISA are effective through December 2023. Missouri law provides for the ability to use the PISA, if Ameren Missouri requests and receives MoPSC approval for extension, through December 2028.
The RESRAM permits Ameren Missouri to recover or refund, through customer rates, the difference between the cost of compliance, net of renewable tax credits, with Missouri’s renewable energy standard and the amount set in base rates. Effective February 28, 2022, all off-system sales from the High Prairie Renewable and Atchison Renewable energy centers will be 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.
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 will allow 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 will be deferred as a regulatory asset or liability. WNAR regulatory assets will earn carrying costs at short-term interest rates. The deferred amount will either be billed or refunded to residential customers in a subsequent period. The WNAR was approved by the December 2021 MoPSC natural gas rate order discussed below, and will replace the DCA effective February 28, 2022.
Illinois
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 an order issued by the ICC in March 2021, Ameren Illinois expects to use the current IEIMA formula framework to establish annual customer rates effective through 2023 and reconcile the related revenue requirements, and anticipates filing an MYRP by mid-January 2023, with rates effective beginning in 2024. 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 IETL, the MYRP, and the March 2021 ICC order. 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.
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 allowed ROE for electric distribution service may be decreased for penalties up to 38 basis points in 2022 and up to 10 basis points in 2023 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 2021, 2020, and 2019, 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 mechanisms is subject to ICC prudence reviews.
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.
Federal
The FERC regulates rates and other matters for Ameren Illinois’ transmission business and ATXI, as well as for Ameren Missouri. See 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
December 2021 MoPSC Electric Rate Order
In December 2021, the MoPSC issued an order in Ameren Missouri’s 2021 electric service regulatory rate review, approving nonunanimous stipulations and agreements. The order will result 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 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 costs that the MoPSC previously authorized in earlier electric rate orders. 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 $140 million and other operating and maintenance expenses of $40 million. As a result of the order, all off-system sales resulting from the High Prairie Renewable and Atchison Renewable energy centers will be included in the RESRAM beginning February 28, 2022. Prior to this change, 95% of these sales were included in the FAC and 5% were included in the RESRAM. The order also establishes a five-year recovery period for $61 million of certain costs associated with the Meramec Energy Center, which is expected to be retired in 2022. The new rates, base level of expenses, and amortizations will become effective on February 28, 2022.
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 will include 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. The MoPSC staff is under no deadline to complete this review. Ameren Missouri is unable to predict the ultimate resolution of this matter; however, such resolution could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.
December 2021 MoPSC Natural Gas Rate Order
In December 2021, the MoPSC issued an order in Ameren Missouri’s 2021 natural gas delivery service regulatory rate review, approving nonunanimous stipulations and agreements. The order will result in an increase of $5 million to Ameren Missouri’s annual revenue requirement for natural gas delivery service. The approved revenue requirement is based on a rate base of $313 million and infrastructure investments as of September 30, 2021. The order did not specify an ROE or a capital structure. The order provides for the continued use of the PGA and trackers for pension and postretirement benefits and certain excess deferred income taxes that the MoPSC previously authorized in earlier natural gas rate orders. The order also authorizes the use of the WNAR, which replaces the DCA and is discussed above. The new rates will become effective on February 28, 2022.
Accounting Authority Orders Related to COVID-19 Pandemic Costs
In March 2021, the MoPSC issued orders approving nonunanimous stipulation and agreements related to Ameren Missouri’s electric and natural gas service accounting authority order requests. The orders allowed Ameren Missouri to accumulate $9 million of certain costs incurred related to the COVID-19 pandemic, net of cost savings, as well as forgone customer late fee and reconnection fee revenues from March 2020 to March 2021. The accumulated costs and forgone customer late fee and reconnection fee revenues were approved for recovery in the MoPSC’s December 2021 electric and natural gas rate orders discussed above. In March 2021, Ameren Missouri deferred other operations and maintenance expenses of $5 million as a regulatory asset related to the accounting authority orders and will amortize the balance over a five-year period once new rates become effective on February 28, 2022. Ameren Missouri will recognize the remaining $4 million associated with forgone customer late fee and reconnection fee revenue when billed to customers over the five-year period beginning on February 28, 2022.
MEEIA
In September 2021, the MoPSC issued an order approving Ameren Missouri’s energy savings results for the second year of the MEEIA 2019 program. As a result of this order and MoPSC orders issued in September 2017, October 2018, January 2019, September 2019, and August 2020, and in accordance with revenue recognition guidance, Ameren Missouri recognized revenues of $9 million, $6 million, and $37 million in 2021, 2020, and 2019 respectively.
In October 2021, the MoPSC issued an order approving Ameren Missouri’s request to implement the 2023 program year of its MEEIA 2019 program. The order established performance incentives that would provide Ameren Missouri an opportunity to earn additional revenues, including $13 million if Ameren Missouri achieves certain energy-efficiency goals during the 2023 program year. Ameren Missouri intends to invest $75 million in energy-efficiency programs during the 2023 program year.
Extension of PGA Recovery
In October 2021, the MoPSC issued an order allowing Ameren Missouri to extend the collection period for the cumulative PGA under-recovery as of August 2021, which includes the February 2021 under-recovery of $53 million, from 12 months to 36 months beginning November 2021, to lessen the impact on customer rates. Similar to other deferrals under the PGA, the deferral associated with the February 2021 under-recovery earns carrying costs at short-term interest rates.
Illinois
IETL
The IETL was enacted in September 2021. The IETL resulted in changes to the regulatory framework applicable to Ameren Illinois’ electric distribution business by giving Ameren Illinois the option to file an MYRP with the ICC by mid-January 2023, with rates effective beginning in 2024, among other things. Ameren Illinois has the option to file for an MYRP every four years. Subject to a constructive outcome regarding the ICC’s determination of performance metrics, Ameren Illinois anticipates filing an MYRP for rates effective beginning in 2024. If it does not file by mid-January 2023, its next opportunity to file an MYRP would be for rates effective beginning in 2028. Ameren Illinois expects to continue to use the current IEIMA performance-based formula ratemaking framework to establish annual customer rates effective through 2023 and reconcile the related revenue requirements. In order to utilize the IEIMA reconciliation, Ameren Illinois must file either a traditional regulatory rate review or an MYRP pursuant to the IETL by mid-January 2023.
Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of a four-year period. The base rates for a particular calendar year would be based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ forecasted average annual rate base using a forecasted capital structure, with a common equity ratio of up to 50% being deemed prudent and reasonable by law and a higher equity ratio requiring specific ICC approval. The ROE determined by the ICC is applicable to each calendar year of the four-year period. Under a traditional regulatory rate review, the revenue requirement may be based on a future test year and would include an ROE determined by the ICC. Ameren Illinois’ existing riders will remain effective whether it elects to file an MYRP or a traditional regulatory rate review. Additionally, electric distribution service revenues would continue to be decoupled from sales volumes under either election.
The MYRP would also allow Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to a reconciliation cap, which provides that the actual revenue requirement does not exceed 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 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 regulatory assets. The reconciliation cap would also exclude 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. 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. Additionally, the ICC-determined ROE in the MYRP would be subject to annual adjustments during the four-year period based on certain performance metrics relating to delivery system reliability, supplier diversity, affordability of customer delivery service cost, customer service performance, timeliness of response to customer requests for interconnection of distributed energy resources, and reductions in peak load due to demand response programs, with aggregate symmetrical performance-based ROE incentives and penalties ranging from 20 to 60 basis points annually. In January 2022, Ameren Illinois filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties. The ICC is required to issue an order on this matter by September 30, 2022. Excluding potential phase-in of the initial rate increase discussed below, 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 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 and 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 recognizes revenues when amounts are expected to be collected from customers within two years from the end of an applicable year.
The IETL contains other provisions in addition to the ratemaking impacts discussed 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. Additionally, the law increases the existing customer surcharge for renewable energy resources, which funds IPA renewable energy credit procurement events. As a result, Ameren Illinois expects additional annual revenues of approximately $100 million to be collected, beginning in February 2022, under the rider for renewable energy credit compliance. It also establishes 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 will be subsidized through customer surcharges collected by electric utilities operating in the state, including Ameren Illinois, and will be remitted in the month following collection to an Illinois state agency. Ameren Illinois expects to collect up to $25 million annually related to this fund, beginning in January 2022. The IETL also requires Ameren Illinois to file a multi-year integrated grid plan with the ICC to ensure electric distribution infrastructure investments align with the state of Illinois’ renewable energy, climate, and environmental goals, and to support grid modernization, clean energy, and energy efficiency, while providing electric distribution service to customers at affordable rates, among other things. The first multi-year
integrated grid plan is required to be filed by mid-January 2023, with the next filing required by mid-January 2026, and every four years thereafter.
See Note 14 – Commitments and Contingencies for additional information on emission standards established by the IETL that will limit the operations of Ameren Missouri’s natural gas-fired energy centers located in the state of Illinois.
Electric Distribution Service Rate Reconciliation Tariff
In March 2021, the ICC issued an order approving Ameren Illinois’ requested tariff to reconcile its electric distribution service revenue requirement once Ameren Illinois ceases to update customer rates under performance-based formula ratemaking. The last update under such ratemaking is anticipated to be for 2023 customer rates. The tariff would allow Ameren Illinois to reconcile its revenue requirement for customer rates established for 2022 and 2023. To utilize the reconciliation, Ameren Illinois is required to file a request to update its electric distribution service rates through either a traditional regulatory rate review, which may be based on a future test year and would reflect a proposed ROE subject to ICC approval, or through the filing of an MYRP, which Ameren Illinois expects to file for rates effective beginning in 2024 pursuant to the IETL as described above. The rate update request would need to be filed by mid-January 2023. Pursuant to the order, Ameren Illinois’ 2022 and 2023 revenues would 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.
Electric Distribution Service Rates Under IEIMA
In December 2021, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $58 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2022. This order reflected an increase to the annual performance-based formula rate based on 2020 actual recoverable costs and expected net plant additions for 2021, an increase to include the 2020 revenue requirement reconciliation adjustment including a capital structure composed of 51% common equity, and an increase for the conclusion of the 2019 revenue requirement reconciliation adjustment, which was fully refunded to customers in 2021, consistent with the ICC’s December 2020 annual update filing order.
Electric Customer Energy-Efficiency Investments
In December 2021, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $61 million beginning in January 2022, which represents an increase of $10 million from 2021 rates.
In July 2021, the ICC issued an order approving Ameren Illinois’ energy-efficiency plan that includes annual investments in electric energy-efficiency programs of approximately $100 million per year from 2022 through 2025. Pursuant to the IETL, the planned annual investments in electric energy-efficiency programs will increase to approximately $120 million. Ameren Illinois expects to file a revised energy-efficiency plan with the ICC by early March 2022 to reflect the expected increased level of annual investments. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan 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.
QIP Reconciliation Hearings
In March 2021, the ICC issued an order approving Ameren Illinois’ QIP reconciliation for 2018. The ICC also found that Ameren Illinois’ natural gas capital investments recovered under the QIP during 2018 were accurate and prudent. The ICC order effectively dismissed the Illinois Attorney General’s office challenge with respect to 2018 capital investments.
In March 2020, 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 2019. In August 2021, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2019, alleging that the ICC should disallow approximately $70 million in natural gas capital investments as improper and imprudent, providing a potential over-recovery of approximately $3 million in 2019. In August and December 2021, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2019. Ameren Illinois’ 2019 QIP rate recovery request under review by the ICC is within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding.
Service Disconnection Moratorium
From March 2020 through March 2021, the ICC limited disconnection activities and late fees for customer nonpayment to varying degrees based on customer class. In March 2021, the ICC issued an order allowing Ameren Illinois to resume disconnection activities for all residential customers through a phased-in approach, which began in April 2021 for customers with the largest past due balances and in June 2021 for all remaining residential customers. The March 2021 order also required Ameren Illinois to offer deferred payment arrangements extending to 18 months to all residential customers through June 2021. In addition, the order requires Ameren Illinois to extend the financial assistance program established by a June 2020 ICC order through 2021. Ameren Illinois is allowed to recover up to $4 million in costs incurred during 2021 related to this financial assistance program. These costs will be deferred as regulatory assets and the portion associated with Ameren Illinois’ electric distribution business will be recovered through its bad debt rider and the portion associated with its natural gas distribution business will be recovered through a special purpose rider.
Federal
Transmission Formula Rate Revisions
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. In June 2020, Ameren Missouri, Ameren Illinois, and ATXI filed requests for rehearing arguing, among other things, the revisions should be applied retrospectively to include the period January 1, 2019, to June 1, 2020, and that the FERC should not require refunds for periods prior to 2019. In July 2020, the FERC denied the rehearing requests without addressing the issues raised. In July 2020, Ameren Missouri, Ameren Illinois, and ATXI filed an appeal of the July 2020 rehearing denials to the United States Court of Appeals for the District of Columbia Circuit, which is under no deadline to address the appeal. In October 2020, the FERC issued an order reaffirming its May 2020 order and denying the arguments raised in the rehearing requests filed by Ameren Missouri, Ameren Illinois, and ATXI. In November 2020, Ameren Missouri, Ameren Illinois, and ATXI filed an appeal of the October 2020 order to the United States Court of Appeals for the District of Columbia Circuit. The court of appeals is under no deadline to address either appeal. Regardless of the outcome of the appeal, the impacts of the May 2020 and October 2020 orders were immaterial to Ameren’s, Ameren Missouri’s, or Ameren Illinois’ results of operations, financial position, or liquidity.
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. In April 2021, Ameren Illinois filed a request for rehearing with the FERC regarding its March 2021 order. In May 2021, the FERC denied the rehearing request without addressing the issues raised. In July 2021, Ameren Illinois filed an appeal of the March 2021 order and the May 2021 rehearing denial to the United States Court of Appeals for the District of Columbia Circuit. In August 2021, the United States Court of Appeals for the District of Columbia Circuit granted a motion to consolidate the July 2021, July 2020, and November 2020 appeals. In November 2021, the FERC issued an order reaffirming its March 2021 order and denying the arguments raised in the rehearing request filed by Ameren Illinois. In December 2021, Ameren Illinois filed an appeal of the November 2021 order to the United States Court of Appeals for the District of Columbia Circuit. In December 2021, Ameren Illinois filed a motion to consolidate the December 2021 appeal with the July 2020, November 2020, and July 2021 appeals. In January 2022, the United States Court of Appeals for the District of Columbia issued an order granting the motion to consolidate the appeals. The court is under no deadline to address the appeal.
FERC Complaint Cases
In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued an order in the November 2013 complaint case, which lowered the allowed base ROE to 10.32%, or a 10.82% total allowed ROE with the inclusion of a 50 basis point incentive adder for participation in an RTO, that was effective from late September 2016 forward. The September 2016 order also required refunds for the period November 2013 to February 2015, which were paid in 2017. In November 2019, the FERC issued an order addressing the November 2013 complaint case, which set the allowed base ROE at 9.88%, superseding the 10.32% previously ordered, and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. In December 2019, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed requests for rehearing with the FERC. In May 2020, the FERC issued an order addressing the requests for rehearing, which set the allowed base ROE at 10.02%, superseding the 9.88% previously ordered, and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. In June 2020, various parties filed requests for rehearing with the FERC, challenging the new ROE methodology established by the May 2020 order. In July 2020, the FERC denied the rehearing requests without addressing the issues raised, and indicated it will address the requests for rehearing in a future order. Also, in July 2020, Ameren Missouri, Ameren Illinois, and ATXI filed
an appeal of the May 2020 order to the United States Court of Appeals for the District of Columbia Circuit challenging the refunds required for the period from September 2016 to May 2020. The court is under no deadline to address the appeal.
As of December 31, 2021, Ameren and Ameren Illinois had substantially paid the refunds, including interest, associated with the allowed base ROE set by the May 2020 order in the November 2013 complaint case. The increase in the FERC-allowed base ROE resulting from the May 2020 order was not material to Ameren Missouri’s results of operations, financial position, or liquidity.
Regulatory Assets and Liabilities
The following table presents our regulatory assets and regulatory liabilities at December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | | 2020 |
| | Ameren
Missouri | | Ameren
Illinois | | Ameren | | | Ameren
Missouri | | Ameren
Illinois | | Ameren |
| Regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a) | | $ | 47 | | | $ | — | | | $ | 47 | | | | $ | 48 | | | $ | — | | | $ | 48 | |
| | | | | | | | | | | | | |
Under-recovered PGA(b)(c) | | 49 | | | 114 | | | 163 | | | | — | | | 2 | | | 2 | |
MTM derivative losses(d) | | 77 | | | 125 | | | 202 | | | | 21 | | | 200 | | | 221 | |
| | | | | | | | | | | | | |
IEIMA revenue requirement reconciliation adjustment(e)(f) | | — | | | 42 | | | 42 | | | | — | | | — | | | — | |
FERC revenue requirement reconciliation adjustment(g) | | — | | | 18 | | | 43 | | | | — | | | 28 | | | 50 | |
Under-recovered VBA(h) | | — | | | 17 | | | 17 | | | | — | | | 11 | | | 11 | |
| | | | | | | | | | | | | |
Income taxes(i) | | 115 | | | 69 | | | 185 | | | | 117 | | | 65 | | | 183 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Bad debt rider(j) | | — | | | 8 | | | 8 | | | | — | | | 11 | | | 11 | |
| | | | | | | | | | | | | |
Callaway refueling and maintenance outage costs(k) | | 14 | | | — | | | 14 | | | | 39 | | | — | | | 39 | |
Unamortized loss on reacquired debt(l) | | 50 | | | 13 | | | 63 | | | | 52 | | | 22 | | | 74 | |
Environmental cost riders(m) | | — | | | 70 | | | 70 | | | | — | | | 93 | | | 93 | |
Storm costs(f)(n) | | — | | | 17 | | | 17 | | | | — | | | 7 | | | 7 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Allowance for funds used during construction for pollution control equipment(f)(o) | | 13 | | | — | | | 13 | | | | 15 | | | — | | | 15 | |
Customer generation rebate program(f)(p) | | — | | | 47 | | | 47 | | | | — | | | 17 | | | 17 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
PISA(f)(q) | | 244 | | | — | | | 244 | | | | 78 | | | — | | | 78 | |
| | | | | | | | | | | | | |
FEJA energy-efficiency rider(f)(r) | | — | | | 350 | | | 350 | | | | — | | | 283 | | | 283 | |
| Other | | 41 | | | 42 | | | 83 | | | | 37 | | | 40 | | | 77 | |
| Total regulatory assets | | $ | 650 | | | $ | 932 | | | $ | 1,608 | | | | $ | 407 | | | $ | 779 | | | $ | 1,209 | |
| Less: current regulatory assets | | (127) | | | (180) | | | (319) | | | | (60) | | | (37) | | | (109) | |
| Noncurrent regulatory assets | | $ | 523 | | | $ | 752 | | | $ | 1,289 | | | | $ | 347 | | | $ | 742 | | | $ | 1,100 | |
| Regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(a) | | $ | 19 | | | $ | — | | | $ | 19 | | | | $ | 10 | | | $ | — | | | $ | 10 | |
Over-recovered Illinois electric power costs(b) | | — | | | 13 | | | 13 | | | | — | | | 15 | | | 15 | |
Over-recovered PGA(b) | | — | | | 1 | | | 1 | | | | 7 | | | 15 | | | 22 | |
| | | | | | | | | | | | | |
MTM derivative gains(d) | | 50 | | | 41 | | | 91 | | | | 11 | | | 10 | | | 21 | |
| | | | | | | | | | | | | |
IEIMA revenue requirement reconciliation adjustment(e) | | — | | | — | | | — | | | | — | | | 22 | | | 22 | |
FERC revenue requirement reconciliation adjustment(g) | | — | | | 2 | | | 4 | | | | — | | | 21 | | | 21 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Income taxes(i) | | 1,208 | | | 770 | | | 2,066 | | | | 1,317 | | | 790 | | | 2,192 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Cost of removal(s) | | 1,028 | | | 929 | | | 1,988 | | | | 1,027 | | | 873 | | | 1,923 | |
AROs(t) | | 603 | | | — | | | 603 | | | | 436 | | | — | | | 436 | |
| | | | | | | | | | | | | |
Bad debt rider(j) | | — | | | 19 | | | 19 | | | | — | | | 5 | | | 5 | |
Pension and postretirement benefit costs(u) | | 399 | | | 392 | | | 791 | | | | 198 | | | 177 | | | 375 | |
Pension and postretirement benefit costs tracker(v) | | 28 | | | — | | | 28 | | | | 55 | | | — | | | 55 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Renewable energy credits and zero emission credits(w) | | — | | | 246 | | | 246 | | | | — | | | 200 | | | 200 | |
| | | | | | | | | | | | | |
RESRAM(x) | | 19 | | | — | | | 19 | | | | 2 | | | — | | | 2 | |
Excess income taxes collected in 2018(y) | | 25 | | | — | | | 25 | | | | 45 | | | — | | | 45 | |
| Other | | 32 | | | 15 | | | 48 | | | | 28 | | | 23 | | | 59 | |
| Total regulatory liabilities | | $ | 3,411 | | | $ | 2,428 | | | $ | 5,961 | | | | $ | 3,136 | | | $ | 2,151 | | | $ | 5,403 | |
| Less: current regulatory liabilities | | (57) | | | (54) | | | (113) | | | | (26) | | | (88) | | | $ | (121) | |
| Noncurrent regulatory liabilities | | $ | 3,354 | | | $ | 2,374 | | | $ | 5,848 | | | | $ | 3,110 | | | $ | 2,063 | | | $ | 5,282 | |
(a)Under-recovered or over-recovered fuel costs to be recovered or refunded through the FAC. Specific accumulation periods aggregate the under-recovered or over-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from, or refund to, 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 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 is collecting its February 2021 PGA under-recovery over 18 months beginning April 2021, but the collection of the remaining balance may be extended at Ameren Illinois’ election to lessen the impact on customer rates.
(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 performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recovery or over-recovery will be recovered from, or refunded to, customers with interest 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 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 35, 28, and 42 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. Pursuant to a June 2020 ICC order, Ameren Illinois’ electric distribution bad debt rider provided for the recovery of bad debt expense in 2020. The under-recovery or over-recovery for each year is recovered from, or refunded to, customers over a twelve-month period beginning June 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 2018, 2020, and 2021 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 through 2028.
(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 are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.
(r)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 5 to 13 years.
(s)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment retired from service, net of salvage.
(t)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,159 million and $982 million at December 31, 2021 and 2020, respectively), net of recoverable removal costs for AROs ($556 million and $546 million at December 31, 2021 and 2020, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
(u)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.
(v)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. The weighted-average remaining amortization period is five years.
(w)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.
(x)Over-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 February the following year.
(y)The excess amount collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability is being amortized over a three-year period, which began in April 2020.
NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET
The following table presents components of “Property, plant, and equipment, net” at December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren
Missouri | | Ameren
Illinois | | Other | | Ameren |
| 2021 | | | | | | | | |
Property, plant, and equipment at original cost:(a) | | | | | | | | |
| Electric generation: | | | | | | | | |
Coal(b)(c) | | $ | 3,955 | | | $ | — | | | $ | — | | | $ | 3,955 | |
| Natural gas | | 1,105 | | | — | | | — | | | 1,105 | |
| Nuclear | | 5,615 | | | — | | | — | | | 5,615 | |
Renewable(d) | | 1,889 | | | — | | | — | | | 1,889 | |
| Electric distribution | | 7,286 | | | 7,017 | | | — | | | 14,303 | |
| Electric transmission | | 1,628 | | | 4,105 | | | 1,800 | | | 7,533 | |
| Natural gas | | 607 | | | 3,586 | | | — | | | 4,193 | |
Other(e) | | 1,584 | | | 1,183 | | | 242 | | | 3,009 | |
| | 23,669 | | | 15,891 | | | 2,042 | | | 41,602 | |
| Less: Accumulated depreciation and amortization | | 9,784 | | | 4,100 | | | 330 | | | 14,214 | |
| | 13,885 | | | 11,791 | | | 1,712 | | | 27,388 | |
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 133 | | | — | | | — | | | 133 | |
| Other | | 674 | | | 432 | | | 30 | | | 1,136 | |
Plant to be abandoned, net(f) | | 604 | | | — | | | — | | | 604 | |
| Property, plant, and equipment, net | | $ | 15,296 | | | $ | 12,223 | | | $ | 1,742 | | | $ | 29,261 | |
| 2020 | | | | | | | | |
Property, plant, and equipment at original cost:(a) | | | | | | | | |
| Electric generation: | | | | | | | | |
Coal(b)(c) | | $ | 4,875 | | | $ | — | | | $ | — | | | $ | 4,875 | |
| Natural gas | | 1,097 | | | — | | | — | | | 1,097 | |
| Nuclear | | 5,608 | | | — | | | — | | | 5,608 | |
Renewable(d) | | 1,301 | | | — | | | — | | | 1,301 | |
| Electric distribution | | 6,784 | | | 6,649 | | | — | | | 13,433 | |
| Electric transmission | | 1,482 | | | 3,575 | | | 1,774 | | | 6,831 | |
| Natural gas | | 561 | | | 3,308 | | | — | | | 3,869 | |
Other(e) | | 1,390 | | | 1,070 | | | 245 | | | 2,705 | |
| | 23,098 | | | 14,602 | | | 2,019 | | | 39,719 | |
| Less: Accumulated depreciation and amortization | | 9,689 | | | 3,780 | | | 304 | | | 13,773 | |
| | 13,409 | | | 10,822 | | | 1,715 | | | 25,946 | |
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 75 | | | — | | | — | | | 75 | |
| Other | | 395 | | | 379 | | | 12 | | | 786 | |
| Property, plant, and equipment, net | | $ | 13,879 | | | $ | 11,201 | | | $ | 1,727 | | | $ | 26,807 | |
(a)The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydroelectric generating assets, which have useful lives of up to 150 years; 20 to 80 years for electric distribution; 50 to 75 years for electric transmission; 20 to 80 years for natural gas; and 2 to 55 years for other.
(b)Includes $29 million and $36 million of oil-fired generation at December 31, 2021 and 2020, respectively.
(c)Original cost amounts include two CTs that have related financing obligations. The gross cumulative asset value of those agreements was $243 million and $240 million at December 31, 2021 and 2020, respectively. The total accumulated depreciation associated with the two CTs was $105 million and $99 million at December 31, 2021 and 2020, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.
(d)Renewable includes hydroelectric, wind, solar, and methane gas generation facilities.
(e)Other property, plant, and equipment includes assets used to support electric and natural gas services.
(f)Represents the net book value of the Rush Island Energy Center and related construction work in progress as Ameren Missouri expects to retire the energy center significantly in advance of its previously expected useful life and in the near term. See Plant to be Abandoned, Net under Note 1 – Summary of Significant Accounting Policies and NSR and Clean Air Act Litigation under Note 14 – Commitments and Contingencies for additional information on the planned accelerated retirement of the Rush Island Energy Center.
Capitalized software costs are classified within “Property, Plant, and Equipment, Net” on the balance sheet and are amortized on a straight-line basis over the expected period of benefit, ranging from 2 to 15 years. The following table presents the amortization, gross carrying value, and related accumulated amortization of capitalized software by year:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Amortization Expense | | Gross Carrying Value | | Accumulated Amortization |
| | 2021 | 2020 | 2019 | | 2021 | 2020 | | 2021 | 2020 |
| | | | | | | | | | |
| Ameren | | $ | 125 | | $ | 93 | | $ | 78 | | | $ | 1,199 | | $ | 1,021 | | | $ | (757) | | $ | (640) | |
| Ameren Missouri | | 66 | | 44 | | 30 | | | 523 | | 398 | | | (255) | | (189) | |
| Ameren Illinois | | 53 | | 45 | | 45 | | | 452 | | 397 | | | (291) | | (238) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Annual amortization expense for capitalized software placed in service as of December 31, 2021, is estimated to be as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2023 | | 2024 | | 2025 | | 2026 |
| Ameren | | $ | 135 | | | $ | 119 | | | $ | 87 | | | $ | 47 | | | $ | 21 | |
| Ameren Missouri | | 75 | | | 69 | | | 54 | | | 31 | | | 14 | |
| Ameren Illinois | | 56 | | | 47 | | | 31 | | | 14 | | | 6 | |
NOTE 4 – SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings.
Short-Term Borrowings
In December 2021, the Credit Agreements, which were scheduled to mature in December 2024, were extended and now mature in December 2025. The Credit Agreements provide $2.3 billion of credit cumulatively through maturity. The total facility size of the Missouri Credit Agreement and Illinois Credit Agreement is $1.2 billion and $1.1 billion, respectively. The maturity date may be extended by an additional one-year period upon the mutual consent of the borrowers and the lenders. Credit available under the agreements is provided by 22 international, national, and regional lenders, with no single lender providing more than $130 million of credit in aggregate.
The obligations of each borrower under the respective Credit Agreements to which it is a party are several and not joint. Except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective Credit Agreements are not guaranteed by Ameren (parent) or any other subsidiary of Ameren. The following table presents the maximum aggregate amount available to each borrower under each facility:
| | | | | | | | | | | |
| | Missouri
Credit Agreement | Illinois
Credit Agreement |
| Ameren (parent) | | $ | 900 | | $ | 500 | |
| Ameren Missouri | | 850 | | (a) |
| Ameren Illinois | | (a) | 800 | |
(a)Not applicable.
The borrowers have the option to seek additional commitments from existing or new lenders to increase the total facility size of the Credit Agreements to a maximum of $1.4 billion for the Missouri Credit Agreement and $1.3 billion for the Illinois Credit Agreement. Ameren (parent) borrowings are due and payable no later than the maturity date of the Credit Agreements. Ameren Missouri and Ameren Illinois borrowings under the applicable Credit Agreement are due and payable no later than the earlier of the maturity date or 364 days after the date of the borrowing.
The obligations of the borrowers under the Credit Agreements are unsecured. Loans are available on a revolving basis under each of the Credit Agreements. Funds borrowed may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate plus the margin applicable to the particular borrower and/or the eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower’s long-term unsecured credit ratings or, if no such ratings are in effect, the borrower’s corporate/issuer ratings then in effect. The borrowers have received commitments from the lenders to issue letters of credit up to $100 million under each of the Credit Agreements. In addition, the issuance of letters of credit is subject to the $2.3 billion overall combined facility borrowing limitations of the Credit Agreements.
The borrowers will use the proceeds from any borrowings under the Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, loan funding under the Ameren money pool arrangements, and other short-term affiliate
loan arrangements. The Missouri Credit Agreement and the Illinois Credit Agreement are available to support issuances under Ameren (parent)’s, Ameren Missouri’s and Ameren Illinois’ commercial paper programs, respectively, subject to borrowing sublimits, as well as to support issuance of letters of credit for the borrowers. As of December 31, 2021, based on commercial paper outstanding and letters of credit issued under the Credit Agreements, along with cash and cash equivalents, the net liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $1.8 billion.
The following table summarizes the activity and relevant interest rates for Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper issuances and borrowings under the Credit Agreements in the aggregate for the years ended December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren (parent) | | Ameren Missouri | | Ameren Illinois | | Ameren Consolidated | |
| 2021 | | | | | | | | | |
| Average daily amount outstanding | | $ | 387 | | | $ | 99 | | | $ | 118 | | | $ | 604 | | |
| Commercial paper issuances outstanding at period-end | | 277 | | | 165 | | | 103 | | | 545 | | |
| Weighted-average interest rate | | 0.22 | % | | 0.22 | % | | 0.21 | % | | 0.22 | % | |
Peak amount outstanding during period(a) | | $ | 650 | | | $ | 546 | | | $ | 485 | | | $ | 1,134 | | |
| Peak interest rate | | 0.38 | % | | 0.35 | % | | 0.35 | % | | 0.38 | % | |
| 2020 | | | | | | | | | |
| Average daily amount outstanding | | $ | 108 | | | $ | 109 | | | $ | 46 | | | $ | 263 | | |
| Commercial paper issuances outstanding at period-end | | 490 | | | — | | | — | | | 490 | | |
| Weighted-average interest rate | | 1.04 | % | | 1.73 | % | | 0.97 | % | | 1.31 | % | |
Peak amount outstanding during period(a) | | $ | 490 | | | $ | 573 | | | $ | 250 | | | $ | 908 | | |
| Peak interest rate | | 3.30 | % | | 5.05 | % | (b) | 3.40 | % | | 5.05 | % | (b) |
(a) The timing of peak outstanding commercial paper issuances and borrowings under the Credit Agreements varies by company. Therefore, the sum of individual company peak amounts may not equal the Ameren consolidated peak amount for the period.
(b) Ameren’s and Ameren Missouri’s peak interest rates were affected by temporary disruptions in the commercial paper market in the first quarter of 2020.
Indebtedness Provisions and Other Covenants
The information below is a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants.
The Credit Agreements contain conditions for borrowings and issuances of letters of credit. These conditions include the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation, and the absence of any notice of violation, liability, or requirement under any environmental laws that could have a material adverse effect), and obtaining required regulatory authorizations. In addition, it is a condition for any Ameren Illinois borrowing that, at the time of and after giving effect to such borrowing, Ameren Illinois not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation.
The Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur certain liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The Credit Agreements require each of Ameren, Ameren Missouri, and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of December 31, 2021, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 58%, 49%, and 45%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
The Credit Agreements contain default provisions that apply separately to each borrower. However, a default of Ameren Missouri or Ameren Illinois under the applicable credit agreement is also deemed to constitute a default of Ameren (parent) under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $100 million in the aggregate (including under the other credit agreement). However, under the default provisions of the Credit Agreements, any default of Ameren (parent) under either credit agreement that results solely from a default of Ameren Missouri or Ameren Illinois does not result in a cross-default of Ameren (parent) under the other credit agreement. Further, the Credit Agreements default provisions provide that an Ameren (parent) default under either of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.
None of the Credit Agreements or financing agreements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. The Ameren Companies were in compliance with the provisions and covenants of the Credit Agreements at December 31, 2021.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.
Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the money pool from participants. The primary sources of external funds for the utility money pool are the Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but it is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2021, was 0.17% (2020 – 0.64%).
See Note 13 – Related-party Transactions for the amount of interest income and expense from the utility money pool agreement recorded by Ameren Missouri and Ameren Illinois for the years ended December 31, 2021, 2020, and 2019.
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding, including maturities due within one year, as of December 31, 2021 and 2020:
| | | | | | | | | | | |
| 2021 | | 2020 |
| Ameren (Parent): | | | |
| | | |
2.50% Senior unsecured notes due 2024 | $ | 450 | | | $ | 450 | |
3.65% Senior unsecured notes due 2026 | 350 | | | 350 | |
1.95% Senior unsecured notes due 2027 | 500 | | | — | |
1.75% Senior unsecured notes due 2028 | 450 | | | — | |
3.50% Senior unsecured notes due 2031 | 800 | | | 800 | |
| Total long-term debt, gross | 2,550 | | | 1,600 | |
| Less: Unamortized discount and premium | (2) | | | (2) | |
| Less: Unamortized debt issuance costs | (15) | | | (10) | |
| | | |
| Long-term debt, net | $ | 2,533 | | | $ | 1,588 | |
| Ameren Missouri: | | | |
| Bonds and notes: | | | |
1.60% 1992 Series bonds due 2022(a) | $ | 47 | | | $ | 47 | |
3.50% Senior secured notes due 2024(b) | 350 | | | 350 | |
2.95% Senior secured notes due 2027(b) | 400 | | | 400 | |
3.50% First mortgage bonds due 2029(d) | 450 | | | 450 | |
2.95% First mortgage bonds due 2030(d) | 465 | | | 465 | |
2.15% First mortgage bonds due 2032(d) | 525 | | | — | |
2.90% 1998 Series A bonds due 2033(a) | 60 | | | 60 | |
2.90% 1998 Series B bonds due 2033(a) | 50 | | | 50 | |
2.75% 1998 Series C bonds due 2033(a) | 50 | | | 50 | |
5.50% Senior secured notes due 2034(b) | 184 | | | 184 | |
5.30% Senior secured notes due 2037(b) | 300 | | | 300 | |
8.45% Senior secured notes due 2039(b)(c) | 350 | | | 350 | |
3.90% Senior secured notes due 2042(b)(c) | 485 | | | 485 | |
3.65% Senior secured notes due 2045(b) | 400 | | | 400 | |
4.00% First mortgage bonds due 2048(d) | 425 | | | 425 | |
3.25% First mortgage bonds due 2049(d) | 330 | | | 330 | |
2.625% First mortgage bonds due 2051(d) | 550 | | | 550 | |
| Finance obligations: | | | |
City of Bowling Green agreement (Peno Creek CT) due 2022(e) | 8 | | | 16 | |
Audrain County agreement (Audrain County CT) due 2023(e) | 240 | | | 240 | |
| Total long-term debt, gross | 5,669 | | | 5,152 | |
| Less: Unamortized discount and premium | (12) | | | (12) | |
| Less: Unamortized debt issuance costs | (38) | | | (36) | |
| Less: Maturities due within one year | (55) | | | (8) | |
| Long-term debt, net | $ | 5,564 | | | $ | 5,096 | |
| | | | | | | | | | | |
| 2021 | | 2020 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
2.70% Senior secured notes due 2022(f)(g) | $ | 400 | | | $ | 400 | |
0.375% First mortgage bonds due 2023(h) | 100 | | | — | |
3.25% Senior secured notes due 2025(f) | 300 | | | 300 | |
6.125% Senior secured notes due 2028(f) | 60 | | | 60 | |
3.80% First mortgage bonds due 2028(h) | 430 | | | 430 | |
1.55% First mortgage bonds due 2030(h) | 375 | | | 375 | |
6.70% Senior secured notes due 2036(f) | 61 | | | 61 | |
6.70% Senior secured notes due 2036(f) | 42 | | | 42 | |
4.80% Senior secured notes due 2043(f) | 280 | | | 280 | |
4.30% Senior secured notes due 2044(f) | 250 | | | 250 | |
4.15% Senior secured notes due 2046(f) | 490 | | | 490 | |
3.70% First mortgage bonds due 2047(h) | 500 | | | 500 | |
4.50% First mortgage bonds due 2049(h) | 500 | | | 500 | |
3.25% First mortgage bonds due 2050(h) | 300 | | | 300 | |
2.90% First mortgage bonds due 2051(h) | 350 | | | — | |
| Total long-term debt, gross | 4,438 | | | 3,988 | |
| Less: Unamortized discount and premium | (7) | | | (6) | |
| Less: Unamortized debt issuance costs | (39) | | | (36) | |
| Less: Maturities due within one year | (400) | | | — | |
| Long-term debt, net | $ | 3,992 | | | $ | 3,946 | |
| ATXI: | | | |
2.45% Senior unsecured notes due 2036(i) | $ | 75 | | | $ | — | |
3.43% Senior unsecured notes due 2050(j) | 450 | | | 450 | |
| Total long-term debt, gross | 525 | | | 450 | |
| | | |
| Less: Unamortized debt issuance costs | (2) | | | (2) | |
| Less: Maturities due within one year | (50) | | | — | |
| Long-term debt, net | $ | 473 | | | $ | 448 | |
| Ameren consolidated long-term debt, net | $ | 12,562 | | | $ | 11,078 | |
(a)These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes.
(b)These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2051 maturity of the 2.625% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (c) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.
(c)Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions.
(d)These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri bond indenture. They are secured by substantially all Ameren Missouri property and franchises.
(e)Payments due related to these financing obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the city/county and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the financing obligations and the related investments in debt securities, recorded in “Other Assets,” was $248 million and $256 million, respectively, as of December 31, 2021 and 2020.
(f)These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under its mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2051 maturity date of the 2.90% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.
(g)Ameren Illinois has agreed that so long as any of the 2.70% senior secured notes due 2022 are outstanding, Ameren Illinois will not permit a release date to occur.
(h)These bonds are first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises.
(i)The following table presents the principal maturities schedule for the 2.45% senior unsecured notes due 2036: | | | | | | | | |
| Payment Date | | Principal Payment |
| November 2029 | $ | 30 |
| November 2036 | | 45 |
| Total | $ | 75 |
(j)The following table presents the principal maturities schedule for the 3.43% senior unsecured notes due 2050:
| | | | | | | | |
| Payment Date | | Principal Payment |
| August 2022 | $ | 49.5 |
| August 2024 | | 49.5 |
| August 2027 | | 49.5 |
| August 2030 | | 49.5 |
| August 2032 | | 49.5 |
| August 2038 | | 49.5 |
| August 2043 | | 76.5 |
| August 2050 | | 76.5 |
| Total | $ | 450.0 |
The following table presents the aggregate maturities of long-term debt, including current maturities, at December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated(a) |
| 2022 | $ | — | | | $ | 55 | | | $ | 400 | | | $ | 50 | | | $ | 505 | |
| 2023 | — | | | 240 | | | 100 | | | — | | | 340 | |
| 2024 | 450 | | | 350 | | | — | | | 50 | | | 850 | |
| 2025 | — | | | — | | | 300 | | | — | | | 300 | |
| 2026 | 350 | | | — | | | — | | | — | | | 350 | |
| Thereafter | 1,750 | | | 5,024 | | | 3,638 | | | 425 | | | 10,837 | |
| Total | $ | 2,550 | | | $ | 5,669 | | | $ | 4,438 | | | $ | 525 | | | $ | 13,182 | |
(a)Excludes unamortized discount, premium, and debt issuance costs of $17 million, $50 million, $46 million, and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI, respectively.
All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends, have voting rights, and are not subject to mandatory redemption. The preferred stock of Ameren’s subsidiaries is included in “Noncontrolling Interests” on Ameren’s consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois, which is redeemable at the option of the issuer, at the prices shown below as of December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | |
| Shares Outstanding | | Redemption Price (per share) | | 2021 | | 2020 |
| Ameren Missouri: | | | | | | | |
Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | |
$3.50 Series | 130,000 shares | | $ | 110.00 | | | $ | 13 | | | $ | 13 | |
$3.70 Series | 40,000 shares | | 104.75 | | | 4 | | | 4 | |
$4.00 Series | 150,000 shares | | 105.625 | | | 15 | | | 15 | |
$4.30 Series | 40,000 shares | | 105.00 | | | 4 | | | 4 | |
$4.50 Series | 213,595 shares | | 110.00 | | (a) | 21 | | | 21 | |
$4.56 Series | 200,000 shares | | 102.47 | | | 20 | | | 20 | |
$4.75 Series | 20,000 shares | | 102.176 | | | 2 | | | 2 | |
$5.50 Series A | 14,000 shares | | 110.00 | | | 1 | | | 1 | |
| Total | | | | $ | 80 | | | $ | 80 | |
| Ameren Illinois: | | | | | | | |
With par value of $100 per share, 2 million shares authorized | | | | | | |
4.00% Series | 144,275 shares | | $ | 101.00 | | | $ | 14 | | | $ | 14 | |
4.08% Series | 45,224 shares | | 103.00 | | | 5 | | | 5 | |
4.20% Series | 23,655 shares | | 104.00 | | | 2 | | | 2 | |
4.25% Series | 50,000 shares | | 102.00 | | | 5 | | | 5 | |
4.26% Series | 16,621 shares | | 103.00 | | | 2 | | | 2 | |
4.42% Series | 16,190 shares | | 103.00 | | | 2 | | | 2 | |
4.70% Series | 18,429 shares | | 104.30 | | | 2 | | | 2 | |
4.90% Series | 73,825 shares | | 102.00 | | | 7 | | | 7 | |
4.92% Series | 49,289 shares | | 103.50 | | | 5 | | | 5 | |
5.16% Series | 50,000 shares | | 102.00 | | | 5 | | | 5 | |
6.625% Series | (b) | | 100.00 | | | — | | | 12 | |
7.75% Series | (b) | | 100.00 | | | — | | | 1 | |
| Total | | | | $ | 49 | | | $ | 62 | |
| Total Ameren | | | | $ | 129 | | | $ | 142 | |
(a)In the event of voluntary liquidation, $105.50.
(b)In March 2021, Ameren Illinois redeemed its 6.625% and 7.75% series preferred stock at par.
Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no such shares outstanding. Ameren Missouri has 7.5 million shares of $1 par value preference stock authorized, with no such shares outstanding. Ameren Illinois has 2.6 million shares of no par value preferred stock authorized, with no such shares outstanding.
Ameren
Under the DRPlus and its 401(k) plan, Ameren issued 0.5 million, 0.7 million, and 0.9 million shares of common stock in 2021, 2020, and 2019, respectively, and received proceeds of $47 million, $51 million, and $68 million for the respective years. In addition, Ameren issued 0.5 million, 0.5 million, and 0.8 million shares of common stock valued at $33 million, $38 million, and $54 million in 2021, 2020, 2019, respectively, for no cash consideration in connection with stock-based compensation.
In May 2020, Ameren filed a Form S-3 registration statement with the SEC, authorizing the offering of 4 million additional shares of its common stock under the DRPlus, which expires in May 2023. Shares of common stock sold under the DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions.
In October 2020, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuance of an unspecified amount of certain types of securities. This registration statement expires in October 2023.
In October 2018, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 4 million additional shares of its common stock under its 401(k) plan. Shares of common stock issuable under the 401(k) plan are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions.
In May 2021, Ameren entered into an equity distribution sales agreement pursuant to which Ameren may offer and sell from time to time up to $750 million of its common stock through an ATM program, which includes the ability to enter into forward sales agreements. During 2021, Ameren issued 1.8 million shares of common stock and received proceeds of $148 million. These proceeds were net of less than $2 million in compensation paid to selling agents. There were no shares issued through the ATM program for the three months ended December 31, 2021.
In September 2021, December 2021, and January 2022, Ameren entered into forward sale agreements under the ATM program with counterparties relating to 0.4 million, 0.5 million, and 0.2 million shares of common stock, respectively. The September 2021, December 2021, and January 2022 forward sale agreements can be settled at Ameren’s discretion on or prior to May 3, 2023, June 30, 2023, and June 30, 2023, respectively. On a settlement date or dates, if Ameren elects to physically settle the forward sale agreement, Ameren will issue shares of common stock to the counterparties at the then-applicable forward sale price. The forward sale price was initially $87.87, $87.03, and $88.10 per share, for the September 2021, December 2021, and January 2022 forward sale agreements, respectively. Each initial forward sale price is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the forward sale agreements by specified amounts related to expected dividends on shares of the common stock during the term of the forward sale agreements. If the overnight bank funding rate is less than the spread on any day, the interest rate factor will result in a reduction of the forward sale price. The forward sale agreements will be physically settled unless Ameren elects to settle in cash or to net share settle. At December 31, 2021, Ameren could have settled the September 2021 and December 2021 forward sale agreements with physical delivery of 0.4 million and 0.5 million shares of common stock, respectively, to the counterparty in exchange for cash of $30 million and $41 million, respectively. The forward sale agreements have been classified as equity transactions.
In August 2019, Ameren entered into a forward sale agreement with a counterparty relating to 7.5 million shares of common stock. In December 2020, pursuant to the agreement terms, Ameren partially settled the forward sale agreement by physically delivering 5.9 million shares of common stock for cash proceeds of $425 million. In February 2021, Ameren settled the remainder of the forward sale agreement by physically delivering 1.6 million shares of common stock for cash proceeds of $113 million. The proceeds were used to fund a portion of Ameren Missouri’s wind generation investments. See Note 15 – Supplemental Information for additional information about the wind generation facilities.
In March 2021, Ameren (parent) issued $450 million of 1.75% senior unsecured notes due March 2028, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2021. Ameren received net proceeds of $447 million which were used for general corporate purposes, including the repayment of short-term debt.
In November 2021, Ameren (parent) issued $500 million of 1.95% senior unsecured notes due March 2027, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2022. Ameren received net proceeds of $497 million which were used to repay short-term debt.
In April 2020, Ameren (parent) issued $800 million of 3.50% senior unsecured notes due January 2031, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2020. Ameren received net proceeds of $793 million, which were used for general corporate purposes, including to repay outstanding short-term debt, and were used to fund the repayment of Ameren’s $350 million of 2.70% senior unsecured notes, which were redeemed at par plus accrued interest in October 2020.
Ameren Missouri
In June 2021, Ameren Missouri issued $525 million of 2.15% first mortgage bonds due March 2032, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2022. Ameren Missouri received net proceeds of $521 million, which were used to repay short-term debt and for near-term capital expenditures. Ameren Missouri intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.
In March 2020, Ameren Missouri issued $465 million of 2.95% first mortgage bonds due March 2030, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2020. Ameren Missouri received net proceeds of $462 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $85 million of its 5.00% senior secured notes that matured in February 2020.
In October 2020, Ameren Missouri issued $550 million of 2.625% first mortgage bonds due March 2051, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2021. Ameren Missouri received net proceeds of $543 million, which were allocated and used to partially finance the acquisition of two wind generation energy centers. See Note 15 – Supplemental Information for information about the wind generation energy centers.
For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
Ameren Illinois
In March 2021, Ameren Illinois redeemed its 6.625% and 7.75% series preferred stock at par for $12 million and $1 million, respectively. The preferred stock of Ameren Illinois is reflected in “Noncontrolling Interests” on Ameren’s consolidated balance sheet.
In June 2021, Ameren Illinois issued $350 million of 2.90% first mortgage bonds due June 2051, with interest payable semiannually on June 15 and December 15 of each year, beginning December 15, 2021. Ameren Illinois received net proceeds of $345 million, which were used to repay short-term debt. Ameren Illinois intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.
In June 2021, Ameren Illinois issued $100 million of 0.375% first mortgage bonds due June 2023, with interest payable semiannually on June 15 and December 15 of each year, beginning December 15, 2021. Ameren Illinois received net proceeds of $100 million, which were used to repay short-term debt.
In November 2020, Ameren Illinois issued $375 million of 1.55% first mortgage bonds due November 2030, with interest payable semiannually on May 15 and November 15 of each year, beginning May 15, 2021. Ameren Illinois received net proceeds of $371 million, which were used to repay short-term debt.
For information on Ameren Illinois’ capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
ATXI
In November 2021, pursuant to a note purchase agreement, ATXI issued $75 million of its 2.45% senior unsecured notes due 2036, with interest payable semiannually on May 16 and November 16 of each year, beginning May 16, 2022, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI received net proceeds of $75 million, which were used to refinance a portion of an intercompany long-term note with Ameren (parent) and to repay short-term debt.
In November 2021, pursuant to a note purchase agreement, ATXI agreed to issue $95 million of its 2.96% senior unsecured notes due 2052, with interest payable semiannually on February 25 and August 25 of each year, beginning February 25, 2023, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI expects to issue the notes and receive net proceeds of $95 million in August 2022, which will be used to refinance the remaining portion of an intercompany long-term note with Ameren (parent), repay a $50 million principal payment of its 3.43% senior unsecured notes, and to repay short-term debt.
Indenture Provisions and Other Covenants
Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges, dividend coverage ratios, and bonds and preferred stock issuable as of December 31, 2021, at an assumed interest rate of 5% and dividend rate of 6%.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Required Interest Coverage Ratio(a) | Actual Interest
Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend
Coverage Ratio | Preferred Stock
Issuable | |
| Ameren Missouri | >2.0 | 3.2 | $4,834 | | >2.5 | 152.4 | $3,418 | |
| Ameren Illinois | >2.0 | 7.3 | 7,697 | | >1.5 | 3.5 | 203 | (d) |
(a)Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $2,437 million and $643 million at Ameren Missouri and Ameren Illinois, respectively.
(c)Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.
(d)Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.
Ameren’s indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million, or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including borrowings under the Credit Agreements or the Ameren commercial paper program, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.
Ameren Missouri and Ameren Illinois and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal
Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on their respective stock unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois has made a commitment to the FERC to maintain a minimum 30% ratio of common stock equity to total capitalization. As of December 31, 2021, using the FERC-agreed upon calculation method, Ameren Illinois’ ratio of common stock equity to total capitalization was 54%.
ATXI’s note purchase agreements includes financial covenants that require ATXI not to permit at any time (1) debt to exceed 70% of total capitalization or (2) secured debt to exceed 10% of total assets.
At December 31, 2021, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements. In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable requirements in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2021, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than variable interest entities and the September and December 2021 forward sale agreements relating to common stock. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.
NOTE 6 – OTHER INCOME, NET
The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the years ended December 31, 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Ameren: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 43 | | | $ | 32 | | | $ | 28 | |
| Interest income on industrial development revenue bonds | 25 | | | 25 | | | 25 | |
| Other interest income | 2 | | | 4 | | | 8 | |
Non-service cost components of net periodic benefit income (a) | 136 | | | 116 | | | 90 | |
| Miscellaneous income | 22 | | | 13 | | | 6 | |
| Donations | (9) | | | (25) | | (b) | (12) | |
| Miscellaneous expense | (17) | | | (14) | | | (15) | |
| Total Other Income, Net | $ | 202 | | | $ | 151 | | | $ | 130 | |
| Ameren Missouri: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 26 | | | $ | 19 | | | $ | 19 | |
| Interest income on industrial development revenue bonds | 25 | | | 25 | | | 25 | |
| Other interest income | 1 | | | 1 | | | 1 | |
Non-service cost components of net periodic benefit income (a) | 55 | | | 46 | | | 18 | |
| Miscellaneous income | 3 | | | 4 | | | 5 | |
| Donations | (4) | | | (12) | | (b) | (3) | |
| Miscellaneous expense | (7) | | | (7) | | | (7) | |
| Total Other Income, Net | $ | 99 | | | $ | 76 | | | $ | 58 | |
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Ameren Illinois: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 17 | | | $ | 13 | | | $ | 9 | |
| Interest income | 1 | | | 3 | | | 6 | |
Non-service cost components of net periodic benefit income (a) | 55 | | | 48 | | | 47 | |
| Miscellaneous income | 6 | | | 6 | | | 3 | |
| Donations | (5) | | | (5) | | | (5) | |
| Miscellaneous expense | (8) | | | (6) | | | (7) | |
| Total Other Income, Net | $ | 66 | | | $ | 59 | | | $ | 53 | |
(a)For the years ended December 31, 2021, 2020, and 2019, the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $(7) million, $(4) million, and $29 million, respectively, due to a tracker for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
(b)Includes $8 million pursuant to Ameren Missouri’s March 2020 electric rate order.
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:
•an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory;
•actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays; and
•actual off-system sales revenues that differ from anticipated revenues.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 – Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery. The following disclosures exclude NPNS contracts and other nonderivative commodity contracts that are accounted for under the accrual method of accounting.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of December 31, 2021 and 2020, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Cash flows for all derivative financial instruments are classified in cash flows from operating activities.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2021 and 2020. As of December 31, 2021, these contracts extended through October 2024, October 2026, May 2032, and March 2024 for fuel oils, natural gas, power, and uranium, respectively.
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| Quantity (in millions, except as indicated) |
| 2021 | 2020 |
| Commodity | Ameren Missouri | Ameren
Illinois | Ameren | Ameren Missouri | Ameren
Illinois | Ameren |
| Fuel oils (in gallons) | 30 | | — | | 30 | | 43 | | — | | 43 | |
| Natural gas (in mmbtu) | 35 | | 144 | | 179 | | 33 | | 114 | | 147 | |
| Power (in MWhs) | 6 | | 6 | | 12 | | 6 | | 7 | | 13 | |
| Uranium (pounds in thousands) | 586 | | — | | 586 | | 365 | | — | | 365 | |
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The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of December 31, 2021 and 2020:
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| 2021 | | | 2020 |
| Commodity | Balance Sheet Location | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren | | | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren |
| Fuel oils | Other current assets | | $ | 8 | | | | $ | — | | | | $ | 8 | | | | | $ | 2 | | | | $ | — | | | | $ | 2 | |
| Other assets | | 5 | | | | — | | | | 5 | | | | | — | | | | — | | | | — | |
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| Natural gas | Other current assets | | 7 | | | | 28 | | | | 35 | | | | | 1 | | | | 8 | | | | 9 | |
| Other assets | | 5 | | | | 13 | | | | 18 | | | | | 2 | | | | 2 | | | | 4 | |
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| Power | Other current assets | | 23 | | | | — | | | | 23 | | | | | 7 | | | | — | | | | 7 | |
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| Uranium | Other assets | | 1 | | | | — | | | | 1 | | | | | — | | | | — | | | | — | |
| | Total assets | | $ | 49 | | | | $ | 41 | | | | $ | 90 | | | | | $ | 12 | | | | $ | 10 | | | | $ | 22 | |
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| Fuel oils | Other current liabilities | | $ | — | | | | $ | — | | | | $ | — | | | | | $ | 7 | | | | $ | — | | | | $ | 7 | |
| Other deferred credits and liabilities | | — | | | | — | | | | — | | | | | 2 | | | | — | | | | 2 | |
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| Natural gas | Other current liabilities | | 2 | | | | 6 | | | | 8 | | | | | 1 | | | | 1 | | | | 2 | |
| Other deferred credits and liabilities | | 1 | | | | 2 | | | | 3 | | | | | — | | | | 1 | | | | 1 | |
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| Power | Other current liabilities | | 50 | | | | 9 | | | | 59 | | | | | 3 | | | | 17 | | | | 20 | |
| Other deferred credits and liabilities | | 23 | | | | 108 | | | | 131 | | | | | 8 | | | | 181 | | | | 189 | |
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| Uranium | Other current liabilities | | 1 | | | | — | | | | 1 | | | | | — | | | | — | | | | — | |
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| | Total liabilities | | $ | 77 | | | | $ | 125 | | | | $ | 202 | | | | | $ | 21 | | | | $ | 200 | | | | $ | 221 | |
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We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar agreement level by counterparty.
The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of December 31, 2021. If the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted at December 31, 2020, the net amounts would not be materially different from the gross amounts.
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| | | | Gross Amounts Not Offset in the Balance Sheet | | |
| Commodity Contracts Eligible to be Offset | | Gross Amounts Recognized in the Balance Sheet | | Derivative Instruments | | Cash Collateral Received/Posted(a) | | Net
Amount |
| 2021 | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | | $ | 49 | | | $ | 15 | | | $ | — | | | $ | 34 | |
| Ameren Illinois | | 41 | | | 4 | | | — | | | 37 | |
| Ameren | | $ | 90 | | | $ | 19 | | | $ | — | | | $ | 71 | |
| Liabilities: | | | | | | | | |
| Ameren Missouri | | $ | 77 | | | $ | 15 | | | $ | 47 | | | $ | 15 | |
| Ameren Illinois | | 125 | | | 4 | | | — | | | 121 | |
| Ameren | | $ | 202 | | | $ | 19 | | | $ | 47 | | | $ | 136 | |
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(a)Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” on Ameren’s balance sheet and in “Current collateral assets” on Ameren Missouri’s balance sheet.
Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. As of December 31, 2021, if counterparty groups were to fail completely to perform on contracts, Ameren’s, Ameren Missouri’s, and Ameren Illinois’ maximum exposure related to derivative assets, predominantly from financial institutions, was $77 million, $36 million, and $41 million, respectively. The potential loss on counterparty exposures may be reduced or eliminated by the application of master netting arrangements or similar agreements and collateral held. As of December 31, 2021, the potential loss after consideration of the application of master netting arrangements or similar agreements and collateral held for Ameren, Ameren Missouri, and Ameren Illinois was $61 million, $23 million, and $38 million, respectively.
Certain of our derivative instruments contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded below investment grade, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered and (2) those counterparties with rights to do so requested collateral. As of December 31, 2021, the aggregate fair value of derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require were each immaterial to Ameren, Ameren Missouri, and Ameren Illinois.
NOTE 8 – FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1 (quoted prices in active markets for identical assets or liabilities): Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives, cash and cash equivalents, and listed equity securities.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants, and the trustee and investment managers. The S&P 500 index comprises stocks of large-capitalization companies.
Level 2 (significant other observable inputs): Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including United States Treasury and agency securities, corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.
Fixed income securities are valued by using prices from independent industry-recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed-income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices.
Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the bid/ask spreads to the midpoints. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoints. The value of natural gas derivative contracts is based upon exchange closing prices without significant unobservable adjustments. The value of power derivative contracts is based upon exchange closing prices or the use of multiple forward prices provided by third parties.
Level 3 (significant other unobservable inputs): Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, such as certain internal assumptions, quotes or prices from outside sources not supported by a liquid market, or trend rates.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by considering any credit enhancements (e.g., collateral). Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in 2021, 2020, or 2019. At December 31, 2021 and 2020, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2021 and 2020:
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| | December 31, 2021 | | | December 31, 2020 | |
| | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | 13 | | $ | — | | $ | — | | $ | 13 | | | | $ | — | | $ | — | | $ | 2 | | $ | 2 | | |
| Natural gas | — | | 12 | | — | | 12 | | | | — | | 3 | | — | | 3 | | |
| Power | 10 | | — | | 13 | | 23 | | | | 2 | | — | | 5 | | 7 | | |
| Uranium | — | | — | | 1 | | 1 | | | | — | | — | | — | | — | | |
| Total derivative assets – commodity contracts | $ | 23 | | $ | 12 | | $ | 14 | | $ | 49 | | | | $ | 2 | | $ | 3 | | $ | 7 | | $ | 12 | | |
| Nuclear decommissioning trust fund: | | | | | | | | | | | |
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| U.S. large capitalization | $ | 824 | | $ | — | | $ | — | | $ | 824 | | | | $ | 680 | | $ | — | | $ | — | | $ | 680 | | |
| Debt securities: | | | | | | | | | | | |
| U.S. Treasury and agency securities | — | | 141 | | — | | 141 | | | | — | | 115 | | — | | 115 | | |
| Corporate bonds | — | | 131 | | — | | 131 | | | | — | | 115 | | — | | 115 | | |
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| Other | — | | 56 | | — | | 56 | | | | — | | 67 | | — | | 67 | | |
| Total nuclear decommissioning trust fund | $ | 824 | | $ | 328 | | $ | — | | $ | 1,152 | | (a) | | $ | 680 | | $ | 297 | | $ | — | | $ | 977 | | (a) |
| Total Ameren Missouri | $ | 847 | | $ | 340 | | $ | 14 | | $ | 1,201 | | | | $ | 682 | | $ | 300 | | $ | 7 | | $ | 989 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | 1 | | $ | 33 | | $ | 7 | | $ | 41 | | | | $ | — | | $ | 6 | | $ | 4 | | $ | 10 | | |
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| Ameren | | | | | | | | | | | |
| Derivative assets – commodity contracts(b) | $ | 24 | | $ | 45 | | $ | 21 | | $ | 90 | | | | $ | 2 | | $ | 9 | | $ | 11 | | $ | 22 | | |
| Nuclear decommissioning trust fund(c) | 824 | | 328 | | — | | 1,152 | | (a) | | 680 | | 297 | | — | | 977 | | (a) |
| Total Ameren | $ | 848 | | $ | 373 | | $ | 21 | | $ | 1,242 | | | | $ | 682 | | $ | 306 | | $ | 11 | | $ | 999 | | |
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| Ameren Missouri | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | — | | $ | — | | $ | — | | $ | — | | | | $ | 6 | | $ | — | | $ | 3 | | $ | 9 | | |
| Natural gas | — | | 2 | | 1 | | 3 | | | | — | | 1 | | — | | 1 | | |
| Power | 45 | | — | | 28 | | 73 | | | | 8 | | — | | 3 | | 11 | | |
| Uranium | — | | — | | 1 | | 1 | | | | — | | — | | — | | — | | |
| Total Ameren Missouri | $ | 45 | | $ | 2 | | $ | 30 | | $ | 77 | | | | $ | 14 | | $ | 1 | | $ | 6 | | $ | 21 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | — | | $ | 5 | | $ | 3 | | $ | 8 | | | | $ | — | | $ | 1 | | $ | 1 | | $ | 2 | | |
| Power | — | | — | | 117 | | 117 | | | | — | | — | | 198 | | 198 | | |
| Total Ameren Illinois | $ | — | | $ | 5 | | $ | 120 | | $ | 125 | | | | $ | — | | $ | 1 | | $ | 199 | | $ | 200 | | |
| Ameren | | | | | | | | | | | |
| Derivative liabilities – commodity contracts(b) | $ | 45 | | $ | 7 | | $ | 150 | | $ | 202 | | | | $ | 14 | | $ | 2 | | $ | 205 | | $ | 221 | | |
(a)Balance excludes $7 million and $5 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2021 and 2020, respectively.
(b)See the Ameren Missouri and Ameren Illinois sections of the table for a breakout of the fair value of Ameren’s derivative assets and liabilities by type of commodity.
(c)See the Ameren Missouri section of the table for a breakout of Ameren’s nuclear decommissioning trust fund by investment type.
See Note 10 – Retirement Benefits for tables that set forth, by level within the fair value hierarchy, Ameren’s pension and postretirement plan assets as of December 31, 2021 and 2020.
Level 3 fuel oils, natural gas and uranium derivative contract assets and liabilities measured at fair value on a recurring basis were immaterial for all periods presented. The following table presents the fair value reconciliation of Level 3 power derivative contract assets and liabilities measured at fair value on a recurring basis for the years ended December 31, 2021 and 2020:
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| 2021 | | | 2020 |
| Ameren
Missouri | Ameren
Illinois | Ameren | | | Ameren
Missouri | Ameren
Illinois | Ameren |
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| Beginning balance at January 1 | $ | 2 | | $ | (198) | | $ | (196) | | | | $ | 13 | | $ | (224) | | $ | (211) | |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | (1) | | 70 | | 69 | | | | 15 | | 8 | | 23 | |
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| Settlements | (16) | | 11 | | (5) | | | | (26) | | 18 | | (8) | |
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| Ending balance at December 31 | $ | (15) | | $ | (117) | | $ | (132) | | | | $ | 2 | | $ | (198) | | $ | (196) | |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | (14) | | $ | 65 | | $ | 51 | | | | $ | 1 | | $ | 9 | | $ | 10 | |
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All gains or losses related to our Level 3 derivative commodity contracts are expected to be recovered or returned through customer rates; therefore, there is no impact to either net income or other comprehensive income resulting from changes in the fair value of these instruments.
The following table describes the valuation techniques and significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of December 31, 2021 and 2020:
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| | Fair Value | | | | | Weighted Average(b) |
| Commodity | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input(a) | Range |
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2021 | Power(c) | $ | 13 | | $ | (145) | | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 32 – 55 | 40 |
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| | | | | | Nodal basis ($/MWh) | (14) – 0 | (2) |
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| | | | | | Trend rate (%) | 0 – 0 | 0 |
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2020 | Power(c) | $ | 5 | | $ | (201) | | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 23 – 37 | 29 |
| | | | | | Nodal basis ($/MWh) | (6) – 0 | (2) |
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| | | | | | Trend rate (%) | 2 – 6 | 3 |
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(a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.
(b)Unobservable inputs were weighted by relative fair value.
(c)Valuations through 2029 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2029 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
The following table sets forth, by level within the fair value hierarchy, the carrying amount and fair value of financial assets and liabilities disclosed, but not carried, at fair value as of December 31, 2021 and 2020:
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| Carrying
Amount | | Fair Value | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| December 31, 2021 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 155 | | | $ | 155 | | | $ | — | | | $ | — | | | $ | 155 | |
Investments in industrial development revenue bonds(a) | 248 | | | — | | | 248 | | | — | | | 248 | |
| Short-term debt | 545 | | | — | | | 545 | | | — | | | 545 | |
Long-term debt (including current portion)(a) | 13,067 | | (b) | — | | | 13,930 | | | 591 | | (c) | 14,521 | |
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 8 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | |
| | | | | | | | | |
Investments in industrial development revenue bonds(a) | 248 | | | — | | | 248 | | | — | | | 248 | |
| Short-term debt | 165 | | | — | | | 165 | | | — | | | 165 | |
| | | | | | | | | |
Long-term debt (including current portion)(a) | 5,619 | | (b) | — | | | 6,321 | | | — | | | 6,321 | |
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 133 | | | $ | 133 | | | $ | — | | | $ | — | | | $ | 133 | |
| | | | | | | | | |
| Short-term debt | 103 | | | — | | | 103 | | | — | | | 103 | |
| | | | | | | | | |
| Long-term debt (including current portion) | 4,392 | | (b) | — | | | 4,971 | | | — | | | 4,971 | |
| December 31, 2020 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 301 | | | $ | 301 | | | $ | — | | | $ | — | | | $ | 301 | |
Investments in industrial development revenue bonds(a) | 256 | | | — | | | 256 | | | — | | | 256 | |
| Short-term debt | 490 | | | — | | | 490 | | | — | | | 490 | |
Long-term debt (including current portion)(a) | 11,086 | | (b) | — | | | 12,778 | | | 537 | | (c) | 13,315 | |
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 145 | | | $ | 145 | | | $ | — | | | $ | — | | | $ | 145 | |
| Advances to money pool | 139 | | | — | | | 139 | | | — | | | 139 | |
Investments in industrial development revenue bonds(a) | 256 | | | — | | | 256 | | | — | | | 256 | |
| | | | | | | | | |
| | | | | | | | | |
Long-term debt (including current portion)(a) | 5,104 | | (b) | — | | | 6,160 | | | — | | | 6,160 | |
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 147 | | | $ | 147 | | | $ | — | | | $ | — | | | $ | 147 | |
| | | | | | | | | |
| | | | | | | | | |
| Borrowings from money pool | 19 | | | — | | | 19 | | | — | | | 19 | |
| Long-term debt (including current portion) | 3,946 | | (b) | — | | | 4,822 | | | — | | | 4,822 | |
(a)Ameren and Ameren Missouri have investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the finance obligations for the Peno Creek and Audrain CT energy centers. As of December 31, 2021 and 2020, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value.
(b)Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $94 million, $38 million, and $39 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2021. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $84 million, $36 million, and $36 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2020.
(c)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.
NOTE 9 – CALLAWAY ENERGY CENTER
Maintenance Outage
During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. After replacement of certain key components of the generator, the energy center returned to service in early August 2021. The cost of generator repairs was approximately $60 million, which was largely capital expenditures. In April 2021, Ameren Missouri’s insurance claims were accepted by NEIL, which covered a significant portion of the capital expenditures and covered lost sales of up to $4.5 million weekly after March 17, 2021. Insurance recoveries related to lost sales were reflected in electric operating revenues and included in net energy costs under the FAC. Expected insurance recoveries related to the capital expenditures were reflected as a reduction to property, plant, and equipment. As of December 31, 2021, a $33 million insurance receivable was included in “Miscellaneous accounts receivable” on Ameren’s and Ameren Missouri’s balance sheets related to the capital expenditures and lost sales insurance claims. In January 2022, Ameren Missouri received $17 million in payments from NEIL and EMANI related to the capital expenditures insurance claims.
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, as amended, the DOE is responsible for disposing of spent nuclear fuel from the Callaway Energy Center and other commercial nuclear energy centers. As required by the act, Ameren Missouri and other utilities have entered into standard contracts with the DOE, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998. However, the DOE failed to fulfill its disposal obligations, and Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri’s lawsuit against the DOE resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. Ameren Missouri received immaterial reimbursements from the DOE in the years ended December 31, 2021, 2020, and 2019. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel. The DOE’s delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway Energy Center is not expected to adversely affect the continued operations of the energy center.
Decommissioning
Electric rates charged to customers provide for the recovery of the Callaway Energy Center’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over the expected life of the nuclear energy center. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway Energy Center’s decommissioning. It is assumed that the Callaway Energy Center site will be decommissioned after its retirement through the immediate dismantlement method and removed from service. The Callaway Energy Center’s operating license expires in 2044. Ameren and Ameren Missouri have recorded an ARO for the Callaway Energy Center decommissioning costs at fair value. Annual decommissioning costs of $7 million are included in the costs used to establish electric rates for Ameren Missouri’s customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway Energy Center. An updated cost study and funding analysis was filed with the MoPSC in November 2020 and reflected within the ARO. In February 2021, the MoPSC approved no change in electric rates for decommissioning costs consistent with Ameren Missouri’s updated cost study and funding analysis.
Ameren and Ameren Missouri have classified the investments in debt and equity securities that are held in the nuclear decommissioning trust fund as available for sale, and have recorded all such investments at their fair market value at December 31, 2021 and 2020. Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities.
The fair value of the trust fund for Ameren Missouri’s Callaway Energy Center is reported as “Nuclear decommissioning trust fund” in Ameren’s and Ameren Missouri’s balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the regulatory liability related to AROs. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. See Note 2 – Rate and Regulatory Matters for the regulatory liability recorded at December 31, 2021. If the assumed return on trust assets is not earned, Ameren Missouri believes that it is probable that any additional funding requirements resulting from such earnings deficiency will be recovered in customer rates.
The following table presents proceeds from the sale and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Proceeds from sales and maturities | $ | 439 | | | $ | 183 | | | $ | 260 | |
| Gross realized gains | 32 | | | 10 | | | 10 | |
| Gross realized losses | 6 | | | 3 | | | 2 | |
The following table presents the cost and fair value of investments in debt and equity securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2021 and December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2021 | | | | | | | |
| Debt securities | $ | 320 | | | $ | 10 | | | $ | 2 | | | $ | 328 | |
| Equity securities | 188 | | | 640 | | | 4 | | | 824 | |
| Cash and cash equivalents | 4 | | | — | | | — | | | 4 | |
Other(a) | 3 | | | — | | | — | | | 3 | |
| Total | $ | 515 | | | $ | 650 | | | $ | 6 | | | $ | 1,159 | |
| 2020 | | | | | | | |
| Debt securities | $ | 272 | | | $ | 25 | | | $ | — | | | $ | 297 | |
| Equity securities | 198 | | | 491 | | | 9 | | | 680 | |
| Cash and cash equivalents | 4 | | | — | | | — | | | 4 | |
Other(a) | 1 | | | — | | | — | | | 1 | |
| Total | $ | 475 | | | $ | 516 | | | $ | 9 | | | $ | 982 | |
(a)Represents net receivables and payables relating to pending securities sales, interest, and securities purchases.
The following table presents the costs and fair values of investments in debt securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2021:
| | | | | | | | | | | |
| Cost | | Fair Value |
| Less than 5 years | $ | 155 | | | $ | 156 | |
| 5 years to 10 years | 71 | | | 72 | |
| Due after 10 years | 94 | | | 100 | |
| Total | $ | 320 | | | $ | 328 | |
Insurance
The following table presents insurance coverage at Ameren Missouri’s Callaway Energy Center at January 1, 2022:
| | | | | | | | | | | | | | | | | |
| Type and Source of Coverage | Most Recent
Renewal Date | Maximum Coverages | | Maximum Assessments
for Single Incidents | |
| Public liability and nuclear worker liability: | | | | | |
| American Nuclear Insurers | January 1, 2022 | $ | 450 | | | $ | — | | |
| Pool participation | (a) | 13,073 | | (a) | 138 | | (b) |
| | $ | 13,523 | | (c) | $ | 138 | | |
| Property damage: | | | | | |
| NEIL and EMANI | April 1, 2021 | $ | 3,200 | | (d) | $ | 25 | | (e) |
| Accidental outage: | | | | | |
| NEIL | April 1, 2021 | $ | 490 | | (f) | $ | 7 | | (e) |
(a)Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.
(b)Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $21 million per year.
(c)Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors.
(d)NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events.
(e)All NEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.
(f)Accidental outage insurance provides for lost sales in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in November 2018. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share the limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination, resulting from terrorist attacks. The EMANI policies are not subject to industrywide aggregates in the event of terrorist attacks on nuclear facilities.
If losses from a nuclear incident at the Callaway Energy Center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.
NOTE 10 – RETIREMENT BENEFITS
The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren has defined benefit pension plans covering substantially all of its employees and has a postretirement benefit plan covering non-union employees hired before October 2015 and union employees hired before January 2020. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. All non-union employees participate in a cash balance pension plan. Ameren Missouri union employees hired after June 2013, and Ameren Illinois union employees hired after mid-October 2012, participate in a cash balance pension plan. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Ameren also has an unfunded nonqualified pension plan, the Ameren Supplemental Retirement Plan, which is available to provide certain management employees and retirees with a supplemental benefit when their qualified pension plan benefits are capped in compliance with Internal Revenue Code limitations. Only Ameren subsidiaries participate in the plans listed above.
Ameren’s pension and other postretirement benefit plans were overfunded by $717 million and $249 million in the aggregate as of December 31, 2021 and 2020, respectively. These net assets are recorded in “Pension and other postretirement benefits,” “Other current liabilities,” and “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. The increase in the overfunded pension and postretirement benefit plans during 2021 was primarily the result of an increase in the return on plan assets of the pension and postretirement trusts and a 25 basis point increase in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligation. The overfunded pension and other postretirement benefit plans also resulted in regulatory liabilities on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets.
The following table presents the net benefit liability/(asset) recorded on the balance sheets as of December 31, 2021 and 2020:
| | | | | | | | | | | |
| 2021 | | 2020 |
Ameren(a) | $ | (717) | | | $ | (249) | |
Ameren Missouri(a) | (189) | | | (25) | |
Ameren Illinois(a) | (416) | | | (210) | |
(a)Liabilities associated with pension and other postretirement benefits are recorded in “Other current liabilities” and “Other deferred credits and liabilities” on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets.
Ameren recognizes the overfunded and underfunded status of its pension and postretirement plans as an asset or a liability on its consolidated balance sheet, with offsetting entries to accumulated OCI and regulatory assets or liabilities. The following table presents the funded status of Ameren’s pension and postretirement benefit plans as of December 31, 2021 and December 31, 2020. It also provides the amounts included in regulatory assets or liabilities and accumulated OCI at December 31, 2021 and December 31, 2020, that have not been recognized in net periodic benefit costs.
| | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2020 |
| Pension
Benefits | | Postretirement
Benefits | | Pension
Benefits | | Postretirement
Benefits |
| Accumulated benefit obligation at end of year | $ | 5,174 | | $ | (a) | | $ | 5,213 | | $ | (a) |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 5,510 | | $ | 1,204 | | | $ | 4,967 | | $ | 1,110 | |
| Service cost | 134 | | | 23 | | | 110 | | | 19 | |
| Interest cost | 152 | | | 33 | | | 174 | | | 39 | |
| | | | | | | |
| Participant contributions | — | | | 9 | | | — | | | 8 | |
| Actuarial (gain) loss | (82) | | | (80) | | | 508 | | | 91 | |
| | | | | | | |
| Benefits paid | (257) | | | (60) | | | (249) | | | (63) | |
| | | | | | | |
| | | | | | | |
| Net benefit obligation at end of year | 5,457 | | | 1,129 | | | 5,510 | | | 1,204 | |
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 5,510 | | | 1,453 | | | 4,564 | | | 1,297 | |
| Actual return on plan assets | 432 | | | 154 | | | 1,143 | | | 209 | |
| Employer contributions | 60 | | | 2 | | | 52 | | | 2 | |
| | | | | | | |
| | | | | | | |
| Participant contributions | — | | | 9 | | | — | | | 8 | |
| | | | | | | |
| | | | | | | |
| Benefits paid | (257) | | | (60) | | | (249) | | | (63) | |
| Fair value of plan assets at end of year | 5,745 | | | 1,558 | | | 5,510 | | | 1,453 | |
| Funded status – surplus | (288) | | | (429) | | | — | | | (249) | |
| Accrued benefit asset at December 31 | $ | (288) | | $ | (429) | | | $ | — | | $ | (249) | |
| Amounts recognized in the balance sheet consist of: | | | | | | | |
| Noncurrent asset | $ | (327) | | $ | (429) | | | $ | (39) | | $ | (249) | |
Current liability(b) | 2 | | | — | | | 2 | | | — | |
Noncurrent liability(c) | 37 | | | — | | | 37 | | | — | |
| Net asset recognized | $ | (288) | | $ | (429) | | | $ | — | | $ | (249) | |
| Amounts recognized in regulatory assets or liabilities consist of: | | | | | | | |
| Net actuarial gain | $ | (415) | | $ | (343) | | | $ | (138) | | $ | (200) | |
| Prior service credit | — | | | (33) | | | — | | | (37) | |
| | | | | | | |
| Amounts recognized in accumulated OCI (pretax) consist of: | | | | | | | |
| Net actuarial (gain) loss | (8) | | | 1 | | | 5 | | | 6 | |
| | | | | | | |
| Total | $ | (423) | | $ | (375) | | | $ | (133) | | $ | (231) | |
(a)Not applicable.
(b)Included in “Other current liabilities” on Ameren’s consolidated balance sheet.
(c)Included in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2021 | | 2020 | | 2021 | | 2020 |
| Discount rate at measurement date | 3.00 | % | | 2.75 | % | | 3.00 | % | | 2.75 | % |
| Increase in future compensation | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | |
| Cash balance pension plan interest crediting rate | 5.00 | | | 5.00 | | | (a) | | (a) |
Medical cost trend rate (initial)(b) | (a) | | (a) | | 5.00 | | | 5.00 | |
Medical cost trend rate (ultimate)(b) | (a) | | (a) | | 5.00 | | | 5.00 | |
| | | | | | | |
(a)Not applicable.
(b)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants was 2.50% and 3.00% at December 31, 2021 and 2020, respectively.
Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan’s projected benefit payments. The settlement portfolio of bonds is selected from a pool of approximately 820 high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan’s benefit payments that equates
to the market value of the selected bonds. During 2021, Ameren elected to continue to use the Society of Actuaries mortality table and the Society of Actuaries 2020 Mortality Improvement Scale.
Funding
Pension benefits are based on the employees’ years of service, age, and compensation. Ameren’s pension plans are funded in compliance with income tax regulations, federal funding requirements, and other regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on its assumptions at December 31, 2021, its investment performance in 2021, and its pension funding policy, Ameren, Ameren Missouri, and Ameren Illinois do not expect to make material contributions in the aggregate over the next five years. These estimated contributions may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the cash contributions made to our defined benefit retirement plans and to our postretirement plan during 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Postretirement Benefits | |
| 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | |
| Ameren Missouri | $ | 22 | | | $ | 17 | | | $ | 3 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | |
| Ameren Illinois | 28 | | | 27 | | | 19 | | | 1 | | | 1 | | | 1 | | |
| Ameren Services | 10 | | | 8 | | | 1 | | | — | | | — | | | 1 | | |
| Ameren | $ | 60 | | | $ | 52 | | | $ | 23 | | | $ | 2 | | | $ | 2 | | | $ | 3 | | |
Investment Strategy and Policies
Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, which includes members of senior management, approves and implements investment strategy and asset allocation guidelines for the plan assets. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable; and second, to maximize total return on plan assets and to minimize expense volatility consistent with its tolerance for risk. Ameren delegates the task of investment management to specialists in each asset class. As appropriate, Ameren provides each investment manager with guidelines that specify allowable and prohibited investment types. The investment committee regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we reviewed the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. Ameren will use an expected return on plan assets for its pension and postretirement plan assets of 6.50% in 2022.
Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate), duration, market capitalization, country, style (growth or value), and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk.
Effective January 2020, Ameren’s investment committee developed and implemented a liability hedging investment strategy for its qualified pension plans designed to reduce interest rate risk as part of an objective for its long-term investment strategy. The plan invests in derivative instruments mainly consisting of interest rate futures intended to extend the duration of the pension plan assets so that the assets are more closely aligned with the duration of the liabilities. In addition, part of Ameren’s investment strategy includes participation in a securities lending program, which allows it to lend eligible securities to third party borrowers. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested in the form of cash, government obligations, and U.S. agency obligations. Ameren’s fair value of securities loaned was $374 million and $365 million as of December 31, 2021 and 2020, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2021 and 2020.
The following table presents our target allocations and our pension and postretirement plans’ asset categories as of December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | |
Asset
Category | Target Allocation 2021(a) | | Percentage of Plan Assets at December 31, |
| 2021 | | 2020 |
| Pension Plan: | | | | | |
| Cash and cash equivalents | 0% – 5% | | 3 | % | | 1 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 11% – 21% | | 23 | % | | 26 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 9 | % |
| International | 9% – 19% | | 15 | % | | 15 | % |
| Global | 7% – 17% | | 11 | % | | 9 | % |
| Total equity | 45% – 55% | | 58 | % | | 59 | % |
| Debt securities | 35% – 45% | | 35 | % | | 36 | % |
| Real estate | 0% – 10% | | 4 | % | | 4 | % |
| Private equity | 0% – 5% | | (b) | | (b) |
| Diversified credit | 0% – 10% | | (b) | | (b) |
| Total | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | |
| Cash and cash equivalents | 0% – 7% | | 3 | % | | 3 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 23% – 33% | | 30 | % | | 31 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 8 | % |
| International | 9% – 19% | | 13 | % | | 15 | % |
| Global | 5% – 15% | | 10 | % | | 10 | % |
| Total equity | 55% – 65% | | 62 | % | | 64 | % |
| Debt securities | 33% – 43% | | 35 | % | | 33 | % |
| Total | | | 100 | % | | 100 | % |
(a)These target allocations reflect targets that were approved in 2021 to take effect in the subsequent year.
(b)Less than 1% of plan assets.
In general, the United States large-capitalization equity investments are passively managed or indexed, whereas the international, global, United States small-capitalization, and United States mid-capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed-income vehicles. Debt security investments in high-yield securities and non-United-States-dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. In addition to the derivative investments included in the liability hedging investment strategy described above, Ameren’s investment committee also allows investment managers to use derivatives, such as index futures, foreign exchange futures, and options, in certain situations to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2021. Fair value is defined as the price that would be received for an asset in the principal or most advantageous market for the asset in an orderly transaction between market participants on the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the measurement date or, if that is not a business day, on the last business day before that date. Securities traded in over-the-counter markets are valued by quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Investments measured under NAV as a practical expedient are based on the fair values of the underlying assets provided by the funds and their administrators. The fair value of real estate investments is based on NAV; it is determined by annual appraisal reports prepared by an independent real estate appraiser. Investments measured at NAV often provide for daily, monthly, or quarterly redemptions with 60 or less days of notice depending on the fund. For some funds, redemption may also require approval from the fund’s board of directors. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pension plans’ assets measured at fair value and NAV as of December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | | December 31, 2020 |
| Level 1 | | Level 2 | | | NAV | | Total | | | Level 1 | | Level 2 | | | NAV | | Total |
| Cash and cash equivalents | $ | — | | | $ | — | | | | $ | 116 | | | $ | 116 | | | | $ | — | | | $ | — | | | | $ | 145 | | | $ | 145 | |
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — | | | — | | | | 1,381 | | | 1,381 | | | | — | | | — | | | | 1,511 | | | 1,511 | |
| U.S. small- and mid-capitalization | 558 | | | — | | | | — | | | 558 | | | | 513 | | | — | | | | — | | | 513 | |
| International | 372 | | | — | | | | 531 | | | 903 | | | | 375 | | | — | | | | 492 | | | 867 | |
| Global | — | | | — | | | | 621 | | | 621 | | | | — | | | — | | | | 546 | | | 546 | |
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — | | | 545 | | | | 27 | | | 572 | | | | — | | | 506 | | | | 17 | | | 523 | |
| Municipal bonds | — | | | 50 | | | | — | | | 50 | | | | — | | | 50 | | | | — | | | 50 | |
| U.S. Treasury and agency securities | — | | | 1,450 | | | | — | | | 1,450 | | | | 3 | | | 1,325 | | | | — | | | 1,328 | |
| Other | 17 | | | 11 | | | | — | | | 28 | | | | (5) | | | 8 | | | | — | | | 3 | |
| Real estate | — | | | — | | | | 228 | | | 228 | | | | — | | | — | | | | 208 | | | 208 | |
| Private equity | — | | | — | | | | 1 | | | 1 | | | | — | | | — | | | | 2 | | | 2 | |
| Total | $ | 947 | | | $ | 2,056 | | | | $ | 2,905 | | | $ | 5,908 | | | | $ | 886 | | | $ | 1,889 | | | | $ | 2,921 | | | $ | 5,696 | |
Less: Medical benefit assets(a) | | | | | | | | (234) | | | | | | | | | | | (219) | |
Plus: Net receivables(b) | | | | | | | | 71 | | | | | | | | | | | 33 | |
| Fair value of pension plans’ assets | | | | | | | | $ | 5,745 | | | | | | | | | | | $ | 5,510 | |
(a)Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation.
(b)Receivables related to pending securities sales, offset by payables related to pending securities purchases.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans’ assets measured at fair value and NAV as of December 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | | | December 31, 2020 |
| Level 1 | | Level 2 | | | NAV | | Total | | | Level 1 | | Level 2 | | | NAV | | Total |
| Cash and cash equivalents | $ | 24 | | | $ | — | | | | $ | — | | | $ | 24 | | | | $ | 38 | | | $ | — | | | | $ | — | | | $ | 38 | |
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 283 | | | — | | | | 115 | | | 398 | | | | 279 | | | — | | | | 107 | | | 386 | |
| U.S. small- and mid-capitalization | 113 | | | — | | | | — | | | 113 | | | | 104 | | | — | | | | — | | | 104 | |
| International | 60 | | | — | | | | 117 | | | 177 | | | | 75 | | | — | | | | 107 | | | 182 | |
| Global | — | | | — | | | | 132 | | | 132 | | | | — | | | — | | | | 120 | | | 120 | |
| | | | | | | | | | | | | | | | | | |
| Debt securities: | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Municipal bonds | — | | | 133 | | | | — | | | 133 | | | | — | | | 106 | | | | — | | | 106 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | | 335 | | | 335 | | | | — | | | — | | | | 295 | | | 295 | |
| Total | $ | 480 | | | $ | 133 | | | | $ | 699 | | | $ | 1,312 | | | | $ | 496 | | | $ | 106 | | | | $ | 629 | | | $ | 1,231 | |
Plus: Medical benefit assets(a) | | | | | | | | 234 | | | | | | | | | | | 219 | |
Plus: Net receivables(b) | | | | | | | | 12 | | | | | | | | | | | 3 | |
| Fair value of postretirement benefit plans’ assets | | | | | | | | $ | 1,558 | | | | | | | | | | | $ | 1,453 | |
(a)Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.
(b)Receivables related to pending securities sales, offset by payables related to pending securities purchases.
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of Ameren’s pension and postretirement benefit plans during 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | | Postretirement Benefits |
| 2021 | | 2020 | | 2019 | | | 2021 | | 2020 | | 2019 |
Service cost(a) | $ | 134 | | | $ | 110 | | | $ | 88 | | | | $ | 23 | | | $ | 19 | | | $ | 18 | |
| Non-service cost components: | | | | | | | | | | | | |
| Interest cost | 152 | | | 174 | | | 187 | | | | 33 | | | 39 | | | 43 | |
| Expected return on plan assets | (297) | | | (291) | | | (276) | | | | (80) | | | (80) | | | (77) | |
| Amortization of: | | | | | | | | | | | | |
| | | | | | | | | | | | |
| Prior service credit | — | | | (1) | | | (1) | | | | (4) | | | (4) | | | (5) | |
| Actuarial (gain) loss | 73 | | | 60 | | | 25 | | | | (6) | | | (9) | | | (15) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Total non-service cost components(b) | $ | (72) | | | $ | (58) | | | $ | (65) | | | | $ | (57) | | | $ | (54) | | | $ | (54) | |
| Net periodic benefit cost (income) | $ | 62 | | | $ | 52 | | | $ | 23 | | | | $ | (34) | | | $ | (35) | | | $ | (36) | |
(a) Service cost, net of capitalization, is reflected in “Operating Expenses - Other operations and maintenance” on Ameren’s statement of income.
(b) Non-service cost components are reflected in “Other Income, Net” on Ameren’s consolidated statement of income. See Note 6 – Other Income, Net for additional information.
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Costs | | Postretirement Costs |
| | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
Ameren Missouri(a) | $ | 29 | | | $ | 22 | | | $ | 5 | | | $ | (4) | | | $ | (5) | | | $ | (6) | |
| Ameren Illinois | 34 | | | 32 | | | 20 | | | (31) | | | (31) | | | (30) | |
| Other | (1) | | | (2) | | | (2) | | | 1 | | | 1 | | | — | |
| Ameren | $ | 62 | | | $ | 52 | | | $ | 23 | | | $ | (34) | | | $ | (35) | | | $ | (36) | |
(a)Does not include the impact of the tracker 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 expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, as of December 31, 2021, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Paid from
Qualified
Trust Funds | | Paid from
Company
Funds | | Paid from
Qualified
Trust Funds | | Paid from
Company
Funds | | |
| 2022 | $ | 267 | | | $ | 2 | | | $ | 59 | | | $ | 2 | | | |
| 2023 | 274 | | | 2 | | | 60 | | | 2 | | | |
| 2024 | 279 | | | 3 | | | 61 | | | 2 | | | |
| 2025 | 284 | | | 3 | | | 61 | | | 2 | | | |
| 2026 | 288 | | | 3 | | | 60 | | | 2 | | | |
| 2027 – 2031 | 1,476 | | | 12 | | | 296 | | | 9 | | | |
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| Discount rate at measurement date | 2.75 | % | | 3.50 | % | | 4.25 | % | | 2.75 | % | | 3.50 | % | | 4.25 | % |
| Expected return on plan assets | 6.50 | | | 7.00 | | | 7.00 | | | 6.50 | | | 7.00 | | | 7.00 | |
| Increase in future compensation | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | |
| Cash balance pension plan interest crediting rate | 5.00 | | | 5.00 | | | 5.00 | | | (a) | | (a) | | (a) |
Medical cost trend rate (initial)(b) | (a) | | (a) | | (a) | | 5.00 | | | 5.00 | | | 5.00 | |
Medical cost trend rate (ultimate)(b) | (a) | | (a) | | (a) | | 5.00 | | | 5.00 | | | 5.00 | |
| | | | | | | | | | | |
(a)Not applicable.
(b)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%.
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible Ameren employees at December 31, 2021. The plan allows employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matches a percentage of the employee contributions up to certain limits. The following table presents the portion of the matching contribution to the Ameren 401(k) plan attributable to each of the Ameren Companies for the years ended December 31, 2021, 2020, and 2019:
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Ameren Missouri | $ | 21 | | | $ | 20 | | | $ | 19 | |
| Ameren Illinois | 16 | | | 17 | | | 16 | |
| Other | 1 | | | 1 | | | — | |
| Ameren | $ | 38 | | | $ | 38 | | | $ | 35 | |
