Annual Statements Open main menu
  1. Annual Statements
  2. » Companies
  3. » UNION ELECTRIC CO
  4. » Annual Report: 2021 (Form 10-K)

UNION ELECTRIC CO - Annual Report: 2021 (Form 10-K)

Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the fiscal year ended December 31, 2021
OR
☐Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the transition period from           to


aee-20211231_g1.jpg
aee-20211231_g2.jpg
aee-20211231_g3.jpg
Commission
File Number		Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number		IRS Employer
Identification No.
1-14756Ameren Corporation43-1723446
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
1-2967Union Electric Company43-0559760
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
1-3672Ameren Illinois Company37-0211380
(Illinois Corporation)
10 Executive Drive
Collinsville, Illinois 62234
(618) 343-8150
Securities Registered Pursuant to Section 12(b) of the Act:
The following security is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par value per shareAEENew York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
RegistrantTitle of each class
Union Electric CompanyPreferred Stock, cumulative, no par value, stated value $100 per share
Ameren Illinois CompanyPreferred Stock, cumulative, $100 par value
Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Ameren CorporationYes☒No☐
Union Electric CompanyYes☒No☐
Ameren Illinois CompanyYes☒No☐
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Ameren CorporationYes☐No☒
Union Electric CompanyYes☐No☒
Ameren Illinois CompanyYes☐No☒
Indicate by checkmark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Ameren CorporationYes☒No☐
Union Electric CompanyYes☒No☐
Ameren Illinois CompanyYes☒No☐
Indicate by checkmark whether each registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Ameren CorporationYes☒No☐
Union Electric CompanyYes☒No☐
Ameren Illinois CompanyYes☒No☐
Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Ameren CorporationLarge accelerated filer☒Accelerated filer☐Non-accelerated filer☐
Smaller reporting company☐Emerging growth company☐
Union Electric CompanyLarge accelerated filer☐Accelerated filer☐Non-accelerated filer☒
Smaller reporting company☐Emerging growth company☐
Ameren Illinois CompanyLarge accelerated filer☐Accelerated filer☐Non-accelerated filer☒
Smaller reporting company☐Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Ameren Corporation☐
Union Electric Company☐
Ameren Illinois Company☐
Indicate by check mark whether each registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Ameren Corporation☒
Union Electric Company☐
Ameren Illinois Company☐
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
Ameren CorporationYes☐No☒
Union Electric CompanyYes☐No☒
Ameren Illinois CompanyYes☐No☒
As of June 30, 2021, the aggregate market value of Ameren Corporation’s common stock, $0.01 par value, (based upon the closing price of the common stock on the New York Stock Exchange on June 30, 2021) held by nonaffiliates was $20,481,306,104. All of the shares of common stock of the other registrants were held by Ameren Corporation as of June 30, 2021.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2022, were as follows:
RegistrantTitle of each class of common stockShares
Ameren CorporationCommon stock, $0.01 par value per share257,724,783 
Union Electric CompanyCommon stock, $5 par value per share, held by Ameren Corporation102,123,834 
Ameren Illinois CompanyCommon stock, no par value, held by Ameren Corporation25,452,373 
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company and Ameren Illinois Company for the 2022 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois Company. Each registrant hereto is filing on its own behalf all of the information contained in this annual report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

Table of Contents
TABLE OF CONTENTS
Page
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
This report contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed.
2020 IRP – Integrated Resource Plan, a long-term nonbinding plan that Ameren Missouri filed with the MoPSC in September 2020, which includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability and achieving a goal of net-zero CO2 emissions by 2050.
Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies – Ameren Corporation, Ameren Missouri, and Ameren Illinois, collectively, which are individual registrants within the Ameren consolidated group.
Ameren Illinois – Ameren Illinois Company, an Ameren Corporation subsidiary that operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois, doing business as Ameren Illinois.
Ameren Illinois Electric Distribution – An Ameren Corporation and Ameren Illinois financial reporting segment consisting of the rate-regulated electric distribution business of Ameren Illinois.
Ameren Illinois Natural Gas – An Ameren Corporation and Ameren Illinois financial reporting segment consisting of the rate-regulated natural gas distribution business of Ameren Illinois.
Ameren Illinois Transmission – An Ameren Illinois financial reporting segment consisting of the rate-regulated electric transmission business of Ameren Illinois.
Ameren Missouri – Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri, doing business as Ameren Missouri. Ameren Missouri is a financial reporting segment of Ameren Corporation.
Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services, such as accounting, legal, treasury, and asset management services, to Ameren (parent) and its subsidiaries.
Ameren Transmission – An Ameren Corporation financial reporting segment primarily consisting of the aggregated electric transmission businesses of Ameren Illinois and ATXI.
ARO – Asset retirement obligations.
ATM program – At-the-market equity distribution program.
ATXI – Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that operates a FERC rate-regulated electric transmission business in the MISO.
Baseload – The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Base rate – The service rate charged to customers, which varies by segmentation within customer classes, excludes rates applicable to riders, and is determined by the ratemaking process used to establish the annual revenue requirement applicable to such service.
Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
CCR – Coal combustion residuals, which include fly ash, bottom ash, boiler slag, and flue gas desulfurization materials generated from burning coal to generate electricity.
CCR Rule – Coal Combustion Residuals Rule, a rule promulgated by the EPA that established regulations for the disposal of CCR in landfills and surface impoundments, and the operation and closure of such landfills and surface impoundments.
CO2 – Carbon dioxide.
COVID-19 pandemic – The global pandemic resulting from the outbreak of the 2019 novel coronavirus, which causes coronavirus disease 2019 (COVID-19).
Customer demand charges – Revenues from nonresidential customers based on their peak demand during a specified time interval.
Cooling degree days – The summation of positive differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of electricity demand by residential and commercial customers for summer cooling.
Credit Agreements – The Illinois Credit Agreement and the Missouri Credit Agreement, collectively.
CSAPR – Cross-State Air Pollution Rule, an EPA rule that requires states that contribute to air pollution in downwind states to limit air emissions from fossil-fuel-fired electric generating units.
CT – Combustion turbine, used primarily for peaking electric generation capacity.
DCA – Delivery charge adjustment, a rate-adjustment mechanism that decouples natural gas revenues from actual sales volumes for Ameren Missouri’s natural gas business and allows Ameren Missouri to adjust customer rates without a traditional regulatory rate review, subject to MoPSC prudence reviews. This mechanism ensures that Ameren Missouri’s natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions. This rate-adjustment mechanism will be replaced by the WNAR in late February 2022.
Deferred payment arrangement – A payment option that allows certain Ameren Missouri and Ameren Illinois retail customers to pay a utility bill balance over a period of time, generally over a period of up to 12 months. On a temporary basis through June 2021, Ameren Illinois’ residential retail customers could have elected to pay a utility bill balance over a period of up to 18 months.
Dekatherm – A standard unit of energy equivalent to approximately one million Btus.
1
Table of Contents
DOE – Department of Energy, a United States government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Electric margins – Electric revenues less fuel and purchased power costs.
EMANI – European Mutual Association for Nuclear Insurance.
EPA – Environmental Protection Agency, a United States government agency.
ERISA – Employee Retirement Income Security Act of 1974, as amended.
ESG – Environmental, social, and governance.
Excess deferred income taxes – Amounts resulting from the revaluation of deferred income taxes subject to regulatory ratemaking, which will be collected from, or refunded to, customers. Deferred income taxes are revalued when federal or state income tax rates change, and the offset to the revaluation of deferred income taxes subject to regulatory ratemaking is recorded to a regulatory asset or liability.
Exchange Act – Securities Exchange Act of 1934, as amended.
FAC – Fuel adjustment clause, a fuel and purchased power rate-adjustment mechanism that allows 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.
FEJA – Future Energy Jobs Act, an Illinois law that allows Ameren Illinois to earn a return on its electric energy-efficiency investments, decouples electric distribution revenues from sales volumes, offers customer rebates for installing distributed generation, and includes extensions and modifications of certain IEIMA performance-based framework provisions, among other things. The decoupling provisions ensure that electric distribution revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions.
FERC – Federal Energy Regulatory Commission, a United States government agency that regulates utility businesses and associated activities of holding and related service companies, including Ameren (parent), Ameren Missouri, Ameren Illinois, ATXI, and Ameren Services.
GAAP – Generally accepted accounting principles in the United States.
Heating degree days – The summation of negative differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter heating by residential and commercial customers.
ICC – Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including Ameren Illinois and ATXI.
IEIMA – Illinois Energy Infrastructure Modernization Act, an Illinois law that established a performance-based formula process for determining electric distribution service rates. Ameren Illinois expects to establish electric distribution rates and reconcile related revenue requirements under this process through 2023.
IETL – Illinois Energy Transition Legislation, Illinois legislation enacted in September 2021 that, among other things, gives Ameren Illinois the option to establish new electric distribution rates through either a traditional regulatory rate review, which may be based on a future test year, or an MYRP for a four-year period.
Illinois Credit Agreement – Ameren’s and Ameren Illinois’ $1.1 billion senior unsecured credit agreement, which expires in December 2025, unless extended.
IPA – Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and small commercial customers.
IRS – Internal Revenue Service, a United States government agency.
Kilowatthour – A measure of electricity consumption equivalent to the use of 1,000 watts of power over one hour.
MATS – Mercury and Air Toxics Standards, an EPA rule that limits emissions of mercury and other air toxics from coal- and oil-fired electric generating units.
MEEIA – A rate-adjustment mechanism allowed under the Missouri Energy Efficiency Investment Act, a Missouri law that allows electric utilities to recover costs and performance incentives, if any, related to MoPSC-approved customer energy-efficiency programs without a traditional regulatory rate review, subject to MoPSC prudence reviews.
MEEIA 2019 – Ameren Missouri’s portfolio of customer energy-efficiency programs, recovery of lost electric margins, and performance incentives for March 2019 through December 2024, pursuant to Missouri law, as approved by the MoPSC in December 2018.
Megawatthour or MWh – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midcontinent Independent System Operator, Inc., an RTO.
Missouri Credit Agreement – Ameren’s and Ameren Missouri’s $1.2 billion senior unsecured credit agreement, which expires in December 2025, unless extended.
Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.
Mmbtu – One million Btus.
Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.
Moody’s – Moody’s Investors Service, Inc., a credit rating agency.
MoPSC – Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including Ameren Missouri.
MTM – Mark-to-market.
2
Table of Contents
MW – Megawatt.
MYRP – Multi-year rate plan, a four-year electric distribution service rate plan allowed to be filed with the ICC under the IETL. Under a multi-year rate plan, the ICC would approve base rates for electric distribution service charged to customers for each calendar year of a four-year period. Ameren Illinois would be allowed to reconcile each year's base rates to its actual revenue requirement, subject to a reconciliation cap with exclusions for certain costs and riders, and adjustments to the ICC-determined ROE for performance incentives and penalties. 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.
Native load – End-use retail customers whom Ameren Missouri or Ameren Illinois is obligated to serve by statute, franchise, contract, or other regulatory requirement.
Natural gas margins – Natural gas revenues less natural gas purchased for resale.
NAV – Net asset value per share.
NEIL – Nuclear Electric Insurance Limited, which includes all of its affiliated companies.
NERC – North American Electric Reliability Corporation.
Net energy costs – Net energy costs, as defined in the FAC, which include fuel, fuel transportation, certain fuel additives, ash disposal costs and revenues, emission allowances, and purchased power costs, net of off-system sales and capacity revenues. Substantially all transmission revenues and charges are excluded from net energy costs. The MoPSC’s March 2020 electric rate order changed the FAC to include certain fuel additives and ash disposal costs and revenues as of April 2020. Pursuant to the MoPSC’s December 2021 electric rate order, effective February 28, 2022, all off-system sales from the High Prairie Renewable and Atchison Renewable energy centers will be excluded as those sales will be included in the RESRAM. Prior to this change, 95% of these sales were included in the FAC and 5% were included in the RESRAM.
Net metering – Net metering allows customers who generate their own electricity or subscribe to receive output from eligible facilities to feed electricity they do not use back into the grid. The customers receive a credit for the energy they add to the grid.
NOx – Nitrogen oxides.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a United States government agency that regulates commercial nuclear power plants and uses of nuclear materials.
NSPS – New Source Performance Standards, provisions under the Clean Air Act.
NSR – New Source Review provisions of the Clean Air Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.
NYSE – New York Stock Exchange, LLC.
OCI – Other comprehensive income (loss) as defined by GAAP.
Off-system sales revenues – Revenues from other than native load sales, including wholesale sales.
PGA – Purchased gas adjustment tariffs, a rate-adjustment mechanism that permits prudently incurred natural gas costs to be recovered directly from utility customers without a traditional regulatory rate review, subject to regulatory prudence reviews.
PHMSA – Pipeline and Hazardous Materials Safety Administration.
PISA – Plant-in-service accounting regulatory mechanism, a mechanism under Missouri law that permits electric utilities to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on rate base for certain property, plant, and equipment placed in service, and not included in base rates, subject to MoPSC prudence reviews. The rate base on which the return is calculated incorporates qualifying capital expenditures not included in base rates, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes. The regulatory asset for accumulated PISA deferrals earns a return at the applicable WACC. For Ameren Missouri, the PISA is effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.
QIP – Qualifying infrastructure plant, a rate-adjustment mechanism that provides Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews, subject to ICC prudence reviews. Without legislative action, the QIP will expire in December 2023.
Rate base – The basis on which a rate-regulated utility is permitted to earn a WACC. This basis is the net investment in assets used to provide utility service, which generally consists of in-service property, plant, and equipment, net of accumulated depreciation and accumulated deferred income taxes, inventories, and, depending on jurisdiction, construction work in progress.
Regulatory lag – The exposure to differences in costs incurred and actual sales volumes as compared with the associated amounts included in customer rates. Rate increase requests in traditional regulatory rate reviews can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue increases authorized by regulators will lag changing costs and sales volumes when based on historical periods.
RESRAM – Renewable energy standard rate-adjustment mechanism, a regulatory mechanism allowed under Missouri law that enables Ameren Missouri to recover costs relating to compliance with Missouri’s renewable energy standard, including recovery of investments in wind generation and other renewables, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism by adjusting customer rates on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. RESRAM regulatory assets will earn carrying costs at short-term interest rates.
3
Table of Contents
Revenue requirement – The cost of providing utility service to customers, which is calculated as the sum of a utility’s recoverable operating expenses, a return at the weighted-average cost of capital on rate base, and an amount for income taxes, based on the currently applicable statutory income tax rates and amortization associated with excess deferred income taxes.
RFP – Request for proposal.
Rider – A rate-adjustment mechanism that allows for the recovery, or refund, through customer rates of amounts specified by the mechanism without a traditional regulatory rate review.
ROE – Return on common equity.
RTO – Regional transmission organization.
S&P – S&P Global Ratings, a credit rating agency.
SEC – Securities and Exchange Commission, a United States government agency.
SERC – SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.
Smart Energy Plan – Ameren Missouri’s plan to upgrade Missouri’s electric grid through at least 2026, which assumes continuation of the PISA. Upgrades include investments to improve reliability and accommodate more renewable energy.
SO2 – Sulfur dioxide.
STEM – Science, technology, engineering, and math.
TCJA – The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities. The TCJA includes specific provisions related to regulated public utilities.
Test year – The selected period of time, typically a 12-month period, for which a utility’s historical or forecasted operating results are used to determine the revenue requirement in a regulatory rate review.
Tracker – a regulatory recovery mechanism that allows for the deferral of differences between actual costs incurred and base level expenses included in customer rates as a regulatory asset or liability. The difference is included in base rates and recovered from, or refunded to, customers over a period of time as determined in a subsequent regulatory rate review.
TSR – Total shareholder return, the cumulative return of a common stock or index over a specified period of time assuming all dividends are reinvested.
VBA – Volume balancing adjustment, a rate-adjustment mechanism for Ameren Illinois’ natural gas business that decouples natural gas revenues from actual sales volumes and allows Ameren Illinois to adjust customer rates without a traditional regulatory rate review, subject to ICC prudence reviews. The rider ensures that Ameren Illinois’ natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions, for residential and small nonresidential customers.
WACC – Weighted-average cost of capital, which is the weighted-average cost of debt and equity, as allowed by the applicable regulator.
WNAR – Weather normalization adjustment rider, a rate-adjustment mechanism that allows Ameren Missouri to adjust natural gas delivery service rates charged to residential customers without a traditional regulatory rate review, subject to MoPSC prudence reviews, when deviations from normal weather conditions cause natural gas revenues to vary from the related revenue requirement approved by the MoPSC in the previous regulatory rate review. This rate-adjustment mechanism will replace the DCA beginning February 28, 2022.
Zero emission credit – A credit that represents the environmental attributes of one MWh of energy produced from certain zero emissions nuclear-powered generation facilities, which certain Illinois utilities are required to purchase pursuant to the FEJA.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, projections, strategies, targets, estimates, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed within Risk Factors under Part I, Item 1A, of this report, and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
•regulatory, judicial, or legislative actions, and any changes in regulatory policies and ratemaking determinations, that may change regulatory recovery mechanisms, such as those that may result from the impact of a final ruling to be issued by the United States Court for the Eastern District of Missouri regarding its September 2019 remedy order for the Rush Island Energy Center, the July 2020 appeal filed by Ameren Missouri, Ameren Illinois, and ATXI challenging the refund period related to the FERC’s May 2020 order determining the allowed base ROE under the MISO tariff, and the July 2020 appeal filed by Ameren Missouri, Ameren Illinois, and ATXI challenging the FERC’s rehearing denials in the transmission formula rate revision cases;
•the length and severity of the COVID-19 pandemic, and its impacts on our business continuity plans and our results of operations, financial position, and liquidity, including but not limited to: changes in customer demand resulting in changes to sales volumes; customers’ payment for our services and their use of deferred payment arrangements; the health, welfare, and availability of our
4
Table of Contents
workforce and contractors; supplier disruptions; delays in the completion of construction projects, which could impact our expected capital expenditures and rate base growth; changes in how we operate our business and increased data security risks as a result of remote working arrangements for a significant portion of our workforce; and our ability to access the capital markets on reasonable terms and when needed;
•the effect of Ameren Illinois’ use of the performance-based formula ratemaking framework for its electric distribution service under the IEIMA, which will establish and allow for a reconciliation of electric distribution service rates through 2023, its participation in electric energy-efficiency programs, and the related impact of the direct relationship between Ameren Illinois’ ROE and the 30-year United States Treasury bond yields;
•the effect and duration of Ameren Illinois’ election to either utilize traditional regulatory rate reviews or MYRPs for electric distribution service ratemaking effective for rates beginning in 2024;
•the effect on Ameren Missouri’s investment plan and earnings if an extension to use PISA is not sought by Ameren Missouri or approved by the MoPSC;
•the effect on Ameren Missouri of any customer rate caps pursuant to Ameren Missouri’s election to use the PISA, including an extension of use beyond 2023, if requested by Ameren Missouri and approved by the MoPSC;
•the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, and energy policies;
•the effects of changes in federal, state, or local tax laws, regulations, interpretations, or rates, and challenges to the tax positions taken by the Ameren Companies, if any, as well as resulting effects on customer rates;
•the effects on energy prices and demand for our services resulting from technological advances, including advances in customer energy efficiency, electric vehicles, electrification of various industries, energy storage, and private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;
•the effectiveness of Ameren Missouri’s customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA programs;
•Ameren Illinois’ ability to achieve the performance standards applicable to its electric distribution business and electric customer energy-efficiency goals and the resulting impact on its allowed ROE;
•our ability to control costs and make substantial investments in our businesses, including our ability to recover costs and investments, and to earn our allowed ROEs, within frameworks established by our regulators, while maintaining affordability of our services for our customers;
•the cost and availability of fuel, such as low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, zero emission credits, renewable energy credits, emission allowances, and natural gas for distribution; and the level and volatility of future market prices for such commodities and credits;
•disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from the one NRC-licensed supplier of Ameren Missouri’s Callaway Energy Center assemblies;
•the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy Ameren Missouri’s energy sales;
•the effectiveness of our risk management strategies and our use of financial and derivative instruments;
•the ability to obtain sufficient insurance, or in the absence of insurance, the ability to timely recover uninsured losses from our customers;
•the impact of cyberattacks on us or our suppliers, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information;
•business and economic conditions, which have been affected by, and will be affected by the length and severity of, the COVID-19 pandemic, including the impact of such conditions on interest rates and inflation;
•disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;
•the actions of credit rating agencies and the effects of such actions, including any impacts on our credit ratings that may result from the economic conditions of the COVID-19 pandemic;
•the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments, including as they relate to the construction and acquisition of electric and natural gas utility infrastructure and the ability of counterparties to complete projects which is dependent upon the availability of necessary materials and equipment, including those that are affected by disruptions in the global supply chain caused by the COVID-19 pandemic;
•the impact of weather conditions and other natural phenomena on us and our customers, including the impact of system outages and the level of wind and solar resources;
•the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;
•the effects of failures of electric generation, electric and natural gas transmission or distribution, or natural gas storage facilities systems and equipment, which could result in unanticipated liabilities or unplanned outages;
•the operation of Ameren Missouri’s Callaway Energy Center, including planned and unplanned outages, as well as the ability to recover costs associated with such outages and the impact of such outages on off-system sales and purchased power, among other things;
5
Table of Contents
•Ameren Missouri’s ability to recover the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs;
•the impact of current environmental laws and new, more stringent, or changing requirements, including those related to NSR, and CO2, other emissions and discharges, Illinois emission standards, cooling water intake structures, CCR, energy efficiency, and wildlife protection, that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our operating costs or investment requirements, result in an impairment of our assets, cause us to sell our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;
•the impact of complying with renewable energy standards in Missouri and Illinois and with the zero emission standard in Illinois;
•Ameren Missouri’s ability to construct and/or acquire wind, solar, and other renewable energy generation facilities, retire energy centers, and implement new or existing customer energy efficiency programs, including any such construction, acquisition, retirement, or implementation in connection with its Smart Energy Plan, integrated resource plan, or emissions reduction goals, and to recover its cost of investment, related return, and, in the case of customer energy-efficiency programs, any lost margins in a timely manner, which is affected by the ability to obtain all necessary regulatory and project approvals, including certificates of convenience and necessity from the MoPSC or any other required approvals for the addition of renewable resources;
•the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind, solar, and other renewable generation and storage technologies; and our ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost for each facility;
•advancements in carbon-free generation and storage technologies, and the impact of constructive federal and state energy and economic policies with respect to those technologies;
•labor disputes, work force reductions, changes in future wage and employee benefits costs, including those resulting from changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;
•the impact of negative opinions of us or our utility services that our customers, investors, legislators, regulators or other stakeholders may have or develop, which could result from a variety of factors, including failures in system reliability, failure to implement our investment plans or to protect sensitive customer information, increases in rates, negative media coverage, or concerns about ESG practices;
•the impact of adopting new accounting guidance;
•the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
•legal and administrative proceedings; and
•acts of sabotage, war, terrorism, or other intentionally disruptive acts.
New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.
PART I
ITEM 1. BUSINESS
GENERAL
Ameren, formed in 1997 and 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.
Below is a summary description of Ameren’s principal subsidiaries – Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
•Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.
•Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.
•ATXI operates a FERC rate-regulated electric transmission business in the MISO.
For additional information about the development of our businesses, our business operations, and factors affecting our results of operations, financial position, and liquidity, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
6
Table of Contents
BUSINESS SEGMENTS
Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI.
Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.
An illustration of the Ameren Companies’ reporting structures is provided below:
aee-20211231_g4.jpg
(a)    The Ameren Transmission segment also includes allocated Ameren (parent) interest charges, as well as other subsidiaries engaged in electric transmission project development and investment.
RATES AND REGULATION
Rates
The rates that Ameren Missouri, Ameren Illinois, and ATXI are allowed to charge for their utility services significantly influence the results of operations, financial position, and liquidity of these companies and Ameren. The electric and natural gas utility industry is highly regulated. The utility rates charged to customers are determined by governmental entities, including the MoPSC, the ICC, and the FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the prudency of expenditures, the quality of service, regulatory staff knowledge and experience, customer intervention, and economic conditions, as well as social and political views. Decisions made by these governmental entities regarding customer rates are largely outside of our control. These decisions, as well as the regulatory lag involved in the process of obtaining approval for new customer rates, could have a material adverse effect on the results of operations, financial position, and liquidity of the Ameren Companies. The extent of the regulatory lag varies for each of Ameren’s electric and natural gas jurisdictions, with the Ameren Transmission and Ameren Illinois Electric Distribution businesses experiencing the least amount of regulatory lag. Depending on the jurisdiction, the effects of regulatory lag are mitigated by various means, including annual revenue requirement reconciliations, the decoupling of revenues from sales volumes to ensure revenues approved in a regulatory rate review are not affected by changes in sales volumes, the recovery of certain capital investments between traditional regulatory rate reviews, the level and timing of expenditures, the use of a future test year, and the use of trackers and riders.
7
Table of Contents
The MoPSC regulates rates and other matters for Ameren Missouri. The ICC regulates rates and other matters for Ameren Illinois. The MoPSC and the ICC regulate non-rate utility matters for ATXI. ATXI does not have retail distribution customers; therefore, the MoPSC and the ICC do not have authority to regulate ATXI’s rates. The FERC regulates Ameren Missouri’s, Ameren Illinois’, and ATXI’s cost-based rates for the wholesale transmission and distribution of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.
For additional information on Ameren Missouri, Ameren Illinois, and ATXI rate matters, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
The following table summarizes the key terms of the rate orders in effect for customer billings for each of Ameren’s rate-regulated utilities as of January 2022, except as noted:
Rate RegulatorEffective
Rate Order
Issued In		Allowed
ROE		Percent of
Common Equity		Rate Base
(in billions)
Portion of Ameren’s 2021 Operating Revenues(a)
Ameren Missouri
Electric service(b)(c)
MoPSC
December 2021(d)
(d)(d)$10.250%
Natural gas delivery service(b)
MoPSC
December 2021(e)
(e)(e)$0.32%
Ameren Illinois
Electric distribution delivery service(f)
ICCDecember 20217.36%51.00%$3.725%
Natural gas delivery service(g)
ICCJanuary 20219.67%52.00%$2.115%
Electric transmission service(h)
FERC(g)10.52%54.02%$3.05%
ATXI
Electric transmission service(h)
FERC(g)10.52%59.96%$1.43%
(a)Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and natural gas purchased for resale for natural gas delivery service, and intercompany eliminations.
(b)New rates approved by the MoPSC’s December 2021 electric and natural gas rate orders will become effective on February 28, 2022.
(c)Ameren Missouri’s electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate. Because the bundled rates charged to MoPSC retail customers include the revenue requirement associated with Ameren Missouri's FERC-regulated transmission services, the table above does not separately reflect a FERC-authorized rate base or allowed ROE.
(d)This rate 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.
(e)This rate order did not specify an ROE or a capital structure.
(f)Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. This rate order was based on 2020 actual costs, expected net plant additions for 2021, and the annual average of the monthly yields during 2020 of the 30-year United States Treasury bonds plus 580 basis points, which was 1.56%. Ameren Illinois’ 2022 electric distribution delivery service revenues will be based on its 2022 actual recoverable costs, rate base, common equity percentage, and an allowed ROE, as calculated under the IEIMA’s performance-based formula ratemaking framework.
(g)This rate order was based on a 2021 future test year.
(h)Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking framework based on each year’s forecasted information. The 10.52% return, which includes a 50 basis points incentive adder for participation in an RTO, is based on the FERC’s May 2020 order. For additional information regarding this order and related requests for rehearing, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
General Regulatory Matters
Ameren Missouri, Ameren Illinois, and ATXI must receive FERC approval to enter into various transactions, such as issuing short-term debt securities and conducting certain acquisitions, mergers, and consolidations involving electric utility holding companies. In addition, Ameren Missouri, Ameren Illinois, and ATXI must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities and to conduct mergers, affiliate transactions, and various other activities.
Ameren Missouri, Ameren Illinois, and ATXI are also subject to mandatory reliability standards, including cybersecurity standards adopted by the FERC, to ensure the reliability of the bulk electric power system. These standards are developed and enforced by the NERC, pursuant to authority delegated to it by the FERC. Ameren Missouri, Ameren Illinois, and ATXI are members of the SERC. The SERC is one of six regional entities representing all or portions of 16 central and southeastern states under authority from the NERC for the purpose of implementing and enforcing reliability standards approved by the FERC. The regional entities of the NERC work to safeguard the reliability of the bulk power systems throughout North America. If any of Ameren Missouri, Ameren Illinois, or ATXI is found not to be in compliance with these mandatory reliability standards, it could incur substantial monetary penalties and other sanctions.
8
Table of Contents
Under the Public Utility Holding Company Act of 2005, the FERC and the state public utility regulatory agencies in each state Ameren and its subsidiaries operate in may access books and records of Ameren and its subsidiaries that are found to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries that may affect jurisdictional rates. The act also permits the MoPSC and the ICC to request that the FERC review cost allocations by Ameren Services to other Ameren subsidiaries.
Operation of Ameren Missouri’s Callaway Energy Center is subject to regulation by the NRC. The license for the Callaway Energy Center expires in 2044. Ameren Missouri’s hydroelectric Osage Energy Center and pumped-storage hydroelectric Taum Sauk Energy Center, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other aspects, the general operation and maintenance of the projects. The licenses for the Osage Energy Center and the Taum Sauk Energy Center expire in 2047 and 2044, respectively. Ameren Missouri’s Keokuk Energy Center and its dam on the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.
For additional information on regulatory matters, see Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
Environmental Matters
Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety. These environmental statutes and regulations are comprehensive and include the storage, handling, and disposal of waste materials, emergency planning and response requirements, limitations and standards applicable to discharges from our facilities into the air or water that are enforced through permitting requirements, and wildlife protection laws, including those related to endangered species. These environmental regulations could also affect the availability of, the cost of, and the demand for electricity and natural gas sold to Ameren Missouri’s and Ameren Illinois’ customers as well as the demand for off-system sales. Federal, state, and local authorities continually revise these regulations, which adds uncertainty to our planning process and to the ultimate implementation of these or other new or revised regulations. Failure to comply with these laws could have a material adverse effect on us. We could be subject to criminal or civil penalties by regulatory agencies, or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing laws that currently apply to our operations.
For discussion of environmental matters, including NOx and SO2 emission reduction requirements, regulation of CO2 emissions, wastewater discharge standards, remediation efforts, CCR management regulations, and a discussion of litigation against Ameren Missouri with respect to NSR, the Clean Air Act, and Missouri law in connection with projects at Ameren Missouri’s Rush Island Energy Center, see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
TRANSMISSION
Ameren owns an integrated transmission system that is composed of the transmission assets of Ameren Missouri, Ameren Illinois, and ATXI. Ameren also operates two MISO balancing authority areas: AMMO and AMIL. The AMMO balancing authority area includes the load and energy centers of Ameren Missouri, and had a peak demand of 7,390 MWs in 2021. The AMIL balancing authority area includes the load of Ameren Illinois, and had a peak demand of 8,504 MWs in 2021. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
Ameren Missouri, Ameren Illinois, and ATXI are transmission-owning members of the MISO. Ameren Missouri is authorized by the MoPSC to participate in the MISO through May 2024. Ameren Missouri is periodically required to make a filing with the MoPSC regarding its continued participation in the MISO. The next filing is due in 2023.
SUPPLY OF ELECTRIC POWER
Ameren Missouri
Ameren Missouri’s electric supply is primarily generated from its energy centers. Factors that could cause Ameren Missouri to purchase power include, among other things, energy center outages, the fulfillment of renewable energy requirements, extreme weather conditions, the availability of power at a cost lower than its generation cost, and the lack of sufficient owned generation.
Ameren Missouri files a long-term nonbinding integrated resource plan with the MoPSC every three years. The most recent integrated resource plan, filed in September 2020, includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability and customer affordability. In August 2021, the MoPSC issued an order affirming the plan’s compliance with Missouri law. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, hydro, and nuclear power, and supports increased investment in new energy technologies. It also includes expanding renewable sources by adding 3,100 MWs of renewable generation by the end of 2030 and a total of 5,400 MWs of renewable generation by 2040,
9
Table of Contents
inclusive of the High Prairie Renewable and Atchison Renewable energy centers, the expectation that Ameren Missouri will seek NRC approval for an extension of the operating license for the Callaway Energy Center, expanding customer energy-efficiency programs, adding cost-effective demand response programs, accelerating the retirement dates of the Sioux and Rush Island coal-fired energy centers to 2028 and 2039, respectively, and retiring the remaining coal-fired energy centers as they reach the end of their useful lives, including the Meramec Energy Center by the end of 2022. The addition of a renewable generation facility is subject to obtaining necessary project approvals, including FERC approval and the issuance of a certificate of convenience and necessity by the MoPSC, as applicable. Ameren Missouri would be adversely affected if the MoPSC does not allow recovery of the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. In December 2021, the MoPSC issued an order in Ameren Missouri’s 2021 electric service regulatory rate review, which, among other things, approved a change in the depreciable lives of the Sioux and Rush Island energy centers’ assets consistent with Ameren Missouri’s 2020 IRP. Due to the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, Ameren Missouri plans to retire the Rush Island Energy Center prior to the 2039 date discussed above. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect an accelerated retirement date for the Rush Island Energy Center and the impact of new emission standards pursuant to the IETL, as discussed in Note 14 – Commitments and Contingencies, among other things. The next integrated resource plan is expected to be filed in September 2023.
Ameren Missouri continues to evaluate its longer-term needs for new generating capacity. The need for investment in new sources of energy is dependent on several key factors, including continuation of and customer participation in energy-efficiency programs, the amount of distributed generation from customers, load growth, technological advancements, costs of generation alternatives, environmental regulation of coal-fired power plants, and state renewable energy requirements, which could lead to the retirement of current baseload assets before the end of their current useful lives or alterations in the way those assets operate, which could result in increased capital expenditures and/or increased operations and maintenance expenses. Because of the significant time required to plan, acquire permits for, and build a baseload energy center, Ameren Missouri continues to study alternatives and to take steps to preserve options to meet future demand. Steps include evaluating the potential for further diversification of Ameren Missouri’s generation portfolio through renewable energy generation, including wind and solar generation, extending the operating license for the Callaway Energy Center, additional customer energy-efficiency and demand response programs, distributed energy resources, and energy storage.
Missouri law requires Ameren Missouri to offer solar rebates and net metering to certain customers that install renewable generation at their premises. The cost of the rebates are deferred as a regulatory asset under the RESRAM, and earn carrying costs at short-term interest rates. Customers that elect to enroll in net metering are allowed to net their generation against their usage within each billing month.
Ameren Illinois
In Illinois, while electric transmission and distribution service rates are regulated, power supply prices are not. Although electric customers are allowed to purchase power from an alternative retail electric supplier, Ameren Illinois is required to be the provider of last resort for its electric distribution customers. In 2021, 2020, and 2019, Ameren Illinois procured power on behalf of its customers for 23%, 23%, and 22%, respectively, of its total kilowatthour sales. Power purchased by Ameren Illinois for its electric distribution customers who do not elect to purchase their power from an alternative retail electric supplier comes either through procurement processes conducted by the IPA or through markets operated by the MISO. The IPA administers an RFP process through which Ameren Illinois procures its expected supply. The power and related procurement costs incurred by Ameren Illinois are passed directly to its electric distribution customers through a cost recovery mechanism. Transmission costs are charged to customers who purchase electricity from Ameren Illinois and to alternative retail electric suppliers through a cost recovery mechanism. The power, power procurement, and transmission costs are reflected in Ameren Illinois Electric Distribution’s results of operations, but do not affect Ameren Illinois Electric Distribution’s earnings because these costs are offset by corresponding revenues. Ameren Illinois charges distribution service rates to electric distribution customers who purchase electricity, regardless of supplier, which does affect Ameren Illinois Electric Distribution’s earnings.
Illinois law requires Ameren Illinois to offer rebates and net metering to certain customers that install renewable generation or paired energy storage systems at their premises. The cost of the rebates are deferred as a regulatory asset, which earn a return at the applicable WACC. Customers that elect to receive a rebate and are enrolled in net metering are allowed to net their supply service charges, but not their distribution service charges. By law, Ameren Illinois’ electric distribution revenues are decoupled from sales volumes, which ensures that the electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes.
POWER GENERATION
Ameren Missouri owns energy centers that rely on a diverse fuel portfolio, including coal, nuclear, and natural gas, as well as renewable sources of generation, which include hydroelectric, wind, methane gas, and solar. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978. The Callaway nuclear energy center began operation in 1984 and is licensed to operate until 2044. As of December 31, 2021, Ameren Missouri’s coal-fired energy centers represented 10% and 20% of Ameren’s and Ameren Missouri’s rate base, respectively. See Item 2 – Properties under Part I of this report for information regarding Ameren Missouri’s energy centers.
10
Table of Contents
Coal
Ameren Missouri has an ongoing need for coal as fuel for generation, and pursues a price-hedging strategy consistent with this requirement. Ameren Missouri has agreements in place to purchase and transport coal to its energy centers. While Ameren Missouri has minimum purchase obligations associated with these agreements, the majority of these agreements are not associated with any specific coal-fired energy center. As of December 31, 2021, Ameren Missouri had price-hedged 99% of its expected coal supply and 100% of its coal transportation requirements for generation in 2022. Ameren Missouri has additional coal supply under contract through 2025. The Powder River Basin coal transport agreements that Ameren Missouri has with Union Pacific Railroad and Burlington Northern Santa Fe Railway are currently set to expire at the end of 2024. Ameren Missouri burned approximately 16.5 million tons of coal in 2021.
About 98% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming, which has a limited number of suppliers. The remaining coal is typically purchased from the Illinois Basin. Targeted coal inventory levels may be adjusted because of generation levels or uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion, staffing and equipment issues, infrastructure maintenance, derailments, weather, and supplier financial hardship. Coal suppliers in the Powder River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations and concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2021, coal inventories at the Sioux and Rush Island energy centers were near targeted levels, and coal inventories at the Labadie Energy Center were below targeted levels due to transportation disruptions in 2021. Ameren Missouri is actively managing inventories at the Meramec Energy Center in preparation for its expected 2022 retirement. Disruptions in coal deliveries could cause Ameren Missouri to pursue a strategy that could include reducing off-system sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
Nuclear
The production of nuclear fuel involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, the enrichment of that gas, the conversion of the enriched uranium hexafluoride gas into uranium dioxide fuel pellets, and the fabrication into fuel assemblies. Ameren Missouri has entered into uranium, uranium conversion, uranium enrichment, and fabrication contracts to procure the fuel supply for its Callaway Energy Center.
The Callaway Energy Center has historically required refueling at 18-month intervals. 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 next refueling is scheduled for the spring of 2022. Ameren Missouri has inventories and supply contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at least through the 2026 refueling. Fuel fabrication service contracts extend through 2023, and procurement efforts are ongoing to extend this coverage.
RENEWABLE ENERGY AND ZERO EMISSION STANDARDS
Missouri and Illinois laws require electric utilities to include renewable energy resources in their portfolios. Ameren Missouri and Ameren Illinois satisfied their renewable energy portfolio requirements in 2021.
Ameren Missouri
In Missouri, utilities were required to purchase or generate electricity equal to at least 15% of native load sales from renewable energy sources in 2021. The requirement, which is applicable to 2022 and each year thereafter, is subject to an average 1% annual increase on customer rates over any 10-year period. At least 2% of the annual renewable energy requirement must be derived from solar energy. Ameren Missouri expects to satisfy the nonsolar requirement in 2022 with its High Prairie Renewable, Atchison Renewable, Keokuk, and Maryland Heights energy centers, a 102-MW power purchase agreement with a wind farm operator, and immaterial renewable energy credit purchases in the market. The High Prairie Renewable and Atchison Renewable energy centers are wind generation facilities. The Keokuk Energy Center generates electricity using a hydroelectric dam located on the Mississippi River. The Maryland Heights Energy Center generates electricity by burning methane gas collected from a landfill. Ameren Missouri is meeting the solar energy requirement by purchasing solar-generated renewable energy credits from customer-installed systems and by generating energy at its solar facilities.
Ameren Illinois
In accordance with Illinois law, Ameren Illinois is required to collect funds from all electric distribution customers to fund IPA procurement events for renewable energy credits. The IPA establishes its long-term renewable resources procurement plans in a filing made every two years. Based on IPA procurement events, Ameren Illinois has contractual commitments of approximately 0.9 million wind renewable energy credits per year and approximately 1.1 million solar renewable energy credits per year. Ameren Illinois has also entered into 20-year
11
Table of Contents
contracts, ending in 2032, to purchase approximately 0.6 million wind renewable energy credits per year. The IETL, which was enacted in September 2021, increased the amount Ameren Illinois collects from customers to fund IPA renewable energy credit procurement events from $1.81 per MWh to $4.58 per MWh, beginning in February 2022. Also, pursuant to the IETL, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to a reconciliation proceeding, the first of which is expected to be initiated after August 2023. Based on amounts collected from customers and renewable energy credit purchases under contract, Ameren Illinois does not expect the first reconciliation proceeding to result in refunds to customers. The IPA is expected to file its first long-term renewable resources procurement plan under the IETL in March 2022, which, once approved by the ICC, will establish the 2022 and 2023 renewable energy credit procurement targets.
Illinois law also required Ameren Illinois to enter into contracts for zero emission credits in an amount equal to approximately 16% of the actual amount of electricity delivered to retail customers during calendar year 2014, pursuant to Illinois’ zero emission standard. As a result of a 2018 IPA procurement event, which was approved by the ICC, Ameren Illinois entered into agreements to acquire zero emission credits through 2026. Annual zero emission credit commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Both renewable energy credits and zero emission credits have cost recovery mechanisms, which allow Ameren Illinois to collect from, or refund to, customers differences between actual costs incurred from the resulting contracts and the amounts collected from customers.
CUSTOMER ENERGY-EFFICIENCY PROGRAMS
Ameren Missouri and Ameren Illinois have implemented energy-efficiency programs to educate their customers and to help them become more efficient energy consumers. These programs provide incentives to customers for installing newer, more efficient technology, and for using energy in a more conservation-minded manner. As a component of the energy-efficiency programs, Ameren Missouri and Ameren Illinois have invested in electric smart meters to provide customers more visibility to their energy consumption and facilitate more efficient use of energy. As of December 31, 2021, smart meters have been installed for approximately 37% of Ameren Missouri’s electric customers and nearly all of Ameren Illinois’ electric customers.
Ameren Missouri
In Missouri, the Missouri Energy Efficiency Investment Act established a rider that, among other things, allows electric utilities to recover costs with respect to MoPSC-approved customer energy-efficiency programs. The law requires the MoPSC to ensure that a utility’s financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy-efficiency programs. Missouri does not have a law mandating energy-efficiency programs.
In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2023 and low-income customer energy-efficiency programs through December 2024, along with a rider. Ameren Missouri intends to invest approximately $360 million over the life of the plan, including $70 million in 2022 and $75 million in 2023. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals. If the target goals are achieved for 2021 and 2022, additional revenues of $24 million would be recognized in 2022, and, if target goals are achieved for 2023, additional revenues of $13 million would be recognized in 2023. Through 2021, Ameren Missouri has invested $202 million in MEEIA 2019 customer energy-efficiency programs. Additionally, as part of its Smart Energy Plan, Ameren Missouri has invested $195 million in smart meters since 2019.
The MEEIA 2019 plan includes the continued use of the MEEIA rider. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any difference between actual program costs, lost electric margins, and any performance incentive and the amounts collected from customers, without a traditional regulatory rate review, subject to MoPSC prudence reviews, until lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates, based upon both forecasted program costs and lost electric margins and collected via the MEEIA rider, are reconciled annually to actual results.
Ameren Illinois
State law requires Ameren Illinois to offer customer energy-efficiency programs, and imposes electric energy-efficiency savings goals and a maximum annual amount of investment in electric energy-efficiency programs. Every four years, Ameren Illinois is required to file a four-year electric energy-efficiency plan with the ICC. In July 2021, the ICC issued an order approving Ameren Illinois’ electric and natural gas energy-efficiency plans for 2022 through 2025, as well as regulatory recovery mechanisms. The order authorized electric and natural gas energy-efficiency program expenditures of $425 million and $66 million, respectively, over the four-year period. Subsequent to this order, the IETL was enacted, which increased the allowed annual investments in electric energy-efficiency programs from approximately $100 million to approximately $120 million for the 2022 to 2025 period, among other things. Ameren Illinois expects to file a revised energy-efficiency plan with the ICC by early March 2022 to reflect the increased level of annual investments allowed under the IETL. Pursuant to the IETL, the annual maximum amount of investment for 2026 to 2029 is approximately $120 million and may increase by up to approximately $30 million depending on the election of certain customers to participate in the programs.
12
Table of Contents
Illinois law allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the applicable WACC, with the ROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The allowed ROE on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. While the ICC approves Ameren Illinois’ four-year electric energy-efficiency plans, the ICC has the ability to reduce the amount of approved 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 included in the electric distribution service performance-based formula ratemaking framework. Ameren Illinois’ natural gas energy-efficiency program costs are recovered through a rider.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their customers. Ameren Missouri and Ameren Illinois each develop and manage a portfolio of natural gas supply resources. These resources include firm natural gas supply agreements with producers, firm interstate and intrastate transportation capacity, firm no-notice storage capacity leased from interstate pipelines, and on-system storage facilities to maintain natural gas deliveries to customers throughout the year and especially during peak demand periods. Ameren Missouri and Ameren Illinois primarily use Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, Mississippi River Transmission Corporation, Northern Border Pipeline Company, and Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to transactions requiring physical delivery, certain financial instruments, including those entered into in the New York Mercantile Exchange futures market and in the over-the-counter financial markets, are used to hedge the price paid for natural gas. Natural gas supply costs are passed on to customers of Ameren Missouri and Ameren Illinois under PGA clauses, subject to prudence reviews by the MoPSC and the ICC. As of December 31, 2021, Ameren Missouri and Ameren Illinois had price-hedged 96% and 93%, respectively, of their expected remaining natural gas supply requirements for the peak winter season through March 2022.
For additional information on our fuel, purchased power, and natural gas for distribution supply, see Results of Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Commodity Price Risk under Part II, Item 7A, of this report. Also see Note 1 – Summary of Significant Accounting Policies, Note 7 – Derivative Financial Instruments, Note 13 – Related-party Transactions, Note 14 – Commitments and Contingencies, and Note 15 – Supplemental Information under Part II, Item 8 of this report.
HUMAN CAPITAL MANAGEMENT
The execution of Ameren’s core strategy to invest and operate in a manner consistent with existing regulatory frameworks, advocate for responsible policies, and capitalize on investment opportunities to deliver superior customer and shareholder value is driven by the capabilities and engagement of our workforce. Ameren’s workforce strategy is designed to promote a skilled and diverse workforce that is prepared to deliver on Ameren’s mission (To Power the Quality of Life) and vision (Leading the Way to a Sustainable Energy Future), both today and in the future. Our workforce strategy is anchored in four key pillars: Culture, Leadership, Talent, and Rewards, which are discussed further below. Foundational to our workforce strategy are our core values of:
•Safety and security
•Commitment to excellence
•Respect
•Accountability
•Diversity, equity, and inclusion
•Integrity
•Teamwork
•Stewardship
Ameren’s chief executive officer and chief human resources officer, with the support of other leaders of the Ameren Companies, are responsible for developing and executing our workforce strategy. In addition to reviewing and determining the Ameren Companies’ compensation practices and policies for the chief executive officer and other executive officers, the Human Resources Committee of Ameren’s board of directors is responsible for oversight of Ameren’s human capital management practices and policies, including those related to diversity, equity, and inclusion. The Human Resources Committee and Ameren’s board of directors are updated regularly on human capital matters.
Culture
We strive to cultivate a values-based “All-In” culture that enables the sustainable execution of our core strategy and reflects the following characteristics:
•We Care about our customers, our communities, and each other
•We Serve with Passion
•We Deliver for our customers and stakeholders, today and tomorrow
•We Win Together as a result of our teamwork and collaboration
13
Table of Contents
We design our human capital management practices and policies to reinforce our core values, foster our culture, and drive employee engagement. In doing so, we strive to align our employees to our mission and vision, improve safety, enhance innovation, increase productivity, attract and retain top talent, and recognize employee contributions, among other things. We assess employee engagement through a variety of channels. As a part of our assessment, we conduct confidential employee engagement surveys at least annually to identify areas of strength and opportunities for improvement in our employees’ experience, and take actions aimed at increasing employee engagement.
As a part of our All-In culture, every employee is expected to challenge any unsafe act, complete each workday safely, and provide feedback on safety and security matters. In addition to comprehensive safety and security standards, and mandatory health, safety, and security training programs for applicable employees, we promote programs designed to encourage employees to provide feedback on practices or actions that could harm employees, customers, or the Ameren Companies, including perceived issues related to safety, security (both physical and cyber), ethics and compliance violations, or acts of discrimination. For additional information about the actions taken that were designed to protect the safety of our employees and customers during the COVID-19 pandemic, see The COVID-19 Pandemic section below.
We seek to foster diversity, equity, and inclusion across our organization. We contribute to community-based organizations, hold diversity, equity, and inclusion leadership summits for employees and community leaders, and offer various training programs. We also offer a program to provide paid-time off for employees who engage in volunteer or learning opportunities with organizations that support diversity, equity, and inclusion. We also have employee resource groups, which bring together groups of employees who share common interests or backgrounds. Within these groups, employees collaborate to address concerns and provide training and development opportunities related to challenges or barriers, and offer support for each other, among other things.
Leadership
Ameren’s leaders play a critical role in setting and executing Ameren’s strategic initiatives, modeling our values and culture, and engaging and enabling the workforce. As such, we seek to develop a strong, diverse leadership team. Management engages in an extensive succession planning process annually, which includes the involvement by Ameren’s board of directors. We develop our leaders both individually, through job rotations, work experiences, and leadership development programs, and as a team, through collaborative learning and mentoring relationships. Throughout the year, we offer a variety of forums intended to connect our leaders to our mission, values, strategy and culture, build leadership skills and capabilities, and to promote connection and inclusion. In addition, we evaluate our organizational structure and make adjustments and expand roles to facilitate execution of our strategy and organizational efficiency.
Talent
In order to attract and retain a skilled and diverse workforce, we promote an inclusive work environment, provide opportunities for employees to expand their knowledge and skill sets, and support career development. Our talent management initiatives include a wide range of recruiting partnerships and programs, including those programs discussed below. Our onboarding efforts are designed to ensure early engagement, including the opportunity to participate in mentoring programs. Additionally, employees are encouraged to participate in technical, professional, and leadership development opportunities, and outreach initiatives to engage with the communities that we serve, among other things. As our business needs change, we remain focused on ensuring that our workforce has the tools and skills necessary to deliver on our strategic initiatives.
We have established programs to recruit early and mid-career talent to further enhance the diversity of our workforce pipelines. These programs include skilled craft education and training for individuals interested in skilled craft roles, an intern/co-op program that serves as a pipeline for STEM-related careers, a career reentry program for experienced professionals transitioning from voluntary career breaks, a program for individuals transitioning from military service, and an early career rotation program. Additionally, each year management and the Human Resources Committee of Ameren’s board of directors review the diversity of our workforce, leadership team, and leadership development pipeline, as well as the actions taken to further enhance the diversity of our leadership team.
Workforce
The majority of our workforce is comprised of skilled-craft and STEM-related professional and technical employees. Our workforce has been stable, with a total attrition rate of 8% in 2021. The majority of employee attrition is attributable to employee retirements, generally
14
Table of Contents
allowing for thoughtful workforce and succession planning in advance of these planned transitions. The following table presents our employee count and their average tenure as of December 31, 2021, and the attrition rate in 2021:
Employee
Count		Average Tenure
(in years)		Attrition
Rate
Ameren9,116148%
Ameren Missouri3,998157%
Ameren Illinois3,239149%
Ameren Services1,879119%
Ameren’s workforce is diverse in many ways. At the officer level, which represents 54 individuals, 22% are female, and 20% are racially and/or ethnically diverse. The following table presents our total employee population that is represented by a collective bargaining unit, is a female, or is racially and/or ethnically diverse at December 31, 2021:
Collective Bargaining UnitFemaleRacially and/or Ethnically Diverse
Ameren48%24%16%
Ameren Missouri58%17%15%
Ameren Illinois55%24%13%
Ameren Services12%40%23%
The following table presents Ameren’s employees by generation at December 31, 2021:
Generation DescriptionAmerenAmeren MissouriAmeren IllinoisAmeren Services
Baby Boomer (birth years between 1946 and 1964)20%21%19%20%
Generation X (birth years between 1965 and 1980)41%41%40%42%
Millennials (birth years between 1981 and 1996)36%35%39%35%
Generation Z/Post Millennial (birth years after 1997)3%3%2%3%
Collective bargaining units at Ameren’s subsidiaries consist of the International Brotherhood of Electrical Workers, the International Union of Operating Engineers, the Laborer’s International Union of North America, the United Association of Plumbers and Pipefitters, and the United Government Security Officers of America. The Ameren Companies expect continued constructive relationships with their respective labor unions. All of the Ameren Missouri collective bargaining unit contracts expire in 2022. The Ameren Illinois collective bargaining unit contracts expire in 2022 and 2023, which cover 92% and 8% of represented employees, respectively. Ameren Missouri and Ameren Illinois expect to renew these contracts prior to their expiration.
Rewards
The primary objective of our rewards program is to provide a total rewards package that attracts and retains a talented workforce and reinforces strong performance in a financially sustainable manner. Management continuously evaluates our core benefits in an effort to create a market-competitive, performance-based, shareholder-aligned total rewards package with a view towards balancing employee value and financial sustainability. We recognize that the rewards package required to attract and retain talent over the long term is about more than pay and benefits; it is about the total employee experience and supporting their overall well-being. In addition to base salary, medical benefits, and retirement benefits, including 401(k) savings and pension, our total rewards package includes short-term incentives and long-term stock-based compensation for certain employees. Further, we offer our employees various programs that encourage overall well-being, including wellness and employee assistance programs. We strive to provide a competitive and sustainable rewards package that supports our ability to attract, engage, and retain a talented and diverse workforce, while at the same time reinforcing and rewarding strong performance.
THE COVID-19 PANDEMIC
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. Although restrictions on social activities and nonessential businesses implemented in our service territories in 2020 have been relaxed, additional restrictions may be imposed in the future.
15
Table of Contents
During the COVID-19 pandemic, Ameren has taken significant actions designed to protect the safety of our employees and customers, including restricting travel for employees, implementing work-from-home policies, offering voluntary leave of absence arrangements and flexible reduced work schedules, enhancing paid time off programs for impacted employees, securing and supplying personal protective equipment, and implementing work practices to protect the safety of our employees and customers. In addition to our existing employee assistance program, we continue to provide additional resources on physical, emotional, and financial well-being throughout the pandemic. We are capitalizing on the opportunities presented by the COVID-19 pandemic, including advancing the digital enablement of our workforce and enhancing our facilities and workforce policies and practices to increase collaboration and productivity.
For further discussion of the impact to our businesses related to the pandemic and regulatory mechanisms that reduce these impacts, see Overview, Results of Operations, and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
INDUSTRY ISSUES
We are facing issues common to the electric and natural gas utility industry. These issues include:
•the potential for changes in laws, regulations, enforcement efforts, and policies at the state and federal levels;
•corporate tax law changes, as well as additional interpretations, regulations, amendments, or technical corrections that affect the amount and timing of income tax payments, reduce or limit the ability to claim certain deductions and use carryforward tax benefits and/or credits, or result in rate base reductions;
•cybersecurity risks, cyber attacks, including ransomware and other ransom-based attacks, hacking, social engineering, and other forms of malicious cybersecurity and/or privacy events, which could result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the theft or inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information;
•political, regulatory, and customer resistance to higher rates;
•the potential for more intense competition in generation, supply, and distribution, including new technologies and their declining costs;
•the impact and effectiveness of vegetation management programs;
•the potential for reliability issues as fossil-fuel-fired and nuclear generation facilities are retired and replaced with renewable energy generation sources, and the impact on customer rates;
•the modernization of the electric grid to accommodate a two-way flow of electricity and increase capacity for distributed generation interconnection;
•net metering rules and other changes in existing regulatory frameworks and recovery mechanisms to address the allocation of costs to customers who own generation resources that enable them both to sell power to us and to purchase power from us through the use of our transmission and distribution assets;
•legislation or programs to encourage or mandate energy efficiency, energy conservation, and renewable sources of power, and the lack of consensus as to how those programs should be paid for;
•pressure and uncertainty on customer growth and sales volumes in light of the COVID-19 pandemic and other economic conditions, distributed generation, energy storage, technological advances, and energy-efficiency or conservation initiatives;
•changes in the structure of the industry as a result of changes in federal and state laws, including the formation and growth of independent transmission entities;
•changes in the allowed ROE on FERC-regulated electric transmission assets;
•the availability of fuel and fluctuations in fuel prices;
•the availability of materials and equipment, and the potential disruptions in supply chains, including those resulting from the COVID-19 pandemic;
•the availability of a skilled work force, including transferring the specialized knowledge of those who are nearing retirement to employees succeeding them;
•inflationary pressures on the prices of commodities, labor, services, materials, and supplies;
•the potential for reduced efficiency and productivity due to the transition to hybrid remote working arrangements for non-field employees;
•regulatory lag;
•the influence of macroeconomic factors on yields of United States Treasury securities and on the allowed ROE provided by regulators;
•higher levels of infrastructure and technology investments and adjustments to customer rates associated with the refund of excess deferred income taxes that have resulted in, and are expected to continue to result in, negative or decreased free cash flow, which is defined as cash flows from operating activities less cash flows from investing activities and dividends paid;
•the demand for access to renewable energy generation at rates acceptable to customers;
•public concerns about the siting of new facilities, and challenges that members of the public can assert against applications for governmental permits and other approvals required to site and build new facilities that can result in significant cost increases, delays and denial of the permits and approvals by the regulators;
16
Table of Contents
•complex new and proposed environmental laws including statutes, regulations, and requirements, such as air and water quality standards, mercury emissions standards, limitations on the use of natural gas in generation, CCR management requirements, and potential CO2 limitations, which may limit, or result in the cessation of, the operation of electric generating units;
•public concerns about the potential environmental impacts from the combustion of fossil fuels, as well as pressure from public interest groups regarding limiting the use of natural gas;
•certain investors’ concerns about investing in utility companies that have coal-fired generation assets;
•increasing scrutiny by investors and other stakeholders of ESG practices;
•aging infrastructure and the need to construct new power generation, transmission, and distribution facilities, which have long time frames for completion, with limited long-term ability to predict power and commodity prices and regulatory requirements;
•public concerns about nuclear generation, decommissioning, and the disposal of nuclear waste;
•industry reputational challenges resulting from inappropriate lobbying and similar activities by certain utility companies; and
•consolidation of electric and natural gas utility companies.
We are monitoring all these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

17
Table of Contents
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
Electric Operating Statistics – Year Ended December 31,
202120202019
Electric Sales – kilowatthours (in millions):
Ameren Missouri:
Residential13,366 13,267 13,532 
Commercial13,556 13,117 14,269 
Industrial4,151 4,158 4,242 
Street lighting and public authority81 88 99 
Ameren Missouri retail load subtotal31,154 30,630 32,142 
Off-system7,425 7,578 5,477 
Ameren Missouri total38,579 38,208 37,619 
Ameren Illinois Electric Distribution(a):
Residential11,620 11,491 11,675 
Commercial11,795 11,414 12,341 
Industrial11,076 10,674 11,587 
Street lighting and public authority430 442 491 
Ameren Illinois Electric Distribution total34,921 34,021 36,094 
Eliminate affiliate sales(412)(322)(84)
Ameren total73,088 71,907 73,629 
Electric Operating Revenues (in millions):
Ameren Missouri:
Residential$1,445 $1,373 $1,403 
Commercial1,126 1,025 1,157 
Industrial280 261 278 
Other, including street lighting and public authority170 155 127 

Ameren Missouri retail load subtotal$3,021 $2,814 $2,965 
Off-system191 170 144 
Ameren Missouri total$3,212 $2,984 $3,109 
Ameren Illinois Electric Distribution:
Residential$933 $867 $848 
Commercial545 486 497 
Industrial135 124 127 
Other, including street lighting and public authority26 21 32 
Ameren Illinois Electric Distribution total$1,639 $1,498 $1,504 
Ameren Transmission:
Ameren Illinois Transmission(b)
$365 $329 $288 
ATXI199 194 176 
Eliminate affiliate revenues(2)— — 
Ameren Transmission total$562 $523 $464 
Other and intersegment eliminations(116)(94)(96)
Ameren total$5,297 $4,911 $4,981 
(a)Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2021, 2020, and 2019, Ameren Illinois procured power on behalf of its customers for 23%, 23%, and 22%, respectively, of its total kilowatthour sales.
(b)Includes $66 million, $52 million, and $62 million in 2021, 2020, and 2019, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution.

18
Table of Contents
Electric Operating Statistics – Year Ended December 31,
202120202019
Ameren Missouri fuel costs (cents per kilowatthour generated)(a)
1.46 ¢1.38 ¢1.38 ¢
Source of Ameren Missouri energy supply:
Coal73.0 %67.3 %63.4 %
Nuclear10.5 19.4 23.3 
Hydroelectric4.2 4.5 5.0 
Wind3.7 — — 
Natural gas1.0 0.5 0.5 
Methane gas and solar0.2 0.5 0.2 
Purchased power – wind0.6 0.6 0.7 
Purchased power – other6.8 7.2 6.9 
Ameren Missouri total100.0 %100.0 %100.0 %
(a)    Ameren Missouri fuel costs exclude $1 million, $(49) million and $5 million in 2021, 2020, and 2019, respectively, for changes in FAC recoveries.
Natural Gas Operating Statistics – Year Ended December 31,
202120202019
Natural Gas Sales – dekatherms (in millions):
Ameren Missouri:
Residential7 7 7 
Commercial4 3 4 
Industrial1 1 1 
Transport9 9 9 
Ameren Missouri total21 20 21 
Ameren Illinois Natural Gas:
Residential54 55 61 
Commercial16 15 19 
Industrial4 7 4 
Transport100 96 101 
Ameren Illinois Natural Gas total174 173 185 
Ameren total195 193 206 
Natural Gas Operating Revenues (in millions):
Ameren Missouri:
Residential$79 $76 $81 
Commercial34 29 34 
Industrial4 4 4 
Transport and other24 16 15 
Ameren Missouri total$141 $125 $134 
Ameren Illinois Natural Gas:
Residential$657 $541 $570 
Commercial172 136 154 
Industrial35 14 13 
Transport and other93 69 60 
Ameren Illinois Natural Gas total$957 $760 $797 
Other and intercompany eliminations(1)(2)(2)
Ameren total$1,097 $883 $929 
Rate Base Statistics – At December 31,
202120202019
Rate Base (in billions):
Electric transmission and distribution$13.5 $12.1 $10.7 
Natural gas transmission and distribution2.7 2.4 2.1 
Coal generation:
Labadie Energy Center0.9 0.9 0.9 
Sioux Energy Center0.7 0.7 0.6 
Rush Island Energy Center0.4 0.4 0.5 
Meramec Energy Center0.1 0.1 0.1 
Coal generation total2.1 2.1 2.1 
Nuclear generation1.5 1.5 1.4 
Renewable generation (hydroelectric, wind, solar, methane gas)1.5 1.0 0.5 
Natural gas generation0.3 0.3 0.4 
Rate base total$21.6 $19.4 $17.2 
19
Table of Contents
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren’s website (www.amereninvestors.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed with or furnished to the SEC pursuant to Sections 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through the SEC’s website (www.sec.gov). Ameren’s website is a channel of distribution for material information about the Ameren Companies. Financial and other material information is routinely posted to, and accessible at, Ameren’s website.
The Ameren Companies also make available free of charge through Ameren’s website the charters of Ameren’s board of directors’ Audit and Risk Committee, Human Resources Committee, Nominating and Corporate Governance Committee, Finance Committee, and Nuclear, Operations and Environmental Sustainability Committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures document with respect to related-person transactions; a code of ethics applicable to all directors, officers and employees; a supplemental code of ethics for principal executive and senior financial officers; and a director nomination policy that applies to the Ameren Companies. The information on Ameren’s website, or any other website referenced in this report, is not incorporated by reference into this report.
ITEM 1A.RISK FACTORS
Investors should review carefully the following material risk factors and the other information contained in this report. The risks that the Ameren Companies face are not limited to those in this section. There may be further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect the results of operations, financial position, and liquidity of the Ameren Companies.
REGULATORY AND LEGISLATIVE RISKS
We are subject to extensive regulation of our businesses.
We are subject to federal, state, and local regulation. The extensive regulatory frameworks, some of which are more specifically identified in the following risk factors, regulate, among other matters, the electric and natural gas utility industries; the rate and cost structure of utilities, including an allowed ROE; the operation of nuclear power plants; the construction and operation of generation, transmission, and distribution facilities; the acquisition, disposal, depreciation and amortization of assets and facilities; the electric transmission system reliability; and wholesale and retail competition. In the planning and management of our operations, we must address the effects of existing and proposed laws and regulations and potential changes in our regulatory frameworks, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities. Significant changes in the nature of the regulation of our businesses, including expiration or discontinuation of, or significant changes to, existing regulatory mechanisms, could require changes to our business planning and management of our businesses and could adversely affect our results of operations, financial position, and liquidity. Failure to obtain adequate rates or regulatory approvals in a timely manner; failure to obtain necessary licenses or permits from regulatory authorities; the impact of new or modified laws, regulations, standards, interpretations, or other legal requirements; or increased compliance costs could adversely affect our results of operations, financial position, and liquidity.
The electric and natural gas rates that we are allowed to charge are determined through regulatory proceedings, which are subject to intervention and appeal. Rates are also subject to legislative actions, which are largely outside of our control. Certain events could prevent us from recovering our costs in a timely manner or from earning adequate returns on our investments.
The rates that we are allowed to charge for our utility services significantly influence our results of operations, financial position, and liquidity. The electric and natural gas utility industry is highly regulated. The utility rates charged to customers are determined by governmental entities, including the MoPSC, the ICC, and the FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the prudency of expenditures, the quality of service, regulatory staff knowledge and experience, customer intervention, and economic conditions, as well as social and political views. Decisions made by these governmental entities regarding customer rates are largely outside of our control. We are exposed to regulatory lag and cost disallowances to varying degrees by jurisdiction, which, if unmitigated, could adversely affect our results of operations, financial position, and liquidity. Rate orders are also subject to appeal, which creates additional uncertainty as to the rates that we will ultimately be allowed to charge for our services. From time to time, our regulators may approve trackers, riders, or other recovery mechanisms that allow electric or natural gas rates to be adjusted without a traditional regulatory rate review. These mechanisms could be changed or terminated.
Ameren Missouri’s electric and natural gas utility rates and Ameren Illinois’ natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Ameren Missouri’s electric and natural gas utility rates established in those proceedings are primarily based on historical costs and revenues. Ameren Illinois’ natural gas rates established in those proceedings are based on
20
Table of Contents
estimated future costs and revenues. Thus, the rates that we are allowed to charge for utility services may not match our actual costs at any given time.
Rates include an allowed return on investments established by the regulator, including a return at the applicable WACC on rate base, and an amount for income taxes based on the currently applicable statutory income tax rates and amortization associated with excess deferred income taxes. Although rate regulation is premised on providing an opportunity to earn a reasonable rate of return on rate base, there can be no assurance that the regulator will determine that our costs were prudently incurred or that the regulatory process will result in rates that will produce full recovery of such costs or provide for an opportunity to earn a reasonable return on those investments. Ameren Missouri and Ameren Illinois, and the utility industry generally, have an increased need for cost recovery, primarily driven by capital investments, which is likely to continue in the future. The resulting increase to the revenue requirement needed to recover such costs and earn a return on investments could result in more frequent regulatory rate reviews and requests for cost recovery mechanisms. Additionally, increasing rates could result in regulatory or legislative actions, as well as competitive or political pressures, all of which could adversely affect our results of operations, financial position, and liquidity.
Ameren Illinois expects to use the IEIMA performance-based formula ratemaking framework to establish annual customer rates effective through 2023. Effective for rates beginning in 2024, Ameren Illinois will establish electric distribution rates through either a traditional regulatory rate review or an MYRP. As a result of its participation in the IEIMA performance-based formula ratemaking, Ameren Illinois’ ROE for its electric distribution service through 2023 and its electric energy-efficiency investments is directly correlated to yields on United States Treasury bonds. Additionally, Ameren Illinois is subject to certain performance standards. With respect to its natural gas delivery service business, unless extended, Ameren Illinois’ QIP will expire after December 2023.
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 through an IEIMA reconciliation. 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. 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. An MYRP would establish rates for a four-year period, and Ameren Illinois has the option to file for an MYRP every four years. For rates effective beginning in 2024, Ameren Illinois will be required to establish future rates through a traditional regulatory rate review or an MYRP with the ICC, which might result in rates that do not produce a full or timely recovery of costs or provide for an adequate return on investments and would expose Ameren Illinois’ electric distribution business to the risks described in the immediately preceding risk factor. By law, Ameren Illinois’ electric distribution revenues are decoupled from sales volumes regardless of the process used to establish electric distribution rates, which ensures that the electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. Ameren Illinois also has an electric energy-efficiency program rider, which includes a return at the applicable WACC on its program investments, that is subject to performance-based formula ratemaking. The ICC annually reviews Ameren Illinois’ rate filings for reasonableness and prudency. If the ICC were to conclude that Ameren Illinois’ costs were not prudently incurred, the ICC would disallow recovery of such costs.
The allowed ROE under the IEIMA and electric energy-efficiency formula ratemaking recovery mechanisms is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual ROE for its electric distribution business is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $11 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2022 projected year-end rate base, including electric energy-efficiency investments.
Ameren Illinois’ electric distribution 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 mechanisms. 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. With respect to the MYRP, the ICC-determined ROE would be subject to annual adjustments during the four-year period based on certain performance metrics, with aggregate symmetrical performance-based ROE incentives and penalties ranging from 20 to 60 basis points annually.
21
Table of Contents
While the ICC has approved a plan for Ameren Illinois to invest approximately $100 million per year in electric energy-efficiency programs through 2025, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in the future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs.
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. 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. Without legislative action, the QIP will expire after December 2023. If Ameren Illinois is unable to recover investments under the QIP or there is no other regulatory change, Ameren Illinois will be subject to increased regulatory lag on its natural gas infrastructure investments that are placed in service between regulatory rate reviews, which could adversely affect Ameren’s and Ameren Illinois’ investment plans and results of operations, financial position, and liquidity.
As a result of the election to use the PISA, Ameren Missouri’s electric rates are subject to a rate cap. Additionally, Ameren Missouri’s investment plan assumes use of PISA through December 2028, which is subject to MoPSC approval that has not yet been requested.
As a result of Ameren Missouri’s election to use the PISA, its rate increases are limited 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. Both the rate cap and the PISA election are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.
Increased capital investments and operating costs could cause customer rates to exceed the rate cap. In addition, a decrease in off-system sales, which are included in net energy costs within the FAC, could also contribute to customer rates exceeding the rate cap. Off-system sales are affected by generation availability, which is affected by planned and unplanned outages at Ameren Missouri’s energy centers, curtailment of generation resulting from unfavorable economic conditions, the addition of new generation sources, and retirements of Ameren Missouri’s energy centers, among other things. 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 over a period of 20 years following approval of amounts in a regulatory rate review. 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. A penalty incurred as the result of exceeding the rate cap could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Ameren Missouri’s planned capital expenditures of up to $9.2 billion from 2022 through 2026 are based on the assumption of continued constructive regulatory frameworks, including an assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028. If Ameren Missouri does not obtain approval to use the PISA through December 2028, it could adversely affect Ameren’s and Ameren Missouri’s investment plans and results of operations, financial position, and liquidity.
We are subject to various environmental laws. Significant capital expenditures may be required to achieve and to maintain compliance with these environmental laws. Failure to comply with these laws could result in the closing of facilities, alterations to the manner in which these facilities operate, increased operating costs, delays and increased costs of building new facilities, or exposure to fines and liabilities.
Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety including permitting programs implemented via federal, state, and local authorities. Such environmental laws address air emissions; discharges to water bodies; the storage, handling and disposal of hazardous substances and waste materials; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. Further, we are subject to risks from changing or conflicting interpretations of existing laws, modification to existing laws, new laws, and new or modified permit terms.
We are also subject to liability under environmental laws that address the remediation of environmental contamination on property currently or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such properties include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws against us. They could allege injury from exposure to hazardous materials, allege a failure to comply with environmental laws, seek to compel remediation of environmental contamination, or seek to recover damages resulting from that contamination.
22
Table of Contents
Environmental regulations have a significant impact on the electric utility industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, 2021, Ameren Missouri’s coal-fired energy centers represented 10% and 20% of Ameren’s and Ameren Missouri’s rate base, respectively. Clean Air Act regulations that apply to the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx, mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Regulations implementing the Clean Water Act govern both intake and discharges of water and may require evaluation of the ecological and biological impact of our operations and could require modifications to water intake structures or more stringent limitations on wastewater discharges. Depending upon the scope of modifications ultimately required by state regulators, these capital expenditures could be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR Rule, which require the closure of our surface impoundments at Ameren Missouri’s coal-fired energy centers. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers.
In January 2011, the United States Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri alleging that in performing projects at its coal-fired Rush Island Energy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2017, the district court issued a liability ruling against Ameren Missouri and, in September 2019, entered a remedy order. That remedy order included a requirement to install a flue gas desulfurization system at the Rush Island Energy Center, which was upheld through an appeals process by the United States Court of Appeals for the Eighth Circuit in the fourth quarter of 2021. Based on its assessment of available legal, operational and regulatory alternatives, Ameren Missouri has determined not to further appeal the court rulings and, in December 2021, filed a motion with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The district court is under no deadline to issue a ruling revising the remedy order. In January 2022, the MISO completed a preliminary assessment regarding potential impacts of the retirement to the regional electric power system, which indicated transmission upgrades and voltage support would be needed in advance of the retirement to address reliability concerns. In February 2022, Ameren Missouri expects to formally notify the MISO of its intent to retire the Rush Island Energy Center. Upon receipt of the formal notification, the MISO will conduct a final reliability assessment. The MISO must also separately approve the specific upgrades and transmission support required to address reliability concerns noted in the assessment. Related to this matter, 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, including 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. As of December 31, 2021, the Rush Island Energy Center had a net plant balance of approximately $0.6 billion and a rate base of approximately $0.4 billion. In addition, Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect the planned acceleration of the retirement of the Rush Island Energy Center from 2039, the retirement year for the facility as reflected in the 2020 IRP and reflected in depreciation rates approved by the December 2021 MoPSC electric rate order. 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.
The EPA’s Affordable Clean Energy Rule repealed the Clean Power Plan and replaced it with a new rule that established emission guidelines for states to follow in developing plans to limit CO2 emissions and identified certain efficiency measures as the best system of emission reduction for coal-fired electric generating units. In January 2021, the United States Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy Rule, and ruled that the EPA had the discretion to consider emission reduction measures that include efficiency measures and generation shifting to lower carbon emissions. The United States Supreme Court agreed to review the court of appeals’ ruling and oral arguments will occur in February 2022 with a decision expected by mid-2022. A decision by the United States Supreme Court could impact the EPA’s development of new regulations to address carbon emissions from coal- and natural gas-fired electric generating units. At this time, Ameren Missouri cannot predict the outcome of the legal challenge or future rulemakings. As such, any impact on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri is uncertain.
The EPA’s CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and will result in the closure of surface impoundments at Ameren Missouri’s energy centers. In January 2022, Ameren Missouri received notice of a proposed determination by the EPA that it has rejected Ameren Missouri’s requests to extend the timeline for operating certain impoundments located at the Sioux and Meramec energy centers. Compliance with the CCR Rule’s requirements for closure of the impoundments would be required 135 days after the EPA issues a final determination, which Ameren Missouri expects to be issued in the spring of 2022. If Ameren Missouri was no longer able to use the surface impoundments at the Sioux or Meramec energy centers, Ameren Missouri would not be able to operate the energy centers unless an alternative for handling the CCR material is in place. Ameren Missouri plans to retire the Meramec Energy Center in 2022, and is accelerating its construction plans to build a CCR Rule-compliant impoundment at the Sioux Energy Center to allow for continued operations. Additionally, Ameren Missouri is seeking a reliability determination from the MISO, which, if granted, would extend the deadline to comply with the requirement to close the impoundments and allow the energy centers to operate.
23
Table of Contents
The IETL established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois will be subject to limits on emissions, including CO2 and NOx, equal to their unit-specific average emissions from 2018 through 2020, for any rolling twelve-month period beginning October 1, 2021, through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, which could limit the operations of Ameren Missouri's five natural gas-fired energy centers located in the state of Illinois, and will result in the closure of one or more energy centers earlier than anticipated. These energy centers are utilized to support peak loads. Subject to conditions in the IETL, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service as necessary. Ameren Missouri is reviewing the emission standards and the effect they may have on its generation strategy, including any increases in capital expenditures or operating costs, and changes to the useful lives of the five natural gas-fired energy centers. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect, among other things, the impact of these new emissions standards.
Ameren and Ameren Missouri have incurred, and expect to incur, significant costs with respect to environmental compliance and site remediation. New or revised environmental regulations, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, penalties or fines, reduced operations or closure of some of Ameren Missouri’s coal-and natural gas-fired energy centers, which, in turn, could lead to increased liquidity and financing needs, and higher financing costs. Actions required to ensure that Ameren Missouri’s facilities and operations are in compliance with environmental laws could be prohibitively expensive for Ameren Missouri if the costs are not fully recovered through rates. Environmental laws could require Ameren Missouri to close or to alter significantly the operations of its energy centers. If Ameren Missouri requests recovery of capital expenditures and costs for environmental compliance through rates, the MoPSC could deny recovery of all or a portion of these costs, prevent timely recovery, or make changes to the regulatory framework in an effort to minimize rate volatility and customer rate increases. Capital expenditures and costs to comply with future legislation or regulations might result in Ameren Missouri closing coal-fired energy centers earlier than planned. If these costs are not recoverable through base rates or other regulatory mechanisms, it could lead to an impairment of assets and reduced revenues. Any of the foregoing could have an adverse effect on our results of operations, financial positions, and liquidity.
We are subject to business and financial risks related to the impact of climate change legislation, regulation, and emission reduction goals.
There is increasing concern and activism among various external stakeholders, both nationally and internationally, about climate change, including public concerns about the potential environmental impacts from the combustion of fossil fuels, as well as pressure from public interest groups regarding limiting the use of natural gas. State and federal authorities, including the United States Congress, have considered initiatives to further restrict greenhouse gases to address global climate change. Additionally, international agreements could lead to future federal or state legislation or regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius. The Biden administration has announced a new policy commitment regarding a reduction in greenhouse gas emissions for the United States, but rulemaking to achieve such reductions has not yet been implemented. Actions taken to implement the Paris Agreement could result in future additional greenhouse gas reduction requirements in the United States. In addition, the Biden administration has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions targeting the utility industry.
As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2 emissions. Future federal and state legislation or regulations that mandate limits on the emission of, or impose taxation on, greenhouse gases could result in a significant increase in capital expenditures and operating costs, decreased revenues, penalties or fines, or reduced operations of some of Ameren Missouri’s coal- and natural gas-fired energy centers, which, in turn, could lead to increased liquidity and financing needs, and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations related to climate change might force Ameren Missouri to close some coal-fired energy centers earlier than planned, which could lead to possible loss on abandonment and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Ameren established a goal of achieving net-zero carbon emissions by 2050. Ameren is also targeting a 50% CO2 emission reduction by 2030 and an 85% reduction by 2040 from the 2005 levels. Achievement of these goals is dependent on many factors, including the pace and extent of development and deployment of low- to zero-carbon energy technologies and carbon capture technologies, and the cost of those technologies; natural gas prices; new transmission infrastructure; and constructive energy policies, including those that address investment in energy infrastructure, global climate change, incentives for clean energy technologies, and environmental regulations. Additional factors associated with operational risks for the construction and acquisition of electric and natural gas infrastructure may also affect the achievement of these goals, as further discussed below. The strategy to achieve these goals also relies on continuing to pursue a diverse portfolio including low-carbon and carbon-free resources and energy-efficiency resources; continuing to participate in efforts to help advance the development of technologies such as carbon capture, utilization, and sequestration; the use of hydrogen fuel for electric production and
24
Table of Contents
energy storage, next generation nuclear, and large-scale long-cycle battery energy storage; and constructively engaging with legislators, regulators, investors, customers, and other stakeholders to support outcomes leading to a net-zero future.
We are subject to federal regulatory compliance and proceedings, which could result in increasing costs and the potential for regulatory penalties and other sanctions.
We are subject to FERC regulations, rules, and orders, including standards required by the NERC. As owners and operators of bulk power transmission systems and electric energy centers, we are subject to mandatory NERC reliability standards, including cybersecurity standards. In addition, our natural gas transmission, distribution, and storage facilities systems are subject to PHMSA rules and regulations. Compliance with these reliability standards, rules, and regulations may subject us to higher operating costs and may result in increased capital expenditures. We may also incur higher operating costs to comply with potential new regulations issued by these regulatory bodies. If we were found not to be in compliance with these mandatory NERC reliability standards, PHMSA rules and regulations, or FERC regulations, rules, and orders, we could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations, financial position, and liquidity. The FERC can impose civil penalties of approximately $1.4 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards. The FERC also conducts audits and reviews of Ameren Missouri’s, Ameren Illinois’, and ATXI’s accounting records to assess the accuracy of their respective formula ratemaking process, and it can require refunds to customers for previously billed amounts, with interest.
OPERATIONAL RISKS
The construction and acquisition of, and capital improvements to, electric and natural gas utility infrastructure, along with Ameren Missouri’s ability to implement its Smart Energy Plan, which is aligned with its 2020 IRP, involve substantial risks.
We expect to make significant capital expenditures to maintain and improve our electric and natural gas utility infrastructure and to comply with existing environmental regulations. We estimate that we will invest up to $18.0 billion (Ameren Missouri – up to $9.2 billion; Ameren Illinois – up to $8.6 billion; ATXI – up to $0.2 billion) of capital expenditures from 2022 through 2026. For additional information on these estimates, see Liquidity and Capital Resources – Capital Expenditures in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. Investments in Ameren’s rate-regulated operations are expected to be recoverable from customers, but they are subject to prudence reviews and are exposed to regulatory lag of varying degrees by jurisdiction.
Our ability to complete construction projects successfully within projected estimates, including schedule, performance, and/or cost, and to implement Ameren Missouri’s Smart Energy Plan, which may include acquisition of generation facilities after they are constructed, is contingent upon many factors and subject to substantial risks. These factors include, but are not limited to, the following: project management expertise; escalating costs and/or shortages for labor, materials, and equipment, including changes to tariffs on materials; the ability of suppliers, contractors, and developers to meet contractual commitments timely; changes in the scope and timing of projects; the ability to obtain required regulatory, project, and permit approvals; the ability to obtain necessary rights-of-way, easements, and transmission connections at an acceptable cost in a timely fashion; unsatisfactory performance by the projects when completed; the inability to earn an adequate return on invested capital; the ability to raise capital on reasonable terms; and other events beyond our control, including construction delays due to weather. With respect to the transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2020 IRP, factors also include MoPSC approval for the retirement of energy centers and new or continued customer energy-efficiency programs; the ability to enter into build-transfer agreements for renewable generation and acquire that generation at a reasonable cost; levels of customer participation in the energy-efficiency programs; the cost and commercial availability of wind, solar, and other renewable generation and storage technologies; the ability to qualify for, and use, federal production or investment tax credits; changes in environmental laws or requirements, including those related to carbon emissions; and energy prices and demand.
Any of these risks could result in higher costs, the inability to complete anticipated projects, or facility closures, and could adversely affect our results of operations, financial position, and liquidity.
Our electric generation, transmission, and distribution facilities are subject to operational risks.
Our financial performance depends on the successful operation of electric generation, transmission, and distribution facilities. Operation of electric generation, transmission, and distribution facilities involves many risks, including:
•facility shutdowns due to operator error, or a failure of equipment or processes;
•longer-than-anticipated maintenance outages;
•failures of equipment that can result in unanticipated liabilities or unplanned outages, such as the unplanned outage resulting from non-nuclear operating issues related to the Callaway Energy Center’s generator that occurred from December 2020 to August 2021;
•aging infrastructure that may require significant expenditures to operate and maintain;
25
Table of Contents
•an energy center that might not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected;
•lack of adequate water required for cooling plant operations;
•labor disputes;
•disruptions in the delivery of electricity to our customers;
•inability to maintain reliability of our electric utility services as coal-fired energy centers are retired and renewable energy generation is placed in service;
•suppliers and contractors who do not perform as required under their contracts;
•failure of other operators’ facilities and the effect of that failure on our electric system and customers;
•inability to comply with regulatory or permit requirements, including those relating to environmental laws;
•handling, storage, and disposition of CCR;
•unusual or adverse weather conditions or other natural disasters, including those that may result from climate change, such as severe storms, droughts, floods, tornadoes, earthquakes, icing, sustained high or low temperatures, such as the extremely low temperatures experienced in mid-February 2021, solar flares, and electromagnetic pulses;
•the level of wind and solar resources;
•inability to operate wind generation facilities at full capacity resulting from requirements to protect natural resources, including wildlife;
•the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, civil unrest, pandemic health events, including the COVID-19 pandemic, or other similar events;
•accidents that might result in injury or loss of life, extensive property damage, or environmental damage;
•ineffective vegetation management programs;
•cybersecurity risks, including loss of operational control of Ameren Missouri’s energy centers and our transmission and distribution systems and loss of data, including sensitive customer, employee, financial, and operating system information, through insider or outsider actions;
•limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities;
•inability to implement or maintain information systems;
•failure to keep pace with and the ability to adapt to rapid technological change; and
•other unanticipated operations and maintenance expenses and liabilities.
The foregoing risks could affect the controls and operations of our facilities or impede our ability to meet regulatory requirements, which could increase operating costs, increase our capital requirements and costs, reduce our revenues, or have an adverse effect on our liquidity.
Ameren Missouri’s ability to obtain an adequate supply of coal could limit operation of its coal-fired energy centers.
Ameren Missouri owns and operates coal-fired energy centers. About 98% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming, which has a limited number of suppliers. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion, staffing and equipment issues, infrastructure maintenance, derailments, weather, and supplier financial hardship. Coal suppliers in the Powder River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations and concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2021, coal inventories at the Sioux and Rush Island energy centers were near targeted levels, and coal inventories at the Labadie Energy Center were below targeted levels due to transportation disruptions in 2021. Ameren Missouri is actively managing inventories at the Meramec Energy Center in preparation for its expected 2022 retirement. However, additional disruptions in the delivery of coal, failure of our coal suppliers to provide adequate quantities or quality of coal, or lack of adequate inventories of coal, including low-sulfur coal used to comply with environmental regulations, could have adverse effects on Ameren Missouri’s electric generation operations. If Ameren Missouri is unable to obtain an adequate supply of coal under existing agreements, it may be required to purchase coal at higher prices or be forced to reduce generation at its coal-fired energy centers, which could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Ameren Missouri’s ownership and operation of a nuclear energy center creates business, financial, and waste disposal risks.
Ameren Missouri’s ownership of the Callaway Energy Center subjects it to risks associated with nuclear generation, including:
•potential harmful effects on the environment and human health resulting from radiological releases associated with the operation of nuclear facilities and the storage, handling, and disposal of radioactive materials;
•continued uncertainty regarding the federal government’s plan to permanently store spent nuclear fuel and, as a result, the need to provide for long-term storage of spent nuclear fuel at the Callaway Energy Center;
•limitations on the amounts and types of insurance available to cover losses that might arise in connection with the Callaway Energy Center or other United States nuclear facilities;
26
Table of Contents
•uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway Energy Center or any other United States nuclear facilities;
•public and governmental concerns about the safety and adequacy of security at nuclear facilities;
•limited availability of fuel supply and our reliance on licensed fuel assemblies from the one NRC-licensed supplier of Callaway Energy Center’s assemblies;
•costly and extended outages for scheduled or unscheduled maintenance and refueling, such as the unplanned outage resulting from non-nuclear operating issues related to the Callaway Energy Center’s generator that occurred from December 2020 to August 2021;
•uncertainties about the technological and financial aspects of decommissioning nuclear facilities at the end of their licensed lives;
•the adverse effect of poor market performance and other economic factors on the asset values of nuclear decommissioning trust funds and the corresponding increase, upon MoPSC approval, in customer rates to fund the estimated decommissioning costs; and
•potential adverse effects of a natural disaster, acts of sabotage or terrorism, including a cyber attack, or any accident leading to a radiological release.
The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear facilities. In the event of noncompliance, the NRC has the authority to impose fines or to shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated from time to time by the NRC could necessitate substantial capital expenditures at the Callaway Energy Center. In addition, if a serious nuclear incident were to occur, it could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial condition, and liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation of any domestic nuclear unit and could also cause the NRC to impose additional conditions or requirements on the industry, which could increase costs and result in additional capital expenditures. While the Callaway Energy Center is in compliance with the current NRC standards relating to seismic design and risk, these standards also require Ameren Missouri to address periodic changes to seismic hazard data and evaluation methods for the impact of an earthquake on its Callaway Energy Center due to its proximity to a fault line, which could require seismic risk evaluation updates and installation of additional capital equipment.
Our natural gas distribution and storage activities involve numerous risks that may result in accidents and increased operating costs.
Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, explosions, mechanical problems and cybersecurity risks, which could cause substantial financial losses, including fines and penalties. In addition, these hazards could result in serious injury, loss of human life, significant damage to property, environmental impacts, and impairment of our operations, which in turn could lead us to incur substantial losses. The location of distribution mains and storage facilities near populated areas, including residential areas, business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. A major domestic incident involving natural gas distribution, and storage systems could result in additional capital expenditures and/or increased operations and maintenance expenses for us and increased regulation of natural gas utilities. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
Significant portions of our electric generation, transmission, and distribution facilities and natural gas transmission and distribution facilities are aging. This aging infrastructure may require significant additional maintenance or replacement. Ameren Missouri could be adversely affected if it is unable to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs.
Our aging infrastructure may pose risks to system reliability and expose us to expedited or unplanned significant capital expenditures and operating costs. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978, and the Callaway Energy Center began operating in 1984. The age of these energy centers increases the risks of unplanned outages, reduced generation output, and higher maintenance expense. Further, Ameren Missouri would be adversely affected if the MoPSC does not allow recovery of the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. In addition, as discussed above, Ameren Missouri expects the retirement date of its Rush Island Energy Center to be accelerated from the date reflected in depreciation rates approved in the December 2021 MoPSC electric rate order. Aging transmission and distribution facilities are more prone to failure than new facilities, which results in higher maintenance expense and the need to replace these facilities with new infrastructure. Even when the system is properly maintained, its reliability may ultimately deteriorate and negatively affect our ability to serve our customers, which could result in increased costs associated with regulatory oversight. The frequency and duration of customer outages are among the IEIMA performance standards. Any failure to achieve these standards will result in a reduction in Ameren Illinois’ allowed ROE on electric distribution assets. The higher maintenance costs associated with aging infrastructure and capital expenditures for new or replacement infrastructure could cause additional rate volatility for our customers, resistance by our regulators to allow customer rate increases, and/or regulatory lag in some of our jurisdictions, any of which could adversely affect our results of operations, financial position, and liquidity.
27
Table of Contents
Energy conservation, energy efficiency, distributed generation, energy storage, technological advances, and other factors could reduce energy demand from our customers.
Without a regulatory mechanism to ensure recovery, declines in energy usage could result in an under-recovery of our revenue requirement or an increase in our customer rates, as the revenue requirement would be spread over less sales volumes, which could adversely affect our results of operations, financial position, and liquidity. Such declines could occur due to a number of factors, including:
•customer energy-efficiency programs that are designed to reduce energy demand;
•energy-efficiency efforts by customers not related to our energy-efficiency programs;
•increased customer use of distributed generation sources, such as solar panels and other technologies, which have become more cost-competitive, with decreasing costs expected in the future, as well as the use of energy storage technologies; and
•macroeconomic factors resulting in low economic growth or contraction within our service territories, which could reduce energy demand.
Decreased use of our generation, transmission, and distribution services might result in stranded costs, which ultimately might not be recovered through rates, and therefore, could lead to an impairment or abandonment of assets.
FINANCIAL, ECONOMIC, AND MARKET RISKS
Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.
Ameren is a holding company; therefore, its primary assets are its investments in the common stock of its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. As a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s ability to service its debt obligations is dependent upon the earnings of its operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under affiliate indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations, and other items affecting retained earnings, and available cash. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of affiliate borrowing arrangements and cash payments under the tax allocation agreement) to Ameren. Certain financing agreements, corporate organizational documents, and certain statutory and regulatory requirements may impose restrictions on the ability of Ameren Missouri, Ameren Illinois, and ATXI to transfer funds to Ameren in the form of cash dividends, loans, or advances.
Significant increases in prices of commodities, labor, services, materials, and supplies and other costs, including costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits, could adversely affect our results of operations, financial position, or liquidity.
A part of our core strategy focuses on disciplined cost management, including prudently monitoring all of our expenses. However, we have observed and expect future inflationary pressures related to prices of commodities, labor, services, materials, and supplies and other costs, including in the areas of health care and pension costs. These inflationary pressures could impact our ability to control costs, to make substantial investments in our businesses, to recover costs and investments, to earn our allowed ROEs within frameworks established by our regulators, and/or to maintain affordability of our services for our customers. Significant increases in our costs could increase our financing needs and otherwise adversely affect our results of operations, financial position, and liquidity.
Related to benefits, Ameren has defined benefit pension plans covering substantially all of its employees and has postretirement benefit plans covering non-union employees hired before October 2015 and union employees hired before January 2020. Assumptions related to future costs, returns on investments, interest rates, timing of employee retirements, and mortality, as well as other actuarial matters, have a significant impact on our customers’ rates and our plan funding requirements. Ameren’s total pension and postretirement benefit plans were overfunded by $717 million as of December 31, 2021. 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. In addition to the costs of our pension plans, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. Future legislative changes related to health care could also significantly change our benefit programs and costs.

28
Table of Contents
GENERAL RISKS
Our results of operations, financial position, and liquidity have been and are expected to continue to be adversely affected by the international public health emergency associated with the COVID-19 pandemic.
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. In addition, although restrictions on social activities and nonessential businesses implemented in our service territories in 2020 have been relaxed, additional restrictions may be imposed in the future. As a result of the COVID-19 pandemic, economic activity has been disrupted in the service territories of Ameren Missouri and Ameren Illinois.
The COVID-19 pandemic could continue to affect total electric sales volumes and sales by customer class. Pursuant to the PISA, Ameren Missouri’s electric rates are limited to a 2.85% rate cap. Long-term declines in sales volumes, along with increased capital investments and operating costs, could result in Ameren Missouri’s inability to recover amounts exceeding the rate cap. 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.
Our customers’ payment for our services has been impacted by the COVID-19 pandemic, resulting in a decrease to cash from operations. For most of the period from March 2020 through June 2021, the ICC limited disconnection activities and late fees for customer nonpayment to varying degrees based on customer class. A March 2021 ICC order also required Ameren Illinois to offer deferred payment arrangements extending to 18 months to all residential customers through June 2021. 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.
In addition, suppliers and contractors may not perform as provided under their contracts. This could cause delays in construction projects, or the performance of necessary maintenance to our electric and natural gas infrastructure, which could lead to failures of equipment that can result in unanticipated liabilities or unplanned outages. Delays in our construction projects could also result in reduced planned capital expenditures and decreased rate base growth.
Also, our businesses depend on skilled professional and technical employees. Our operations could be adversely affected if a large portion of our employees contracted COVID-19 or became quarantined at the same time. This could lead to facility shutdowns and disruptions in the delivery of electricity and natural gas to our customers. In addition, remote working arrangements increase our data security risks, including loss of data related to sensitive customer, employee, financial, and operating system information, through insider or outsider actions. Further, compliance with any future vaccine mandates associated with COVID-19 may result in labor shortages, including shortages in skilled professional and technical labor, supply chain disruptions, delays in contractors’ performance or completion of work, and/or increased costs for us, our contractors, or our suppliers.
Ameren cannot predict the extent or duration of the COVID-19 pandemic or its effects on the global, national, or local economy, the capital markets, or its customers, suppliers, business continuity plans, results of operations, financial position, liquidity, planned rate base growth, or sales volumes.
Customers’, investors’, legislators’, and regulators’ opinions of us are affected by many factors, including system reliability, implementation of our strategic plan, protection of customer information, rates, media coverage, and ESG practices, as well as actions by other utility companies. Negative opinions developed by customers, investors, legislators, or regulators could harm our reputation.
Our results are influenced by the expectations of our customers, investors, legislators, and regulators. Those expectations are based, in part, on the reliability and affordability of our utility services. Service interruptions and facility shutdowns can occur due to failures of equipment as a result of severe or destructive weather or other causes. The ability of Ameren Missouri and Ameren Illinois to respond promptly to such failures can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, our ability to safeguard sensitive customer information and protect our systems from cyber attacks, and other actions can affect customer satisfaction. The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction.
29
Table of Contents
Our ability to successfully execute our strategic plan, including the transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2020 IRP, may affect customers’, investors’, legislators’, and regulators’ opinions and actions. Additionally, negative perceptions or publicity resulting from increasing scrutiny of ESG practices could negatively impact our reputation, investment in our common stock, or our access to capital markets. Customers’, investors’, legislators’, and regulators’ opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation.
If customers, investors, legislators, or regulators have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the ROEs we are allowed to earn, as well as the access to, and the cost of, capital. Additionally, negative opinions about us or other utility companies could make it more difficult for our businesses to achieve favorable legislative or regulatory outcomes. Negative opinions could also result in sales volume reductions or increased use of distributed generation by our customers. Any of these consequences could adversely affect our results of operations, financial position, and liquidity.
We are subject to employee work force factors that could adversely affect our operations.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. Certain specialized knowledge that focuses on skilled-craft and STEM-related disciplines is required to construct and operate generation, transmission, and distribution assets. Further, a significant portion of our work force is nearing retirement. As of December 31, 2021, approximately 26%, 27%, and 25% of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ total employees were 55 years old or older, respectively. We are also party to collective bargaining agreements that collectively represent about 48%, 58%, and 55% of Ameren’s, Ameren Missouri’s and Ameren Illinois’ total employees, respectively. All of the Ameren Missouri collective bargaining unit contracts expire in 2022. The Ameren Illinois collective bargaining unit contracts expire in 2022 and 2023, which cover 92% and 8% of represented employees, respectively. Due to the COVID-19 pandemic, a large portion of our non-field employees have been primarily working from home since March 2020. While our workforce has largely been stable, we experienced an increase in our attrition rate in 2021. Certain events, such as significant delays in finding appropriate replacement talent, inadequately trained replacement employees, a mismatch of skill sets to future needs, any work stoppage experienced in connection with negotiations of collective bargaining agreements, or challenges with transitioning working arrangements, could adversely affect our operations.
Our operations are subject to acts of terrorism, cyber attacks, and other intentionally disruptive acts.
Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and enterprise information systems may be affected by malicious acts, terrorist activities and other intentionally disruptive acts, including cyber attacks, which could disrupt our ability to produce or distribute our energy products. There have been attacks in the industry on energy infrastructure, such as substations and related assets, in the past, and there may be more attacks in the future as technology becomes more prevalent in energy infrastructure and the threat landscape continues to expand. Any such incident could limit our ability to generate, purchase, or transmit power or natural gas and could have significant regional economic consequences. Any such disruption could result in a significant decrease in revenues, a significant increase in costs including those for repair, or adversely affect economic activity in our service territory which, in turn, could adversely affect our results of operations, financial position, and liquidity.
There has been an increase in the number and sophistication of physical and cyber attacks across all industries worldwide. Cyber attacks could include viruses, malicious or destructive code, phishing attacks, denial of service attacks, ransomware and other ransom-based attacks, improper access by third parties, attacks on email systems, and attacks leading to data loss, operational control, or exploitation of vulnerabilities specific to internally developed systems or to those provided and/or maintained by our suppliers, among various other security breaches. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm resulting from theft or the inappropriate release or destruction of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected grid. Therefore, a disruption caused by a cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. Insurance might not be adequate to cover losses that arise in connection with these events. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
30
Table of Contents
Our businesses are dependent on our ability to access the capital markets successfully. We might not have access to sufficient capital in the amounts and at the times needed, as well as on reasonable terms.
We rely on the issuance of short-term and long-term debt and equity as significant sources of liquidity and funding for capital requirements not satisfied by our operating cash flow, as well as to refinance existing long-term debt. The inability to raise debt or equity capital on reasonable terms, or at all, could negatively affect our ability to maintain or to expand our businesses. Events beyond our control, such as depressed economic conditions, the COVID-19 pandemic, or extreme volatility in the debt, equity, or credit markets, might create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity, or credit markets, including our ability to draw on bank credit facilities. Any adverse change in our credit ratings could reduce access to capital and trigger collateral postings and prepayments. Such changes could also increase the cost of borrowing and the costs of fuel, power, and natural gas supply, among other things, which could adversely affect our results of operations, financial position, and liquidity.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
31
Table of Contents
ITEM 2.PROPERTIES
For information on our principal properties, see the energy center and in-service utility-related properties tables below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of planned additions. See also Note 5 – Long-term Debt and Equity Financings and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows the anticipated capability of Ameren Missouri’s energy centers at the time of Ameren Missouri’s expected 2022 peak summer electrical demand for all energy centers owned as of December 31, 2021:
Primary Fuel SourceEnergy CenterLocation
Net Kilowatt Capability(a)
Coal
Labadie(b)
Franklin County, Missouri2,372,000 
Rush Island(c)
Jefferson County, Missouri1,178,000 
Sioux(d)
St. Charles County, Missouri972,000 
 
Meramec(d)
St. Louis County, Missouri510,000 
Total coal  5,032,000 
Nuclear
Callaway(e)
Callaway County, Missouri1,194,000 
Hydroelectric
Osage(e)
Lakeside, Missouri235,000 
 KeokukKeokuk, Iowa148,000 
Total hydroelectric  383,000 
Pumped-storage
Taum Sauk(e)
Reynolds County, Missouri440,000 
WindHigh Prairie RenewableAdair and Schuyler Counties, Missouri400,000 
Atchison RenewableAtchison County, Missouri298,800 
Total wind698,800 
Natural gas
Audrain(f)
Audrain County, Missouri616,000 
Venice(g)
Venice, Illinois489,000 
Goose Creek(g)
Piatt County, Illinois444,000 
Pinckneyville(g)
Pinckneyville, Illinois316,000 
Raccoon Creek(g)
Clay County, Illinois308,000 
Meramec(d)
St. Louis County, Missouri226,000 
Kinmundy(g)
Kinmundy, Illinois210,000 
Peno Creek(f)
Bowling Green, Missouri172,000 
Total natural gas  2,781,000 
Oil (CTs)
Fairgrounds(d)
Jefferson City, Missouri55,000 
Mexico(d)
Mexico, Missouri55,000 
Moberly(d)
Moberly, Missouri55,000 
Moreau(d)
Jefferson City, Missouri55,000 
Total oil  220,000 
Methane gas (CT)Maryland HeightsMaryland Heights, Missouri9,000 
SolarO’FallonO’Fallon, Missouri4,500 
LambertSt. Louis County, Missouri900 
BJCSt. Louis, Missouri1,600 
South St. LouisSt. Louis, Missouri200 
Total solar7,200 
Total Ameren and Ameren Missouri  10,765,000 
(a)Net kilowatt capability, except for wind and solar generating facilities, is the generating capacity available for dispatch from the energy center into the electric transmission grid. Capability for wind and solar generating facilities represents nameplate capacity. This capacity is only attainable when wind/solar conditions are sufficiently available. The on-demand capability for wind and solar units is zero.
(b)The Labadie Energy Center is scheduled to retire 1,186,000 kilowatts by 2036 and 1,186,000 kilowatts by 2042.
(c)The Rush Island Energy Center was scheduled to retire by 2039 as noted in the 2020 IRP. However, changes to the retirement date are subject to a final judgment to be issued by the United States District Court for the Eastern District of Missouri regarding a September 2019 remedy order. For additional information, see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
(d)The Sioux and Meramec energy centers are scheduled to retire by 2028 and 2022, respectively. The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to be retired by 2026 as noted in the 2020 IRP.
(e)The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively.
(f)There are economic development arrangements applicable to these CTs, as discussed below.
(g)See Illinois Emissions Standards in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
32
Table of Contents
The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2021:
Ameren
Missouri		Ameren
Illinois
Circuit miles of electric transmission lines(a)
3,109 4,659 
Circuit miles of electric distribution lines33,656 45,890 
Percentage of circuit miles of electric distribution lines underground24 %16 %
Miles of natural gas transmission and distribution mains3,480 18,620 
Underground natural gas storage fields— 12 
Total working capacity of underground natural gas storage fields in billion cubic feet— 24 
(a)ATXI owns 545 miles of transmission lines not reflected in this table.
Our other properties include office buildings, warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all principal energy centers and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bonds and to certain permitted liens and judgment liens). The exceptions are as follows:
•Certain property is situated on lands occupied under leases, easements, franchises, licenses, or permits. That property includes a portion of Ameren Missouri’s Osage Energy Center reservoir; certain facilities at Ameren Missouri’s Sioux Energy Center; most of Ameren Missouri’s High Prairie Renewable, Atchison Renewable, Peno Creek CT and Audrain CT energy centers; Ameren Missouri’s Maryland Heights, Lambert, and BJC energy centers; certain substations; and most transmission and distribution lines and natural gas mains. The United States or the state of Missouri may own or may have paramount rights with respect to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which certain of Ameren Missouri’s energy centers and other properties are located.
•The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of Ameren Missouri’s Keokuk Energy Center is located.
Substantially all of the properties and plant of Ameren Missouri and Ameren Illinois are subject to the liens of the indentures securing their mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek CT Energy Center to the city of Bowling Green, Missouri through December 2022. Ameren Missouri has rights and obligations as the operator of the energy center under a long-term agreement with the city of Bowling Green. Under the terms of this agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the agreement, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri mortgage bond indenture.
Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as the operator of the energy center under a long-term agreement with Audrain County. Under the terms of this agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. The agreement will expire in December 2023. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the agreement, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri mortgage bond indenture.
ITEM 3.LEGAL PROCEEDINGS
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses. For additional information on material legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report. Pursuant to Item 103(c)(3)(iii) of Regulation S-K, our policy is to disclose environmental proceedings to which a governmental entity is a party if we reasonably believe such proceedings will result in monetary sanctions of $1 million or more.

ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
33
Table of Contents
INFORMATION ABOUT OUR EXECUTIVE OFFICERS:
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2021, all their positions and offices held with the Ameren Companies as of February 22, 2022, and their tenures as officers, and their titles for at least the last five years.
AMEREN CORPORATION:
NameAgePositionsPeriod
Warner L. Baxter60Executive Chairman; AmerenJanuary 2022 – Present
Chairman, President, and Chief Executive Officer; Ameren
2014(a) – January 2022
Martin J. Lyons, Jr.55President and Chief Executive Officer; AmerenJanuary 2022 – Present
Chairman and President; Ameren Missouri
December 2019 – January 2022
Chairman and President; Ameren ServicesMarch 2016 – December 2019
Executive Vice President and Chief Financial Officer; AmerenJanuary 2013 – December 2019
Michael L. Moehn52Executive Vice President and Chief Financial Officer; AmerenDecember 2019 – Present
Chairman and President; Ameren ServicesDecember 2019 – Present
Chairman and President; Ameren MissouriApril 2014 – December 2019
Chonda J. Nwamu50Senior Vice President, General Counsel, and Secretary; AmerenAugust 2019 – Present
Senior Vice President and Deputy General Counsel; Ameren ServicesJanuary 2019 – August 2019
Vice President and Deputy General Counsel; Ameren ServicesSeptember 2016 – January 2019
Theresa A. Shaw49Senior Vice President, Finance, and Chief Accounting Officer; AmerenAugust 2021 – Present

Senior Vice President, Regulatory Affairs and Financial Services; Ameren IllinoisSeptember 2019 – August 2021
Vice President, Regulatory Affairs and Financial Services; Ameren IllinoisJuly 2018 – August 2019
Vice President, Internal Audit; AmerenJune 2014 – July 2018
(a)Elected President of Ameren in February 2014, Chief Executive Officer of Ameren in April 2014, and Chairman of Ameren in July 2014.
34
Table of Contents
SUBSIDIARIES:
NameAgePositionsPeriod
Bhavani Amirthalingam46Senior Vice President and Chief Digital Information Officer; Ameren Services
March 2018(a) – Present
Mark C. Birk57Chairman and President; Ameren MissouriJanuary 2022 – Present

Senior Vice President, Customer and Power Operations; Ameren Missouri
October 2017 – January 2022
Senior Vice President, Customer Operations; Ameren Missouri
January 2017 – October 2017
Senior Vice President, Corporate Safety, Planning and Operations Oversight; Ameren Services
April 2015 – January 2017
Fadi M. Diya59Senior Vice President and Chief Nuclear Officer; Ameren MissouriJanuary 2014 – Present
Mary P. Heger65Senior Vice President, Customer Experience; Ameren IllinoisFebruary 2019 – Present
Senior Vice President and Chief Information Officer; Ameren ServicesSeptember 2015 – February 2019
Mark C. Lindgren54Senior Vice President, Corporate Communications, and Chief Human Resources Officer; Ameren ServicesSeptember 2015 – Present
Richard J. Mark66Chairman and President; Ameren IllinoisJune 2012 – Present
Shawn E. Schukar60Chairman and President; ATXIMay 2017 – Present
Senior Vice President, Transmission Operations, Construction and Project Management; ATXIDecember 2013 – May 2017
(a)Bhavani Amirthalingam served as the Chief Information Officer and Vice President North America for Schneider Electric SE from January 2015 to March 2018.
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the executive officers or between any executive officers and any directors of the Ameren Companies. Except as noted, the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
35
Table of Contents
PART II
ITEM 5.MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 40,340 on January 31, 2022. There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding common stock of Ameren Missouri and Ameren Illinois.
Purchases of Equity Securities
Ameren Corporation, Ameren Missouri, and Ameren Illinois did not purchase any equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 2021, to December 31, 2021.
Performance Graph
The following graph shows Ameren’s cumulative TSR during the five years ended December 31, 2021. The graph also shows the cumulative total returns of the S&P 500 Index, S&P 500 Utility Index, and the Philadelphia Utility Index. The S&P 500 Utility Index and the Philadelphia Utility Index are market capitalization-weighted indices of U.S. public utility companies. The comparison assumes that $100 was invested on December 31, 2016, in Ameren common stock and in each of the indices shown and that all of the dividends were reinvested.
Comparison of Five-Year Cumulative Return
aee-20211231_g5.jpg
36
Table of Contents
December 31,201620172018201920202021
Ameren (AEE)$100.00 $115.96 $132.17 $159.69 $166.51 $194.96 
S&P 500 Index100.00 121.83 116.49 153.18 181.36 233.43 
S&P 500 Utility Index100.00 112.11 116.72 147.47 148.18 174.36 
Philadelphia Utility Index100.00 112.82 116.79 148.11 152.14 179.90 
Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.
ITEM 6.(RESERVED)
ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Below is a summary description of Ameren’s principal subsidiaries – Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
•Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.
•Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.
•ATXI operates a FERC rate-regulated electric transmission business in the MISO.
Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. See Note 16 – Segment Information under Part II, Item 8, of this report for further discussion of Ameren’s and Ameren Illinois’ segments.
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 under Part II, Item 8, of this report. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular and graphical dollar amounts are in millions, unless otherwise indicated.
The following discussion should be read in conjunction with the financial statements contained in this Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Discussion regarding our financial condition and results of operations for the year ended December 31, 2019, including comparisons with the year ended December 31, 2020, is included in Item 7 of our Form 10-K for the year ended December 31, 2020, filed with the SEC on February 22, 2021.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per diluted share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per diluted share information helps readers to understand the impact of these factors on Ameren’s earnings per diluted share.
37
Table of Contents
OVERVIEW
Our core strategy is driven by the following three pillars:
Investing in and operating our utilities in a manner consistent with existing regulatory frameworksEnhancing regulatory frameworks and advocating for responsible energy and economic policiesCreating and capitalizing on opportunities for investment for the benefit of our customers and shareholders
We seek to earn competitive returns on investments in our businesses. Accordingly, we remain focused on disciplined cost management and strategic capital allocation. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators, to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned ROEs and allocating capital resources to business opportunities that we expect will provide the most benefit to our customers and offer the most attractive risk-adjusted return potential.We seek to partner with our stakeholders, including our customers, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers and shareholders. We believe constructive regulatory frameworks for investment exist at all of our business segments. Accordingly, we expect to earn competitive returns on investments in our businesses and realize timely recovery of our costs in the coming years with the benefits accruing to both customers and shareholders.We seek to make prudent investments that benefit our customers. The goal of these investments is to maintain and enhance the reliability of our services, develop cleaner sources of energy, create economic development opportunities in our region, and provide customers with more options and greater control over their energy usage, among other things. By prudently investing in our businesses, we believe that we deliver superior value to both customers and shareholders.
Improved Reliability(f)
aee-20211231_g6.gif
Rate Base ($ in billions)(a)
Constructive Regulatory Frameworks(c)
aee-20211231_g7.gif
SegmentRegulatory Framework
Ameren
Transmission		Formula ratemaking
Allowed ROE of 10.52%
Customer Rates, (¢/KWH)(g)
Ameren Illinois
Natural Gas		Future test year ratemaking and QIP, PGA, VBA
Allowed ROE of 9.67%
aee-20211231_g8.gif
Ameren Illinois
Electric Distribution
Formula ratemaking
Allowed ROE of 30-year U.S. Treasury + 5.8%(d)
Ameren
Missouri
Historical test year ratemaking and
PISA, RESRAM, FAC, MEEIA, PGA
Allowed ROE is not specified(e)
TSR 2016-2021(h)
aee-20211231_g9.gif
(a)Reflects year-end rate base except for Ameren Transmission, which is average rate base.
(b)Compound annual growth rate.
(c)As of January 2022 for Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Illinois Electric Distribution. As of February 28, 2022, for Ameren Missouri.
(d)Allowed ROE is subject to performance standards as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
(e)Allowed ROE applicable to electric and natural gas delivery service.
(f)As measured by the System Average Interruption Frequency Index (SAIFI). Represents the average of Ameren Missouri and Ameren Illinois.
(g)Average residential electric prices. Source: Edison Electric Institute, “Typical Bills and Average Rates Report” for the 12 months ended June 30, 2021.
(h)Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.
Key announcements, updates, and regulatory outcomes
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 impacts on electric and natural gas sales volumes, liquidity, bad debt expense, and supply chain operations. For further discussion of these and other matters discussed below, see Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and Results of Operations, Liquidity and Capital Resources, and Outlook sections below. In addition, for information regarding Ameren Illinois’ suspension and
38
Table of Contents
subsequent reinstatement of customer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Due to extremely cold winter weather in mid-February 2021, Ameren Missouri and Ameren Illinois experienced higher than anticipated commodity costs for natural gas purchased for resale and purchased power, which contributed to the acceleration of the timing of certain planned 2021 long-term debt issuances. Ameren Missouri and Ameren Illinois have cost recovery mechanisms in place that provide recovery of the higher natural gas costs and purchased power from customers over periods of time established under the applicable mechanisms.
In January 2021, Ameren Missouri acquired a 300-MW wind generation project located in northwestern Missouri. As of June 30, 2021, Ameren Missouri had placed the project in service as the Atchison Renewable Energy Center. The purchase price of the energy center was approximately $500 million, including an immaterial amount of transaction costs. In December 2020, Ameren Missouri acquired a 400-MW wind generation project located in northeastern Missouri for approximately $615 million, and placed the assets in service as the High Prairie Renewable Energy Center. The purchase price included $564 million of cash, a deferred purchase price obligation withheld as credit support in relation to certain potential claims, contingent consideration, and transaction costs. Both renewable energy centers support Ameren Missouri’s compliance with the Missouri renewable energy standard.
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. See Note 9 – Callaway Energy Center under Part II, Item 8, of this report for additional information.
In August 2021, the United States Court of Appeals for the Eighth Circuit issued a decision that affirmed the United States District Court for the Eastern District of Missouri’s January 2017 liability ruling and the district court’s September 2019 remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In November 2021, the court of appeals issued an order denying requests for consideration previously sought by both Ameren Missouri and the United States Department of Justice. Based on its assessment of available legal, operational and regulatory alternatives, Ameren Missouri has determined not to further appeal the court rulings and, in December 2021, filed a motion with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The district court is under no deadline to issue a ruling revising the remedy order. In January 2022, the MISO completed a preliminary assessment regarding potential impacts of the retirement to the regional electric power system, which indicated transmission upgrades and voltage support would be needed in advance of the retirement to address reliability concerns. In February 2022, Ameren Missouri expects to formally notify the MISO of its intent to retire the Rush Island Energy Center. Upon receipt of the formal notification, the MISO will conduct a final reliability assessment. The MISO must also separately approve the specific upgrades and transmission support required to address reliability concerns noted in the assessment. Related to this matter, 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, including 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 expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute that became effective in August 2021. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.
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 in accordance with revenue recognition guidance, Ameren Missouri recognized revenues of $9 million in 2021.
In December 2021, the MoPSC issued orders in Ameren Missouri’s 2021 electric service and natural gas delivery service regulatory rate reviews. The orders will result in increases of $220 million and $5 million to Ameren Missouri’s annual revenue requirements for electric retail service and natural gas delivery service, respectively. The electric revenue requirement increase 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 electric 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 electric rate 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. It 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 orders also approved for recovery $9 million of certain costs and forgone customer late fee and reconnection fee revenues resulting from the COVID-19 pandemic that were accumulated pursuant to March 2021 MoPSC orders. The new electric and natural gas rates will become effective on February 28, 2022.
39
Table of Contents
In February 2022, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2022. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4 billion over the five-year period from 2022 through 2026, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 through 2026 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA from December 2023 to December 2028.
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 below. 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.
In September 2021, the IETL was enacted, which resulted in changes to the regulatory framework applicable to Ameren Illinois’ electric distribution business, among other things. The IETL allows Ameren Illinois to file an MYRP with the ICC by mid-January 2023, with rates effective beginning in 2024. Subject to a constructive outcome regarding the ICC’s determination of performance metrics, Ameren Illinois anticipates filing an MYRP by mid-January 2023 to establish rates for 2024. 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, based on each year's forecasted recoverable costs, an ICC-determined ROE applied to each calendar year of the four-year period, and a common equity ratio of up to 50% being deemed prudent and reasonable by law, with a higher equity ratio requiring specific ICC approval. The approved ROE would be subject to adjustment during the four-year period based on certain performance metrics, with aggregate symmetrical performance-based ROE incentives and penalties ranging from 20 to 60 basis points. The MYRP would also allow Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to an aggregate reconciliation cap of 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs and costs recovered through riders outside of base rates would be excluded from the reconciliation cap. Electric distribution service revenues would continue to be decoupled from sales volumes under an MYRP. If Ameren Illinois does not file an MYRP for rates effective beginning in 2024, its next opportunity to file an MYRP would be for rates effective beginning in 2028.
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.
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.
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 February 2021, Ameren’s board of directors increased the quarterly common stock dividend to 55 cents per share, resulting in an annualized equivalent dividend rate of $2.20 per share. In February 2022, Ameren’s board of directors increased the quarterly common stock dividend to 59 cents per share, resulting in an annualized equivalent dividend rate of $2.36 per share.
40
Table of Contents
Earnings
Net income attributable to Ameren common shareholders was $990 million, or $3.84 per diluted share, for 2021, and $871 million, or $3.50 per diluted share, for 2020. Net income was favorably affected in 2021, compared with 2020, by increased infrastructure investments across all business segments; increased Ameren Missouri electric retail sales, primarily resulting from improving economic conditions and the effects of weather; and by the results of Ameren Missouri’s March 2020 electric rate order. Earnings in 2021, compared with 2020, were also favorably affected by higher delivery service rates at Ameren Illinois Natural Gas and a higher recognized ROE at Ameren Illinois Electric Distribution. Net income was unfavorably affected in 2021, compared with 2020, by the effect of dilution and higher other operations and maintenance expenses at Ameren Missouri due to the amortization of expenses related to the 2020 scheduled refueling and maintenance outage at the Callaway Energy Center and increased non-nuclear energy center and distribution maintenance costs, as well as higher other operations and maintenance expenses due to increased infrastructure maintenance and compliance costs at Ameren Illinois Natural Gas. Earnings in 2021, compared with 2020, were also unfavorably affected by the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which increased earnings in the year-ago period, and the result of the FERC’s March 2021 order, primarily related to the historical recovery of materials and supplies inventories; increased financing costs at Ameren (parent) and Ameren Missouri, primarily due to higher long-term debt balances; and increased depreciation and amortization expenses not recoverable under riders or trackers at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to additional property, plant, and equipment investments.
Liquidity
At December 31, 2021, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.8 billion.
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. 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. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.
41
Table of Contents
Ameren remains focused on strategic capital allocation. The following chart presents 2021 capital expenditures by segment and the midpoint of projected cumulative capital expenditures for 2022 through 2026 by segment:
2021 Capital Expenditures by Segment
(Total Ameren – $3.5 billion)
(in billions)
Midpoint of 2022 – 2026 Projected Capital
Expenditures by Segment (Total Ameren – $17.3 billion)
(in billions)
aee-20211231_g10.jpgaee-20211231_g11.jpg
Ameren Missouri(a)
Ameren Illinois Natural Gas
Ameren Illinois Electric DistributionAmeren Transmission
(a)Ameren Missouri’s capital expenditures include $525 million for wind generation expenditures for the year ended December 31, 2021. Ameren Missouri’s projected capital expenditures for 2022 through 2026 includes approximately $0.7 billion of capital expenditures related to coal-fired generation.
For 2022 through 2026, Ameren’s cumulative capital expenditures are projected to range from $16.6 billion to $18.0 billion. The following table presents the range of projected spending by segment:
Range (in billions)
Ameren Missouri(a)
$8.5 –$9.2 
Ameren Illinois Electric Distribution3.0 –3.3 
Ameren Illinois Natural Gas1.7 –1.8 
Ameren Transmission3.4 –3.7 
Ameren(a)
$16.6 –$18.0 
(a)Amounts exclude renewable generation investment opportunities of 1,200 MWs by 2026, which are included in Ameren Missouri’s 2020 IRP, and additional investment opportunities that may be approved by the MISO to address reliability concerns in connection with the planned accelerated retirement of the Rush Island Energy Center.
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Economic conditions, including those resulting from the COVID-19 pandemic discussed below, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing, and our pension and postretirement benefits costs. Almost all of our revenues are subject to state or federal regulation. This regulation has a material impact on the rates we charge customers for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, with the frameworks established by our regulators. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory frameworks.
42
Table of Contents
We continue to assess the impacts of the COVID-19 pandemic on our businesses, including impacts on electric and natural gas sales volumes, supply chain operations, and bad debt expense. 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 accounts receivable balances that were past due or that were a part of a deferred payment arrangement are more comparable to pre-pandemic levels. As of December 31, 2021, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 20%, 17%, and 24%, or $94 million, $34 million, and $60 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. As of December 31, 2019, these percentages were 18%, 18%, and 20%, or $75 million, $30 million, and $45 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. Ameren Missouri’s electric sales volumes have been, and continue to be, affected by the COVID-19 pandemic, including a shift in sales volumes by customer class compared to pre-pandemic levels, with an increase in residential sales, and a decrease in commercial and industrial sales, excluding the estimated effects of weather and customer energy-efficiency programs.
Ameren Missouri principally uses coal and enriched uranium for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, inflation, and many other factors. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution business, and a FAC for Ameren Missouri’s electric business.
We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of Ameren Missouri’s energy centers and our transmission and distribution systems and the level and timing of operations and maintenance costs and capital investment are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.
Earnings Summary
The following table presents a summary of Ameren’s earnings for the years ended December 31, 2021 and 2020:
20212020
Net income attributable to Ameren common shareholders
$990 $871 
Earnings per common share – diluted
3.84 3.50 
Net income attributable to Ameren common shareholders in 2021 increased $119 million, or $0.34 per diluted share, from 2020. The increase was due to net income increases of $82 million, $22 million, $14 million, and $9 million at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively. The increases in net income were partially offset by an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent) of $8 million.
Earnings per share in 2021, compared with 2020, were favorably affected by:
•investments in infrastructure and wind generation pursuant to the PISA and the RESRAM, which resulted in increased deferral of interest expense (21 cents per share);
•increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE at Ameren Illinois Electric Distribution, which increased revenues at these segments (19 cents per share);
•the results of the MoPSC’s March 2020 electric rate order, which reduced the base level of expenses at Ameren Missouri, partially offset by lower base rates, net of recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs and recoverable depreciation under the PISA (10 cents per share);
•increased electric retail sales, excluding the estimated effects of weather and MEEIA, at Ameren Missouri, largely due to improving economic conditions, which resulted in increased sales volumes (10 cents per share);
•higher base rates pursuant to the ICC's January 2021 natural gas rate order, which increased margins at Ameren Illinois Natural Gas (8 cents per share);
•higher other income, net, due to the absence of charitable donations made in 2020 pursuant to the MoPSC’s March 2020 electric rate order, increased earnings from equity method investments to advance clean and resilient energy technologies, and a return to more normal levels of charitable donations at Ameren (parent) (8 cents per share);
•the impact of weather on electric retail sales at Ameren Missouri, primarily resulting from warmer summer temperatures experienced in 2021 (estimated at 6 cents per share); and
•the results of true-ups to the 2020 revenue requirement reconciliation adjustment in 2021 related to Ameren Illinois’ rates for electric distribution delivery service and electric customer energy-efficiency program investments (2 cents per share).
43
Table of Contents
Earnings per share in 2021, compared with 2020, were unfavorably affected by:
•increased other operations and maintenance expenses at Ameren Missouri, primarily due to the amortization of expenses related to the 2020 scheduled refueling and maintenance outage at the Callaway Energy Center and increased non-nuclear energy center and distribution maintenance costs, and at Ameren Illinois Natural Gas due to increased infrastructure maintenance and compliance activity (17 cents per share);
•the effect of dilution, primarily due to increased weighted-average basic common shares outstanding resulting from issuances of common shares as detailed in Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report (14 cents per share);
•the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which increased Ameren Transmission earnings in the year-ago period, and the result of the FERC’s March 2021 order, primarily related to the historical recovery of materials and supplies inventories, which decreased Ameren Transmission earnings in 2021 (7 cents per share);
•increased financing costs, primarily at Ameren (parent) and Ameren Missouri, largely due to higher long-term debt balances (5 cents per share);
•increased depreciation and amortization expenses not recoverable under riders or trackers at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to additional property, plant, and equipment investments (5 cents per share); and
•decreased income tax benefits at Ameren (parent), primarily related to employee retention tax credits, changes in the distribution of taxable income by state, and company owned life insurance, partially offset by increased amortization of excess deferred income taxes at Ameren Missouri (3 cents per share).
The cents per share information presented is based on the weighted-average basic shares outstanding in 2020 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 2021 statutory tax rate of 26%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income, Net, Interest Charges, and Income Taxes, see the major headings below.

44
Table of Contents
Below is Ameren’s table of income statement components by segment for the years ended December 31, 2021 and 2020:
2021Ameren
Missouri		Ameren
Illinois
Electric
Distribution		Ameren
Illinois
Natural Gas		Ameren
Transmission		Other /
Intersegment
Eliminations		Ameren
Electric revenues$3,212 $1,639 $— $562 $(116)$5,297 
Fuel(581)— — — — (581)
Purchased power(227)(466)— — 87 (606)
Electric margins2,404 1,173 — 562 (29)4,110 
Natural gas revenues141 — 957 — (1)1,097 
Natural gas purchased for resale(60)— (382)— — (442)
Natural gas margins81 — 575 — (1)655 
Other operations and maintenance expenses(948)(534)(236)(62)6 (1,774)
Depreciation and amortization(632)(309)(90)(111)(4)(1,146)
Taxes other than income taxes(343)(76)(73)(8)(12)(512)
Operating income (loss)562 254 176 381 (40)1,333 
Other income, net99 39 13 15 36 202 
Interest charges(137)(74)(42)(83)(47)(383)
Income (taxes) benefit(3)(53)(39)(82)20 (157)
Net income (loss)521 166 108 231 (31)995 
Noncontrolling interests – preferred stock dividends(3)(1)— (1)— (5)
Net income (loss) attributable to Ameren common shareholders$518 $165 $108 $230 $(31)$990 
2020
Electric revenues$2,984 $1,498 $— $523 $(94)$4,911 
Fuel(490)— — — — (490)
Purchased power(171)(407)— — 65 (513)
Electric margins2,323 1,091 — 523 (29)3,908 
Natural gas revenues125 — 760 — (2)883 
Natural gas purchased for resale(43)— (229)— — (272)
Natural gas margins82 — 531 — (2)611 
Other operations and maintenance expenses(886)(506)(221)(57)9 (1,661)
Depreciation and amortization(604)(288)(81)(98)(4)(1,075)
Taxes other than income taxes(328)(72)(65)(8)(10)(483)
Operating income (loss)587 225 164 360 (36)1,300 
Other income, net76 33 13 13 16 151 
Interest charges(190)(72)(41)(78)(38)(419)
Income (taxes) benefit(34)(42)(36)(78)35 (155)
Net income (loss)439 144 100 217 (23)877 
Noncontrolling interests – preferred stock dividends(3)(1)(1)(1)— (6)
Net income (loss) attributable to Ameren common shareholders$436 $143 $99 $216 $(23)$871 
45
Table of Contents
Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2021 and 2020:
2021Ameren
Illinois
Electric
Distribution		Ameren
Illinois
Natural Gas		Ameren
Illinois
Transmission		Other /
Intersegment
Eliminations		Ameren Illinois
Electric revenues$1,639 $— $365 $(66)$1,938 
Purchased power(466)— — 66 (400)
Electric margins1,173 — 365 — 1,538 
Natural gas revenues— 957 — — 957 
Natural gas purchased for resale— (382)— — (382)
Natural gas margins— 575 — — 575 
Other operations and maintenance expenses(534)(236)(50)— (820)
Depreciation and amortization(309)(90)(73)— (472)
Taxes other than income taxes(76)(73)(4)— (153)
Operating income254 176 238 — 668 
Other income, net39 13 14 — 66 
Interest charges(74)(42)(48)— (164)
Income taxes(53)(39)(51)— (143)
Net income166 108 153 — 427 
Preferred stock dividends(1)— (1)— (2)
Net income attributable to common shareholder$165 $108 $152 $— $425 
2020
Electric revenues$1,498 $— $329 $(52)$1,775 
Purchased power(407)— — 52 (355)
Electric margins1,091 — 329 — 1,420 
Natural gas revenues— 760 — — 760 
Natural gas purchased for resale— (229)— — (229)
Natural gas margins— 531 — — 531 
Other operations and maintenance expenses(506)(221)(48)— (775)
Depreciation and amortization(288)(81)(65)— (434)
Taxes other than income taxes(72)(65)(3)— (140)
Operating income225 164 213 — 602 
Other income, net33 13 13 — 59 
Interest charges(72)(41)(42)— (155)
Income taxes(42)(36)(46)— (124)
Net income144 100 138 — 382 
Preferred stock dividends(1)(1)(1)— (3)
Net income attributable to common shareholder$143 $99 $137 $— $379 
Margins
Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
46
Table of Contents
Electric Margins
Total by Segment(a)
Increase by Segment
Overall Ameren Increase of $202 Million
aee-20211231_g12.jpgaee-20211231_g13.jpg
(a)Includes other/intersegment eliminations of $(29) million and $(29) million in 2021 and 2020, respectively.
Ameren MissouriAmeren Illinois Electric DistributionAmeren TransmissionOther/Intersegment Eliminations
Natural Gas Margins
Total by Segment(a)
Increase (Decrease) by Segment
Overall Ameren Increase of $44 Million
aee-20211231_g14.jpgaee-20211231_g15.jpg
(a)Includes other/intersegment eliminations of $(1) million and $(2) million in 2021 and 2020, respectively.
Ameren MissouriAmeren Illinois Natural GasOther/Intersegment Eliminations
47
Table of Contents
The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2021, compared with 2020:
Electric and Natural Gas Margins
2021 versus 2020Ameren
Missouri		Ameren Illinois
Electric Distribution		Ameren Illinois
Natural Gas
Ameren
Transmission(a)
Other /
Intersegment
Eliminations		Ameren
Electric revenue change:
Effect of weather (estimate)(b)
$24 $— $— $— $— $24 
Base rates (estimate)(c)
(6)63 — 39 — 96 
Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)35 — — — — 35 
MEEIA performance incentives3 — — — — 3 
Off-system sales, capacity, and FAC revenues, net96 — — — — 96 
Customer energy-efficiency program investments— 12 — — — 12 
Other6 6 — — — 12 
Cost recovery mechanisms – offset in fuel and purchased power(d)
70 59 — — (22)107 
Other cost recovery mechanisms(e)
— 1 — — — 1 
Total electric revenue change$228 $141 $— $39 $(22)$386 
Fuel and purchased power change:
Energy costs$(99)$— $— $— $— $(99)
Sales volumes (excluding the estimated effects of weather)(3)— (3)
Effect of weather (estimate)(b)
(4)— — — — (4)
Effect of lower net energy costs included in base rates36 — — — — 36 
Other(7)— — — — (7)
Cost recovery mechanisms – offset in electric revenue(d)
(70)(59)— — 22 (107)
Total fuel and purchased power change$(147)$(59)$— $— $22 $(184)
Net change in electric margins$81 $82 $— $39 $— $202 
Natural gas revenue change:
Effect of weather (estimate)(b)
$(4)$— $— $— $— $(4)
Base rates (estimate)— — 28 — — 28 
Change in rate design— — (2)— — (2)
QIP rider— — 9 — — 9 
Other(1)— — — 1 — 
Cost recovery mechanisms – offset in natural gas purchased for resale(d)
21 — 153 — — 174 
Other cost recovery mechanisms(e)
— — 9 — — 9 
Total natural gas revenue change$16 $— $197 $— $1 $214 
Natural gas purchased for resale change:
Effect of weather (estimate)(b)
$4 $— $— $— $— $4 
Cost recovery mechanisms – offset in natural gas revenue(d)
(21)— (153)— — (174)
Total natural gas purchased for resale change$(17)$— $(153)$— $— $(170)
Net change in natural gas margins$(1)$— $44 $— $1 $44 
(a)Includes an increase in transmission electric margins of $36 million in 2021, compared with 2020, at Ameren Illinois.
(b)Represents the estimated variation resulting primarily from changes in cooling and heating degree days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.
(c)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates. For Ameren Missouri, base rates exclude an increase of $7 million for the recovery of lost electric margins in 2021, compared with 2020, resulting from the MEEIA customer energy-efficiency programs. This amount is included in the “sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” line item.
(d)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of income, resulting in no change to electric and natural gas margins. Activity in Other/Intersegment Eliminations represents the elimination of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI, as well as Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution. See Note 13 – Related-party Transactions and Note 16 – Segment Information under Part II, Item 8, of this report for additional information on intersegment eliminations.
(e)Offsetting expense increases or decreases are reflected in “Other operations and maintenance,” “Depreciation and amortization,” or in “Taxes other than income taxes” within the “Operating Expenses” section of the statement of income. These items have no overall impact on earnings.
48
Table of Contents
Ameren
Ameren’s electric margins increased $202 million, or 5%, in 2021, compared with 2020, because of increased margins at Ameren Missouri, Ameren Illinois Electric Distribution, and Ameren Transmission, as discussed below. Ameren’s natural gas margins increased $44 million, or 7%, between years primarily because of increased margins at Ameren Illinois Natural Gas, as discussed below.
Ameren Transmission
Ameren Transmission’s electric margins increased $39 million, or 7%, in 2021, compared with 2020. Base rate revenues were favorably affected by continued capital investment (+$23 million), as evidenced by a 12% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$33 million). These increases were partially offset by the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE and the effect of the FERC’s March 2021 order (-$17 million), which required refunds primarily related to historical recovery of materials and supplies inventories. See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the May 2020 and March 2021 FERC orders.
Ameren Missouri
Ameren Missouri’s electric margins increased $81 million, or 3%, in 2021, compared with 2020. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $70 million in 2021, compared with 2020. The increased revenues are fully offset by an increase in fuel and purchased power costs, which increased primarily due to higher electric prices, the absence of the Callaway Energy Center generation and a significant increase in customer demand for electricity in mid-February 2021 due to extremely cold weather. The changes to “Cost recovery mechanisms – offset in fuel and purchased power” are fully offset by “Cost recovery mechanisms – offset in electric revenue” in the table above, and result in no impact to margins. Ameren Missouri’s 5% exposure to net energy costs variances under the FAC is reflected within “Off-system sales, capacity and FAC revenues, net” and “Energy costs”.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2021, compared with 2020:
•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric sales margins increased an estimated $32 million. The increase was primarily due to an increase in retail sales volumes in 2021, which were unfavorably affected by the COVID-19 pandemic in 2020, partially offset by a decrease in the average retail price per kilowatthour due to changes in customer usage patterns. The change in sales margins is the sum of the change in “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” on electric revenues (+$35 million) and “Sales volumes (excluding the estimated effects of weather)” on fuel and purchased power (-$3 million). While the MEEIA customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins under the MEEIA ensured that electric margins were not affected.
•The March 2020 MoPSC electric rate order that resulted in lower net energy costs included in base rates, partially offset by lower electric base rates, increased margins $30 million. The change in electric base rates is the sum of the change in “Base rates (estimate)” (-$6 million) and the “Effect of lower net energy costs included in base rates” (+$36 million) in the table above.
•Summer temperatures were warmer as cooling degree days increased 12%, and winter temperatures were warmer as heating degree days decreased 4%. The aggregate effect of weather increased margins by an estimated $20 million. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (+$24 million) and the “Effect of weather (estimate)” on fuel and purchased power (-$4 million) in the table above.
Ameren Missouri’s electric margins decreased $3 million due to higher net energy costs. The absence of the Callaway Energy Center generation and the extremely cold weather in mid-February 2021, partially offset by insurance recoveries related to the unplanned Callaway Energy Center maintenance outage, drove net energy costs higher than those reflected in base rates, resulting from Ameren Missouri’s 5% exposure to net energy cost variances under the FAC. The change in net energy costs is the sum of “Off-system sales, capacity and FAC revenues, net” (+$96 million) and “Energy costs” (-$99 million) in the table above.
Ameren Missouri’s natural gas margins were comparable between years. Purchased gas costs increased $21 million in 2021, compared with 2020, primarily resulting from higher natural gas prices throughout 2021 and the significant increase in customer demand and prices for natural gas in mid-February 2021 due to extremely cold weather. The increased purchased gas costs are fully offset by an increase in natural gas revenues under the PGA, resulting in no impact to margin. The increase in purchased gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above.
Ameren Illinois
Ameren Illinois’ electric margins increased $118 million, or 8%, in 2021, compared with 2020, driven by increased margins at Ameren Illinois Electric Distribution and Ameren Illinois Transmission. Ameren Illinois Natural Gas’ margins increased $44 million, or 8%, between years.
49
Table of Contents
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $82 million, or 8%, in 2021, compared with 2020. Purchased power costs increased $59 million in 2021, compared with 2020, primarily resulting from higher electric prices and the significant increase in customer demand for electricity in mid-February 2021 due to extremely cold weather. The increased purchased power costs are fully offset by an increase in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin. The increase in purchased power cost is reflected in “Cost recovery mechanisms – offset in electric revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in fuel and purchased power” in the table above.
The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in 2021, compared with 2020:
•Base rates increased due to a higher recognized ROE (+$9 million), as evidenced by an increase of 49 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, increased capital investment (+$10 million), as evidenced by a 8% increase in year-end rate base, higher recoverable non-purchased power expenses (+$35 million), and revenue requirement reconciliation adjustment true-ups for 2020 (+$9 million). The sum of these changes collectively increased margins $63 million.
•Revenues increased $12 million due to the recovery of and return on increased customer energy-efficiency program investments under performance-based formula ratemaking.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $44 million, or 8%, in 2021, compared with 2020. Purchased gas costs increased $153 million in 2021, compared with 2020, primarily resulting from higher natural gas prices throughout 2021 and the significant increase in customer demand for natural gas in mid-February 2021 due to extremely cold weather. The increased purchased gas costs are fully offset by an increase in natural gas revenues under the PGA, resulting in no impact to margin. The increase in purchased gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins in 2021, compared with 2020:
•Revenues increased $28 million due to higher natural gas base rates as a result of the January 2021 natural gas rate order.
•Revenues increased $9 million due to additional investment in qualified natural gas infrastructure under the QIP.
•Other cost recovery mechanisms increased revenues $9 million, primarily due to increased revenues for excise taxes.
Ameren Illinois Transmission
Ameren Illinois Transmission’s electric margins increased $36 million, or 11%, in 2021, compared with 2020. Margins were favorably affected by increased capital investment (+$23 million), as evidenced by an 18% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$26 million). These increases were partially offset by the absence in 2021 of the FERC’s May 2020 order addressing the allowed base ROE and the effect of the FERC’s March 2021 order (-$13 million), which required refunds primarily related to historical recovery of materials and supplies inventories. See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the May 2020 and March 2021 FERC orders.
50
Table of Contents
Other Operations and Maintenance Expenses
Total by Segment(a)
Increase by Segment
Overall Ameren Increase of $113 Million
aee-20211231_g16.jpgaee-20211231_g17.jpg
(a)Includes $62 million and $57 million at Ameren Transmission in 2021 and 2020, respectively, and other/intersegment eliminations of $(6) million and $(9) million in 2021 and 2020, respectively.
Ameren MissouriAmeren Illinois Natural GasOther/Intersegment Eliminations
Ameren Illinois Electric DistributionAmeren Transmission
Ameren
Other operations and maintenance expenses at Ameren increased $113 million in 2021, compared with 2020. In addition to changes by segments discussed below, other operations and maintenance expenses increased $3 million in 2021 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of increased costs for support services.
Ameren Transmission
Other operations and maintenance expenses at Ameren Transmission increased $5 million in 2021, compared with 2020, primarily because of increased maintenance activity.
Ameren Missouri
The $62 million increase in Ameren Missouri’s other operations and maintenance expenses in 2021, compared with 2020, was primarily due to the following items:
•Energy center maintenance costs, other than Callaway refueling and maintenance costs, increased $29 million, primarily because of costs related to new wind generation facilities, which are recovered under the RESRAM, and the deferral of projects in 2020.
•Callaway Energy Center refueling and maintenance costs increased $28 million because of the amortization of those costs, beginning in January 2021, which were previously deferred as a regulatory asset, pursuant to the MoPSC’s February 2020 order.
•Recoverable customer energy-efficiency program costs increased $16 million because of increased participation in the MEEIA programs in 2021.
•Technology-related expenditures increased $11 million, primarily because of cloud computing licensing costs and software maintenance.
•Transmission and distribution expenditures increased $6 million, primarily because of increased storm costs.
•The cash surrender value of company-owned life insurance decreased $6 million because of less favorable market returns in 2021, compared with 2020.
51
Table of Contents
The following items partially offset the above increases in other operations and maintenance expenses between years:
•Labor and benefit costs decreased $12 million, primarily because of higher capitalization of costs resulting from increased construction activity.
•Amortization of regulatory balances, primarily solar rebate costs pursuant to the MoPSC’s March 2020 electric rate order and RESRAM deferrals, decreased $11 million.
•Expenses decreased $10 million because of increased bad debt costs in 2020 largely due to the COVID-19 pandemic.
•Deferral to a regulatory asset of $5 million of certain costs incurred in 2020 related to the COVID-19 pandemic, pursuant to the MoPSC’s March 2021 orders.
Ameren Illinois
Other operations and maintenance expenses increased $45 million at Ameren Illinois in 2021, compared with 2020, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2021 and 2020.
Ameren Illinois Electric Distribution
The $28 million increase in Ameren Illinois Electric Distribution’s other operations and maintenance expenses in 2021, compared with 2020, was primarily due to the following items:
•Amortization of regulatory assets associated with customer energy-efficiency program investments under formula ratemaking increased $8 million.
•Technology-related expenditures increased $8 million, primarily because of cloud computing licensing costs and software maintenance.
•Increased bad debt expense of $7 million, primarily because of increased recovery of bad debt costs allowed by the ICC.
•Expenses increased $5 million because of the true-up of vegetation management expenditures consistent with the December 2021 ICC electric distribution service rate order.
•The cash surrender value of company-owned life insurance decreased $3 million because of less favorable market returns in 2021 compared with 2020.
The above increases were partially offset by a $7 million reduction in environmental remediation rider costs, which resulted from a decline in the required remediation efforts.
Ameren Illinois Natural Gas
Other operations and maintenance expenses at Ameren Illinois Natural Gas increased $15 million in 2021, compared with 2020, largely due to an $8 million increase in infrastructure maintenance and compliance activity. Other operations and maintenance expenses also increased $5 million because of the absence in 2021 of miscellaneous amortizations of regulatory liabilities, which lowered expenses in 2020. These increases were partially offset by $3 million reduction in recoverable bad debt expense and environmental remediation rider costs consistent with the amounts allowed by the ICC.
52
Table of Contents
Depreciation and Amortization
Total by Segment(a)
Increase by Segment
Overall Ameren Increase of $71 Million
aee-20211231_g18.jpgaee-20211231_g19.jpg
(a)Includes other/intersegment eliminations of $4 million and $4 million in 2021 and 2020, respectively.
Ameren MissouriAmeren Illinois Natural GasOther/Intersegment Eliminations
Ameren Illinois Electric DistributionAmeren Transmission
The $71 million, $28 million, and $38 million increase in depreciation and amortization expenses in 2021, compared with 2020, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, was primarily due to additional property, plant, and equipment across their respective segments. Ameren’s and Ameren Missouri’s depreciation and amortization expenses reflected a deferral to a regulatory asset of depreciation and amortization expenses pursuant to the PISA and the RESRAM. The PISA and RESRAM deferrals of depreciation and amortization expenses was $98 million and $27 million in 2021 and 2020, respectively.
53
Table of Contents
Taxes Other Than Income Taxes
Total by Segment(a)
Increase by Segment
Overall Ameren Increase of $29 Million
aee-20211231_g20.jpgaee-20211231_g21.jpg
(a)Includes $8 million and $8 million at Ameren Transmission in 2021 and 2020, respectively, and other/intersegment eliminations of $12 million and $10 million in 2021 and 2020, respectively.
Ameren MissouriAmeren Illinois Natural GasOther/Intersegment Eliminations
Ameren Illinois Electric DistributionAmeren Transmission
Taxes other than income taxes increased $29 million at Ameren in 2021, compared with 2020, primarily because of increased excise taxes of $11 million and $7 million at Ameren Missouri and Ameren Illinois Natural Gas, respectively, resulting from increased sales. Additionally, taxes other than income taxes increased $5 million, compared with the year-ago period, at Ameren Missouri because of increased property taxes, primarily resulting from the addition of wind generation properties and higher assessed values, partially offset by lower natural gas property taxes. Taxes other than income taxes also increased $3 million at Ameren Illinois Electric Distribution because of increased excise taxes, resulting from decreased tax credits compared with 2020.
See Excise Taxes in Note 15 – Supplemental Information under Part II, Item 8, of this report for additional information.
54
Table of Contents
Other Income, Net
Total by SegmentIncrease by Segment
Overall Ameren Increase of $51 Million
aee-20211231_g22.jpgaee-20211231_g23.jpg
Ameren MissouriAmeren Illinois Natural GasOther/Intersegment Eliminations
Ameren Illinois Electric DistributionAmeren Transmission
Other income, net, increased $51 million at Ameren in 2021, compared with 2020, primarily because of the following items:
•The non-service cost component of net periodic benefit income increased $20 million, primarily because of increases of $9 million, $5 million, and $4 million for Ameren Missouri, Ameren Illinois Electric Distribution, and activity not reported as part of a segment, respectively.
•Income from equity method investments to advance clean and resilient energy technologies increased $9 million for activity not reported as part of a segment.
•Charitable donations were $8 million lower at Ameren Missouri due to the absence of charitable donations made in the year-ago period pursuant to the MoPSC’s March 2020 electric rate order. Charitable donations were $7 million lower for activity not reported as part of a segment due to a return to normal levels at Ameren (parent).
•The equity portion of allowance for funds used during construction increased $7 million at Ameren Missouri due to higher construction work in progress balances during 2021.
See Note 6 – Other Income, Net under Part II, Item 8, of this report for additional information. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for more information on the non-service cost components of net periodic benefit income.
55
Table of Contents
Interest Charges
Total by SegmentIncrease (Decrease) by Segment
Overall Ameren Decrease of $36 Million
aee-20211231_g24.jpgaee-20211231_g25.jpg
Ameren MissouriAmeren Illinois Natural GasOther/Intersegment Eliminations
Ameren Illinois Electric DistributionAmeren Transmission
Interest charges decreased $36 million and $53 million in 2021, compared with 2020, at Ameren and Ameren Missouri, respectively, primarily because of increased deferrals to a regulatory asset of interest charges pursuant to the PISA and RESRAM. The PISA and RESRAM deferrals of interest charges were $82 million and $12 million in 2021 and 2020, respectively. Interest charges increased $9 million at Ameren Illinois in 2021, compared with 2020, as discussed below.
The following items partially offset the above decreases in interest charges in 2021, compared with 2020:
•Issuances of long-term debt at Ameren Missouri in October 2020 and June 2021 collectively increased interest charges by $11 million and $6 million, respectively.
•Issuance of long-term debt at Ameren (parent) in April 2020 increased interest charges by $7 million.
•Interest charges at Ameren Illinois Transmission increased by $5 million as a result of the Ameren Illinois issuances of long-term debt in November 2020 and June 2021 and a March 2021 FERC order, primarily related to the historical recovery of materials and supplies inventories.
56
Table of Contents
Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2021 and 2020:
20212020
Ameren14%15%
Ameren Missouri1%7%
Ameren Illinois25%24%
Ameren Illinois Electric Distribution24%22%
Ameren Illinois Natural Gas27%26%
Ameren Illinois Transmission25%25%
Ameren Transmission26%26%
See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois.
The effective income tax rate was higher at Ameren Illinois Electric Distribution in 2021, compared with 2020, primarily because of decreased tax benefits from certain depreciation differences on property-related items largely attributable to lower amortization of excess deferred taxes.
LIQUIDITY AND CAPITAL RESOURCES
Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash provided by operating activities, we use 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 to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). In addition, to support a portion of its fuel requirements for generation, Ameren Missouri has entered into various long-term commitments to meet these requirements. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. Ameren’s, Ameren Missouri’s, and Ameren Illinois’ estimated minimum purchase obligations associated with these commitments totaled $1.6 billion, $0.7 billion, and, $0.8 billion, respectively, which include $0.7 billion, $0.3 billion, and, $0.4 billion, respectively, in 2022.
We expect to make significant capital expenditures over the next five years, as discussed in the Capital Expenditures sections below, supported by a combination of long-term debt and equity, as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy target requirements, environmental compliance, and other improvements. For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2026. Ameren expects these issuances to provide equity of about $100 million annually. In addition, in 2021, Ameren established an ATM program under which Ameren may offer and sell from time to time up to $750 million of its common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. During 2021, Ameren issued a total of 3.4 million shares of common stock and received aggregate proceeds of $261 million under the ATM program and the settlement of the remaining portion of the August 2019 forward sale agreement. Ameren plans to issue approximately $300 million of equity each year from 2022 to 2026 in addition to issuances under the DRPlus and employee benefit plans. Ameren expects its equity to total capitalization to be about 45% through December 31, 2026, with the long-term intent to support solid investment-grade credit ratings. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the ATM program, the 2021 settlement of the remaining portion of the August 2019 forward sale agreement, and the September 2021, December 2021, and January 2022 forward sale agreements.
The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments at the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2021, for Ameren, Ameren Missouri, and Ameren Illinois. With the credit capacity available under the Credit Agreements, and cash and cash equivalents, Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively had net available liquidity of $1.8 billion at December 31, 2021. See Credit Facility Borrowings and Liquidity and Long-term Debt and Equity below for additional information.
57
Table of Contents
The following table presents net cash provided by (used in) operating, investing, and financing activities for the years ended December 31, 2021 and 2020:
Net Cash Provided By
Operating Activities		Net Cash Used In
Investing Activities		Net Cash Provided By
Financing Activities
20212020Variance20212020Variance20212020Variance
Ameren$1,661 $1,727 $(66)$(3,528)$(3,329)$(199)$1,721 $1,727 $(6)
Ameren Missouri929 911 18 (1,922)(1,904)(18)856 1,099 (243)
Ameren Illinois662 679 (17)(1,437)(1,444)7 761 787 (26)
Cash Flows from Operating Activities
Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional regulatory rate review, subject to prudence reviews. Similar regulatory mechanisms exist for certain other operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by seasonal customer rates and changes in customer demand due to weather, such as increased demand resulting from the extremely cold weather in mid-February 2021, significantly affects the amount and timing of our cash provided by operating activities. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our regulatory frameworks.
Ameren
Ameren’s cash provided by operating activities decreased $66 million in 2021, compared with 2020. The following items contributed to the decrease:
•A $62 million increase in payroll tax payments primarily due to the employer portion of Social Security taxes as a result of a payment deferral allowed in 2020 under the Coronavirus Aid, Relief, and Economic Security Act. Half of the 2020 deferral was paid at the end of 2021 and the remaining half will be paid at the end of 2022.
•A $49 million increase in the cost of natural gas held in storage, primarily at Ameren Illinois, because of higher prices.
•A $44 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of power, natural gas, and other fuels.
•A $43 million increase in interest payments, primarily due to an increase in the average outstanding debt.
•An $18 million increase in energy center maintenance costs, other than those associated with the Callaway refueling and maintenance outage, at Ameren Missouri, primarily because of costs related to new wind generation facilities.
•A $15 million increase in major storm restoration costs at Ameren Illinois, primarily due to a January 2021 storm.
•An $8 million increase in pension and postretirement benefit plan contributions.
•A $6 million increase in payments to contractors at Ameren Illinois, primarily related to distribution expenditures for increased natural gas infrastructure maintenance and compliance costs.
•A $6 million increase in property tax payments at Ameren Missouri due to higher assessed property tax values.
The following items partially offset the decrease in Ameren’s cash from operating activities between periods:
•A $74 million increase due to the net impact of customer collections, the effect of riders, and increased commodity costs. An increase at Ameren Missouri, as discussed below, and increased customer collections at ATXI were partially offset by a decrease at Ameren Illinois, as discussed below.
•A $30 million decrease in payments for nuclear refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. There was no scheduled refueling and maintenance outage in 2021.
•A $21 million decrease in payments to settle ARO liabilities, primarily related to the closure of Ameren Missouri’s CCR storage facilities.
•A $21 million increase, primarily resulting from reduced purchases of materials and supplies at Ameren Illinois to support operations in 2021 as levels were increased in 2020 to mitigate against potential supply disruptions associated with the COVID-19 pandemic.
•A $21 million increase resulting from a reduction in payments for certain cloud computing arrangements.
•A $14 million increase resulting from income tax refunds of $1 million in 2021, compared with income tax payments of $13 million in 2020, primarily from lower taxable income and the timing of payments in 2021.
•A $12 million decrease in payments related to charitable donations.
58
Table of Contents
Ameren Missouri
Ameren Missouri’s cash provided by operating activities increased $18 million in 2021, compared with 2020. The following items contributed to the increase:
•An $86 million increase due to the net impact of customer collections, the effect of riders, and increased commodity costs. The increase resulted from increased retail sales and a net increase attributable to riders, excluding the PGA. These increases were partially offset by increased purchases for natural gas for resale and purchased power as a result of the significant increase in customer demand and increased prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, which also contributed to a net decrease under the PGA, and a decrease in collections of outstanding account receivables. See Outlook below for additional information about the extension of the collection period for the PGA related to the extremely cold weather in mid-February 2021.
•A $30 million decrease in payments for nuclear refueling and maintenance outages at the Callaway Energy Center. There was no scheduled refueling and maintenance outage in 2021.
•A $22 million decrease in payments to settle ARO liabilities, primarily related to the closure of CCR storage facilities.
•An $11 million increase resulting from a reduction in payments for certain cloud computing arrangements.
The following items partially offset the increase in Ameren Missouri’s cash from operating activities between periods:
•A $45 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of power, natural gas, and other fuels.
•A $28 million increase in payroll tax payments primarily due to the employer portion of Social Security taxes as a result of a payment deferral allowed in 2020 under the Coronavirus Aid, Relief, and Economic Security Act. Half of the 2020 deferral was paid at the end of 2021 and the remaining half will be paid at the end of 2022.
•An $18 million increase in energy center maintenance costs, other than those associated with the Callaway refueling and maintenance outage, primarily because of costs related to new wind generation facilities.
•A $15 million increase in interest payments, primarily due to an increase in the average outstanding debt.
•A $6 million increase in property tax payments due to higher assessed property tax values.
•A $5 million increase in pension and postretirement benefit plan contributions.
Ameren Illinois
Ameren Illinois’ cash provided by operating activities decreased $17 million in 2021, compared with 2020. The following items contributed to the decrease:
•A $45 million increase in the cost of natural gas held in storage because of higher prices.
•A $27 million decrease due to the net impact of commodity costs, the effect of riders, and customer collections. The decrease resulted from increased purchases for natural gas for resale and purchased power as a result of the significant increase in customer demand and increased prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, which also contributed to a net decrease under the PGA, and a net decrease attributable to other riders. The decrease from riders was partially offset by increased retail sales; the effect of the phase-in of collection activities beginning in April 2021, which had been suspended for most of 2020; increased customer collections resulting from base rate increases pursuant to the January 2021 natural gas rate order and due to electric transmission rate base growth; and state funding received for customer billing assistance. See Outlook below for additional information about the extension of the collection period for the PGA related to the extremely cold weather in mid-February 2021.
•A $21 million increase in payroll tax payments primarily due to the employer portion of Social Security taxes as a result of a payment deferral allowed in 2020 under the Coronavirus Aid, Relief, and Economic Security Act. Half of the 2020 deferral was paid at the end of 2021 and the remaining half will be paid at the end of 2022.
•A $15 million increase in major storm restoration costs, primarily due to a January 2021 storm.
•An $11 million increase in interest payments, primarily due to an increase in the average outstanding debt.
•A $6 million increase in payments to contractors primarily related to distribution expenditures for increased natural gas infrastructure maintenance and compliance costs.
The following items partially offset the decrease in Ameren Illinois’ cash from operating activities between periods:
•An $82 million increase resulting from income tax refunds of $41 million in 2021, compared with income tax payments of $41 million in 2020, from Ameren (parent) pursuant to the tax allocation agreement, primarily from lower taxable income and the timing of payments in 2021.
•A $21 million increase, primarily resulting from reduced purchases of materials and supplies to support operations in 2021 as levels were increased in 2020 to mitigate against potential supply disruptions associated with the COVID-19 pandemic.
•A $10 million increase resulting from a reduction in payments for certain cloud computing arrangements.
59
Table of Contents
Cash Flows from Investing Activities
Ameren’s cash used in investing activities increased $199 million during 2021, compared with 2020, primarily as a result of a $246 million increase in capital expenditures, net of a decrease in wind generation expenditures. Increased capital expenditures at Ameren Missouri were partially offset by decreased expenditures at Ameren Illinois and ATXI. See discussion of changes at Ameren Missouri and Ameren Illinois below. ATXI’s capital expenditures decreased $66 million, primarily as a result of placing the ninth and final line segment of the Illinois Rivers transmission line in service in December 2020. Ameren’s increase in capital expenditures was partially offset by a $28 million decrease in net investment activity in the nuclear decommissioning trust fund at Ameren Missouri and a $22 million decrease due to the timing of nuclear fuel expenditures.
Ameren Missouri’s cash used in investing activities increased $18 million during 2021, compared with 2020, primarily as a result of a $349 million increase in capital expenditures, primarily related to electric delivery infrastructure upgrades and electric transmission system reliability projects partially offset by a decrease in wind generation expenditures. The increase in capital expenditures was partially offset by a $278 million decrease related to money pool advances activity, a $28 million decrease in net investment activity in the nuclear decommissioning trust fund, and a $22 million decrease due to the timing of nuclear fuel expenditures.
Ameren Illinois’ cash used in investing activities decreased $7 million during 2021, compared with 2020, due to decreased capital expenditures, primarily related to electric transmission system reliability projects and natural gas infrastructure, partially offset by electric delivery infrastructure upgrades.
Capital Expenditures
The following charts present our capital expenditures for the years ended December 31, 2021 and 2020:
2021 – Total Ameren $3,479(a)
2020 – Total Ameren $3,233(a)
aee-20211231_g26.jpgaee-20211231_g27.jpg
Ameren Missouri(b)
Ameren Illinois Natural GasATXI and other electric transmission subsidiaries
Ameren Illinois Electric DistributionAmeren Illinois Transmission
(a)Includes Other capital expenditures of $(9) million and $7 million for the years ended December 31, 2021 and 2020, respectively, which includes amounts for the elimination of intercompany transfers.
(b)Ameren Missouri’s capital expenditures include $525 million and $564 million for wind generation expenditures for the years ended December 31, 2021 and 2020, respectively.
Ameren’s 2021 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI and other electric transmission subsidiaries, which spent $41 million. Of the $278 million in capital expenditures spent by Ameren Illinois Natural Gas during 2021, $170 million related to natural gas projects eligible for QIP recovery. In addition, Ameren Missouri expenditures included $525 million for wind generation, primarily for the acquisition of the Atchison Renewable Energy Center. In both years, other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested
60
Table of Contents
in various software projects. As of December 31, 2021, Ameren Illinois exceeded the minimum capital spending levels required pursuant to IEIMA.
Ameren’s 2020 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI and other electric transmission subsidiaries, which spent $113 million primarily on the Illinois Rivers transmission line. Of the $301 million in capital expenditures spent by Ameren Illinois Natural Gas during 2020, $189 million related to natural gas projects eligible for QIP recovery. In addition, Ameren Missouri expenditures included $564 million for the acquisition of the High Prairie Renewable Energy Center.
The following table presents Ameren’s estimate of capital expenditures that will be incurred from 2022 through 2026, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations:
20222023 – 2026Total
Ameren Missouri$1,690 $6,805 –$7,520 $8,495 –$9,210 
Ameren Illinois Electric Distribution580 2,405 –2,660 2,985 –3,240 
Ameren Illinois Natural Gas370 1,320 –1,455 1,690 –1,825 
Ameren Illinois Transmission650 2,580 –2,855 3,230 –3,505 
ATXI and other electric transmission subsidiaries85 105 –115 190 –200 
Other5 20 –20 25 –25 
Ameren$3,380 $13,235 –$14,625 $16,615 –$18,005 
Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, as well as expenditures for compliance with environmental regulations. Capital expenditures related to coal-fired generation of approximately $0.7 billion are included in Ameren Missouri’s estimated capital expenditures. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, including capital expenditures to modernize its electric and gas distribution systems. These planned investments are based on the assumption of continued constructive regulatory frameworks, including an assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA from December 2023 to December 2028. Ameren’s and Ameren Missouri’s estimated capital expenditures exclude renewable generation investment opportunities of 1,200 MWs by 2026, which are included in Ameren Missouri’s 2020 IRP, and additional investment opportunities that may be approved by the MISO to address reliability concerns in connection with the planned accelerated retirement of the Rush Island Energy Center.
In April 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In February 2022, the MISO updated a list of projects under consideration for the first phase of the roadmap, and is expected to approve certain projects for the first phase by mid-2022. Expenditures that result from the MISO long-range transmission planning roadmap may cause adjustments to our estimated 2022 through 2026 capital expenditures.
Ameren Missouri continually reviews its generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments within and outside our service territories. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, as well as our ability to obtain necessary regulatory approvals, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.
Environmental Capital Expenditures
Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO2, NOx, and mercury emissions from its coal-fired energy centers. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws that affect, or may affect, our facilities and capital expenditures to comply with such laws.
Cash Flows from Financing Activities
Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the level of dividends, and our long-term debt maturities, among other things.
61
Table of Contents
Ameren’s cash provided by consolidated financing activities decreased $6 million during 2021, compared with 2020. During 2021, Ameren utilized net proceeds of $1,997 million from the issuance of long-term debt for general corporate purposes, including to repay then-outstanding short-term debt, including short-term debt incurred in connection with the increased purchases for natural gas for resale and purchased power costs discussed above, and to fund, in part, investing activities. In 2021, Ameren received $55 million from net commercial paper issuances. In addition, Ameren received aggregate cash proceeds of $308 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan and the settlement of the remaining portion of the August 2019 forward sale agreement. These proceeds, along with cash on hand, were used to fund a portion of Ameren Missouri’s wind generation investments and to fund, in part, other investing activities. In comparison, in 2020, Ameren utilized net proceeds of $2,183 million from the issuance of long-term debt for general corporate purposes, including to repay then-outstanding short-term debt, including short-term debt incurred in connection with the repayment at maturity of long-term debt, to partially finance the acquisition of two wind generation facilities, and to repay other long-term debt. In addition, in 2020, Ameren received cash proceeds of $425 million from the partial settlement of a forward sale agreement of common stock that were used to fund a portion of Ameren Missouri’s wind generation investments. Collectively, in 2020, Ameren repaid long-term debt of $442 million, received $50 million from net commercial paper issuances, and used cash provided by financing activities to fund, in part, investing activities. During 2021, Ameren paid common stock dividends of $565 million, compared with $494 million in dividend payments in 2020.
Ameren Missouri’s cash provided by financing activities decreased $243 million during 2021, compared with 2020. During 2021, Ameren Missouri utilized net proceeds of $524 million from the issuance of long-term debt to repay then-outstanding short-term debt, including short-term debt incurred in connection with the increased purchases for natural gas for resale and purchased power costs discussed above. Additionally, the proceeds from the issuance of long-term debt and $207 million of capital contributions from Ameren (parent) were used to fund, in part, investing activities. In 2021, Ameren Missouri also received $165 million from commercial paper issuances. In comparison, in 2020, Ameren Missouri utilized cash on hand and net proceeds of $1,012 million from the issuance of long-term debt to repay then-outstanding short-term debt, including short-term debt incurred in connection with the repayment of maturity of long-term debt, and to partially finance the acquisition of two wind generation facilities. In 2020, Ameren Missouri also received $491 million in capital contributions from Ameren (parent). Collectively, in 2020, Ameren Missouri repaid long-term debt of $92 million, repaid net short-term debt of $234 million, and used cash provided by financing activities to fund, in part, investing activities. During 2021, Ameren Missouri paid common stock dividends of $24 million, compared with $66 million in dividend payments in 2020.
Ameren Illinois’ cash provided by financing activities decreased $26 million during 2021, compared with 2020. During 2021, Ameren Illinois utilized net proceeds of $449 million from the issuance of long-term debt to repay then-outstanding short-term debt, including short-term debt incurred in connection with the increased purchases for natural gas for resale and purchased power costs discussed above. Additionally, the proceeds from the issuance of long-term debt and $262 million of capital contributions from Ameren (parent) were used to fund, in part, investing activities. In 2021, Ameren Illinois also received $103 million from commercial paper issuances. In addition, Ameren Illinois repaid $19 million of money pool borrowings and redeemed $13 million of preferred stock in 2021. In comparison, in 2020, Ameren Illinois received $464 million in capital contributions from Ameren (parent). In addition, in 2020, Ameren Illinois utilized net proceeds of $373 million from the issuance of long-term debt to repay then-outstanding short-term debt. Collectively, in 2020 Ameren Illinois repaid net short-term debt of $53 million, borrowed $19 million from the money pool, and used cash provided by financing activities to fund, in part, investing activities.
Credit Facility Borrowings 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. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, commercial paper issuances, Ameren’s money pool arrangements and related borrowings, and relevant interest rates.
62
Table of Contents
The following table presents Ameren’s consolidated net available liquidity as of December 31, 2021:
Available at
December 31, 2021
Ameren (parent) and Ameren Missouri(a):
Missouri Credit Agreement – borrowing capacity
$1,200 
Less: Ameren (parent) commercial paper outstanding
178 
Less: Ameren Missouri commercial paper outstanding
165 
Less: Letters of credit
2 
Missouri Credit Agreement – subtotal
855 
Ameren (parent) and Ameren Illinois(b):
Illinois Credit Agreement – borrowing capacity
1,100 
Less: Ameren (parent) commercial paper outstanding
99 
Less: Ameren Illinois commercial paper outstanding
103 
Illinois Credit Agreement – subtotal
898 
Subtotal$1,753 
Cash and cash equivalents8 
Net available liquidity$1,761 
(a)     The maximum aggregate amount available to Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $900 million and $850 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.
(b)     The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the Illinois Credit Agreement is $500 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.
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 through December 2025. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on the Credit Agreements. During the year ended December 31, 2021, Ameren (parent), Ameren Missouri, and Ameren Illinois each issued commercial paper. Borrowings under the Credit Agreements and commercial paper issuances are based upon available interest rates at that time of the borrowing or issuance.
Ameren has a money pool agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option has the lowest interest rates.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval under the Federal Power Act. In 2020, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 2022 and September 2022, respectively. In July 2021, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2023.
The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements for changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or to other short-term borrowing arrangements, or other arrangements may be made.
63
Table of Contents
Long-term Debt and Equity
The following table presents Ameren’s issuances (net of any issuance premiums or discounts) of long-term debt and equity, as well as redemptions and maturities of long-term debt and preferred stock for the years ended December 31, 2021 and 2020. For additional information related to the terms and uses of these issuances and effective registration statements, and Ameren’s forward sale agreements relating to common stock, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. For information on capital contributions received by Ameren Missouri and Ameren Illinois from Ameren (parent), see Note 13 – Related-party Transactions under Part II, Item 8, of this report.
Month Issued, Redeemed, Repurchased, or Matured20212020
Issuances of Long-term Debt
Ameren:
1.75% Senior unsecured notes due 2028March$450 $— 
1.95% Senior unsecured notes due 2027November499 — 
3.50% Senior unsecured notes due 2031April— 798 
Ameren Missouri:
2.15% First mortgage bonds due 2032 (green bonds)June524 — 
2.95% First mortgage bonds due 2030March— 465 
2.625% First mortgage bonds due 2051 (green bonds)October— 547 
Ameren Illinois:
2.90% First mortgage bonds due 2051 (green bonds)June349 
0.375% First mortgage bonds due 2023June100 — 
1.55% First mortgage bonds due 2030November— 373 
ATXI:(a)
2.45% Senior unsecured notes due 2036November75 — 
Total Ameren long-term debt issuances $1,997 $2,183 
Issuances of Common Stock
Ameren:
DRPlus and 401(k)(b)
Various$47 $51 
August 2019 forward sale agreement(c)
Various113 425 
ATM program(d)
Various148 — 
Total Ameren common stock issuances(e)
$308 $476 
Maturities of Long-term Debt
Ameren:
2.70% Senior unsecured notes due 2020October$— $350 
Ameren Missouri:
5.00% Senior secured notes due 2020February— 85 
City of Bowling Green financing obligation (Peno Creek CT)December8 7 
Total long-term debt redemptions, repurchases, and maturities $8 $442 
Redemptions of Preferred Stock
Ameren Illinois:
6.625% SeriesMarch$12 $— 
7.75% SeriesMarch1 — 
Total Ameren Illinois preferred stock redemptions$13 $— 
(a)    Pursuant to a note purchase agreement, ATXI agreed to issue $95 million principal amount of 2.96% senior unsecured notes due 2052, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further information.
(b)    Ameren issued a total of 0.5 million and 0.7 million shares of common stock under its DRPlus and 401(k) plan in 2021 and 2020, respectively.
(c)    Ameren issued 1.6 million shares of common stock in February 2021 to settle the remainder of the August 2019 forward sale agreement. Ameren issued 5.9 million shares of common stock pursuant to a partial settlement of the August 2019 forward sale agreement in December 2020.
(d)     Ameren issued 1.8 million shares of common stock under the ATM program in 2021.
(e)     Excludes 0.5 million and 0.5 million shares of common stock valued at $33 million and $38 million issued for no cash consideration in connection with stock-based compensation in 2021 and 2020, respectively
The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
64
Table of Contents
Indebtedness Provisions and Other Covenants
At December 31, 2021, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreements.
We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $565 million, or $2.20 per share, in 2021 and $494 million, or $2.00 per share, in 2020. The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On February 11, 2022, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 59 cents per share, payable on March 31, 2022, to shareholders of record on March 9, 2022.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances.
Ameren Illinois’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions with respect to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in the capital structure at Ameren Illinois.
Ameren Missouri and Ameren Illinois, as well as 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 from 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.
At December 31, 2021, the amount of restricted net assets of Ameren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $3.8 billion.
The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren subsidiaries to their parent, Ameren:
20212020
Ameren$565 $494 
Ameren Missouri24 66 
Ameren Illinois— 9 
ATXI99 30 
Ameren Missouri and Ameren Illinois each have issued preferred stock, which provide for cumulative dividends. Each company’s board of directors considers the declaration of preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
65
Table of Contents
Credit Ratings
Our credit ratings affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.
The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:
Moody’sS&P
Ameren:
Issuer/corporate credit ratingBaa1BBB+
Senior unsecured debtBaa1BBB
Commercial paperP-2A-2
Ameren Missouri:
Issuer/corporate credit ratingBaa1BBB+
Secured debtA2A
Senior unsecured debtBaa1Not Rated
Commercial paperP-2A-2
Ameren Illinois:
Issuer/corporate credit ratingA3BBB+
Secured debtA1A
Senior unsecured debtA3BBB+
Commercial paperP-2A-2
ATXI:
Issuer credit ratingA2Not Rated
Senior unsecured debtA2Not Rated
A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
Collateral Postings
Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, were $66 million for Ameren and Ameren Missouri and cash collateral posted by external parties were $22 million for Ameren and Ameren Illinois at December 31, 2021. A sub-investment-grade issuer or senior unsecured debt rating (below “Baa3” from Moody’s or below “BBB-” from S&P) at December 31, 2021, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade obligations amounting to $89 million, $61 million, and $28 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2021, if market prices were 15% higher or lower than December 31, 2021 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade obligations.
Environmental Matters
Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety including permitting programs implemented via federal, state, and local authorities. Such environmental laws address air emissions; discharges to water bodies; the storage, handling and disposal of hazardous substances and waste materials; siting and land use requirements; and potential ecological impacts. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws, including those that may address climate change, that affect, or may affect, our facilities, operations, and capital expenditures to comply with such laws. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers.
Additionally, international agreements could lead to future federal or state legislation or regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris
66
Table of Contents
Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius. The Biden administration has announced a new policy commitment regarding a reduction in greenhouse gas emissions for the United States, but rulemaking to achieve such reductions has not yet been implemented. Actions taken to implement the Paris Agreement could result in future additional greenhouse gas reduction requirements in the United States. In addition, the Biden administration has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions targeting the utility industry.
We provide information regarding our sustainability initiatives through our website, including in our annual sustainability report, our responses to the annual climate change and water surveys conducted by CDP, and an ESG investor presentation. In addition, we issue an annual report in accordance with the Edison Electric Institute’s (EEI) and American Gas Association’s (AGA) ESG and sustainability-related reporting program. We also issue a periodic climate risk report and a report on our management of CCR. Additionally, we have posted a Task Force on Climate-related Financial Disclosures (TCFD) and Sustainability Accounting Standards Board (SASB) mapping of sustainability data. The reports may be updated at any time. The information on Ameren’s website, including the reports and documents mentioned in this paragraph, is not incorporated by reference into this report.
OUTLOOK
Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2022 and beyond. 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. Although restrictions on social activities and nonessential businesses implemented in our service territories in 2020 have been relaxed, additional restrictions may be imposed in the future. 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. For additional information regarding recent rate orders, lawsuits, and pending requests filed with state and federal regulatory commissions, including those discussed below, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Operations
•In 2021, our sales volumes, which have been, and continue to be, affected by the COVID-19 pandemic, among other things, increased compared to 2020, excluding the estimated effects of weather and customer energy-efficiency programs. While 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. We expect total weather-normalized sales to return to 2019 levels by mid-2022 with the growth expected to be primarily over the second half of 2022. Because of their regulatory frameworks, Ameren Illinois’ and ATXI’s revenues are largely decoupled from changes in sales volumes. See the Results of Operations section above for additional information on our accounts receivable balances and Ameren Illinois’ electric and natural gas bad debt riders. Additionally, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information on Ameren Illinois’ reinstatement of customer disconnection and late fee charges for non-payment, accounting authority orders issued by the MoPSC related to Ameren Missouri's electric and natural gas services to allow Ameren Missouri to accumulate certain costs incurred, net of savings, and forgone customer late fee revenues related to the COVID-19 pandemic, with such amounts approved for recovery by the MoPSC in the December 2021 electric and natural gas service rate orders, and orders issued by the ICC in a service disconnection moratorium proceeding, which required Ameren Illinois to implement more flexible credit and collection practices and allowed for recovery of costs incurred related to the COVID-19 pandemic and forgone late fees.
•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. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. 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. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. Ameren Missouri does not expect to exceed these rate increase limitations in 2022. Both the rate increase
67
Table of Contents
limitation and the PISA are effective through December 2023, unless Ameren Missouri requests and the MoPSC approves an extension through December 2028.
•In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2023 and low-income customer energy-efficiency programs through December 2024, along with a rider. Ameren Missouri intends to invest approximately $360 million over the life of the plan, including $70 million in 2022 and $75 million in 2023. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals. If the target goals are achieved for 2021 and 2022, additional revenues of $24 million would be recognized in 2022, and, if target goals are achieved for 2023, additional revenues of $13 million would be recognized in 2023.
•In December 2021, the MoPSC issued an order in Ameren Missouri’s 2021 electric service regulatory rate review, resulting in an increase of $220 million to Ameren Missouri’s annual revenue requirement for electric retail service. 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.
•Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base and the currently allowed 10.52% ROE, which includes a 50 basis point incentive adder for participation in an RTO, the revenue requirements included in 2022 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $422 million and $195 million, respectively. These revenue requirements represent an increase in Ameren Illinois’ revenue requirement of $42 million and a decrease in ATXI’s revenue requirements of $5 million from the revenue requirements reflected in 2021 rates, primarily due to higher expected rate base at Ameren Illinois and a lower expected rate base at ATXI. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2022, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2022 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the FERC formula ratemaking framework.
•The allowed base ROE for FERC-regulated transmission rates previously charged under the MISO tariff is the subject of an appeal filed with the United States Court of Appeals for the District of Columbia Circuit. Depending on the outcome of the appeal, the transmission rates charged during previous periods and the currently effective rates may be subject to change. Additionally, in March 2019, the FERC issued a Notice of Inquiry regarding its transmission incentives policy. In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which addressed many of the issues in the Notice of Inquiry on transmission incentives. The Notice of Proposed Rulemaking included an increased incentive in the allowed base ROE for participation in an RTO to 100 basis points from the current 50 basis points and revised the parameters for awarding incentives, while limiting the overall incentives to a cap of 250 basis points, among other things. In April 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking, which proposes to modify the Notice of Proposed Rulemaking’s incentive for participation in an RTO by limiting this incentive for utilities that join an RTO to 50 basis points and only allowing them to earn the incentive for three years, among other things. If this proposal is included in a final rule, Ameren Illinois and ATXI would no longer be eligible for the 50 basis point RTO incentive adder, prospectively. The FERC is under no deadline to issue a final rule on this matter. Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy, or any further order on base ROE. A 50 basis point change in the FERC-allowed base ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $12 million and $8 million, respectively, based on each company’s 2022 projected rate base.
•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 to reflect actual recoverable costs incurred and a return at the applicable WACC on year-end rate base. 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. Pursuant to 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 requirement for customer rates established for 2022 and 2023. As such, 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. For more information on the
68
Table of Contents
March 2021 ICC order, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. 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.
•Pursuant to the IETL, which was enacted in September 2021, Ameren Illinois may file an MYRP with the ICC to establish base rates for electric distribution service to be charged to customers for each calendar year of a four-year period. An MYRP would allow Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to a reconciliation cap and adjustments to the ICC-determined ROE for performance incentives and penalties. 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. Subject to a constructive outcome regarding the ICC’s determination of performance metrics, Ameren Illinois anticipates filing an MYRP by mid-January 2023, with rates effective beginning in 2024. If Ameren Illinois does not file an MYRP for rates effective beginning in 2024, its next opportunity to file an MYRP would be for rates effective beginning in 2028.
•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. Ameren Illinois’ 2022 electric distribution service revenues will be based on its 2022 actual recoverable costs, 2022 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. As of December 31, 2021, Ameren Illinois expects its 2022 electric distribution year-end rate base to be $3.9 billion. The 2022 revenue requirement reconciliation adjustment will be collected from, or refunded to, customers in 2024. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $11 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2022 projected year-end rate base, including electric energy-efficiency investments. Ameren Illinois’ allowed ROE for 2021 was based on an annual average of the monthly yields of the 30-year United States Treasury bonds of 2.05%.
•Pursuant to Illinois law, Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn 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 allowed ROE on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. While the ICC has approved a plan for Ameren Illinois to invest approximately $100 million per year in electric energy-efficiency programs through 2025, 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. 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.
•Ameren Missouri’s next scheduled refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2022. Effective beginning with the fall 2020 refueling and maintenance outage, during a scheduled refueling, which occurs every 18 months, maintenance expenses are deferred as a regulatory asset and amortized until the completion of the next refueling and maintenance outage. During an outage, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri may incur increased non-nuclear energy center maintenance costs in non-outage years.
•In August 2021, the United States Court of Appeals for the Eighth Circuit issued a decision that affirmed the United States District Court for the Eastern District of Missouri’s January 2017 liability ruling and the district court’s September 2019 remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In November 2021, the court of appeals issued an order denying requests for consideration previously sought by both Ameren Missouri and the United States Department of Justice. Based on its assessment of available legal, operational and regulatory alternatives, Ameren Missouri has determined not to further appeal the court rulings and, in December 2021, filed a motion with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The district court is under no deadline to issue a ruling revising the remedy order. In January 2022, the MISO completed a preliminary assessment regarding potential impacts of the retirement to the regional electric power system, which indicated transmission upgrades and voltage support would be needed in advance of the retirement to address reliability concerns. In February 2022, Ameren Missouri expects to formally notify the MISO of its intent to retire the Rush Island Energy Center. Upon receipt of the formal notification, the MISO will conduct a final reliability assessment. The MISO must also separately approve the specific upgrades and transmission support required to address reliability concerns noted in the assessment. For additional information on the NSR and Clean Air Act litigation, see Note 14 –
69
Table of Contents
Commitments and Contingencies under Part II, Item 8, of this report. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect the planned acceleration of the retirement of the Rush Island Energy Center from 2039, the retirement year for the facility as reflected in the 2020 IRP. 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, including 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. As of December 31, 2021, Ameren and Ameren Missouri classified the remaining net book value of the Rush Island Energy Center as plant to be abandoned, net, within “Property, Plant, and Equipment, Net” on Ameren’s and Ameren Missouri’s balance sheets. 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.
•In January 2022, Ameren Missouri received notice of a proposed determination by the EPA that it has rejected Ameren Missouri’s requests to extend the timeline for operating certain impoundments located at the Sioux and Meramec energy centers. Compliance with the CCR Rule’s requirements for closure of the impoundments would be required 135 days after the EPA issues a final determination, which Ameren Missouri expects to be issued in the spring of 2022. If Ameren Missouri was no longer able to use the surface impoundments at the Sioux or Meramec energy centers, Ameren Missouri would not be able to operate the energy centers unless an alternative for handling the CCR material is in place. Ameren Missouri plans to retire the Meramec Energy Center in 2022, and is accelerating its construction plans to build a CCR Rule-compliant impoundment at the Sioux Energy Center to allow for continued operations. Additionally, Ameren Missouri is seeking a reliability determination from the MISO, which, if granted, would extend the deadline to comply with the requirement to close the impoundments and allow the energy centers to operate. Ameren Missouri does not expect that this matter will have a material adverse effect on its results of operations, financial position, or liquidity.
•The IETL established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois will be subject to limits on emissions, including CO2 and NOx, equal to their unit-specific average emissions from 2018 through 2020, for any rolling twelve-month period beginning October 1, 2021, through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, which could limit the operations of Ameren Missouri's five natural gas-fired energy centers located in the state of Illinois, and will result in the closure of one or more energy centers earlier than anticipated. These energy centers are utilized to support peak loads. Subject to conditions in the IETL, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service as necessary. Ameren Missouri is reviewing the emission standards and the effect they may have on its generation strategy, including any increases in capital expenditures or operating costs, and changes to the useful lives of the five natural gas-fired energy centers. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect, among other things, the impact of these new emissions standards.
•Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek increases to electric and natural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, legislative solutions to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, economic impacts of the COVID-19 pandemic, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective technological advances, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy for efficiencies and as a means to address economy-wide CO2 emission concerns. We expect that increased investments, including expected future investments for environmental compliance, system reliability improvements, and new generation sources, will result in rate base and revenue growth but also higher depreciation and financing costs.
•We are observing inflationary pressures on the prices of commodities, labor, services, materials, and supplies. Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for fuel, purchased power, and natural gas supply. Additionally, for certain non-commodity cost changes, the use of trackers, riders, and formula ratemaking, as applicable, mitigates our exposure. The inflationary pressures could impact our ability to control costs and/or make substantial investments in our businesses, including our ability to recover costs and investments, and to earn our allowed ROEs within frameworks established by our regulators, while maintaining rates that are affordable to our customers.
Liquidity and Capital Resources
•Our customers’ payment for our services has been adversely affected by the COVID-19 pandemic. See the Results of Operations section above for additional information on our accounts receivable balances. Further, our liquidity and our capital expenditure plans could be adversely affected by other impacts resulting from the COVID-19 pandemic, including but not limited to potential impacts on our ability to access the capital markets on reasonable terms when needed and the timing of tax payments and the utilization of tax credits. We expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, however, disruptions to
70
Table of Contents
the capital markets and the ability of our suppliers and contractors to perform as required under their contracts could impact the execution of our capital investment strategy. For further discussion on the impacts to our ability to access the capital markets, see below.
•In February 2022, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2022. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4 billion over the five-year period from 2022 through 2026, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 through 2026 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA from December 2023 to December 2028.
•In connection with Ameren Missouri’s 2020 IRP, Ameren established a goal of achieving net-zero carbon emissions by 2050. Ameren is also targeting a 50% CO2 emission reduction by 2030 and an 85% reduction by 2040 from the 2005 level. In August 2021, the MoPSC issued an order affirming the plan’s compliance with Missouri law. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, hydro, and nuclear power, and supports increased investment in new energy technologies. It also includes expanding renewable sources by adding 3,100 MWs of renewable generation by the end of 2030 and a total of 5,400 MWs of renewable generation by 2040. These amounts include 700 MWs related to the High Prairie Renewable and Atchison Renewable energy centers, which support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources that began in 2021. The plan also includes accelerating the retirement dates of the Sioux and Rush Island coal-fired energy centers to 2028 and 2039, respectively, the continued implementation of customer energy-efficiency programs, and the expectation that Ameren Missouri will seek NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date. Additionally, the plan includes retiring the Meramec and Labadie coal-fired energy centers at the end of their useful lives (by 2022 and 2042, respectively). Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain certificates of convenience and necessity from the MoPSC, and any other required approvals for the addition of renewable resources, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability to enter into build-transfer agreements for renewable generation and acquire that generation at a reasonable cost; the ability of developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment, including those that are affected by the disruptions in the global supply chain caused by the COVID-19 pandemic, among other things; changes in the scope and timing of projects; the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind, solar, and other renewable generation and storage technologies; changes in environmental regulations, including those related to carbon emissions; energy prices and demand; and Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion. In December 2021, the MoPSC issued an order in Ameren Missouri’s 2021 electric service regulatory rate review, which, among other things, approved a change in the depreciable lives of the Sioux and Rush Island energy centers’ assets consistent with Ameren Missouri’s 2020 IRP. Due to the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, Ameren Missouri plans to retire the Rush Island Energy Center prior to the 2039 date discussed above. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect an accelerated retirement date for the Rush Island Energy Center and the impact of new emission standards pursuant to the IETL, as discussed in Note 14 – Commitments and Contingencies, among other things. The next integrated resource plan is expected to be filed in September 2023.
•Effective beginning August 2021, Missouri law allows Missouri electric utility companies to petition the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance the cost of retiring electric generation facilities before the end of their useful lives, including the repayment of existing debt. In connection with the planned accelerated retirement of the Rush Island Energy Center due to the NSR and Clean Air Act Litigation discussed above, Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds.
•In February 2022, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Invenergy Renewables Global, LLC to acquire a 150-megawatt solar generation facility after construction. The facility is expected to be located in southeastern Illinois. The acquisition is subject to certain conditions, including the issuance of a certificate of convenience and necessity by the MoPSC, obtaining a MISO transmission interconnection agreement, and approval by the FERC. Ameren Missouri expects to file for a certificate of convenience and necessity with the MoPSC by mid-2022.
•Through 2026, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest up to $18.0 billion (Ameren Missouri – up to $9.2 billion; Ameren Illinois – up to $8.6 billion; ATXI – up to $0.2 billion) of capital expenditures during the period from 2022 through 2026. These planned investments are based on the assumption of continued constructive regulatory frameworks, including an assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA from December 2023 to December 2028. Ameren’s and Ameren Missouri’s estimates exclude renewable generation investment opportunities of 1,200 MWs by
71
Table of Contents
2026, which are included in Ameren Missouri’s 2020 IRP, and additional investment opportunities that may be approved by the MISO to address reliability concerns in connection with the planned accelerated retirement of the Rush Island Energy Center.
•In April 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In February 2022, the MISO updated a list of projects under consideration for the first phase of the roadmap, and is expected to approve certain projects for the first phase by mid-2022. Expenditures that result from the MISO long-range transmission planning roadmap may cause adjustments to our estimated 2022 through 2026 capital expenditures.
•Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA or state regulators, or requirements that may result from the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, could result in significant increases in capital expenditures and operating costs. Regulations enacted by a prior federal administration can be reviewed and repealed, and replacement or alternative regulations can be proposed or adopted by the current federal administration including the EPA. The ultimate implementation of any of these regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal and natural gas-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.
•The Ameren Companies have multiyear credit agreements that cumulatively provide $2.3 billion of credit through December 2025, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $2.7 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. By the end of 2022, $55 million $400 million, and $50 million of long-term debt obligations are due to mature at Ameren Missouri, Ameren Illinois, and ATXI, respectively. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and financing plans. To date, the Ameren Companies have been able to access the capital markets on reasonable terms when needed. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
•Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2026. Ameren expects these issuances to provide equity of about $100 million annually. In addition, in 2021, Ameren established an ATM program under which Ameren may offer and sell from time to time up to $750 million of its common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. Ameren plans to issue approximately $300 million of equity each year from 2022 to 2026 in addition to issuances under the DRPlus and employee benefit plans. Ameren expects its equity to total capitalization to be about 45% through December 31, 2026, with the long-term intent to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent).
•As of December 31, 2021, Ameren had $133 million in tax benefits from federal and state income tax credit carryforwards and $66 million in tax benefits from federal and state net operating loss carryforwards, which will be utilized in future periods. Ameren expects federal income tax payments at the required minimum levels from 2022 to 2026 resulting from the anticipated use of existing production tax credits generated by Ameren Missouri’s High Prairie Renewable and Atchison Renewable energy centers, existing tax net operating losses, tax credit carryforwards, tax overpayments, and outstanding refunds.
•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 and, for Ameren Missouri, under the FAC (Ameren Missouri - PGA $53 million, FAC $50 million; Ameren Illinois - PGA $221 million). Ameren Missouri’s PGA and FAC under-recoveries are designed to be collected from customers over 12 months beginning November 2021 and eight months beginning October 2021, respectively. 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, from 12 months to 36 months beginning November 2021, to lessen the impact on customer rates. Ameren Illinois is collecting the 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.
72
Table of Contents
The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are the most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
Accounting Estimate
Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery
We defer costs and recognize revenues that we intend to collect in future rates.
•Regulatory environment and external regulatory decisions and requirements
•Anticipated future regulatory decisions and our assessment of their impact
•The impact of prudence reviews, complaint cases, limitations on electric rate increases in Missouri, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments
•Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under performance-based formula ratemaking framework
•Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks
•Ameren Missouri’s estimate of revenue recovery under the MEEIA plans
Basis for Judgment
The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, legislation, or historical experience, as well as discussions with legal counsel. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers. We also recognize revenues for alternative revenue programs authorized by our regulators that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months following the end of the annual period in which they are recognized. Under IEIMA performance-based formula ratemaking, effective through 2023, Ameren Illinois estimates its annual electric distribution revenue requirement for interim periods by using internal forecasted rate base and published forecasted data regarding the annual average of the monthly yields of the 30-year United States Treasury bonds.
73
Table of Contents
Ameren Illinois estimates its annual revenue requirement as of December 31 of each year using that year’s actual operating results and assesses the probability of recovery from or refund to customers that the ICC will order at the end of the following year. Variations in investments made or orders by the ICC or courts can result in a subsequent change in Ameren Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates lost electric margins resulting from its MEEIA customer energy-efficiency programs, which are subsequently recovered through the MEEIA rider. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a description of our regulatory mechanisms and quantification of these assets or liabilities for each of the Ameren Companies.
The following table reflects the gain and other comprehensive income, which would be offset by the removal of regulatory assets and liabilities and an increase in accumulated other comprehensive income, that would have resulted if accounting guidance for rate-regulated businesses had been eliminated as of December 31, 2021:
AmerenAmeren
Missouri		Ameren
Illinois
Gains$3,562 $2,362 $1,104 
Other comprehensive income (before taxes) - pension and other postretirement benefit plan activity
791 399 392 
Accounting Estimate
Uncertainties Affecting Application
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of providing future employee benefits for the benefit plans we offer our employees. See Note 10 – Retirement Benefits under Part II, Item 8, of this report.
•Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable
•Discount rate
•Cash balance plan interest crediting rate on certain plans
•Future compensation increase assumption
•Health care cost trend rates
•Assumptions on the timing of employee retirements, terminations, benefit payments, and mortality
•Ability to recover certain benefit plan costs from our customers
•Changing market conditions that may affect investment and interest rate environments
•Future rate of return on pension and other plan assets
Basis for Judgment
Ameren has defined benefit pension plans covering substantially all of its employees and has postretirement benefit plans covering non-union employees hired before October 2015 and union employees hired before January 2020. Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable.
The following table reflects the sensitivity of Ameren’s pension and postretirement plans to potential changes in key assumptions for the year ended December 31, 2021:
  Pension BenefitsPostretirement Benefits
  Net Periodic
Benefit Cost		Projected Pension Benefit ObligationNet Periodic
Benefit Cost		Projected Postretirement Benefit
Obligation
0.25% decrease in discount rate$18 $188 $3 $38 
0.25% decrease in return on assets11 — 3 — 
0.25% increase in future compensation5 21 — — 
74
Table of Contents
Accounting Estimate
Uncertainties Affecting Application
Accounting for Contingencies
We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and that the amount of the loss can be reasonably estimated.
•Estimating financial impact of events
•Estimating likelihood of various potential outcomes
•Regulatory and political environments and requirements
•Outcome of legal proceedings, settlements, or other factors
•Changes in regulation, expected scope of work, technology, or timing of environmental remediation
Basis for Judgment
The determination of a loss contingency requires significant judgment as to the expected outcome of the contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider the nature of the litigation, the claim or assessment, opinions or views of legal counsel, and the expected outcome of potential litigation, among other things. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. The amount recorded for any contingency may differ from actual costs incurred when the contingency is resolved. Contingencies are normally resolved over long periods of time. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. See Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for information on the Ameren Companies’ contingencies.
Accounting Estimate
Uncertainties Affecting Application
Accounting for Income Taxes
We record a provision for income taxes, deferred tax assets and liabilities, and a valuation allowance against net deferred tax assets, if any. See Note 12 – Income Taxes under Part II, Item 8, of this report.
•Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations
•Estimates of the amount and character of future taxable income and forecasted use of our tax credit carryforwards
•Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled
•Effectiveness of implementing tax planning strategies
•Changes in income tax laws, including amounts subject to income tax, and the regulatory treatment of any tax reform changes
•Results of audits and examinations by taxing authorities
75
Table of Contents
Basis for Judgment
The reporting of tax-related assets and liabilities requires the use of estimates and significant management judgment. Deferred tax assets and liabilities are recorded to represent future effects on income taxes for temporary differences between the basis of assets for financial reporting and tax purposes. Although management believes that current estimates for deferred tax assets and liabilities are reasonable, actual results could differ from these estimates for a variety of reasons, including: a change in forecasted financial condition and/or results of operations; changes in income tax laws, enacted tax rates or amounts subject to income tax; the form, structure, and timing of asset or stock sales or dispositions; changes in the regulatory treatment of any tax reform benefits; and changes resulting from audits and examinations by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At each period end, and as new developments occur, management reevaluates its tax positions. See Note 12 – Income Taxes under Part II, Item 8, of this report for the amount of deferred income taxes recorded at December 31, 2021.
Accounting Estimate
Uncertainties Affecting Application
Accounting for Asset Retirement Obligations
We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
•Discount rates
•Cost escalation rates
•Changes in regulation, expected scope of work, technology, or timing of environmental remediation
•Estimates as to the probability, timing, or amount of cash expenditures associated with AROs
Basis for Judgment
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. We estimate the fair value of our AROs using present value techniques, in which we make various assumptions about discount rates and cost escalation rates. In addition, these estimates include assumptions of the probability, timing, and amount of cash expenditures to settle the ARO, and are based on currently available technology. 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 under Part II, Item 8, of this report for the amount of AROs recorded at December 31, 2021.
A significant portion of Ameren’s and Ameren Missouri’s AROs relate to the decommissioning of Ameren Missouri’s Callaway Energy Center. Changes in key assumptions could materially affect the decommissioning obligation. The following table reflects the sensitivity of potential changes in key assumptions to Ameren Missouri’s Callaway Energy Center decommissioning obligation as of December 31, 2021:
Change in Callaway Energy Center’s Key ARO AssumptionsIncrease (Decrease) to ARO
Discount rate decreased by 0.10%$26 
Cost escalation rate increased by 0.25%63 
Increase in the estimated decommissioning costs by 10%94 
Two-year deferral in timing of cash expenditures
(8)
Impact of New Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent
76
Table of Contents
on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.
Our risk management objectives are to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
•short-term variable-rate debt;
•fixed-rate debt;
•United States Treasury bonds; and
•the discount rate applicable to asset retirement obligations, goodwill, and defined pension and postretirement benefit plans.
We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio and by monitoring the effects of market changes on interest rates. For defined pension and postretirement benefit plans, we control the duration and the portfolio mix of our plan assets. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information related to asset retirement obligations, goodwill, and the defined pension and postretirement benefit plans.
The estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 100 basis points on variable-rate debt outstanding at December 31, 2021 is immaterial.
The allowed ROE under Ameren Illinois’ IEIMA electric distribution service and its electric energy-efficiency investments formula ratemaking recovery mechanisms is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual ROE for its electric distribution business is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. Ameren Illinois expects to use the current IEIMA formula framework to establish annual customer rates effective through 2023 and reconcile the related revenue requirements. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $11 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2022 projected year-end rate base, including electric energy-efficiency investments. Interest rate levels also influence the ROE allowed by our regulators in our other ratemaking jurisdictions, as well as the carrying costs associated with certain regulatory assets and liabilities.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and carry only a nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 7 – Derivative Financial Instruments under Part II, Item 8, of this report for information on the potential loss on counterparty exposure as of December 31, 2021.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2021, no nonaffiliated customer represented more than 10% of our accounts receivable. Additionally, Ameren Illinois faces risks associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois may be required to purchase the supplier’s receivables relating to Ameren Illinois’ distribution customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers to reflect charges for electric distribution and purchased receivables. As of December 31, 2021, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $27 million. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rider that allows Ameren Illinois to recover the difference between its actual net bad debt write-offs under GAAP and the amount of net bad debt write-offs included in its base rates. Ameren Missouri and Ameren Illinois continue to monitor the impact of the COVID-19 pandemic on customer collections and customer account balances. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as
77
Table of Contents
deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances. See Results of Operations in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for more information on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement as of December 31, 2021. In addition, for information regarding Ameren Illinois’ suspension and reinstatement of customer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Investment Price Risk
Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and company-owned life insurance contracts include equity and debt securities. The equity securities are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates.
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide benefits at the time they are payable, while also maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren 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 are 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 adjust 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. Contributions to the plans and future costs could increase materially if we do not achieve pension and postretirement asset portfolio investment returns equal to or in excess of our 2022 assumed return on plan assets of 6.50%.
Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2021, this fund was invested in domestic equity securities (71%) and debt securities (28%). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the trust assets to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Additionally, Ameren and Ameren Illinois have company-owned life insurance contracts with net asset values of $169 million and $8 million, respectively, as of December 31, 2021. To the extent not recovered through rates, changes in the market values of these contracts are reflected in earnings.
Commodity Price Risk
Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution businesses’ exposure to changing market prices for commodities is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and natural gas supply.
Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their customers. The effects of price volatility cannot be eliminated. However, procurement and sales strategies involve risk management techniques and instruments, as well as the management of physical assets.
Ameren Missouri has a FAC that allows it 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. Ameren Missouri remains exposed to the remaining 5% of such changes.
Ameren Illinois has cost recovery mechanisms for power purchased, capacity, zero emission credit, and renewable energy credit costs and expects full recovery of such costs. Ameren Illinois is required to serve as the provider of last resort for electric customers in its service territory who have not chosen an alternative retail electric supplier. In 2021, Ameren Illinois procured power on behalf of its customers for 23% of its total kilowatthour sales. Ameren Illinois purchases energy and capacity through the MISO and through bilateral contracts resulting
78
Table of Contents
from IPA procurement events. The IPA has proposed and the ICC has approved multiple procurement events covering portions of years through 2024 for capacity and energy. Ameren Illinois has also entered into ICC-approved contracts for zero emission credits through 2026 and for renewable energy credits with various terms, including contracts with a 20-year term ending 2032, and contracts entered into beginning in 2018 through 2021 with 15-year terms commencing on the date of first renewable energy credit delivery. Ameren Illinois does not generate earnings based on the resale of power or purchase of zero emission credits or renewable energy credits but rather on the delivery of the energy.
Ameren Missouri and Ameren Illinois have PGA clauses that permit costs incurred for natural gas to be recovered directly from utility customers without a traditional regulatory rate review, subject to prudence reviews.
The following table presents, as of December 31, 2021, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri’s coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway Energy Center, natural gas for Ameren Missouri’s and Ameren Illinois’ retail distribution, and purchased power for Ameren Illinois that are price-hedged over the period 2022 through 2026. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for electricity and natural gas supplied by us and inventory levels, as well as Ameren Missouri’s generation output, among other matters.
202220232024 – 2026
Ameren:
Coal(a)
99 %51 %22 %
Coal transportation(a)
100 100 32 
Nuclear fuel(b)
100 97 80 
Natural gas for distribution(c)
94 37 11 
Purchased power for Ameren Illinois(d)
69 34 11 
Ameren Missouri:
Coal(a)
99 %51 %22 %
Coal transportation(a)
100 100 32 
Nuclear fuel(b)
100 97 80 
Natural gas for distribution(c)
96 40 19 
Ameren Illinois:
Natural gas for distribution(c)
93 %36 %9 %
Purchased power(d)
69 34 11 
(a)Ameren Missouri has agreements in place to purchase and transport coal to its energy centers. While Ameren Missouri has minimum purchase obligations associated with these agreements, the majority of these agreements are not associated with any specific coal-fired energy center.
(b)The Callaway Energy Center has historically required refueling at 18-month intervals. As there is no refueling and maintenance outage scheduled to occur during 2024, there are also no nuclear fuel deliveries anticipated to occur in this year.
(c)Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2022 represents January 2022 through March 2022. The year 2023 represents November 2022 through March 2023. This continues each successive year through March 2026.
(d)Represents the percentage of purchased power price-hedged for fixed-price residential and nonresidential customers with less than 150 kilowatts of demand.
Our exposure to commodity price risk for construction and maintenance activities is related to changes in market prices for metal commodities and to labor availability.
Also see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for additional information.
Commodity Supplier Risk
The use of low-sulfur coal is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has agreements with multiple suppliers to purchase low-sulfur coal through 2025 to comply with environmental regulations. Disruptions to the deliveries of low-sulfur coal from a supplier could compromise Ameren Missouri’s ability to operate in compliance with emission standards. The suppliers of low-sulfur coal are limited. In addition, low-sulfur coal suppliers have experienced financial hardships in recent years and could continue to experience financial hardships that could impact their ability to deliver shipments of low-sulfur coal in accordance with existing supply contracts. If Ameren Missouri were to experience a temporary disruption of low-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of low-sulfur coal were not available, Ameren Missouri would have to use its existing emission allowances, purchase emission allowances, and reduce generation to achieve compliance with environmental regulations. Ameren Missouri would then need to purchase power necessary to meet demand.
Currently, the Callaway Energy Center has a single NRC-licensed supplier able to provide fuel assemblies to the Callaway Energy Center. Ameren Missouri is pursuing a program to qualify an alternate NRC-licensed supplier, and expects to obtain NRC approval in 2023.
79
Table of Contents
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income and comprehensive income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
80
Table of Contents
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation
As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2021, there were approximately $1.6 billion of regulatory assets and approximately $6.0 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
/s/ PricewaterhouseCoopers LLP

St. Louis, Missouri
February 22, 2022
We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.
81
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Union Electric Company (the “Company”) as of December 31, 2021 and 2020, and the related statements of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation
As described in Notes 1 and 2 to the financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2021, there were approximately $0.7 billion of regulatory assets and approximately $3.4 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, and (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, which in turn led to a high degree of auditor judgment, subjectivity, and audit effort when performing audit procedures and
82
Table of Contents
evaluating audit evidence obtained related to management’s application of regulatory accounting and assessment of probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders, and (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities.
/s/ PricewaterhouseCoopers LLP

St. Louis, Missouri
February 22, 2022
We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.
83
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ameren Illinois Company (the “Company”) as of December 31, 2021 and 2020, and the related statements of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation
As described in Notes 1 and 2 to the financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2021, there were approximately $0.9 billion of regulatory assets and approximately $2.4 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor
84
Table of Contents
judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
/s/ PricewaterhouseCoopers LLP

St. Louis, Missouri
February 22, 2022
We have served as the Company’s auditor since 1998.
85
Table of Contents
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions, except per share amounts)
 Year Ended December 31,
 202120202019
Operating Revenues:
Electric$5,297 $4,911 $4,981 
Natural gas1,097 883 929 
Total operating revenues6,394 5,794 5,910 
Operating Expenses:
Fuel581 490 535 
Purchased power606 513 556 
Natural gas purchased for resale442 272 331 
Other operations and maintenance1,774 1,661 1,745 
Depreciation and amortization1,146 1,075 995 
Taxes other than income taxes512 483 481 
Total operating expenses5,061 4,494 4,643 
Operating Income1,333 1,300 1,267 
Other Income, Net202 151 130 
Interest Charges383 419 381 
Income Before Income Taxes1,152 1,032 1,016 
Income Taxes157 155 182 
Net Income995 877 834 
Less: Net Income Attributable to Noncontrolling Interests 5 6 6 
Net Income Attributable to Ameren Common Shareholders$990 $871 $828 
Net Income$995 $877 $834 
Other Comprehensive Income, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $4, $5, and $1, respectively
14 16 5 
Comprehensive Income1,009 893 839 
Less: Comprehensive Income Attributable to Noncontrolling Interests5 6 6 
Comprehensive Income Attributable to Ameren Common Shareholders$1,004 $887 $833 
Earnings per Common Share – Basic$3.86 $3.53 $3.37 
Earnings per Common Share – Diluted$3.84 $3.50 $3.35 
Weighted-average Common Shares Outstanding – Basic256.3 247.0 245.6 
Weighted-average Common Shares Outstanding – Diluted257.6 248.7 247.1 
The accompanying notes are an integral part of these consolidated financial statements.
86
Table of Contents
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
 December 31,
 20212020
ASSETS
Current Assets:
Cash and cash equivalents$8 $139 
Accounts receivable – trade (less allowance for doubtful accounts of $29 and $50, respectively)
434 415 
Unbilled revenue301 269 
Miscellaneous accounts receivable85 65 
Inventories592 521 
Current regulatory assets319 109 
Other current assets229 135 
Total current assets1,968 1,653 
Property, Plant, and Equipment, Net29,261 26,807 
Investments and Other Assets:
Nuclear decommissioning trust fund1,159 982 
Goodwill411 411 
Regulatory assets1,289 1,100 
Pension and other postretirement benefits756 288 
Other assets891 789 
Total investments and other assets4,506 3,570 
TOTAL ASSETS$35,735 $32,030 
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt$505 $8 
Short-term debt545 490 
Accounts and wages payable1,095 958 
Interest accrued123 114 
Current regulatory liabilities113 121 
Other current liabilities445 489 
Total current liabilities2,826 2,180 
Long-term Debt, Net12,562 11,078 
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net3,499 3,211 
Regulatory liabilities5,848 5,282 
Asset retirement obligations757 696 
Other deferred credits and liabilities414 503 
Total deferred credits and other liabilities10,518 9,692 
Commitments and Contingencies (Notes 2, 9, and 14)
Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 257.7 and 253.3, respectively
3 3 
Other paid-in capital, principally premium on common stock6,502 6,179 
Retained earnings3,182 2,757 
Accumulated other comprehensive income (loss)13 (1)
Total shareholders’ equity9,700 8,938 
Noncontrolling Interests129 142 
Total equity9,829 9,080 
TOTAL LIABILITIES AND EQUITY$35,735 $32,030 
The accompanying notes are an integral part of these consolidated financial statements.
87
Table of Contents
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202120202019
Cash Flows From Operating Activities:
Net income $995 $877 $834 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization1,219 1,085 1,002 
Amortization of nuclear fuel58 68 79 
Amortization of debt issuance costs and premium/discounts23 22 19 
Deferred income taxes and investment tax credits, net156 148 167 
Allowance for equity funds used during construction(43)(32)(28)
Stock-based compensation costs22 21 20 
Other19 22 (14)
Changes in assets and liabilities:
Receivables(74)(47)79 
Inventories(71)(25)(10)
Accounts and wages payable28 40 (3)
Taxes accrued1 34 (8)
Regulatory assets and liabilities(439)(254)164 
Assets, other(126)(83)(59)
Liabilities, other(74)(111)(33)
Pension and other postretirement benefits(33)(38)(39)
Net cash provided by operating activities1,661 1,727 2,170 
Cash Flows From Investing Activities:
Capital expenditures(2,954)(2,669)(2,411)
Wind generation expenditures(525)(564)— 
Nuclear fuel expenditures(44)(66)(31)
Purchases of securities – nuclear decommissioning trust fund(452)(224)(256)
Sales and maturities of securities – nuclear decommissioning trust fund439 183 260 
Purchase of bonds— — (207)
Proceeds from sale of remarketed bonds— — 207 
Other8 11 3 
Net cash used in investing activities(3,528)(3,329)(2,435)
Cash Flows From Financing Activities:
Dividends on common stock(565)(494)(472)
Dividends paid to noncontrolling interest holders(5)(6)(6)
Short-term debt, net55 50 (157)
Maturities of long-term debt(8)(442)(580)
Issuances of long-term debt1,997 2,183 1,527 
Issuances of common stock308 476 68 
Redemptions of Ameren Illinois preferred stock(13)— — 
Employee payroll taxes related to stock-based compensation(17)(20)(29)
Debt issuance costs(18)(20)(17)
Other(13)— — 
Net cash provided by financing activities1,721 1,727 334 
Net change in cash, cash equivalents, and restricted cash(146)125 69 
Cash, cash equivalents, and restricted cash at beginning of year301 176 107 
Cash, cash equivalents, and restricted cash at end of year$155 $301 $176 
Cash Paid (Refunded) During the Year:
Interest (net of $17, $16, and $20 capitalized, respectively)
$426 $383 $367 
Income taxes, net(1)13 13 
The accompanying notes are an integral part of these consolidated financial statements.
88
Table of Contents
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
December 31,
202120202019
Common Stock:
Beginning of year$3 $2 $2 
Settlement of forward sale agreement through common shares issuance— 1 — 
Common stock, end of year3 3 2 
Other Paid-in Capital:
Beginning of year6,179 5,694 5,627 
Settlement of forward sale agreement through common shares issuance113 424 — 
Shares issued under the ATM program148 — — 
Shares issued under the DRPlus and 401(k) plan47 51 68 
Stock-based compensation activity15 10 (1)
Other paid-in capital, end of year6,502 6,179 5,694 
Retained Earnings:
Beginning of year2,757 2,380 2,024 
Net income attributable to Ameren common shareholders990 871 828 
Dividends on common stock(565)(494)(472)
Retained earnings, end of year3,182 2,757 2,380 
Accumulated Other Comprehensive Income (Loss):
Deferred retirement benefit costs, beginning of year(1)(17)(22)
Change in deferred retirement benefit costs14 16 5 
Deferred retirement benefit costs, end of year13 (1)(17)
Total accumulated other comprehensive gain (loss), end of year13 (1)(17)
Total Shareholders’ Equity$9,700 $8,938 $8,059 
Noncontrolling Interests:
Beginning of year142 142 142 
Net income attributable to noncontrolling interest holders5 6 6 
Dividends paid to noncontrolling interest holders(5)(6)(6)
Redemptions of Ameren Illinois preferred stock(13)— — 
Noncontrolling interests, end of year129 142 142 
Total Equity$9,829 $9,080 $8,201 
Common stock shares outstanding at beginning of year253.3 246.2 244.5 
Shares issued under forward sale agreement1.6 5.9 — 
Shares issued under the ATM program1.8 — — 
Shares issued under the DRPlus and 401(k) plan0.5 0.7 0.9 
Shares issued for stock-based compensation0.5 0.5 0.8 
Common stock shares outstanding at end of year257.7 253.3 246.2 
Dividends per common share$2.20 $2.00 $1.92 
The accompanying notes are an integral part of these consolidated financial statements.
89
Table of Contents
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
STATEMENT OF INCOME
(In millions)
 Year Ended December 31,
 202120202019
Operating Revenues:
Electric$3,212 $2,984 $3,109 
Natural gas141 125 134 
Total operating revenues3,353 3,109 3,243 
Operating Expenses:
Fuel581 490 535 
Purchased power227 171 193 
Natural gas purchased for resale60 43 53 
Other operations and maintenance948 886 960 
Depreciation and amortization632 604 556 
Taxes other than income taxes343 328 329 
Total operating expenses2,791 2,522 2,626 
Operating Income562 587 617 
Other Income, Net99 76 58 
Interest Charges137 190 178 
Income Before Income Taxes524 473 497 
Income Taxes3 34 68 
Net Income521 439 429 
Preferred Stock Dividends3 3 3 
Net Income Attributable to Ameren Common Shareholders$518 $436 $426 
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
90
Table of Contents
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
BALANCE SHEET
(In millions, except per share amounts)
 December 31,
 20212020
ASSETS
Current Assets:
Cash and cash equivalents$— $136 
Advances to money pool— 139 
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $16, respectively)
190 166 
Accounts receivable – affiliates44 57 
Unbilled revenue142 133 
Miscellaneous accounts receivable71 36 
Inventories419 386 
Current regulatory assets127 60 
Current collateral assets66 11 
Other current assets76 68 
Total current assets1,135 1,192 
Property, Plant, and Equipment, Net15,296 13,879 
Investments and Other Assets:
Nuclear decommissioning trust fund1,159 982 
Regulatory assets523 347 
Pension and other postretirement benefits208 60 
Other assets401 323 
Total investments and other assets2,291 1,712 
TOTAL ASSETS$18,722 $16,783 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt$55 $8 
Short-term debt165 — 
Accounts and wages payable631 501 
Accounts payable – affiliates46 46 
Taxes accrued34 42 
Interest accrued60 53 
Current asset retirement obligations7 60 
Other current liabilities219 123 
Total current liabilities1,217 833 
Long-term Debt, Net5,564 5,096 
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net1,852 1,742 
Regulatory liabilities3,354 3,110 
Asset retirement obligations753 691 
Other deferred credits and liabilities71 101 
Total deferred credits and other liabilities6,030 5,644 
Commitments and Contingencies (Notes 2, 9, 13, and 14)
Shareholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
511 511 
Other paid-in capital, principally premium on common stock2,725 2,518 
Preferred stock80 80 
Retained earnings2,595 2,101 
Total shareholders’ equity5,911 5,210 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY$18,722 $16,783 
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
91
Table of Contents
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
STATEMENT OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202120202019
Cash Flows From Operating Activities:
Net income$521 $439 $429 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization704 613 564 
Amortization of nuclear fuel58 68 79 
Amortization of debt issuance costs and premium/discounts6 6 5 
Deferred income taxes and investment tax credits, net3 17 (19)
Allowance for equity funds used during construction(26)(19)(19)
Other19 22 13 
Changes in assets and liabilities:
Receivables(60)(8)75 
Inventories(32)(11)(13)
Accounts and wages payable28 26 16 
Taxes accrued(27)9 (15)
Regulatory assets and liabilities(207)(166)17 
Assets, other(27)(2)(28)
Liabilities, other(29)(80)(32)
Pension and other postretirement benefits(2)(3)(5)
Net cash provided by operating activities929 911 1,067 
Cash Flows From Investing Activities:
Capital expenditures(1,490)(1,102)(1,076)
Wind generation expenditures(525)(564)— 
Nuclear fuel expenditures(44)(66)(31)
Purchases of securities – nuclear decommissioning trust fund(452)(224)(256)
Sales and maturities of securities – nuclear decommissioning trust fund439 183 260 
Purchase of bonds— — (207)
Proceeds from sale of remarketed bonds— — 207 
Money pool advances, net139 (139)— 
Other11 8 8 
Net cash used in investing activities(1,922)(1,904)(1,095)
Cash Flows From Financing Activities:
Dividends on common stock(24)(66)(430)
Dividends on preferred stock(3)(3)(3)
Short-term debt, net165 (234)179 
Maturities of long-term debt(8)(92)(580)
Issuances of long-term debt524 1,012 778 
Debt issuance costs(5)(9)(9)
Capital contribution from parent207 491 124 
Net cash provided by financing activities856 1,099 59 
Net change in cash, cash equivalents, and restricted cash(137)106 31 
Cash, cash equivalents, and restricted cash at beginning of year145 39 8 
Cash, cash equivalents, and restricted cash at end of year$8 $145 $39 
Cash Paid During the Year:
Interest (net of $10, $10, and $12 capitalized, respectively)
$205 $190 $190 
Income taxes, net19 25 101 
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
92
Table of Contents
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
 December 31,
 202120202019
Common Stock$511 $511 $511 
Other Paid-in Capital:
Beginning of year2,518 2,027 1,903 
Capital contribution from parent207 491 124 
Other paid-in capital, end of year2,725 2,518 2,027 
Preferred Stock80 80 80 
Retained Earnings:
Beginning of year2,101 1,731 1,735 
Net income521 439 429 
Dividends on common stock(24)(66)(430)
Dividends on preferred stock(3)(3)(3)
Retained earnings, end of year2,595 2,101 1,731 
Total Shareholders’ Equity$5,911 $5,210 $4,349 
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
93
Table of Contents
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF INCOME
(In millions)
 Year Ended December 31,
 202120202019
Operating Revenues:
Electric$1,938 $1,775 $1,730 
Natural gas957 760 797 
Total operating revenues2,895 2,535 2,527 
Operating Expenses:
Purchased power400 355 368 
Natural gas purchased for resale382 229 278 
Other operations and maintenance820 775 782 
Depreciation and amortization472 434 406 
Taxes other than income taxes153 140 143 
Total operating expenses2,227 1,933 1,977 
Operating Income668 602 550 
Other Income, Net66 59 53 
Interest Charges164 155 147 
Income Before Income Taxes570 506 456 
Income Taxes143 124 110 
Net Income427 382 346 
Preferred Stock Dividends2 3 3 
Net Income Attributable to Ameren Common Shareholders$425 $379 $343 
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
94
Table of Contents
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
BALANCE SHEET
(In millions)
 December 31,
 20212020
ASSETS
Current Assets:
Cash and cash equivalents$— $— 
Accounts receivable – trade (less allowance for doubtful accounts of $16 and $34, respectively)
228 234 
Accounts receivable – affiliates24 64 
Unbilled revenue159 136 
Miscellaneous accounts receivable1 12 
Inventories173 135 
Current regulatory assets180 37 
Other current assets58 29 
Total current assets823 647 
Property, Plant, and Equipment, Net12,223 11,201 
Investments and Other Assets:
Goodwill411 411 
Regulatory assets752 742 
Pension and other postretirement benefits427 280 
Other assets399 254 
Total investments and other assets1,989 1,687 
TOTAL ASSETS$15,035 $13,535 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt$400 $— 
Short-term debt103 — 
Borrowings from money pool— 19 
Accounts and wages payable361 363 
Accounts payable – affiliates64 51 
Customer deposits52 74 
Current regulatory liabilities54 88 
Other current liabilities199 221 
Total current liabilities1,233 816 
Long-term Debt, Net3,992 3,946 
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net1,558 1,367 
Regulatory liabilities2,374 2,063 
Other deferred credits and liabilities238 377 
Total deferred credits and other liabilities4,170 3,807 
Commitments and Contingencies (Notes 2, 13, and 14)
Shareholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding
— — 
Other paid-in capital2,914 2,652 
Preferred stock49 62 
Retained earnings2,677 2,252 
Total shareholders’ equity5,640 4,966 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY$15,035 $13,535 
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
95
Table of Contents
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF CASH FLOWS
(In millions)
 Year Ended December 31,
 202120202019
Cash Flows From Operating Activities:
Net income$427 $382 $346 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization471 434 405 
Amortization of debt issuance costs and premium/discounts13 12 12 
Deferred income taxes and investment tax credits, net165 118 80 
Allowance for equity funds used during construction(17)(13)(9)
Other10 21 16 
Changes in assets and liabilities:
Receivables(17)(28)11 
Inventories(40)(15)2 
Accounts and wages payable2 15 (19)
Taxes accrued22 (23)21 
Regulatory assets and liabilities(222)(72)155 
Assets, other(75)(76)(23)
Liabilities, other(45)(46)(5)
Pension and other postretirement benefits(32)(30)(30)
Net cash provided by operating activities662 679 962 
Cash Flows From Investing Activities:
Capital expenditures(1,432)(1,447)(1,208)
Other(5)3 3 
Net cash used in investing activities(1,437)(1,444)(1,205)
Cash Flows From Financing Activities:
Dividends on common stock— (9)— 
Dividends on preferred stock(2)(3)(3)
Short-term debt, net103 (53)(19)
Money pool borrowings, net(19)19 — 
Redemption of preferred stock(13)— — 
Issuances of long-term debt449 373 299 
Debt issuance costs(6)(4)(4)
Capital contribution from parent262 464 15 
Other(13)— — 
Net cash provided by financing activities761 787 288 
Net change in cash, cash equivalents, and restricted cash(14)22 45 
Cash, cash equivalents, and restricted cash at beginning of year147 125 80 
Cash, cash equivalents, and restricted cash at end of year$133 $147 $125 
Cash Paid During the Year:
Interest (net of $7, $6, and $8 capitalized, respectively)
$148 $137 $127 
Income taxes, net(41)41 4 
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
96
Table of Contents
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
 December 31,
 202120202019
Common Stock$— $— $— 
Other Paid-in Capital:
Beginning of year2,652 2,188 2,173 
Capital contribution from parent262 464 15 
Other paid-in capital, end of year2,914 2,652 2,188 
Preferred Stock:
Beginning of year62 62 62 
Redemptions of preferred stock(13)— — 
Preferred stock, end of year49 62 62 
Retained Earnings:
Beginning of year2,252 1,882 1,539 
Net income427 382 346 
Dividends on common stock— (9)— 
Dividends on preferred stock(2)(3)(3)
Retained earnings, end of year2,677 2,252 1,882 
Total Shareholders’ Equity$5,640 $4,966 $4,132 
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
97
Table of Contents
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2021
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
98
Table of Contents
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,
99
Table of Contents
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
100
Table of Contents
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
101
Table of Contents
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.
102
Table of Contents
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 MissouriAmeren Illinois’ electric distribution businessAmeren Illinois’ natural gas delivery service businessAmeren 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.
103
Table of Contents
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.
104
Table of Contents
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.
105
Table of Contents
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
106
Table of Contents
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.
107
Table of Contents
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
108
Table of Contents
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.
109
Table of Contents
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
110
Table of Contents
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.
111
Table of Contents
Regulatory Assets and Liabilities
The following table presents our regulatory assets and regulatory liabilities at December 31, 2021 and 2020:
20212020
Ameren
Missouri		Ameren
Illinois		AmerenAmeren
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 
Other41 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 
Other32 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.
112
Table of Contents
(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.
113
Table of Contents
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		OtherAmeren
2021
Property, plant, and equipment at original cost:(a)
Electric generation:
Coal(b)(c)
$3,955 $— $— $3,955 
Natural gas1,105 — — 1,105 
Nuclear5,615 — — 5,615 
Renewable(d)
1,889 — — 1,889 
Electric distribution7,286 7,017 — 14,303 
Electric transmission1,628 4,105 1,800 7,533 
Natural gas607 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 amortization9,784 4,100 330 14,214 
13,885 11,791 1,712 27,388 
Construction work in progress:
Nuclear fuel in process133 — — 133 
Other674 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 gas1,097 — — 1,097 
Nuclear5,608 — — 5,608 
Renewable(d)
1,301 — — 1,301 
Electric distribution6,784 6,649 — 13,433 
Electric transmission1,482 3,575 1,774 6,831 
Natural gas561 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 amortization9,689 3,780 304 13,773 
13,409 10,822 1,715 25,946 
Construction work in progress:
Nuclear fuel in process75 — — 75 
Other395 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.
114
Table of Contents
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 ExpenseGross Carrying ValueAccumulated Amortization
2021202020192021202020212020
Ameren$125 $93 $78 $1,199 $1,021 $(757)$(640)
Ameren Missouri66 44 30 523 398 (255)(189)
Ameren Illinois53 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:
20222023202420252026
Ameren$135 $119 $87 $47 $21 
Ameren Missouri75 69 54 31 14 
Ameren Illinois56 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 Missouri850 (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
115
Table of Contents
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 MissouriAmeren IllinoisAmeren Consolidated
2021
Average daily amount outstanding$387 $99 $118 $604 
Commercial paper issuances outstanding at period-end277 165 103 545 
Weighted-average interest rate0.22 %0.22 %0.21 %0.22 %
Peak amount outstanding during period(a)
$650 $546 $485 $1,134 
Peak interest rate0.38 %0.35 %0.35 %0.38 %
2020
Average daily amount outstanding$108 $109 $46 $263 
Commercial paper issuances outstanding at period-end490 — — 490 
Weighted-average interest rate1.04 %1.73 %0.97 %1.31 %
Peak amount outstanding during period(a)
$490 $573 $250 $908 
Peak interest rate3.30 %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.
116
Table of Contents
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.
117
Table of Contents
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:
20212020
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, gross2,550 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, gross5,669 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 
118
Table of Contents
20212020
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, gross4,438 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, gross525 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.
119
Table of Contents
(i)The following table presents the principal maturities schedule for the 2.45% senior unsecured notes due 2036:
Payment DatePrincipal Payment
November 2029$30
November 203645
Total$75
(j)The following table presents the principal maturities schedule for the 3.43% senior unsecured notes due 2050:
Payment DatePrincipal Payment
August 2022$49.5
August 202449.5
August 202749.5
August 203049.5
August 203249.5
August 203849.5
August 204376.5
August 205076.5
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 
2024450 350 — 50 850 
2025— — 300 — 300 
2026350 — — — 350 
Thereafter1,750 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.
120
Table of Contents
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 OutstandingRedemption Price (per share)20212020
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 shares104.75 4 4 
$4.00 Series
150,000 shares105.625 15 15 
$4.30 Series
40,000 shares105.00 4 4 
$4.50 Series
213,595 shares110.00 
(a)
21 21 
$4.56 Series
200,000 shares102.47 20 20 
$4.75 Series
20,000 shares102.176 2 2 
$5.50 Series A
14,000 shares110.00 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 shares103.00 5 5 
4.20% Series
23,655 shares104.00 2 2 
4.25% Series
50,000 shares102.00 5 5 
4.26% Series
16,621 shares103.00 2 2 
4.42% Series
16,190 shares103.00 2 2 
4.70% Series
18,429 shares104.30 2 2 
4.90% Series
73,825 shares102.00 7 7 
4.92% Series
49,289 shares103.50 5 5 
5.16% Series
50,000 shares102.00 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.
121
Table of Contents
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.
122
Table of Contents
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
7.37,697
>1.5
3.5203
(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
123
Table of Contents
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:
202120202019
Ameren:
Other Income, Net
Allowance for equity funds used during construction$43 $32 $28 
Interest income on industrial development revenue bonds25 25 25 
Other interest income2 4 8 
Non-service cost components of net periodic benefit income (a)
136 116 90 
Miscellaneous income22 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 bonds25 25 25 
Other interest income1 1 1 
Non-service cost components of net periodic benefit income (a)
55 46 18 
Miscellaneous income3 4 5 
Donations(4)(12)
(b)
(3)
Miscellaneous expense(7)(7)(7)
Total Other Income, Net$99 $76 $58 
124
Table of Contents
202120202019
Ameren Illinois:
Other Income, Net
Allowance for equity funds used during construction$17 $13 $9 
Interest income1 3 6 
Non-service cost components of net periodic benefit income (a)
55 48 47 
Miscellaneous income6 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.
125
Table of Contents
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.
Quantity (in millions, except as indicated)
20212020
CommodityAmeren MissouriAmeren
Illinois		AmerenAmeren MissouriAmeren
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 
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:
20212020
CommodityBalance Sheet LocationAmeren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois		Ameren
Fuel oilsOther current assets$8 $— $8 $2 $— $2 
Other assets5 — 5 — — — 
Natural gasOther current assets7 28 35 1 8 9 
Other assets5 13 18 2 2 4 
PowerOther current assets23 — 23 7 — 7 
UraniumOther assets1 — 1 — — — 
 Total assets$49 $41 $90 $12 $10 $22 
Fuel oilsOther current liabilities$— $— $— $7 $— $7 
Other deferred credits and liabilities— — — 2 — 2 
Natural gasOther current liabilities2 6 8 1 1 2 
Other deferred credits and liabilities1 2 3 — 1 1 
PowerOther current liabilities50 9 59 3 17 20 
Other deferred credits and liabilities23 108 131 8 181 189 
UraniumOther current liabilities1 — 1 — — — 
 Total liabilities$77 $125 $202 $21 $200 $221 
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.
126
Table of Contents
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.
Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be OffsetGross Amounts Recognized in the Balance SheetDerivative Instruments
Cash Collateral Received/Posted(a)
Net
Amount
2021
Assets:
Ameren Missouri$49 $15 $— $34 
Ameren Illinois41 4 — 37 
Ameren$90 $19 $— $71 
Liabilities:
Ameren Missouri$77 $15 $47 $15 
Ameren Illinois125 4 — 121 
Ameren$202 $19 $47 $136 
(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.
127
Table of Contents
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.
128
Table of Contents
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:
December 31, 2021December 31, 2020
Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets:
Ameren Missouri
Derivative assets – commodity contracts:
Fuel oils$13 $— $— $13 $— $— $2 $2 
Natural gas— 12 — 12 — 3 — 3 
Power10 — 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:
Equity securities:
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 
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 
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 $999 
Liabilities:
Ameren Missouri
Derivative liabilities – commodity contracts:
Fuel oils$— $— $— $— $6 $— $3 $9 
Natural gas— 2 1 3 — 1 — 1 
Power45 — 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.
129
Table of Contents
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:
20212020
Ameren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois		Ameren
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 
Settlements(16)11 (5)(26)18 (8)
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 
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:
Fair Value
Weighted Average(b)
CommodityAssetsLiabilitiesValuation Technique(s)
Unobservable Input(a)
Range
2021
Power(c)
$13 $(145)Discounted cash flowAverage forward peak and off-peak pricing – forwards/swaps ($/MWh)
32 – 55
40
Nodal basis ($/MWh)
(14) – 0
(2)
Trend rate (%)
0 – 0
0
2020
Power(c)
$5 $(201)Discounted cash flowAverage forward peak and off-peak pricing – forwards/swaps ($/MWh)
23 – 37
29
Nodal basis ($/MWh)
(6) – 0
(2)
Trend rate (%)
2 – 6
3
(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.
130
Table of Contents
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:
Carrying
Amount		Fair Value
Level 1Level 2Level 3Total
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 debt545 — 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 debt165 — 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 debt103 — 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 debt490 — 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 pool139 — 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 pool19 — 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.
131
Table of Contents
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:
202120202019
Proceeds from sales and maturities$439 $183 $260 
Gross realized gains32 10 10 
Gross realized losses6 3 2 
132
Table of Contents
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 TypeCostGross Unrealized GainGross Unrealized LossFair Value
2021
Debt securities$320 $10 $2 $328 
Equity securities188 640 4 824 
Cash and cash equivalents4 — — 4 
Other(a)
3 — — 3 
Total$515 $650 $6 $1,159 
2020
Debt securities$272 $25 $— $297 
Equity securities198 491 9 680 
Cash and cash equivalents4 — — 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:
CostFair Value
Less than 5 years$155 $156 
5 years to 10 years71 72 
Due after 10 years94 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 CoverageMost Recent
Renewal Date		Maximum CoveragesMaximum Assessments
for Single Incidents
Public liability and nuclear worker liability:
American Nuclear InsurersJanuary 1, 2022$450 $— 
Pool participation(a)13,073 
(a)
138 
(b)
$13,523 
(c)
$138 
Property damage:
NEIL and EMANIApril 1, 2021$3,200 
(d)
$25 
(e)
Accidental outage:
NEILApril 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.
133
Table of Contents
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:
20212020
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.
134
Table of Contents
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.
20212020
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 $1,110 
Service cost134 23 110 19 
Interest cost152 33 174 39 
Participant contributions— 9 — 8 
Actuarial (gain) loss(82)(80)508 91 
Benefits paid(257)(60)(249)(63)
Net benefit obligation at end of year5,457 1,129 5,510 1,204 
Change in plan assets:
Fair value of plan assets at beginning of year5,510 1,453 4,564 1,297 
Actual return on plan assets432 154 1,143 209 
Employer contributions60 2 52 2 
Participant contributions— 9 — 8 
Benefits paid(257)(60)(249)(63)
Fair value of plan assets at end of year5,745 1,558 5,510 1,453 
Funded status – surplus(288)(429)— (249)
Accrued benefit asset at December 31$(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 BenefitsPostretirement Benefits
  2021202020212020
Discount rate at measurement date3.00 %2.75 %3.00 %2.75 %
Increase in future compensation3.50 3.50 3.50 3.50 
Cash balance pension plan interest crediting rate5.00 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
135
Table of Contents
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 BenefitsPostretirement Benefits
202120202019202120202019
Ameren Missouri$22 $17 $3 $1 $1 $1 
Ameren Illinois28 27 19 1 1 1 
Ameren Services10 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.
136
Table of Contents
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,
20212020
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.
137
Table of Contents
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, 2021December 31, 2020
Level 1Level 2NAVTotalLevel 1Level 2NAVTotal
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-capitalization558 — — 558 513 — — 513 
International372 — 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 
Other17 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, 2021December 31, 2020
Level 1Level 2NAVTotalLevel 1Level 2NAVTotal
Cash and cash equivalents$24 $— $— $24 $38 $— $— $38 
Equity securities:
U.S. large-capitalization283 — 115 398 279 — 107 386 
U.S. small- and mid-capitalization113 — — 113 104 — — 104 
International60 — 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.
138
Table of Contents
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 BenefitsPostretirement Benefits
202120202019202120202019
Service cost(a)
$134 $110 $88 $23 $19 $18 
Non-service cost components:
Interest cost152 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) loss73 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 CostsPostretirement Costs
  202120202019202120202019
Ameren Missouri(a)
$29 $22 $5 $(4)$(5)$(6)
Ameren Illinois34 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 BenefitsPostretirement Benefits
  Paid from
Qualified
Trust Funds		Paid from
Company
Funds		Paid from
Qualified
Trust Funds		Paid from
Company
Funds
2022$267 $2 $59 $2 
2023274 2 60 2 
2024279 3 61 2 
2025284 3 61 2 
2026288 3 60 2 
2027 – 20311,476 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 BenefitsPostretirement Benefits
  202120202019202120202019
Discount rate at measurement date2.75 %3.50 %4.25 %2.75 %3.50 %4.25 %
Expected return on plan assets6.50 7.00 7.00 6.50 7.00 7.00 
Increase in future compensation3.50 3.50 3.50 3.50 3.50 3.50 
Cash balance pension plan interest crediting rate5.00 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%.
139
Table of Contents
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:
202120202019
Ameren Missouri$21 $20 $19 
Ameren Illinois16 17 16 
Other1 1 — 
Ameren$38 $38 $35 
NOTE 11 – STOCK-BASED COMPENSATION
The 2014 Omnibus Incentive Compensation Plan is Ameren’s long-term stock-based compensation plan for eligible employees and directors. It provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors. At December 31, 2021, there were 1.8 million common shares remaining for grant. Awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2021, 2020, and 2019, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2022.
The following table summarizes Ameren’s nonvested performance share unit and restricted stock unit activity for the year ended December 31, 2021:
Performance Share Units –
Market Condition(a)
Performance Share Units – Performance Condition(b)
Restricted Stock Units
Share
Units		Weighted-average Fair Value per Share UnitSharesWeighted-average Fair Value per Share UnitStock
Units		Weighted-average Fair Value per Stock Unit
Nonvested at January 1, 2021(c)
464,139 $73.34 31,896 $76.66 303,695 $68.52 
Granted266,081 87.11 42,672 78.11 129,723 78.17 
Forfeitures(21,143)80.77 (2,449)77.55 (10,209)74.88 
Vested and undistributed(d)
(186,792)77.91 (15,134)77.27 (87,427)73.13 
Vested and distributed(93,499)62.88 — — (87,597)56.38 
Performance share adjustment— — (13,881)77.54 — — 
Nonvested at December 31, 2021(e)
428,786 $81.81 43,104 $77.54 248,185 $75.97 
(a)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions. Compensation cost on nonforfeited awards is recognized regardless of whether Ameren achieves the specified market conditions.
(b)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. Compensation cost is recognized ratably over the requisite service period only for awards for which it is probable that the performance condition will be satisfied. The performance share adjustment represents the change in the probability that a performance condition will be satisfied.
(c)Does not include 366,243 market condition performance share units, 7,607 performance shares based on Ameren’s clean energy transition, and 160,034 restricted stock units that were vested and undistributed.
(d)Vested and undistributed units are awards that vest on a pro-rata basis due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For vested and undistributed performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.
(e)Does not include 357,575 market condition performance share units, 22,739 performance shares based on Ameren’s clean energy transition, and 164,000 restricted stock units that were vested and undistributed.
Performance Share Units – Market Condition
A market condition performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions.
The fair value of each share unit is based on Ameren’s closing common share price at December 31 of the year prior to the award year and a Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on Ameren’s TSR for a three-year performance period relative to the designated peer group beginning January 1st of the award year. The simulation can produce a
140
Table of Contents
greater fair value for the share unit than the applicable closing common share price because it includes the weighted payout scenarios in which an increase in the share price has occurred and/or in which the payout is above 100% due to Ameren’s projected TSR performance. The significant assumptions used to calculate fair value also include a three-year risk-free rate, Ameren’s common stock volatility, and volatility for the peer group. The following table presents the fair value of each share unit along with the significant assumptions used to calculate the fair value of each share unit for the years ended December 31, 2021, 2020, and 2019:
202120202019
Fair value of share units awarded$87.11$82.49$67.42
Three-year risk-free rate0.17%1.62%2.46%
Ameren’s common stock volatility(a)
28%15%17%
Volatility range for the peer group(a)
26% – 36%
14% – 28%
15% – 25%
(a)Based on a historical period that is equal to the remaining term of the performance period as of the grant date.
Performance Share Units – Performance Condition
A performance condition share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has met the specified performance condition and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual performance conditions achieved. The specified performance condition is based on Ameren’s clean energy transition. The grant-date fair value for an individual outcome of a performance condition is determined by Ameren’s closing common share price on the grant date.
Restricted Stock Units
Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. Generally, in the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date.
Stock-Based Compensation Expense
The following table presents the stock-based compensation expense for the years ended December 31, 2021, 2020, and 2019:
202120202019
Ameren Missouri$5 $5 $4 
Ameren Illinois3 3 3 
Other(a)
14 13 13 
Ameren22 21 20 
Less: Income tax benefit6 6 5 
Stock-based compensation expense, net$16 $15 $15 
(a)Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above.
Ameren settled performance share units and restricted stock units of $50 million, $58 million, and $83 million for the years ended December 31, 2021, 2020, and 2019. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2021, 2020, and 2019. As of December 31, 2021, total compensation cost of $35 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 21 months.
For the years ended December 31, 2021, 2020, and 2019, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $5 million, $8 million, and $15 million, respectively.
NOTE 12 – INCOME TAXES
Missouri Income Tax Rate
In 2018, legislation modifying Missouri tax law was enacted to decrease the state’s corporate income tax rate from 6.25% to 4%, effective January 1, 2020. As a result, in 2018, Ameren’s and Ameren Missouri’s accumulated deferred tax balances were revalued, resulting in a net decrease of $122 million to their accumulated deferred tax liability, which was offset by a regulatory liability. Additionally, Ameren recorded an immaterial amount to income tax expense. As a result of the March 2020 MoPSC electric rate order, the effect of this tax
141
Table of Contents
decrease was reflected in customer rates on April 1, 2020. This income tax decrease did not have a material impact on the net income of Ameren (parent) and nonregistrant subsidiaries.
The following table presents the principal reasons for the difference between the effective income tax rate and the federal statutory corporate income tax rate for the years ended December 31, 2021, 2020, and 2019:
Ameren MissouriAmeren IllinoisAmeren
2021
Federal statutory corporate income tax rate21 %21 %21 %
Increases (decreases) from:
Amortization of excess deferred income taxes(15)(3)(8)
Amortization of deferred investment tax credit(1)— — 
Renewable and other tax credits(7)
(a)
— (3)
(a)
State tax3 7 5 
Stock-based compensation— — (1)
Effective income tax rate1 %25 %14 %
2020
Federal statutory corporate income tax rate21 %21 %21 %
Increases (decreases) from:
Amortization of excess deferred income taxes(16)(3)(9)
Amortization of deferred investment tax credit(1)(1)(1)
State tax3 7 5 
Stock-based compensation— — (1)
Effective income tax rate7 %24 %15 %
2019
Federal statutory corporate income tax rate21 %21 %21 %
Increases (decreases) from:
Amortization of excess deferred income taxes(11)(4)(7)
Amortization of deferred investment tax credit(1)— (1)
State tax5 7 6 
Stock-based compensation— — (1)
Effective income tax rate14 %24 %18 %
(a)Includes credits associated with the High Prairie Renewable and Atchison Renewable energy centers. Ameren Missouri placed the High Prairie Renewable Energy Center in service in December 2020. Additionally, Ameren Missouri placed in service the wind turbines at its Atchison Renewable Energy Center throughout the first half of 2021. The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM.
142
Table of Contents
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2021, 2020, and 2019:
Ameren MissouriAmeren IllinoisOtherAmeren
2021
Current taxes:
Federal$— $(15)$22 $7 
State— (7)1 (6)
Deferred taxes:
Federal65 120 (15)170 
State23 59 4 86 
Amortization of excess deferred income taxes(81)(14)(1)(96)
Amortization of deferred investment tax credits(4)— — (4)
Total income tax expense$3 $143 $11 $157 
2020
Current taxes:
Federal$14 $12 $(24)$2 
State3 (6)8 5 
Deferred taxes:
Federal82 81 24 187 
State15 52 (10)57 
Amortization of excess deferred income taxes(75)(15)(1)(91)
Amortization of deferred investment tax credits(5)— — (5)
Total income tax expense (benefit)$34 $124 $(3)$155 
2019
Current taxes:
Federal$65 $19 $(88)$(4)
State22 11 (14)19 
Deferred taxes:
Federal37 66 82 185 
State5 29 25 59 
Amortization of excess deferred income taxes(56)(15)(1)(72)
Amortization of deferred investment tax credits(5)— — (5)
Total income tax expense$68 $110 $4 $182 
The following table presents the accumulated deferred income tax assets and liabilities recorded as a result of temporary differences and accumulated deferred investment tax credits at December 31, 2021 and 2020:
Ameren MissouriAmeren IllinoisOtherAmeren
2021
Accumulated deferred income taxes, net liability (asset):
Plant-related$2,188 $1,715 $226 $4,129 
Regulatory assets and liabilities, net(259)(199)(25)(483)
Deferred employee benefit costs(52)17 (53)(88)
Tax carryforwards(68)(46)(84)(198)
Other13 71 25 109 
Total net accumulated deferred income tax liabilities (assets)1,822 1,558 89 3,469 
Accumulated deferred investment tax credits30 — — 30 
Accumulated deferred income taxes and investment tax credits$1,852 $1,558 $89 $3,499 
2020
Accumulated deferred income taxes, net liability (asset):
Plant-related$2,112 $1,559 $205 $3,876 
Regulatory assets and liabilities, net(285)(207)(23)(515)
Deferred employee benefit costs(58)8 (54)(104)
Tax carryforwards(26)(6)(65)(97)
Other(35)13 39 17 
Total net accumulated deferred income tax liabilities (assets)1,708 1,367 102 3,177 
Accumulated deferred investment tax credits34 — — 34 
Accumulated deferred income taxes and investment tax credits$1,742 $1,367 $102 $3,211 
143
Table of Contents
The following table presents the components of accumulated deferred income tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2021 and 2020:
Ameren MissouriAmeren IllinoisOtherAmeren
2021
Net operating loss carryforwards:
Federal(a)
$2 $17 $15 $34 
State(b)
$1 $25 $5 $31 
Total net operating loss carryforwards$3 $42 $20 $65 
Tax credit carryforwards:
Federal(c)
$65 $3 $58 $126 
State(d)
— 1 6 7 
Total tax credit carryforwards$65 $4 $64 $133 
2020
Net operating loss carryforwards:
State
$— $3 $4 $7 
Total net operating loss carryforwards$— $3 $4 $7 
Tax credit carryforwards:
Federal
$26 $3 $54 $83 
State
— — 7 7 
Total tax credit carryforwards$26 $3 $61 $90 
(a)Will not expire.
(b)Will expire between 2032 and 2041.
(c)Will expire between 2030 and 2041.
(d)Will expire between 2022 and 2026.
Uncertain Tax Positions
As of December 31, 2021 and 2020, the Ameren Companies did not record any uncertain tax positions.
Ameren is a part of the IRS’s compliance assurance process program, which involves real-time review of compliance with federal income tax law. State income tax returns are generally subject to examination for a period of three years after filing. The state impact of any federal changes remains subject to examination by various states for up to one year after formal notification to the states. Ameren’s federal tax returns for the 2015, 2017, 2018, 2019, and 2020 tax years are open, but, at the time of this filing, the Ameren Companies do not have material income tax issues under examination, administrative appeals, or litigation.
Ameren Missouri has an uncertain tax position tracker. Under Missouri’s regulatory framework, uncertain tax positions do not reduce Ameren Missouri’s electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value, with a return at the applicable WACC included in each of the electric rate orders in effect before the tax position was resolved, of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will affect earnings in the year it is created. It will then be amortized over three years, beginning on the effective date of new rates established in the next electric service regulatory rate review.
NOTE 13 – RELATED-PARTY TRANSACTIONS
In the normal course of business, Ameren Missouri and Ameren Illinois engage in affiliate transactions. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements, except as noted in Software Licensing Agreement discussion below. Below are the material related-party agreements.
Electric Power Supply Agreements
Ameren Illinois must acquire capacity and energy sufficient to meet its obligations to customers. Ameren Illinois uses periodic RFP processes, administered by the IPA and approved by the ICC, to contract capacity and energy on behalf of its customers. Ameren Missouri participates in the RFP process and has been a winning supplier for certain periods.
144
Table of Contents
Capacity Supply Agreements
In procurement events in 2021, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $2 million from June 2022 through May 2023.
Energy Product Agreements
Based on the outcome of IPA-administered procurement events, Ameren Missouri and Ameren Illinois have entered into energy product agreements by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, a set amount of MWhs at a predetermined price over a specified period of time. The following table presents the specified performance period, price, and amount of MWhs included in the agreements:
IPA Procurement EventPerformance PeriodMWhAverage Price per MWh
April 2017March 2019 – May 202085,600$34 
April 2018June 2019 – September 2020110,00032 
April 2019January 2020 – December 2021288,00035 
September 2019April 2020 – November 2021170,80029 
September 2020September 2021 – November 2022204,80031 
April 2021July 2022 – November 202233,60034 
September 2021January 2022 – September 2023136,00037 
Collateral Postings
Under the terms of the Illinois energy product agreements entered into through RFP processes administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, which means that only the suppliers can be required to post collateral. Therefore, Ameren Missouri, as a winning supplier in the RFP process, may be required to post collateral. As of December 31, 2021 and 2020, there were no collateral postings required of Ameren Missouri related to the Illinois energy product agreements.
Interconnection Agreements
Ameren Missouri and Ameren Illinois are parties to an interconnection agreement that governs the connection of their respective transmission lines and other facilities used for the distribution of power. These agreements have no contractual expiration date, but may be terminated by either party with three years’ notice.
Ameren Missouri and ATXI are parties to an interconnection agreement that governs the connection of the High Prairie Renewable Energy Center to an ATXI transmission line that allows Ameren Missouri to distribute power generated from the High Prairie Renewable Energy Center. See Note 15 – Supplemental Information for further information on the acquisition of the High Prairie Renewable Energy Center.
Support Services Agreements
Ameren Services provides support services to its affiliates. The costs of support services including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The support services agreement can be terminated at any time by the mutual agreement of Ameren Services and that affiliate or by either party with 60 days’ notice before the end of a calendar year.
In addition, Ameren Missouri and Ameren Illinois provide affiliates with access to their facilities for administrative purposes and with use of other assets. The costs of the rent and facility services and other assets are based on, or are an allocation of, actual costs incurred.
Ameren Missouri and Ameren Illinois also provide storm-related and miscellaneous support services to each other on an as-needed basis.
At December 31, 2021, Ameren Missouri and Ameren Illinois had long-term receivables included in “Other assets” from Ameren Services of $77 million and $80 million, respectively, related to Ameren Services’ allocated portion of Ameren’s pension and postretirement benefit plans.
Transmission Services
Ameren Missouri and Ameren Illinois receives transmission services from ATXI for their retail load.
145
Table of Contents
Electric Transmission Maintenance and Construction Agreements
ATXI entered into separate agreements with Ameren Missouri and Ameren Illinois in which Ameren Missouri or Ameren Illinois, as applicable, may perform certain maintenance and construction services related to ATXI’s electric transmission assets.
Money Pool
See Note 4 – Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.
Software Licensing Agreement
In September 2019, Ameren Missouri purchased a license for advanced metering infrastructure software from Ameren Illinois. The amount of the $24 million cost-based transaction price over the $5 million remaining carrying value of the software was recorded as revenue by Ameren Illinois, with $14 million of revenue recorded at Ameren Illinois Electric Distribution and $5 million recorded at Ameren Illinois Natural Gas. The revenue recorded at Ameren Illinois Electric Distribution was reflected in formula ratemaking, which resulted in no impact to net income. Per authoritative accounting guidance for sales to rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation by Ameren. Ameren Missouri’s cost-based investment of $24 million was included in “Property, Plant, and Equipment, Net.”
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreement. The following table presents the affiliate balances related to income taxes for Ameren Missouri and Ameren Illinois as of December 31, 2021 and December 31, 2020:
20212020
Ameren MissouriAmeren IllinoisAmeren MissouriAmeren Illinois
Income taxes payable to parent(a)
$— $8 $— $6 
Income taxes receivable from parent(b)
27 18 9 15 
(a)Included in “Accounts payable – affiliates” on the balance sheet.
(b)Included in “Accounts receivable – affiliates” on the balance sheet.
Capital Contributions
The following table presents cash capital contributions received from Ameren (parent) by Ameren Missouri and Ameren Illinois for the years ended December 31, 2021, 2020, and 2019:
202120202019
Ameren Missouri(a)
$207 $491 $124 
Ameren Illinois(a)
262 464 15 
(a)Includes capital contributions made as a result of the tax allocation agreement.
146
Table of Contents
Effects of Related-party Transactions on the Statement of Income
The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the years ended December 31, 2021, 2020, and 2019. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 – Short-term Debt and Liquidity.
AgreementIncome Statement Line ItemAmeren
Missouri		Ameren
Illinois
Ameren Missouri power supply agreementsOperating Revenues2021$16 $(a)
with Ameren Illinois202011 (a)
  20193 (a)
Ameren Missouri and Ameren IllinoisOperating Revenues202126 1 
rent and facility services202026 1 
  201927 2 
Ameren Missouri and Ameren Illinois miscellaneousOperating Revenues2021(b)5 
support services and services provided to ATXI20203 1 
20191 2 
Ameren Missouri software licensingOperating Revenues2021(a)(a)
with Ameren Illinois2020(a)(a)
2019(a)19 
Total Operating Revenues2021$42 $6 
202040 2 
  201931 23 
Ameren Illinois power supplyPurchased Power2021$(a)$16 
agreements with Ameren Missouri2020(a)11 
  2019(a)3 
Ameren Missouri and Ameren IllinoisPurchased Power20214 1 
transmission services from ATXI2020(a)2 
2019(a)2 
Total Purchased Power2021$4 $17 
2020(a)13 
2019(a)5 
Ameren Missouri and Ameren IllinoisOther Operations and 2021$1 $4 
rent and facility servicesMaintenance2020(b)4 
20192 5 
Ameren Services support servicesOther Operations and2021147 137 
agreementMaintenance2020140 133 
  2019135 127 
Total Other Operations and2021$148 $141 
Maintenance Expenses2020140 137 
  2019137 132 
Money pool borrowings (advances)(Interest Charges)2021$(b)$(b)
Other Income, Net2020(b)(b)
  2019(b)(b)
(a)Not applicable.
(b)Amount less than $1 million.
NOTE 14 – COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, Note 13 – Related-party Transactions, and Note 15 – Supplemental Information in this report.
147
Table of Contents
Environmental Matters
Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety including permitting programs implemented via federal, state, and local authorities. Such environmental laws address air emissions; discharges to water bodies; the storage, handling and disposal of hazardous substances and waste materials; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. We employ dedicated personnel knowledgeable in environmental matters to oversee our business activities’ compliance with regulatory requirements.
Environmental regulations have a significant impact on the electric utility industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. Clean Air Act regulations that apply to the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx, mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Regulations implementing the Clean Water Act govern both intake and discharges of water and may require evaluation of the ecological and biological impact of our operations and could require modifications to water intake structures or more stringent limitations on wastewater discharges. Depending upon the scope of modifications ultimately required by state regulators, these capital expenditures could be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR Rule, which require the closure of our surface impoundments at Ameren Missouri’s coal-fired energy centers. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.
Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $125 million to $175 million from 2022 through 2026 in order to comply with existing environmental regulations. Additional environmental controls beyond 2026 could be required. This estimate of capital expenditures includes ash pond closure and corrective action measures required by the CCR Rule, and the effluent limitation guidelines applicable to steam electric generating units, and potential modifications to cooling water intake structures at existing power plants under Clean Water Act rules, all of which are discussed below. In addition to planned retirements of coal-fired energy centers as set forth in the 2020 IRP and as noted in the NSR and Clean Air Act litigation discussed below, Ameren Missouri’s current plan for compliance with existing air emission regulations includes natural gas-fired energy center retirements as discussed below in Illinois Emission Standards, burning low-sulfur coal and installing new or optimizing existing air pollution control equipment. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimates because of uncertainty as to future permitting requirements made by state regulators and the EPA, potential revisions to regulatory obligations, and the cost of potential compliance strategies, among other things.
The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of several regulations and proposed amendments to regulations and guidelines, including to the effluent limitation guidelines and the CCR Rule, which could ultimately result in the revision of all or part of such rules. Additionally, Ameren Missouri’s wind generation facilities may be subject to operating restrictions to limit the impact on protected species. From April 2021 through October 2021, Ameren Missouri's High Prairie Renewable Energy Center curtailed nighttime operations to limit impacts on protected species. Ameren Missouri resumed nighttime operations in November 2021 as the critical biological season had ended. Seasonal nighttime curtailment will begin again in April 2022, but the extent and duration of the curtailment is unknown at this time as assessment of mitigation technologies is ongoing. Ameren Missouri does not anticipate these operating curtailments to result in significant impacts on its results of operations, financial position, or liquidity.
Clean Air Act
Federal and state laws, including CSAPR, regulate emissions of SO2 and NOx through the reduction of emissions at their source and the use and retirement of emission allowances. CSAPR is implemented through a series of phases, and the second phase became effective in 2017. Additional emission reduction requirements may apply in subsequent years. Ameren Missouri complies with current CSAPR requirements by minimizing emissions through the use of low-sulfur coal, operation of two scrubbers at its Sioux Energy Center, and optimization of other existing air pollution control equipment. Ameren Missouri could incur additional costs to lower its emissions at one or more of its energy centers to comply with additional CSAPR requirements in future years. These additional costs for compliance are expected to be recovered from customers through the FAC or higher base rates.
148
Table of Contents
CO2 Emissions Standards
The EPA’s Affordable Clean Energy Rule repealed the Clean Power Plan and replaced it with a new rule that established emission guidelines for states to follow in developing plans to limit CO2 emissions and identified certain efficiency measures as the best system of emission reduction for coal-fired electric generating units. In January 2021, the United States Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy Rule, and ruled that the EPA had the discretion to consider emission reduction measures that include efficiency measures and generation shifting to lower carbon emissions. The United States Supreme Court agreed to review the court of appeals’ ruling and oral arguments will occur in February 2022 with a decision expected by mid-2022. A decision by the United States Supreme Court could impact the EPA’s development of new regulations to address carbon emissions from coal- and natural gas-fired electric generating units. At this time, Ameren Missouri cannot predict the outcome of the legal challenge or future rulemakings. As such, any impact on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri is uncertain.
NSR and Clean Air Act Litigation
In January 2011, the United States Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri alleging that in performing projects at its coal-fired Rush Island Energy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2017, the district court issued a liability ruling against Ameren Missouri and, in September 2019, entered a remedy order that required Ameren Missouri to install a flue gas desulfurization system at the Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. Ameren Missouri appealed both the liability and remedy orders and, in August 2021, the United States Court of Appeals for the Eighth Circuit issued a decision that affirmed the liability ruling and the district court’s remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In November 2021, the court of appeals issued an order denying requests for consideration previously sought by both Ameren Missouri and the United States Department of Justice.
Based on its assessment of available legal, operational and regulatory alternatives, Ameren Missouri has determined not to further appeal the court rulings and, in December 2021, filed a motion with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The district court is under no deadline to issue a ruling revising the remedy order. In January 2022, the MISO completed a preliminary assessment regarding potential impacts of the retirement to the regional electric power system, which indicated transmission upgrades and voltage support would be needed in advance of the retirement to address reliability concerns. In February 2022, Ameren Missouri expects to formally notify the MISO of its intent to retire the Rush Island Energy Center. Upon receipt of the formal notification, the MISO will conduct a final reliability assessment. The MISO must also separately approve the specific upgrades and transmission support required to address reliability concerns noted in the assessment. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review the planned accelerated retirement of the Rush Island Energy Center. See Note 2 – Rate and Regulatory Matters for additional information.
In connection with the planned accelerated retirement of the Rush Island Energy Center, Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute that became effective in August 2021. As of December 31, 2021, the Rush Island Energy Center had a net plant balance of approximately $0.6 billion included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net” and a rate base of approximately $0.4 billion. See Note 1 – Summary of Significant Accounting Policies for additional information regarding plant to be abandoned, net. In addition, Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect the planned acceleration of the retirement of the Rush Island Energy Center from 2039, the retirement year for the facility as reflected in the 2020 IRP and reflected in depreciation rates approved by the December 2021 MoPSC electric rate order.
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.
Clean Water Act
The EPA’s regulations implementing Section 316(b) of the Clean Water Act require power plant operators to evaluate cooling water intake structures and identify measures for reducing the number of aquatic organisms impinged on a power plant’s cooling water intake screens or entrained through the plant’s cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. Requirements of the rule are implemented by state regulators through the permit renewal process of each power plant’s water discharge permit, which is expected to be completed by 2023 for Ameren Missouri.
In 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines established national standards for water discharges, prohibit effluent discharges of certain waste streams, and impose more stringent limitations on certain water discharges from power plants. To meet the requirements of the guidelines, Ameren Missouri installed dry ash
149
Table of Contents
handling systems and in 2020 completed construction of wastewater treatment facilities at three of its four coal-fired energy centers. The Meramec Energy Center is scheduled to retire in 2022 and, as a result, does not require new wastewater and dry ash handling systems.
CCR Management
The EPA’s CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and will result in the closure of surface impoundments at Ameren Missouri’s energy centers. Ameren Missouri completed the closure of all surface impoundments at two of its facilities in 2021, and has made significant progress by closing several impoundments at its other two facilities. Ameren Missouri plans to complete the closures of the remaining surface impoundments in 2023. In January 2022, Ameren Missouri received notice of a proposed determination by the EPA that it has rejected Ameren Missouri’s requests to extend the timeline for operating certain impoundments located at the Sioux and Meramec energy centers. Compliance with the CCR Rule’s requirements for closure of the impoundments would be required 135 days after the EPA issues a final determination, which Ameren Missouri expects to be issued in the spring of 2022. If Ameren Missouri was no longer able to use the surface impoundments at the Sioux or Meramec energy centers, Ameren Missouri would not be able to operate the energy centers unless an alternative for handling the CCR material is in place. Ameren Missouri plans to retire the Meramec Energy Center in 2022, and is accelerating its construction plans to build a CCR Rule-compliant impoundment at the Sioux Energy Center to allow for continued operations. Additionally, Ameren Missouri is seeking a reliability determination from the MISO, which, if granted, would extend the deadline to comply with the requirement to close the impoundments and allow the energy centers to operate. Ameren Missouri does not expect that this matter will have a material adverse effect on its results of operations, financial position, or liquidity.
Ameren and Ameren Missouri have AROs of $76 million recorded on their respective balance sheets as of December 31, 2021, associated with CCR storage facilities. Ameren Missouri estimates it will need to make capital expenditures of $60 million to $80 million from 2022 through 2026 to implement its CCR management compliance plan, which includes installation of groundwater monitoring equipment and groundwater treatment facilities.
Remediation
The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site.
As of December 31, 2021, Ameren Illinois has remediated the majority of the 44 former MGP sites in Illinois and could substantially conclude remediation efforts at the remaining sites by 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders that are subject to annual prudence reviews by the ICC. As of December 31, 2021, Ameren Illinois estimated the remaining obligation related to these former MGP sites at $71 million to $125 million. Ameren and Ameren Illinois recorded a liability of $71 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.
The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the actual costs, including unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs and timing of completion may vary substantially from these estimates.
Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such historical practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.
Illinois Emission Standards
The IETL established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois will be subject to limits on emissions, including CO2 and NOx, equal to their unit-specific average emissions from 2018 through 2020, for any rolling twelve-month period beginning October 1, 2021, through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, which could limit the operations of Ameren Missouri's five natural gas-fired energy centers located in the state of Illinois, and will result in the closure of one or more energy centers earlier than anticipated. These energy centers are utilized to support peak loads. Subject to conditions in the IETL, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service as necessary. Ameren Missouri is reviewing the emission standards and the effect they may have on its generation strategy, including any increases in capital expenditures or operating costs, and changes to the useful lives of the five natural gas-fired energy centers. Ameren Missouri expects to file an update to the 2020 IRP with the MoPSC in the first half of 2022 to reflect, among other things, the impact of these new emissions standards.
150
Table of Contents
NOTE 15 – SUPPLEMENTAL INFORMATION
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of December 31, 2021 and 2020:
December 31, 2021December 31, 2020
AmerenAmeren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois
Cash and cash equivalents$8 $— $— $139 $136 $— 
Restricted cash included in “Other current assets”16 4 6 17 5 6 
Restricted cash included in “Other assets”127 — 127 141 — 141 
Restricted cash included in “Nuclear decommissioning trust fund”4 4 — 4 4 — 
Total cash, cash equivalents, and restricted cash$155 $8 $133 $301 $145 $147 
Restricted cash included in “Other current assets” primarily represents funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees. Restricted cash included in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets primarily represents amounts collected under a cost recovery rider restricted for use in the procurement of renewable energy credits and amounts in a trust fund restricted for the use of funding certain asbestos-related claims.
Accounts Receivable
“Accounts receivable – trade” on Ameren’s and Ameren Illinois’ balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At December 31, 2021 and 2020, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $27 million and $28 million, respectively.
The following table provides a reconciliation of the beginning and ending amount of the allowance for doubtful accounts for the years ended December 31, 2021 and 2020:
December 31, 2021December 31, 2020
Ameren Missouri
Ameren Illinois(a)
AmerenAmeren Missouri
Ameren Illinois(a)
Ameren
Beginning of period$16 $34 $50 $7 $10 $17 
Bad debt expense5 4 
(b)
9 15 33 48 
Net write-offs(8)(22)(30)(6)(9)(15)
End of period$13 $16 $29 $16 $34 $50 
(a)Ameren Illinois has rate-adjustment mechanisms that allow it to recover the difference between its actual net bad debt write-offs under GAAP, including those associated with receivables purchased from alternative retail electric suppliers, and the amount of net bad debt write-offs included in its base rates.
(b)In 2021, Ameren Illinois’ bad debt expense was reduced as a result of incremental state funding received for customer bill assistance. The incremental state funding granted relief to low-income customers at risk of service disconnection resulting from the impacts of the COVID-19 pandemic.
Net write-offs increased for the year ended December 31, 2021 due to the resumption of disconnection activities for nonpayment. See Note 2 – Rate and Regulatory Matters for additional information.
Inventories
The following table presents the components of inventories for each of the Ameren Companies at December 31, 2021 and 2020:
December 31, 2021December 31, 2020
Ameren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois		Ameren
Fuel(a)
$118 $— $118 $115 $— $115 
Natural gas stored underground9 90 99 5 52 57 
Materials, supplies, and other292 83 375 266 83 349 
Total inventories$419 $173 $592 $386 $135 $521 
(a)Consists of coal, oil, and propane.
151
Table of Contents
Property, Plant, and Equipment
In January 2021, Ameren Missouri acquired a 300-MW wind generation project located in northwestern Missouri. As of June 30, 2021, Ameren Missouri had placed the project in service as the Atchison Renewable Energy Center. The purchase price of the energy center was approximately $500 million, including an immaterial amount of transaction costs. In December 2020, Ameren Missouri acquired a 400-MW wind generation project located in northeastern Missouri for approximately $615 million, and placed the assets in service as the High Prairie Renewable Energy Center. The purchase price included $564 million of cash, a deferred purchase price obligation withheld as credit support in relation to certain potential claims, contingent consideration, and transaction costs. Both renewable energy centers support Ameren Missouri’s compliance with the Missouri renewable energy standard.
Asset Retirement Obligations
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years ended December 31, 2021 and 2020:
December 31, 2021December 31, 2020
Ameren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois		Ameren
Beginning balance at January 1$751 

$5 
(a)
$756 
(b)
$687 $4 $691 
Liabilities incurred18 
(c)
— 18 
(c)
36 
(c)
— 36 
(c)
Liabilities settled(36)(1)(37)(58)— (58)
Accretion(d)
31 — 31 29 1 30 
Change in estimates(4)
(e)
— (4)
(e)
57 
(f)
— 57 
(f)
Ending balance at December 31$760 
(g)
$4 
(a)
$764 
(b)(g)
$751 

$5 
(a)
$756 
(b)
(a)Included in “Other deferred credits and liabilities” on the balance sheet.
(b)Balance included $7 million and $60 million in “Other current liabilities” on the balance sheet as of December 31, 2021 and 2020, respectively.
(c)Ameren Missouri recorded AROs related to the decommissioning of the Atchison Renewable and High Prairie Renewable energy centers in 2021 and 2020, respectively.
(d)Accretion expense attributable to Ameren Missouri and Ameren Illinois was recorded as a decrease to regulatory liabilities and an increase to regulatory assets, respectively.
(e)Ameren Missouri changed its fair value estimate primarily due to a decrease in the cost estimate for closure of certain CCR storage facilities, partially offset by an increase due to the planned accelerated retirement of the Rush Island Energy Center.
(f)Ameren Missouri changed its fair value estimate primarily due to an update to the decommissioning of the Callaway Energy Center to reflect the cost study and funding analysis filed with the MoPSC in November 2020 and an increase in the cost estimate for closure of certain CCR storage facilities.
(g)The balance as of December 31, 2021, included an ARO related to the decommissioning of the Callaway Enter Center of $574 million.
Noncontrolling Interests
As of December 31, 2021 and 2020, Ameren’s noncontrolling interests included the preferred stock of Ameren Missouri and Ameren Illinois.
Deferred Compensation
As of December 31, 2021, and 2020, the present value of benefits to be paid for deferred compensation obligations was $91 million and $90 million, respectively, which was primarily reflected in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet.
Excise Taxes
Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the sale or distribution of natural gas and electricity. The following table presents the excise taxes recorded on a gross basis in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income for the years ended December 31, 2021, 2020, and 2019:
202120202019
Ameren Missouri$150 $139 $147 
Ameren Illinois125 115 117 
Ameren$275 $254 $264 
152
Table of Contents
Allowance for Funds Used During Construction
The following table presents the average rate that was applied to eligible construction work in progress and the amounts of allowance for funds used during construction capitalized in 2021, 2020, and 2019:
202120202019
Average rate:
Ameren Missouri6 %5 %6 %
Ameren Illinois5 %5 %5 %
Ameren:
Allowance for equity funds used during construction$43 $32 $28 
Allowance for borrowed funds used during construction17 16 20 
Total Ameren$60 $48 $48 
Ameren Missouri:
Allowance for equity funds used during construction$26 $19 $19 
Allowance for borrowed funds used during construction10 10 12 
Total Ameren Missouri$36 $29 $31 
Ameren Illinois:
Allowance for equity funds used during construction$17 $13 $9 
Allowance for borrowed funds used during construction7 6 8 
Total Ameren Illinois$24 $19 $17 
Earnings per Share
Earnings per basic and diluted share are computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of basic and diluted common shares outstanding, respectively, during the applicable period. The weighted-average shares outstanding for earnings per diluted share includes the incremental effects resulting from performance share units, restricted stock units, and forward sale agreements relating to common stock when the impact would be dilutive, as calculated using the treasury stock method. For information regarding performance share units and restricted stock units, see Note 11 – Stock-based Compensation. For information regarding forward sale agreements, see Note 5 – Long-term Debt and Equity Financings.
The following table reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2021, 2020, and 2019:
202120202019
Weighted-average Common Shares Outstanding – Basic256.3 247.0 245.6 
Assumed settlement of performance share units and restricted stock units1.3 1.2 1.4 
Dilutive effect of forward sale agreements— 0.5 0.1 
Weighted-average Common Shares Outstanding – Diluted(a)
257.6 248.7 247.1 
(a)There was an immaterial number of anti-dilutive securities excluded from the earnings per diluted share calculations for the year ended December 31, 2021. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the years ended December 31, 2020 and 2019.
153
Table of Contents
Supplemental Cash Flow Information
The following table provides noncash financing and investing activity excluded from the statements of cash flows for the years ended December 31, 2021, 2020, and 2019:
December 31, 2021December 31, 2020December 31, 2019
AmerenAmeren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois		AmerenAmeren
Missouri		Ameren
Illinois
Investing
Accrued capital expenditures, including wind generation expenditures$508 $285 $215 $446 $229 $218 $333 $140 $163 
Accrued nuclear fuel expenditures16 16 — — — — 19 19 — 
Net realized and unrealized gain – nuclear decommissioning trust fund163 163 — 116 116 — 143 143 — 
Exchange of bond investments for the extinguishment of senior unsecured notes(a)
— — — — — — 17 — 17 
Financing
Issuance of common stock for stock-based compensation$33 $— $— $38 $— $— $54 $— $— 
Exchange of bond investments for the extinguishment of senior unsecured notes(a)
— — — — — — (17)— (17)
(a)In 2006, Ameren Illinois purchased all $17 million of the 1993 Series B-1 bonds due 2028 issued by the Illinois Finance Authority on behalf of Ameren Illinois pursuant to a mandatory tender. Ameren Illinois’ 1993 Series B-1 senior unsecured notes due 2028 were not extinguished and remained as “Long-term debt, net” on Ameren’s and Ameren Illinois’ balance sheets. In September 2019, Ameren Illinois exchanged its bond investments for the extinguishment of its senior unsecured notes.
NOTE 16 – SEGMENT INFORMATION
Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. The category called Other primarily includes Ameren (parent) activities and Ameren Services.
Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri, Ameren Illinois, and ATXI.
Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution, other retail electric suppliers, and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.
154
Table of Contents
The following tables present information about the reported revenue and specified items reflected in net income attributable to common shareholders and capital expenditures by segment at Ameren and Ameren Illinois for the years ended December 31, 2021, 2020, and 2019. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.
Ameren
Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren TransmissionOtherIntersegment EliminationsAmeren
2021
External revenues$3,311 $1,635 $957 $491 $— $— $6,394 
Intersegment revenues42 4 — 71 — (117)— 
Depreciation and amortization632 309 90 111 4 — 1,146 
Interest income26 1 — — 3 (3)27 
Interest charges137 74 42 83 
(a)
50 (3)383 
Income taxes (benefit)3 53 39 82 (20)— 157 
Net income (loss) attributable to Ameren common shareholders518 165 108 230 (31)— 990 
Capital expenditures2,015 
(b)
579 278 616 4 (13)3,479 
(b)
2020
External revenues$3,069 $1,496 $760 $469 $— $— $5,794 
Intersegment revenues40 2 — 54 — (96)— 
Depreciation and amortization604 288 81 98 4 — 1,075 
Interest income26 2 — 1 4 (4)29 
Interest charges190 72 41 78 
(a)
42 (4)419 
Income taxes (benefit)34 42 36 78 (35)— 155 
Net income (loss) attributable to Ameren common shareholders436 143 99 216 (23)— 871 
Capital expenditures1,666 
(b)
543 301 716 5 2 3,233 
(b)
2019
External revenues$3,212 $1,487 $791 $401 $— $— $5,891 
Intersegment revenues31 17 6 63 — (98)19 
(c)
Depreciation and amortization556 273 78 84 4 — 995 
Interest income26 6 — 1 5 (5)33 
Interest charges178 71 38 74 
(a)
25 (5)381 
Income taxes (benefit)68 45 30 64 (25)— 182 
Net income (loss) attributable to Ameren common shareholders426 146 84 185 (13)— 828 
Capital expenditures1,076 518 318 528 3 (32)
(d)
2,411 
(a)Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent).
(b)Includes $525 million and $564 million at Ameren and Ameren Missouri for wind generation expenditures for the year ended December 31, 2021 and 2020, respectively.
(c)Intersegment revenues at Ameren include $14 million and $5 million of revenue from Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. Under authoritative accounting guidance for rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation. See Note 13 – Related-party Transactions for additional information.
(d)Intersegment capital expenditure eliminations include $24 million of eliminations for the year ended December 31, 2019, for a software licensing agreement between Ameren Illinois and Ameren Missouri. See Note 13 – Related-party Transactions for additional information.
155
Table of Contents
Ameren Illinois
Ameren Illinois Electric DistributionAmeren Illinois
Natural Gas		Ameren Illinois TransmissionIntersegment EliminationsAmeren Illinois
2021
External revenues$1,639 $957 $299 $— $2,895 
Intersegment revenues— — 66 (66)— 
Depreciation and amortization309 90 73 — 472 
Interest income1 — — — 1 
Interest charges74 42 48 — 164 
Income taxes53 39 51 — 143 
Net income available to common shareholder165 108 152 — 425 
Capital expenditures579 278 575 — 1,432 
2020
External revenues$1,498 $760 $277 $— $2,535 
Intersegment revenues— — 52 (52)— 
Depreciation and amortization288 81 65 — 434 
Interest income2 — 1 — 3 
Interest charges72 41 42 — 155 
Income taxes42 36 46 — 124 
Net income available to common shareholder143 99 137 — 379 
Capital expenditures543 301 603 — 1,447 
2019
External revenues$1,504 $797 $226 $— $2,527 
Intersegment revenues— — 62 (62)— 
Depreciation and amortization273 78 55 — 406 
Interest income6 — — — 6 
Interest charges71 38 38 — 147 
Income taxes45 30 35 — 110 
Net income available to common shareholder146 84 113 — 343 
Capital expenditures518 318 372 — 1,208 
156
Table of Contents
The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the years ended December 31, 2021, 2020, and 2019. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.
Ameren
Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren TransmissionIntersegment EliminationsAmeren
2021
Residential$1,445 $933 $— $— $— $2,378 
Commercial1,126 545 — — — 1,671 
Industrial280 135 — — — 415 
Other361 26 — 562 (116)833 
Total electric revenues$3,212 $1,639 $— $562 $(116)$5,297 
Residential$79 $— $657 $— $— $736 
Commercial34 — 172 — — 206 
Industrial4 — 35 — — 39 
Other24 — 93 — (1)116 
Total gas revenues$141 $— $957 $— $(1)$1,097 
Total revenues(a)
$3,353 $1,639 $957 $562 $(117)$6,394 
2020
Residential$1,373 $867 $— $— $— $2,240 
Commercial1,025 486 — — — 1,511 
Industrial261 124 — — — 385 
Other325 21 — 523 (94)775 
Total electric revenues$2,984 $1,498 $— $523 $(94)$4,911 
Residential$76 $— $541 $— $— $617 
Commercial29 — 136 — — 165 
Industrial4 — 14 — — 18 
Other16 — 69 — (2)83 
Total gas revenues$125 $— $760 $— $(2)$883 
Total revenues(a)
$3,109 $1,498 $760 $523 $(96)$5,794 
2019
Residential$1,403 $848 $— $— $— $2,251 
Commercial1,157 497 — — — 1,654 
Industrial278 127 — — — 405 
Other271 32 
(b)
— 464 (96)671 
Total electric revenues$3,109 $1,504 $— $464 $(96)$4,981 
Residential$81 $— $570 $— $— $651 
Commercial34 — 154 — — 188 
Industrial4 — 13 — — 17 
Other15 — 60 
(b)
— (2)73 
Total gas revenues$134 $— $797 $— $(2)$929 
Total revenues(a)
$3,243 $1,504 $797 $464 $(98)$5,910 
(a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the years ended December 31, 2021, 2020, and 2019:
157
Table of Contents
Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren TransmissionAmeren
2021
Revenues from alternative revenue programs$(16)$77 $5 $11 $77 
Other revenues not from contracts with customers56 
(a)
10 2 — 68 
(a)
2020
Revenues from alternative revenue programs$(14)$(20)$20 $50 $36 
Other revenues not from contracts with customers25 8 2 1 36 
2019
Revenues from alternative revenue programs$35 $(74)$— $(31)$(70)
Other revenues not from contracts with customers19 7 2 — 28 
(a)Includes insurance recoveries related to lost sales associated with the Callaway Energy Center maintenance outage. See Note 9 – Callaway Energy Center for additional information.
(b)Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information.
Ameren Illinois
Ameren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Illinois TransmissionIntersegment EliminationsAmeren Illinois
2021
Residential$933 $657 $— $— $1,590 
Commercial545 172 — — 717 
Industrial135 35 — — 170 
Other26 93 365 (66)418 
Total revenues(a)
$1,639 $957 $365 $(66)$2,895 
2020
Residential$867 $541 $— $— $1,408 
Commercial486 136 — — 622 
Industrial124 14 — — 138 
Other21 69 329 (52)367 
Total revenues(a)
$1,498 $760 $329 $(52)$2,535 
2019
Residential$848 $570 $— $— $1,418 
Commercial497 154 — — 651 
Industrial127 13 — — 140 
Other32 
(b)
60 
(b)
288 (62)318 
Total revenues(a)
$1,504 $797 $288 $(62)$2,527 
(a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the years ended December 31, 2021, 2020, and 2019:
Ameren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Illinois TransmissionAmeren Illinois
2021
Revenues from alternative revenue programs$77 $5 $9 $91 
Other revenues not from contracts with customers10 2 — 12 
2020
Revenues from alternative revenue programs$(20)$20 $42 $42 
Other revenues not from contracts with customers8 2 — 10 
2019
Revenues from alternative revenue programs$(74)$— $(33)$(107)
Other revenues not from contracts with customers7 2 — 9 
(b)Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information.
158
Table of Contents
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.CONTROLS AND PROCEDURES
(a)Evaluation of Disclosure Controls and Procedures
As of December 31, 2021, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and the principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of December 31, 2021, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
(b)Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision of and with the participation of management, including the principal executive officer and the principal financial officer, an evaluation was conducted of the effectiveness of each of the Ameren Companies’ internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). After making that evaluation, management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2021. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of Ameren Missouri’s or Ameren Illinois’ (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over financial reporting. Management’s report for each of the Subsidiary Registrants is not subject to attestation by an independent registered public accounting firm.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that internal controls might become inadequate because of changes in conditions, and to the risk that the degree of compliance with the policies or procedures might deteriorate.
(c)Change in Internal Control
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
ITEM 9B.OTHER INFORMATION
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 2021 that has not previously been reported.
ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not Applicable.
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and to each of Ameren Missouri’s and Ameren Illinois’ definitive information statements: “Information Concerning Nominees to the Board of Directors,” “Section 16(a) Reports,” “Corporate Governance” and “Board Structure.”
159
Table of Contents
Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Information about our Executive Officers” in Part I of this report.
Ameren Missouri and Ameren Illinois do not have separately designated standing audit committees, but instead use Ameren’s Audit and Risk Committee to perform such committee functions for their boards of directors. These companies do not have securities listed on the NYSE and therefore are not subject to the NYSE listing standards. J. Edward Coleman serves as chairman of Ameren’s Audit and Risk Committee and Catherine S. Brune, Ward H. Dickson, Noelle K. Eder, and Leo S. Mackay, Jr. serve as members. The board of directors of Ameren has determined that J. Edward Coleman and Ward H. Dickson each qualify as an audit committee financial expert and that each is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of Ameren Missouri and Ameren Illinois use the Nominating and Corporate Governance Committee of Ameren’s board of directors to perform such committee functions. This Committee is responsible for the nomination of directors and for corporate governance practices. Ameren’s Nominating and Corporate Governance Committee will consider director nominations from shareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s website: www.amereninvestors.com.
To encourage ethical conduct in its financial management and reporting, Ameren has adopted a code of ethics that applies to the directors, officers, and employees of the Ameren Companies. Ameren has also adopted a supplemental code of ethics that applies to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the controller, and the treasurer of the Ameren Companies. The Ameren Companies make available free of charge through Ameren’s website (www.amereninvestors.com) the code of ethics and the supplemental code of ethics. Any amendment to the code of ethics or the supplemental code of ethics and any waiver from a provision of the code of ethics or the supplemental code of ethics as it relates to the principal executive officer, the president, the principal financial officer, the principal accounting officer, the controller, or the treasurer of each of the Ameren Companies will be posted on Ameren’s website within four business days following the date of the amendment or waiver.
ITEM 11.EXECUTIVE COMPENSATION
Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and to each of Ameren Missouri’s and Ameren Illinois’ definitive information statements: “Executive Compensation Matters” and “Human Resources Committee Interlocks and Insider Participation.”
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Equity Compensation Plan Information
The following table presents information as of December 31, 2021, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans:
Plan
Category
Column A
Number of Securities To Be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights(a)
Column B
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
Column C
Number of Securities Remaining
Available for Future Issuance
Under Equity Compensation Plans (excluding
securities reflected in Column A)
Equity compensation plans approved by security holders(b)
1,442,122 (c)1,753,758 
Equity compensation plans not approved by security holders— — — 
Total1,442,122 (c)1,753,758 
(a)Of the securities to be issued, 913,649 of the securities represent the target number of outstanding performance share units (PSUs) and 433,248 of the securities represent the number of outstanding restricted stock units (RSUs), both including accrued and reinvested dividends. The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level, depending upon the achievement of TSR objectives or performance goals established for such awards. For additional information about the PSUs and RSUs, including payout calculations, see “Compensation Discussion and Analysis – Long-Term Incentive Compensation” in Ameren’s definitive proxy statement for its 2022 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. The remaining 95,225 of the securities represent shares that may be issued to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for Members of the Board of Directors.
(b)Consists of the 2014 Omnibus Incentive Compensation Plan.
(c)No cash consideration is received when shares are distributed for earned PSUs, RSUs, and director awards. Accordingly, there is no weighted-average exercise price.
Ameren Missouri and Ameren Illinois do not have separate equity compensation plans.
160
Table of Contents
Security Ownership of Certain Beneficial Owners and Management
The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Security Ownership.”
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by Items 404 and 407(a) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 2022 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and to each of Ameren Missouri’s and Ameren Illinois’ definitive information statements: “Related Person Transactions Policy” and “Director Independence.”
ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of Ameren Missouri and Ameren Illinois for their 2022 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Selection of Independent Registered Public Accounting Firm.”

161
Table of Contents
PART IV

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Page No.
(a)(1) Financial Statements
Ameren
Report of Independent Registered Public Accounting Firm –
(PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238)
Consolidated Statement of Income and Comprehensive Income – Years Ended December 31, 2021, 2020, and 2019
Consolidated Balance Sheet – December 31, 2021 and 2020
Consolidated Statement of Cash Flows – Years Ended December 31, 2021, 2020, and 2019
Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2021, 2020, and 2019
Ameren Missouri
Report of Independent Registered Public Accounting Firm –
(PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238)
Statement of Income – Years Ended December 31, 2021, 2020, and 2019
Balance Sheet – December 31, 2021 and 2020
Statement of Cash Flows – Years Ended December 31, 2021, 2020, and 2019
Statement of Shareholders’ Equity – Years Ended December 31, 2021, 2020, and 2019
Ameren Illinois
Report of Independent Registered Public Accounting Firm –
(PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238)
Statement of Income – Years Ended December 31, 2021, 2020, and 2019
Balance Sheet – December 31, 2021 and 2020
Statement of Cash Flows – Years Ended December 31, 2021, 2020, and 2019
Statement of Shareholders’ Equity – Years Ended December 31, 2021, 2020, and 2019
(a)(2) Financial Statement Schedules
Schedule I
Condensed Financial Information of Parent – Ameren:
Condensed Statement of Income and Comprehensive Income – Years Ended December 31, 2021, 2020, and 2019
Condensed Balance Sheet – December 31, 2021 and 2020
Condensed Statement of Cash Flows – Years Ended December 31, 2021, 2020, and 2019
Schedule II
Ameren
Valuation and Qualifying Accounts for the years ended December 31, 2021, 2020, and 2019
Ameren Missouri
Valuation and Qualifying Accounts for the years ended December 31, 2021, 2020, and 2019
Ameren Illinois
Valuation and Qualifying Accounts for the years ended December 31, 2021, 2020, and 2019
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
(a)(3) Exhibits – reference is made to the Exhibit Index
(b) Exhibit Index
162
Table of Contents
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2021, 2020, and 2019
(In millions)202120202019
Operating revenues$— $— $— 
Operating expenses13 12 15 
Operating loss(13)(12)(15)
Equity in earnings of subsidiaries1,039 908 850 
Interest income from affiliates3 4 5 
Total other expense, net— (8)(2)
Interest charges(64)(57)(39)
Income tax benefit25 36 29 
Net Income Attributable to Ameren Common Shareholders$990 $871 $828 
Net Income Attributable to Ameren Common Shareholders$990 $871 $828 
Other Comprehensive Income, Net of Taxes:
Pension and other postretirement benefit plan activity, net of income taxes of $4, $5, and $1, respectively
14 16 5 
Comprehensive Income Attributable to Ameren Common Shareholders$1,004 $887 $833 
163
Table of Contents
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET
(In millions, except per share amounts)December 31, 2021December 31, 2020
Assets:
Cash and cash equivalents$— $— 
Advances to money pool108 16 
Accounts receivable – affiliates30 12 
Miscellaneous accounts and notes receivable11 15 
Other current assets4 4 
Total current assets153 47 
Investments in subsidiaries12,281 10,872 
Note receivable – ATXI35 75 
Accumulated deferred income taxes, net65 42 
Other assets184 167 
Total assets
$12,718 $11,203 
Liabilities and Shareholders’ Equity:
Short-term debt$277 $490 
Taxes accrued7 — 
Accounts payable – affiliates53 41 
Other current liabilities38 34 
Total current liabilities375 565 
Long-term debt2,533 1,588 
Pension and other postretirement benefits24 27 
Other deferred credits and liabilities86 85 
Total liabilities3,018 2,265 
Commitments and Contingencies (Note 5)
Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 257.7 and 253.3, respectively
3 3 
Other paid-in capital, principally premium on common stock6,502 6,179 
Retained earnings3,182 2,757 
Accumulated other comprehensive income (loss)13 (1)
Total shareholders’ equity9,700 8,938 
Total liabilities and shareholders’ equity$12,718 $11,203 
164
Table of Contents
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2021, 2020, and 2019
(In millions)202120202019
Net cash flows provided by operating activities$79 $147 $491 
Cash flows from investing activities:
Money pool advances, net(92)86 (26)
Notes receivable – ATXI40 — — 
Investments in subsidiaries(489)(956)(142)
Other7 8 5 
Net cash flows used in investing activities(534)(862)(163)
Cash flows from financing activities:
Dividends on common stock(565)(494)(472)
Short-term debt, net(213)337 (317)
Money pool borrowings, net— (24)(22)
Maturities of long-term debt— (350)— 
Issuances of long-term debt949 798 450 
Issuances of common stock308 476 68 
Employee payroll taxes related to stock-based compensation(17)(20)(29)
Debt issuance costs(7)(7)(4)
Net cash flows provided by (used in) financing activities455 716 (326)
Net change in cash, cash equivalents, and restricted cash$— $1 $2 
Cash, cash equivalents, and restricted cash at beginning of year4 3 1 
Cash, cash equivalents, and restricted cash at end of year$4 $4 $3 
Supplemental information:
Cash dividends received from consolidated subsidiaries$123 $105 $445 
Noncash financing activity – Issuance of common stock for stock-based compensation33 38 54 
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS December 31, 2021
NOTE 1 – BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. Ameren Corporation (parent company only) has accounted for its subsidiaries using the equity method. These financial statements are presented on a condensed basis.
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
NOTE 2 – CASH AND CASH EQUIVALENTS
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheet and the statement of cash flows as of December 31, 2021 and 2020:
(In millions)20212020
Cash and cash equivalents$— $— 
Restricted cash included in “Other current assets”4 4 
Total cash, cash equivalents, and restricted cash$4 $4 
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
NOTE 3 – SHORT-TERM DEBT AND LIQUIDITY
Ameren, Ameren Services, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. All participants may borrow from or lend to the non-state-regulated money pool. The total amount available to pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the
165
Table of Contents
amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary 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 non-state-regulated subsidiary money pool. Interest revenues and interest charges related to non-state-regulated money pool advances and borrowings were immaterial in 2019, 2020, and 2021.
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).
NOTE 4 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on Ameren Corporation’s (parent company only) long-term debt, indenture provisions, forward sale agreements related to common stock, and ATM program.
NOTE 5 – COMMITMENTS AND CONTINGENCIES
See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies of Ameren Corporation (parent company only).
NOTE 6 – TOTAL OTHER EXPENSE, NET
The following table presents the components of “Total Other Expense, Net” in the Condensed Statement of Income and Comprehensive Income for the years ended December 31, 2021, 2020, and 2019:
(In millions)202120202019
Total Other Expense, Net
Non-service cost components of net periodic benefit income$1 $1 $2 
Donations— (8)(3)
Other expense, net(1)(1)(1)
Total Other Expense, Net$— $(8)$(2)
166
Table of Contents
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2021, 2020, AND 2019
(In millions)
Column AColumn BColumn CColumn DColumn E
DescriptionBalance at
Beginning
of Period		(1)
Charged to Costs
and Expenses
(2)
Charged to Other
Accounts(a)
Deductions(b)
Balance at End
of Period
Ameren:
Deducted from assets – allowance for doubtful accounts:
2021$50 $9 $— $30 $29 
202017 42 6 15 50 
201918 26 4 31 17 
Ameren Missouri:
Deducted from assets – allowance for doubtful accounts:
2021$16 $5 $— $8 $13 
20207 15 — 6 16 
20197 9 — 9 7 
Ameren Illinois:
Deducted from assets – allowance for doubtful accounts:
2021$34 $4 $— $22 $16 
202010 27 6 9 34 
201911 17 4 22 10 
(a)Amounts associated with the allowance for doubtful accounts relate to the uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.
(b)Uncollectible accounts charged off, less recoveries.
ITEM 16.FORM 10-K SUMMARY
The Ameren Companies elected not to provide a summary of the Form 10-K.
167
Table of Contents
EXHIBIT INDEX
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith: 
Exhibit DesignationRegistrant(s)Nature of ExhibitPreviously Filed as Exhibit to:
Articles of Incorporation/ By-Laws
3.1(i)AmerenAnnex F to Part I of the Registration Statement on Form S-4, File No. 33-64165
3.2(i)Ameren
1998 Form 10-K, Exhibit 3(i),
File No. 1-14756
3.3(i)Ameren
April 21, 2011 Form 8-K, Exhibit 3(i),
File No. 1-14756
3.4(i)Ameren
December 18, 2012 Form 8-K, Exhibit 3.1(i),
File No. 1-14756
3.5(i)Ameren Missouri
1993 Form 10-K, Exhibit 3(i),
File No. 1-2967
3.6(i)Ameren Illinois
2010 Form 10-K, Exhibit 3.4(i),
File No. 1-3672
3.7(ii)Ameren
October 12, 2021 Form 8-K, Exhibit 3.1,
File No. 1-14756
3.8(ii)Ameren Missouri
2020 Form 10-K, Exhibit 3.8(ii), File No. 1-2967
3.9(ii)Ameren Illinois
2020 Form 10-K, Exhibit 3.9(ii), File No. 1-3672
Instruments Defining Rights of Security Holders, Including Indentures
4.1AmerenExhibit 4.5, File No. 333-81774
4.2Ameren
June 30, 2008 Form 10-Q, Exhibit 4.1,
File No. 1-14756
4.3AmerenNovember 24, 2015 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-14756
4.4AmerenSeptember 16, 2019 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756
4.5Ameren    
April 3, 2020 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756
4.6AmerenMarch 5, 2021 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756
4.7AmerenNovember 18, 2021 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756
4.8AmerenJune 26, 2017 Form 8-K, Exhibit 4.1, File No. 1-14756
4.9Ameren
4.10Ameren
Ameren Missouri		Indenture of Mortgage and Deed of Trust, dated June 15, 1937 (Ameren Missouri Mortgage), from Ameren Missouri to The Bank of New York Mellon, as successor trustee, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941Exhibit B-1, File No. 2-4940
4.11Ameren
Ameren Missouri		Exhibit 4.22, File No. 333-222108
4.12
Ameren
Ameren Missouri
Exhibit 4.23, File No. 333-222108
4.13
Ameren
Ameren Missouri
Exhibit 4.24, File No. 333-222108
168
Table of Contents
4.14
Ameren
Ameren Missouri
Exhibit 4.25, File No. 333-222108
4.15
Ameren
Ameren Missouri
1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
4.16
Ameren
Ameren Missouri
2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
4.17
Ameren
Ameren Missouri
August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967
4.18
Ameren
Ameren Missouri
March 11, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.19
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.1,
File No. 1-2967
4.20
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.2,
File No. 1-2967
4.21
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.3,
File No. 1-2967
4.22
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.8,
File No. 1-2967
4.23
Ameren
Ameren Missouri
September 23, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.24
Ameren
Ameren Missouri
January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.25
Ameren
Ameren Missouri
July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.26
Ameren
Ameren Missouri
June 19, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2967
4.27
Ameren
Ameren Missouri
March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967
4.28
Ameren
Ameren Missouri
Exhibit 4.45, File No. 333-182258
4.29
Ameren
Ameren Missouri
September 11, 2012 Form 8-K, Exhibit 4.4,
File No. 1-2967
4.30
Ameren
Ameren Missouri
April 4, 2014 Form 8-K, Exhibit 4.5,
File No. 1-2967
4.31
Ameren
Ameren Missouri
April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967
4.32
Ameren
Ameren Missouri
June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967
4.33
Ameren
Ameren Missouri
April 6, 2018 Form 8-K, Exhibit 4.2, File No. 1-2967
4.34
Ameren
Ameren Missouri
March 6, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967
4.35
Ameren
Ameren Missouri
October 1, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967
4.36
Ameren
Ameren Missouri
March 20, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967
4.37
Ameren
Ameren Missouri
October 9, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967
4.38Ameren
Ameren Missouri		June 22, 2021 Form 8-K, Exhibit 4.2, File No. 1-2967
169
Table of Contents
4.39
Ameren
Ameren Missouri
Loan Agreement, dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri, together with Indenture of Trust dated as of December 1, 1992, between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N.A.1992 Form 10-K, Exhibit 4.38,
File No. 1-2967
4.40
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.10,
File No. 1-2967
4.41
Ameren
Ameren Missouri
September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
4.42
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.11,
File No. 1-2967
4.43
Ameren
Ameren Missouri
September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
4.44
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.12,
File No. 1-2967
4.45
Ameren
Ameren Missouri
September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967
4.46
Ameren
Ameren Missouri
March 31, 2004 Form 10-Q, Exhibit 4.13,
File No. 1-2967
4.47
Ameren
Ameren Missouri
August 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-2967
4.48
Ameren
Ameren Missouri
Exhibit 4.48, File No. 333-182258
4.49
Ameren
Ameren Missouri
March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.50
Ameren
Ameren Missouri
July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.51
Ameren
Ameren Missouri
March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.52
Ameren
Ameren Missouri
September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967
4.53
Ameren
Ameren Missouri
April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.54
Ameren
Ameren Missouri
April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.55Ameren
Ameren Missouri		June 23, 2016 Form 8-K, Exhibits 4.3, and 4.4, File No. 1-2967
4.56
Ameren
Ameren Missouri
June 15, 2017 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.57
Ameren
Ameren Illinois
Exhibit 4.4, File No. 333-59438
4.58
Ameren
Ameren Illinois
June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672
4.59
Ameren
Ameren Illinois
Exhibit 4.17, File No. 333-166095
4.60
Ameren
Ameren Illinois
2010 Form 10-K, Exhibit 4.59, File No. 1-3672
170
Table of Contents
4.61
Ameren
Ameren Illinois
2010 Form 10-K, Exhibit 4.60, File No. 1-3672
4.62
Ameren
Ameren Illinois
2010 Form 10-K, Exhibit 4.62, File No. 1-3672
4.63
Ameren
Ameren Illinois
June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-14756
4.64
Ameren
Ameren Illinois
October 7, 2010 Form 8-K, Exhibit 4.1, File No. 1-3672
4.65
Ameren
Ameren Illinois
September 30, 2011 Form 10-Q, Exhibit 4.1,
File No. 1-3672
4.66
Ameren
Ameren Illinois
September 30, 2019 Form 10-Q, Exhibit 4.2, File No. 1-3672
4.67
Ameren
Ameren Illinois
June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-14756
4.68
Ameren
Ameren Illinois
General Mortgage Indenture and Deed of Trust, dated as of November 1, 1992 between Ameren Illinois (successor in interest to Illinois Power Company) and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Ameren Illinois Mortgage)1992 Form 10-K, Exhibit 4(cc), File No. 1-3004
4.69
Ameren
Ameren Illinois
December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004
4.70
Ameren
Ameren Illinois
October 7, 2010 Form 8-K, Exhibit 4.9, File No. 1-3672
4.71
Ameren
Ameren Illinois
Exhibit 4.78, File No. 333-182258
4.72
Ameren
 Ameren Illinois
August 20, 2012 Form 8-K, Exhibit 4.5, File No. 1-3672
4.73
Ameren
Ameren Illinois
December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672
4.74
Ameren
Ameren Illinois
June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672
4.75
Ameren
Ameren Illinois
December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672
4.76
Ameren
Ameren Illinois
December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672
4.77
Ameren
Ameren Illinois
September 30, 2017 Form 10-Q, Exhibit 4.1, File No. 1-3672
4.78
Ameren
Ameren Illinois
November 28, 2017 Form 8-K, Exhibit 4.2, File No. 1-3672
4.79
Ameren
Ameren Illinois
May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672
4.80
Ameren
Ameren Illinois
November 15, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672
4.81
Ameren
Ameren Illinois
September 30, 2019 Form 10-Q, Exhibit 4.3, File No. 1-3672
4.82Ameren
Ameren Illinois		November 26, 2019 Form 8-K, Exhibit 4.2, File No. 1-3672
4.83Ameren
Ameren Illinois		2019 Form 10-K, Exhibit 4.79, File No. 1-3672
4.84Ameren
Ameren Illinois		November 23, 2020 Form 8-K, Exhibit 4.2, File No. 1-3672
4.85Ameren
Ameren Illinois		June 29, 2021 Form 8-K, Exhibit 4.2, File No. 1-3672
171
Table of Contents
4.86
Ameren
Ameren Illinois
June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-14756
4.87
Ameren
Ameren Illinois
October 7, 2010 Form 8-K, Exhibit 4.5, File No. 1-14756
4.88
Ameren
Ameren Illinois
September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672
4.89
Ameren
Ameren Illinois
Exhibit 4.83, File No. 333-182258
4.90
Ameren
Ameren Illinois
September 30, 2019 Form 10-Q, Exhibit 4.4, File No. 1-3672
4.91
Ameren
Ameren Illinois
August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672
4.92Ameren
Ameren Illinois		December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672
4.93Ameren
Ameren Illinois		June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672
4.94Ameren
Ameren Illinois		December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672
4.95Ameren
Ameren Illinois		December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672
4.96Ameren
Ameren Illinois		December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672
4.97Ameren
Ameren Illinois		September 30, 2019 Form 10-Q, Exhibits 4.5 and 4.6, File No. 1-3672
4.98Ameren
4.99Ameren Missouri
4.100Ameren Illinois
Material Contracts
10.1Ameren CompaniesJune 30, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.2Ameren
Ameren Missouri		December 11, 2019 Form 8-K, Exhibit 10.1, File No. 1-2967
10.3Ameren
Ameren Missouri
10.4Ameren
Ameren Illinois		December 11, 2019 Form 8-K, Exhibit 10.2, File No. 1-3672
10.5Ameren
Ameren Illinois
10.6Ameren
10.7AmerenJune 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756
10.8Ameren2009 Form 10-K, Exhibit 10.15, File No. 1-14756
172
Table of Contents
10.9Ameren2010 Form 10-K, Exhibit 10.15, File No. 1-14756
10.10AmerenOctober 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.11Ameren2010 Form 10-K, Exhibit 10.17, File No. 1-14756
10.12Ameren Companies2017 Form 10-K, Exhibit 10.13, File No. 1-14756
10.13Ameren Companies2018 Form 10-K, Exhibit 10.14, File No. 1-14756
10.14Ameren Companies2019 Form 10-K, Exhibit 10.17, File No. 1-14756
10.15Ameren Companies2020 Form 10-K, Exhibit 10.16, File No. 1-14756
10.16Ameren Companies
10.17Ameren Companies2018 Form 10-K, Exhibit 10.19, File No. 1-14756
10.18Ameren Companies2019 Form 10-K, Exhibit 10.23, File No. 1-14756
10.19Ameren Companies2020 Form 10-K, Exhibit 10.23, File No. 1-14756
10.20Ameren Companies
10.21Ameren Companies2008 Form 10-K, Exhibit 10.37, File No. 1-14756
10.22Ameren CompaniesOctober 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756
10.23Ameren Companies
10.24Ameren Companies2015 Form 10-K, Exhibit 10.24, File No. 1-14756
10.25Ameren Companies2016 Form 10-K, Exhibit 10.24, File No. 1-14756
10.26Ameren Companies2017 Form 10-K, Exhibit 10.24, File No. 1-14756
10.27Ameren Companies2018 Form 10-K, Exhibit 10.27, File No. 1-14756
10.28Ameren Companies2019 Form 10-K, Exhibit 10.32, File No. 1-14756
10.29Ameren Companies2020 Form 10-K, Exhibit 10.33, File No. 1-14756
10.30Ameren Companies
10.31Ameren CompaniesExhibit 99, File No. 333-196515
10.32Ameren Companies2015 Form 10-K, Exhibit 10.31, File No. 1-14756
10.33Ameren Companies2016 Form 10-K, Exhibit 10.31, File No. 1-14756
10.34Ameren CompaniesDecember 13, 2017 Form 8-K, Exhibit 10.1, File No. 1-14756
10.35Ameren CompaniesDecember 13, 2017 Form 8-K, Exhibit 10.2, File No. 1-14756
10.36Ameren Companies2018 Form 10-K, Exhibit 10.34, File No. 1-14756
10.37Ameren Companies2018 Form 10-K, Exhibit 10.35, File No. 1-14756
10.38Ameren Companies2019 Form 10-K, Exhibit 10.41, File No. 1-14756
173
Table of Contents
10.39Ameren Companies2019 Form 10-K, Exhibit 10.42, File No. 1-14756
10.40Ameren Companies2020 Form 10-K, Exhibit 10.44, File No. 1-14756
10.41Ameren Companies2020 Form 10-K, Exhibit 10.45, File No. 1-14756
10.42Ameren Companies
10.43Ameren Companies
10.44Ameren Companies2018 Form 10-K, Exhibit 10.36, File No. 1-14756
10.45Ameren CompaniesJune 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.46Ameren Companies2008 Form 10-K, Exhibit 10.44, File No. 1-14756
10.47Ameren CompaniesFebruary 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756
Subsidiaries of the Registrant
21.1Ameren Companies 
Consent of Experts and Counsel
23.1Ameren 
23.2Ameren Missouri
23.3Ameren Illinois
Power of Attorney
24.1Ameren 
24.2Ameren Missouri 
24.3Ameren Illinois 
Rule 13a-14(a)/15d-14(a) Certifications
31.1Ameren 
31.2Ameren 
31.3Ameren Missouri 
31.4Ameren Missouri 
31.5Ameren Illinois 
31.6Ameren Illinois 
Section 1350 Certifications
32.1Ameren 
32.2Ameren Missouri 
32.3Ameren Illinois 
Additional Exhibits
99.1Ameren Companies2013 Form 10-K, Exhibit 99.1, File No. 1-14756
Interactive Data Files
101.INSAmeren CompaniesInline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document 
101.SCHAmeren CompaniesXBRL Taxonomy Extension Schema Document 
174
Table of Contents
101.CALAmeren CompaniesXBRL Taxonomy Extension Calculation Linkbase Document 
101.LABAmeren CompaniesXBRL Taxonomy Extension Label Linkbase Document 
101.PREAmeren CompaniesXBRL Taxonomy Extension Presentation Linkbase Document 
101.DEFAmeren CompaniesXBRL Taxonomy Extension Definition Document 
104Ameren CompaniesCover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; Ameren Missouri, 1-2967; and Ameren Illinois, 1-3672.
*Compensatory plan or arrangement.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
175
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
AMEREN CORPORATION (registrant)
Date: February 22, 2022By /s/ Martin J. Lyons, Jr.
 Martin J. Lyons, Jr.
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Martin J. Lyons, Jr.President and Chief Executive Officer, and Director (Principal Executive Officer)February 22, 2022
Martin J. Lyons, Jr. 
/s/ Michael L. MoehnExecutive Vice President and Chief Financial Officer
(Principal Financial Officer)		February 22, 2022
Michael L. Moehn 
/s/ Theresa A. ShawSenior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer)February 22, 2022
Theresa A. Shaw
*DirectorFebruary 22, 2022
Warner L. Baxter
*DirectorFebruary 22, 2022
Cynthia J. Brinkley
 
*DirectorFebruary 22, 2022
Catherine S. Brune
 
*DirectorFebruary 22, 2022
J. Edward Coleman
*DirectorFebruary 22, 2022
Ward H. Dickson
 
*DirectorFebruary 22, 2022
Noelle K. Eder
 
*DirectorFebruary 22, 2022
Ellen M. Fitzsimmons
 
*DirectorFebruary 22, 2022
Rafael Flores
*DirectorFebruary 22, 2022
Richard J. Harshman
*DirectorFebruary 22, 2022
Craig S. Ivey
*DirectorFebruary 22, 2022
James C. Johnson
*DirectorFebruary 22, 2022
Steven H. Lipstein
*DirectorFebruary 22, 2022
Leo S. Mackay, Jr.
*By /s/ Michael L. Moehn February 22, 2022
Michael L. Moehn
Attorney-in-Fact
176
Table of Contents
UNION ELECTRIC COMPANY (registrant)
Date: February 22, 2022By/s/ Mark C. Birk
Mark C. Birk
Chairman and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Mark C. BirkChairman and President, and Director
(Principal Executive Officer)		February 22, 2022
Mark C. Birk

/s/ Michael L. Moehn		Executive Vice President and Chief Financial Officer, and Director
(Principal Financial Officer)		February 22, 2022
Michael L. Moehn
/s/ Theresa A. ShawSenior Vice President, Finance, and Chief Accounting Officer
(Principal Accounting Officer)		February 22, 2022
Theresa A. Shaw
*DirectorFebruary 22, 2022
Bhavani Amirthalingam
*DirectorFebruary 22, 2022
Fadi M. Diya
*DirectorFebruary 22, 2022
Chonda J. Nwamu
*By/s/ Michael L. MoehnFebruary 22, 2022
Michael L. Moehn
Attorney-in-Fact
177
Table of Contents
    
AMEREN ILLINOIS COMPANY (registrant)
Date: February 22, 2022By /s/ Richard J. Mark
Richard J. Mark
Chairman and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
 
/s/ Richard J. MarkChairman and President, and Director
(Principal Executive Officer)		February 22, 2022
Richard J. Mark
/s/ Michael L. MoehnExecutive Vice President and Chief Financial Officer, and Director (Principal Financial Officer)February 22, 2022
Michael L. Moehn
/s/ Theresa A. ShawSenior Vice President, Finance, and Chief Accounting Officer
(Principal Accounting Officer)		February 22, 2022
Theresa A. Shaw
*DirectorFebruary 22, 2022
Chonda J. Nwamu
*DirectorFebruary 22, 2022
Patrick E. Smith
*DirectorFebruary 22, 2022
David N. Wakeman
*By /s/ Michael L. MoehnFebruary 22, 2022
Michael L. Moehn
Attorney-in-Fact
178