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, 2023 | ||||
OR
| ☐ | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to | ||||
 |  |  | ||||||
| Commission File Number | Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | IRS Employer Identification No. | ||||||
| 1-14756 | Ameren Corporation | 43-1723446 | ||||||
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
| 1-2967 | Union Electric Company | 43-0559760 | ||||||
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
| 1-3672 | Ameren Illinois Company | 37-0211380 | ||||||
(Illinois Corporation)
10 Richard Mark Way
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 class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
| Common Stock, $0.01 par value per share | AEE | New York Stock Exchange | ||||||
Securities Registered Pursuant to Section 12(g) of the Act:
| Registrant | Title of each class | |||||||
| Union Electric Company | Preferred Stock, cumulative, no par value, stated value $100 per share | |||||||
| Ameren Illinois Company | Preferred Stock, cumulative, $100 par value | |||||||
Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
| Ameren Corporation | Yes | ☒ | No | ☐ | ||||||||||
| Union Electric Company | Yes | ☒ | No | ☐ | ||||||||||
| Ameren Illinois Company | Yes | ☒ | No | ☐ | ||||||||||
Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| Ameren Corporation | Yes | ☐ | No | ☒ | ||||||||||
| Union Electric Company | Yes | ☐ | No | ☒ | ||||||||||
| Ameren Illinois Company | Yes | ☐ | No | ☒ | ||||||||||
Indicate by check mark whether each registrant: (1) has 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) has been subject to such filing requirements for the past 90 days.
| Ameren Corporation | Yes | ☒ | No | ☐ | ||||||||||
| Union Electric Company | Yes | ☒ | No | ☐ | ||||||||||
| Ameren Illinois Company | Yes | ☒ | No | ☐ | ||||||||||
Indicate by check mark 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 Corporation | Yes | ☒ | No | ☐ | ||||||||||
| Union Electric Company | Yes | ☒ | No | ☐ | ||||||||||
| Ameren Illinois Company | Yes | ☒ | No | ☐ | ||||||||||
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Ameren Corporation | Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | ||||||||||||||
| Smaller reporting company | ☐ | Emerging growth company | ☐ | |||||||||||||||||
| Union Electric Company | Large accelerated filer | ☐ | Accelerated filer | ☐ | Non-accelerated filer | ☒ | ||||||||||||||
| Smaller reporting company | ☐ | Emerging growth company | ☐ | |||||||||||||||||
| Ameren Illinois Company | Large 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 | ☐ | |||||||||||||
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
| Ameren Corporation | ☐ | |||||||||||||
| Union Electric Company | ☐ | |||||||||||||
| Ameren Illinois Company | ☐ | |||||||||||||
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
| Ameren Corporation | ☐ | |||||||||||||
| Union Electric Company | ☐ | |||||||||||||
| Ameren Illinois Company | ☐ | |||||||||||||
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
| Ameren Corporation | Yes | ☐ | No | ☒ | ||||||||||
| Union Electric Company | Yes | ☐ | No | ☒ | ||||||||||
| Ameren Illinois Company | Yes | ☐ | No | ☒ | ||||||||||
As of June 30, 2023, 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, 2023) held by nonaffiliates was $21,380,504,079. All of the shares of common stock of the other registrants were held by Ameren Corporation as of June 30, 2023.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2024, were as follows:
| Registrant | Title of each class of common stock | Shares | ||||||
| Ameren Corporation | Common stock, $0.01 par value per share | 266,288,867 | ||||||
| Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation | 102,123,834 | ||||||
| Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation | 25,452,373 | ||||||
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 2024 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
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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,” “targets,” and similar expressions.
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.
2023 IRP – Integrated Resource Plan, a long-term nonbinding plan that Ameren Missouri filed with the MoPSC in September 2023 that includes Ameren Missouri’s preferred plan for meeting customers’ projected long-term energy needs.
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 obligation.
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.
CCN – Certificate of convenience and necessity.
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, an EPA rule that established requirements for the disposal of CCR in landfills and surface impoundments, and the operation and closure of such landfills and surface impoundments.
CDP – A not-for-profit entity that administers a global disclosure system related to environmental matters, among other things.
CEJA – Climate and Equitable Jobs Act, 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. Formerly referred to as the Illinois Energy Transition Legislation or IETL in previous filings.
CO2 – Carbon dioxide.
COLI – Company-owned life insurance.
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.
Deferred payment arrangement – A payment option that allows certain Ameren Missouri and Ameren Illinois retail customers to pay a utility bill balance over an extended period of time, generally up to 12 months.
Dekatherm – A standard unit of energy equivalent to approximately one million Btus.
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.
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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 refunded to customers. Deferred income taxes are revalued when federal or state income tax rates decrease, and the offset to the revaluation of deferred income taxes subject to regulatory ratemaking is recorded to a regulatory 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.
Grid Plan – Multi-year integrated grid plan, a plan required to be filed with the ICC every four years under the CEJA, which outlines how Ameren Illinois expects to invest in electric distribution infrastructure in order to support grid modernization, clean energy, energy efficiency, and the state of Illinois’ renewable energy, equity, climate, electrification, and environmental goals over a five-year period.
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 established electric distribution rates through 2023 and will reconcile related revenue requirements under this process.
Illinois Credit Agreement – Ameren’s and Ameren Illinois’ $1.2 billion senior unsecured credit agreement, which expires in December 2027, 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.
IRA – The Inflation Reduction Act of 2022, federal legislation enacted in August 2022, which includes various provisions, such as expanded production and investment tax credits for clean energy investments, transferability of certain tax credits to an unrelated party for cash, and a corporate alternative minimum tax on certain entities, among other things.
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.
MGP – Manufactured gas plant.
MISO – Midcontinent Independent System Operator, Inc., an RTO.
Missouri Credit Agreement – Ameren’s and Ameren Missouri’s $1.4 billion senior unsecured credit agreement, which expires in December 2027, unless extended.
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.
MoOPC – Missouri Office of Public Counsel.
MoPSC – Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including Ameren Missouri.
MRO – Midwest Reliability Organization, one of the regional electric reliability councils organized for coordinating the planning and operation of the United States’ bulk power supply.
MTM – Mark-to-market.
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MW – Megawatt.
MWh – Megawatthour, one thousand kilowatthours.
MW-day – Megawatt-day, a measure of electric generation equivalent to one MW of power generated over one day.
MYRP – Multi-year rate plan, a four-year electric distribution service rate plan allowed to be filed with the ICC under the CEJA. Under a multi-year rate plan, the ICC will approve base rates for electric distribution service charged to customers for each calendar year of a four-year period. Ameren Illinois will reconcile its actual revenue requirement to the ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap with exclusions for certain costs and riders, and adjustments to the ICC-determined ROE for performance incentives and penalties.
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. Effective February 28, 2022, all off-system sales from the High Prairie Renewable and Atchison Renewable energy centers are excluded as those sales are 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. 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, a United States government agency.
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. The PISA is effective through 2028, unless Ameren Missouri requests and receives MoPSC approval of an extension through 2033.
QIP – Qualifying infrastructure plant, a rate-adjustment mechanism that provided Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure plant investments that were placed in service between regulatory rate reviews, subject to ICC prudence reviews. The QIP expired 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 earn carrying costs at short-term interest rates.
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.
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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 United States’ bulk power supply.
Smart Energy Plan – Ameren Missouri’s plan to upgrade Missouri’s electric grid through at least 2028. Planned 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.
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 Ameren Missouri’s petition to the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance the cost of the planned retirement of the Rush Island Energy Center, Ameren Missouri’s proposed customer energy-efficiency plan under the MEEIA filed with the MoPSC in January 2024, Ameren Illinois’ December 2023 ICC order for the MYRP electric distribution service regulatory rate review that directed Ameren Illinois to file a revised Grid Plan for 2023 through 2027 along with Ameren Illinois’ January 2024 rehearing request of the order and appeal of the order to the Illinois Appellate Court for the Fifth Judicial District, Ameren Illinois’ appeal of the November 2023 ICC natural gas delivery service rate order to the Illinois Appellate Court for the Fifth Judicial District, and the August 2022 United States Court of Appeals for the District of Columbia Circuit ruling that vacated FERC’s MISO ROE-determining orders and remanded the proceedings to the FERC;
•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 services for our customers;
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•the effect and duration of Ameren Illinois’ election to utilize MYRPs for electric distribution service ratemaking effective for rates beginning in 2024, including the effect of the reconciliation cap on the electric distribution revenue requirement;
•the effect of Ameren Illinois’ use of the performance-based formula ratemaking framework for 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 on Ameren Missouri of any customer rate caps or limitations on increasing the electric service revenue requirement pursuant to Ameren Missouri’s election to use the PISA;
•Ameren Missouri’s ability to construct and/or acquire wind, solar, and other renewable energy generation facilities and battery storage, as well as natural gas-fired energy centers, extend the operating license for the Callaway Energy Center, retire fossil fuel-fired 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, a related return, and, in the case of customer energy-efficiency programs, any lost margins in a timely manner, each of which is affected by the ability to obtain all necessary regulatory and project approvals, including CCNs from the MoPSC or any other required approvals for the addition of renewable resources and natural gas-fired energy centers;
•Ameren Missouri’s ability to use or transfer federal production and investment tax credits related to renewable energy projects; 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;
•the outcome of competitive bids related to requests for proposals associated with the MISO’s long-range transmission planning;
•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 obligations that are affected by supply chain disruptions;
•advancements in energy technologies, including carbon capture, utilization, and sequestration, hydrogen fuel for electric production and energy storage, next generation nuclear, and large-scale long-cycle battery energy storage, and the impact of federal and state energy and economic policies with respect to those technologies;
•the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, foreign trade, and energy policies;
•the effects of changes in federal, state, or local tax laws or rates, including the effects of the IRA and the 15% minimum tax on adjusted financial statement income, as well as additional regulations, interpretations, amendments, or technical corrections to, or in connection with the IRA, and challenges to the tax positions taken by the Ameren Companies, if any, as well as resulting effects on customer rates and the recoverability of the minimum tax imposed under the IRA;
•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 cost and availability of fuel, such as low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of natural gas for distribution and purchased power, including capacity, zero emission credits, renewable energy credits, emission allowances; 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 primarily 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 our 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 and data security risks on us, our suppliers, or other entities on the grid, 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;
•acts of sabotage, which have increased in frequency and severity within the utility industry, war, terrorism, or other intentionally disruptive acts;
•business, economic, and capital market conditions, including the impact of such conditions on interest rates, inflation, and investments;
•the impact of inflation or a recession on our customers and the related impact on our results of operations, financial position, and liquidity;
•disruptions of the capital and credit 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, and our ability to access the capital and credit markets on reasonable terms when needed;
•the actions of credit rating agencies and the effects of such actions;
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•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 ability to maintain system reliability during the transition to clean energy generation by Ameren Missouri and the electric utility industry as well as Ameren Missouri’s ability to meet generation capacity obligations;
•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;
•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, CO2, NOx, and 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;
•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;
•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, creditors, 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 and reporting guidance;
•the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
•legal and administrative proceedings;
•pandemics or other significant global health events, and their impacts on our results of operations, financial position, and liquidity; and
•the impacts of the Russian invasion of Ukraine and the Israel-Hamas war, related sanctions imposed by the U.S. and other governments, and any broadening of these or other global conflicts, including potential impacts on the cost and availability of fuel, natural gas, enriched uranium, and other commodities, materials, and services, the inability of our counterparties to perform their obligations, disruptions in the capital and credit markets, and other impacts on business, economic, and geopolitical conditions, including inflation.
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.
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•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.
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:
(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 business experiencing the least amount of regulatory lag. Depending on the
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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 future test years to establish customer rates, and the use of trackers and riders.
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.
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 1, 2024, except as noted:
| Rate Regulator | Effective Rate Order Issued In | Rates Effective | Allowed ROE | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren’s 2023 Operating Revenues(a) | |||||||||||||||||
| Ameren Missouri | |||||||||||||||||||||||
Electric service(b) | MoPSC | June 2023 | July 2023 | (c) | (c) | (c) | 49% | ||||||||||||||||
| Natural gas delivery service | MoPSC | December 2021 | February 2022 | (d) | (d) | $0.3 | 2% | ||||||||||||||||
| Ameren Illinois | |||||||||||||||||||||||
Electric distribution delivery service(e) | ICC | December 2023 | January 2024 | 8.72% | 50.00% | $3.9 | 29% | ||||||||||||||||
Natural gas delivery service(f) | ICC | November 2023 | November 2023 | 9.44% | 50.00% | $2.8 | 12% | ||||||||||||||||
Electric transmission service(g) | FERC | (g) | January 2024 | 10.52% | 54.90% | $3.9 | 5% | ||||||||||||||||
| ATXI | |||||||||||||||||||||||
Electric transmission service(g) | FERC | (g) | January 2024 | 10.52% | 60.16% | $1.5 | 3% | ||||||||||||||||
(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)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.
(c)This rate order did not specify an ROE, capital structure, or rate base.
(d)This rate order did not specify an ROE or a capital structure.
(e)In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027. This rate order was based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ 2022 year-end rate base approved by the 2022 electric distribution service revenue requirement reconciliation adjustment order. The December 2023 ICC order rejected Ameren Illinois’ Grid Plan, which was addressed as part of the MYRP proceeding. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The ICC will be under no deadline to act on the revised Grid Plan when filed. This rate base will remain in effect through 2027, unless the rehearing of the MYRP order or approval of a revised Grid Plan by the ICC results in an update of each year’s revenue requirement. Under an MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC.
(f)This rate order was based on a 2024 future test year.
(g)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-point incentive adder for participation in an RTO, is based on the FERC’s May 2020 order.
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.
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. 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 and represents all or portions of 16 central and southeastern states under authority from the NERC for the purpose of
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implementing and enforcing reliability standards approved by the FERC. Ameren Missouri is also a member of the MRO, which is also one of the six regional entities and represents all or portions of 16 central, southern, and midwestern states, as well as two Canadian provinces, under authority from the NERC. 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.
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 and hazardous substances, 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. Federal and state authorities continually revise these regulations and adopt new regulations, which may impact our planning process and the ultimate implementation of these or other new or revised regulations. Local and state land use requirements can also potentially impact our planning activities.
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 most energy centers of Ameren Missouri, and had a peak demand of 7,836 MWs in 2023. The AMIL balancing authority area includes the load of Ameren Illinois and certain natural gas-fired energy centers of Ameren Missouri, and had a peak demand of 8,859 MWs in 2023. 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 for an indefinite term, subject to the MoPSC’s authority to require future proceedings if an event or circumstance occurs that significantly affects Ameren Missouri’s position in the MISO. Ameren Illinois’ election to participate in the MISO is subject to the ICC’s oversight. In July 2022, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study of continued participation in the MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed its cost-benefit study with the ICC. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study. For additional information regarding the RTO cost-benefit study, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
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SUPPLY OF ELECTRIC POWER
Capacity
Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. In the April 2023 MISO capacity auction, Ameren Missouri’s generation resources exceeded its native load capacity requirements for the June 2023 through May 2024 period. Ameren Illinois purchases capacity from the MISO and through bilateral contracts resulting from IPA procurement events. In 2022, the FERC issued an order approving changes to the annual MISO capacity auction. Historically, the auctions were designed to cover annual peak demand plus a target reserve margin. Beginning with the April 2023 auction for the June 2023 to May 2024 planning year, auctions include four seasonal load forecasts and available capacity levels and are designed to cover each season’s peak demand plus a target reserve margin. The seasonal auction structure was established to help to address variability in resources as the MISO begins to rely more heavily on renewable generation.
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 availability.
Ameren Missouri files a long-term nonbinding integrated resource plan with the MoPSC every three years. The most recent integrated resource plan was filed in September 2023 and includes Ameren Missouri’s preferred plan for meeting customers’ projected long-term energy needs in a manner that maintains system reliability and customer affordability while transitioning to clean energy generation in an environmentally responsible manner. The preferred plan includes, among other things, the following:
•adding an 800-MW natural gas-fired simple-cycle energy center by 2027 and an additional 1,200-MW natural gas-fired combined-cycle energy center by 2033, representing investment opportunities of $0.8 billion and $1.7 billion, respectively;
•adding 2,800 MWs of renewable generation by 2030, which includes the 900 MWs of solar generation projects discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and an additional 1,900 MWs by 2036, representing investment opportunities of $5.3 billion and $4.1 billion, respectively;
•adding 400 MWs of battery storage by 2030 and an additional 400 MWs by 2035, representing investment opportunities of $0.6 billion and $0.7 billion, respectively;
•adding 1,200 MWs of other clean dispatchable generation resources by 2040 and an additional 1,200 MWs by 2043;
•retiring all of Ameren Missouri’s coal-fired energy centers by 2042;
•accelerating the retirement date of the Rush Island coal-fired energy center from 2025 to 2024;
•extending the retirement date of the Sioux coal-fired energy center from 2030 to 2032 to ensure reliability during the transition to clean energy generation, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC;
•retiring 1,800 MWs of Ameren Missouri’s natural gas-fired energy centers by 2040 to comply with Illinois law;
•the continued implementation of customer energy-efficiency and demand response programs; and
•the expectation that Ameren Missouri will seek and receive NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date.
The addition of renewable or natural gas-fired generation facilities is subject to obtaining necessary project approvals, including FERC approval and the issuance of a CCN 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 connection with the accelerated retirement of the Rush Island Energy Center, Ameren Missouri is seeking 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. The next integrated resource plan is expected to be filed in September 2026.
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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 and natural gas-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, natural gas-fired generation, including the potential to switch to hydrogen fuel and/or blend hydrogen fuel with natural gas and install carbon capture technology, 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 required Ameren Missouri to offer solar rebates through December 2023 and currently requires Ameren Missouri to offer net metering to certain customers that install renewable generation at their premises. The difference between the cost of the solar rebates and the amount set in base rates was deferred as a regulatory asset or liability 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 distribution 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 2023, 2022, and 2021, Ameren Illinois procured power on behalf of its customers for 28%, 28%, and 23%, 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 purchased 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 through a cost recovery mechanism. The purchased 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.
Pursuant to the CEJA, Ameren Illinois is required to file a Grid Plan with the ICC every four years. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024 after its initial Grid Plan for the years 2023 to 2027 was rejected by the ICC’s December 2023 order in Ameren Illinois’ MYRP proceeding. For additional information regarding Ameren Illinois’ MYRP proceeding, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. The Grid Plan outlines how Ameren Illinois expects to invest in electric distribution infrastructure in order to support grid modernization, clean energy, energy efficiency, and the state of Illinois’ renewable energy, equity, climate, electrification, and environmental goals. Ameren Illinois’ next Grid Plan is required to be filed by mid-January 2026.
Illinois law requires Ameren Illinois to offer rebates and net metering to certain customers who install renewable generation or paired energy storage systems at their premises. The cost of the customer generation rebate program is deferred as a regulatory asset, which earns a return at the applicable WACC. Customers that elect to receive a generation rebate and are enrolled in net metering are allowed to net their power supply service charges, but not their distribution service charges. Customers that elect to receive energy storage rebates and have not received generation rebates are allowed to net their power supply and 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. As of December 31, 2023, Ameren Missouri’s coal-fired energy centers represented 8% and 16% of Ameren’s and Ameren Missouri’s rate base, respectively. The Callaway Energy Center began operation in 1984 and is licensed to operate until 2044. Ameren Illinois operates a solar generation facility, which is one of two pilot solar projects Ameren Illinois is allowed to invest in under the CEJA. The second solar generation facility is planned be placed in service before the end of 2025. See Item 2 – Properties under Part I of this report for information regarding our energy centers.
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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. Ameren Missouri burned approximately 11.5 million tons of coal in 2023. For information regarding the percentages of Ameren Missouri’s projected required supply of coal and coal transportation that are price-hedged through 2028, see Commodity Price Risk under Part II, Item 7A, of this report.
About 97% 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 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. Delays and 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 requires refueling at 18-month intervals. The last refueling was completed in November 2023. The next refueling is scheduled for the spring of 2025. Ameren Missouri has inventories and supply contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, enrichment, and fabrication requirements at least through the spring 2028 refueling.
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 2023, pending regulatory review by the MoPSC for Ameren Missouri.
Ameren Missouri
In Missouri, utilities are required to purchase or generate electricity equal to at least 15% of native load sales from renewable energy sources, with at least 2% of the requirement derived from solar energy. The requirement is subject to an average 1% annual limit on increases to customer rates over any 10-year period. For renewable generation facilities located in Missouri, 125% of the electricity generated counts towards meeting the requirement. Ameren Missouri expects to satisfy the non-solar requirement in 2024 with its High Prairie Renewable, Atchison Renewable, Keokuk, and Maryland Heights energy centers, a 102-MW power purchase agreement with a wind farm operator, which expires in August 2024, and previously purchased renewable energy credits. 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 amount set by law and required to be collected from customers by Ameren Illinois is capped at $4.58 per MWh. The IPA establishes its long-term renewable resources procurement plans in a filing made every two years. In February 2024, the ICC approved the IPA’s latest long-term renewable resources procurement plan, which established the 2024 and 2025 renewable energy credit procurement targets. Based on IPA procurement events that align with the IPA’s plan, Ameren Illinois has contractual commitments to purchase approximately 1.0 million wind renewable energy credits per year and approximately 3.1 million solar renewable energy credits per year. Ameren Illinois has also entered into contracts, ending in 2032, to purchase approximately 0.6 million wind renewable energy credits per year. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to a reconciliation proceeding, the first of which was initiated in August 2023. Based on amounts collected from customers and renewable energy credit purchases under contract, the August 2023 reconciliation proceeding did not result in refunds to customers.
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Illinois law also required Ameren Illinois to enter into contracts to purchase 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 May 2027. 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 purchase of the credits 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, 2023, smart meters have been installed for 88% of Ameren Missouri’s electric customers. Ameren Illinois has completed its transition to smart meters, which have been installed for nearly all its electric and natural gas 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 and demand response programs through December 2024. Ameren Missouri intends to invest approximately $420 million over the life of the plan, including $76 million in 2024. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn revenues by achieving certain customer energy-efficiency goals. If the target program spending goal is achieved for 2024, the performance incentive would result in revenues of $12 million in 2024. Through 2023, Ameren Missouri has invested approximately $343 million in MEEIA 2019 customer energy-efficiency programs. Additionally, as part of its Smart Energy Plan, Ameren Missouri has invested $336 million in smart meters since 2019.
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
Illinois 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, which is approximately $120 million annually through 2029 and may increase by up to approximately $30 million from 2026 to 2029 depending on the election of certain customers to participate in the programs. Every four years, Ameren Illinois is required to file a four-year electric energy-efficiency plan with the ICC. In June 2022, 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 $476 million and $66 million, respectively, over the four-year period.
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 MYRP framework. Ameren Illinois’ natural gas energy-efficiency program costs are recovered through a rider.
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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, MoGas Pipeline, 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. For information regarding the percentage of Ameren Missouri’s and Ameren Illinois’ projected remaining natural gas supply requirements that are price-hedged through 2028, see Commodity Price Risk under Part II, Item 7A, of this report.
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 in rate-regulated energy infrastructure, enhance regulatory frameworks and advocate for responsible policies, and optimize operating performance to capitalize on opportunities to benefit our customers, communities, shareholders, and the environment 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 competencies of:
•Be Strategic •Continuously Improve •Deliver Results | •Engage Respectfully •Foster Collaboration •Think Customer | ||||
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 mission-driven, values-based culture that enables the sustainable execution of our core strategy.
We design our human capital management practices and policies to reinforce our core values, shape our culture, and drive employee engagement. In doing so, we strive to align our employees to our mission and vision, improve safety, continuously improve operating performance, 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 twice each year to identify areas of strength and opportunities for improvement in our employees’ experience, and take actions aimed at increasing employee engagement. We also offer flexible work arrangements, such as permitting certain employees to work from alternate locations or to make adjustments to an employee’s daily work hours, among other things, complemented by our work to advance the digital enablement of our workforce, and have enhanced our facilities and workforce policies and practices to increase collaboration and productivity.
As a part of our 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.
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We seek to foster diversity, equity, and inclusion across our organization. Our efforts extend to the community through philanthropic contributions and volunteerism, including to support non-profit organizations in leading community-building efforts, providing education and support to our community and company leaders through our diversity leadership summit, providing various training programs, and organizing and promoting opportunities for employee volunteerism. 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, 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 of 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 pipeline.
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 7% in 2023. The majority of employee attrition is attributable to employee retirements, generally allowing for thoughtful workforce and succession planning in advance of these planned transitions. The following table presents our employee count and their average tenure at December 31, 2023, and the attrition rate in 2023:
| Employee Count | Average Tenure (in years) | Attrition Rate | |||||||||||||||||||||
| Ameren | 9,372 | 13 | 7% | ||||||||||||||||||||
| Ameren Missouri | 4,011 | 14 | 8% | ||||||||||||||||||||
| Ameren Illinois | 3,280 | 13 | 7% | ||||||||||||||||||||
| Ameren Services | 2,081 | 10 | 7% | ||||||||||||||||||||
Ameren’s workforce is diverse in many ways. At the officer level, which represented 50 individuals as of December 31, 2023, 26% were female, and 26% were 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, 2023:
| Collective Bargaining Unit | Female(a) | Racially and/or Ethnically Diverse(a) | ||||||||||||||||||||||||
| Ameren | 46% | 24% | 16% | |||||||||||||||||||||||
| Ameren Missouri | 58% | 17% | 14% | |||||||||||||||||||||||
| Ameren Illinois | 54% | 23% | 14% | |||||||||||||||||||||||
| Ameren Services | 10% | 41% | 23% | |||||||||||||||||||||||
(a)Gender, race, and ethnicity were self-reported by our employees.
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The following table presents Ameren’s employees by generation at December 31, 2023:
| Generation Description | Ameren | Ameren Missouri | Ameren Illinois | Ameren Services | ||||||||||
| Baby Boomer (birth years between 1946 and 1964) | 13% | 13% | 13% | 13% | ||||||||||
| Generation X (birth years between 1965 and 1980) | 40% | 40% | 39% | 42% | ||||||||||
| Millennials (birth years between 1981 and 1996) | 41% | 40% | 42% | 39% | ||||||||||
| Generation Z/Post Millennial (birth years after 1997) | 6% | 7% | 6% | 6% | ||||||||||
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. The Ameren Missouri collective bargaining unit contracts expire in 2025 and 2026, and cover 4% and 96% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2026 and 2027, and cover 92% and 8% of represented employees, respectively.
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 support of their overall well-being. In addition to base salary, medical benefits, and retirement benefits, including pension for substantially all employees and 401(k) savings, 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.
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, including the IRA, 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 and those attacks arising from or generated by artificial intelligence, 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;
•acts of sabotage, which have increased in frequency and severity within the utility industry, terrorism, and other intentionally disruptive acts;
•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 due to inadequate resources resulting from the retirement of fossil-fuel-fired and nuclear generation facilities as they are replaced with renewable energy generation sources, market inefficiencies related to prices for purchased power, capacity, and ancillary services, and other factors;
•the need to place new transmission and generation facilities in service, which is dependent upon timely regulatory approvals and the availability of necessary labor and materials, among other things, to maintain grid reliability;
•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 economic conditions;
•distributed generation, energy storage, technological advances, and energy-efficiency or conservation initiatives;
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•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, including ROE incentive adders, 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;
•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, high interest rates, and impacts associated with extended recovery periods from customers;
•maintaining affordability of electric and natural gas utility services for customers;
•the potential for reduced efficiency and productivity due to challenges of 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;
•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;
•pressure from public interest groups regarding limiting the use of natural gas, as well as proposed restrictions on the use of natural gas by state and local authorities;
•certain investors’ concerns about investing in, as well as certain insurers’ concerns about providing coverage to, 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 alleged or actual legal, regulatory or compliance failures, including in connection with lobbying and political activities or liabilities arising out of wildfires or other catastrophic events; 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.
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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, | 2023 | 2022 | 2021 | |||||||||||||||||
| Electric Sales – kilowatthours (in millions): | ||||||||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||
| Residential | 12,839 | 13,915 | 13,366 | |||||||||||||||||
| Commercial | 13,466 | 13,826 | 13,556 | |||||||||||||||||
| Industrial | 3,977 | 4,090 | 4,151 | |||||||||||||||||
| Street lighting and public authority | 71 | 76 | 81 | |||||||||||||||||
| Ameren Missouri retail load subtotal | 30,353 | 31,907 | 31,154 | |||||||||||||||||
| Off-system sales | 4,145 | 7,645 | 7,425 | |||||||||||||||||
| Ameren Missouri total | 34,498 | 39,552 | 38,579 | |||||||||||||||||
Ameren Illinois Electric Distribution(a): | ||||||||||||||||||||
| Residential | 10,774 | 11,708 | 11,620 | |||||||||||||||||
| Commercial | 11,602 | 11,867 | 11,795 | |||||||||||||||||
| Industrial | 10,740 | 10,981 | 11,076 | |||||||||||||||||
| Street lighting and public authority | 385 | 410 | 430 | |||||||||||||||||
| Ameren Illinois Electric Distribution total | 33,501 | 34,966 | 34,921 | |||||||||||||||||
| Eliminate affiliate sales | (30) | (190) | (412) | |||||||||||||||||
| Ameren total | 67,969 | 74,328 | 73,088 | |||||||||||||||||
| Electric Operating Revenues (in millions): | ||||||||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||
| Residential | $ | 1,577 | $ | 1,578 | $ | 1,445 | ||||||||||||||
| Commercial | 1,280 | 1,219 | 1,126 | |||||||||||||||||
| Industrial | 306 | 290 | 280 | |||||||||||||||||
| Other, including street lighting and public authority | 124 | 171 | 170 | |||||||||||||||||
| Ameren Missouri retail load subtotal | $ | 3,287 | $ | 3,258 | $ | 3,021 | ||||||||||||||
| Off-system sales and capacity | 407 | 591 | 191 | |||||||||||||||||
| Ameren Missouri total | $ | 3,694 | $ | 3,849 | $ | 3,212 | ||||||||||||||
| Ameren Illinois Electric Distribution: | ||||||||||||||||||||
| Residential | $ | 1,344 | $ | 1,325 | $ | 933 | ||||||||||||||
| Commercial | 747 | 768 | 545 | |||||||||||||||||
| Industrial | 186 | 199 | 135 | |||||||||||||||||
| Other, including street lighting and public authority | (59) | (36) | 26 | |||||||||||||||||
| Ameren Illinois Electric Distribution total | $ | 2,218 | $ | 2,256 | $ | 1,639 | ||||||||||||||
| Ameren Transmission: | ||||||||||||||||||||
Ameren Illinois Transmission(b) | $ | 480 | $ | 424 | $ | 365 | ||||||||||||||
| ATXI | 198 | 192 | 199 | |||||||||||||||||
| Eliminate affiliate revenues | (1) | (1) | (2) | |||||||||||||||||
| Ameren Transmission total | $ | 677 | $ | 615 | $ | 562 | ||||||||||||||
| Other and intersegment eliminations | (150) | (139) | (116) | |||||||||||||||||
| Ameren total | $ | 6,439 | $ | 6,581 | $ | 5,297 | ||||||||||||||
(a)Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2023, 2022, and 2021, Ameren Illinois procured power on behalf of its customers for 28%, 28%, and 23%, respectively, of its total kilowatthour sales.
(b)Includes $113 million, $104 million, and $66 million in 2023, 2022, and 2021, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution.
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Electric Operating Statistics – Year Ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
Ameren Missouri fuel costs (cents per kilowatthour generated)(a) | 1.29 | ¢ | 1.41 | ¢ | 1.46 | ¢ | ||||||||||||||
| Source of Ameren Missouri energy supply: | ||||||||||||||||||||
| Coal | 54.6 | % | 61.6 | % | 73.0 | % | ||||||||||||||
| Nuclear | 25.6 | 21.6 | 10.5 | |||||||||||||||||
| Hydroelectric | 2.4 | 3.2 | 4.2 | |||||||||||||||||
| Wind | 4.9 | 4.7 | 3.7 | |||||||||||||||||
| Natural gas | 1.1 | 1.1 | 1.0 | |||||||||||||||||
| Methane gas and solar | 0.2 | 0.2 | 0.2 | |||||||||||||||||
| Purchased power – wind | 0.6 | 0.8 | 0.6 | |||||||||||||||||
| Purchased power – other | 10.6 | 6.8 | 6.8 | |||||||||||||||||
| Ameren Missouri total | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||||||||
(a) Ameren Missouri fuel costs exclude $72 million, $(98) million, and $1 million in 2023, 2022, and 2021, respectively, for changes in FAC recoveries.
Natural Gas Operating Statistics – Year Ended December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Natural Gas Sales – dekatherms (in millions): | ||||||||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||
| Residential | 6 | 8 | 7 | |||||||||||||||||
| Commercial | 3 | 4 | 4 | |||||||||||||||||
| Industrial | 1 | 1 | 1 | |||||||||||||||||
| Transport | 9 | 9 | 9 | |||||||||||||||||
| Ameren Missouri total | 19 | 22 | 21 | |||||||||||||||||
| Ameren Illinois Natural Gas: | ||||||||||||||||||||
| Residential | 47 | 59 | 54 | |||||||||||||||||
| Commercial | 14 | 18 | 16 | |||||||||||||||||
| Industrial | 3 | 6 | 4 | |||||||||||||||||
| Transport | 99 | 99 | 100 | |||||||||||||||||
| Ameren Illinois Natural Gas total | 163 | 182 | 174 | |||||||||||||||||
| Ameren total | 182 | 204 | 195 | |||||||||||||||||
| Natural Gas Operating Revenues (in millions): | ||||||||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||
| Residential | $ | 100 | $ | 119 | $ | 79 | ||||||||||||||
| Commercial | 46 | 56 | 34 | |||||||||||||||||
| Industrial | 5 | 7 | 4 | |||||||||||||||||
| Transport and other | 14 | 15 | 24 | |||||||||||||||||
| Ameren Missouri total | $ | 165 | $ | 197 | $ | 141 | ||||||||||||||
| Ameren Illinois Natural Gas: | ||||||||||||||||||||
| Residential | $ | 657 | $ | 846 | $ | 657 | ||||||||||||||
| Commercial | 164 | 221 | 172 | |||||||||||||||||
| Industrial | 14 | 41 | 35 | |||||||||||||||||
| Transport and other | 62 | 72 | 93 | |||||||||||||||||
| Ameren Illinois Natural Gas total | $ | 897 | $ | 1,180 | $ | 957 | ||||||||||||||
| Other and intercompany eliminations | (1) | (1) | (1) | |||||||||||||||||
| Ameren total | $ | 1,061 | $ | 1,376 | $ | 1,097 | ||||||||||||||
Rate Base Statistics – At December 31, | 2023 | 2022 | 2021 | |||||||||||||||||
| Rate Base (in billions): | ||||||||||||||||||||
| Electric transmission and distribution | $ | 17.5 | $ | 15.4 | $ | 13.5 | ||||||||||||||
| Natural gas transmission and distribution | 3.2 | 2.9 | 2.7 | |||||||||||||||||
| Coal generation: | ||||||||||||||||||||
| Labadie Energy Center | 0.9 | 0.9 | 0.9 | |||||||||||||||||
| Sioux Energy Center | 0.6 | 0.7 | 0.7 | |||||||||||||||||
| Rush Island Energy Center (scheduled to be retired in October 2024) | 0.4 | 0.4 | 0.4 | |||||||||||||||||
Meramec Energy Center (retired in December 2022) | — | — | 0.1 | |||||||||||||||||
| Coal generation total | 1.9 | 2.0 | 2.1 | |||||||||||||||||
| Nuclear generation | 1.5 | 1.5 | 1.5 | |||||||||||||||||
| Renewable generation (hydroelectric, wind, solar, methane gas) | 1.4 | 1.5 | 1.5 | |||||||||||||||||
| Natural gas generation | 0.3 | 0.3 | 0.3 | |||||||||||||||||
| Rate base total | $ | 25.8 | $ | 23.6 | $ | 21.6 | ||||||||||||||
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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, Cybersecurity and Digital Technology Committee, Finance Committee, Human Resources Committee, Nominating and Corporate Governance 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, and actions by local jurisdictions that may affect the constructing or siting of facilities. 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 at all, 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, including the impact of inflationary pressures, 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
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are primarily based on historical costs, revenues, and sales volumes. Ameren Illinois’ natural gas rates established in those proceedings are based on estimated future costs, revenues, and sales volumes. Effective for rates beginning in 2024 through at least 2027, Ameren Illinois’ electric distribution rates will be established through an MYRP as discussed in the following risk factor. An MYRP includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap. 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.
Beginning in 2024 through at least 2027, electric distribution rates for Ameren Illinois are established through an MYRP, which are subject to ongoing regulatory and judicial proceedings and associated risks, and are subject to a reconciliation cap. Additionally, Ameren Illinois is subject to certain performance metrics that if not achieved would result in a reduction to the company’s allowed ROE.
The CEJA 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 or establish future rates through a traditional regulatory rate review, among other things. An MYRP establishes rates for a four-year period, and Ameren Illinois has the option to file for an MYRP every four years. Ameren Illinois elected to file an MYRP for rates effective in 2024 through 2027. Under the MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs are excluded from the reconciliation cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and amortization of certain assets. The reconciliation cap also excludes costs recovered outside of base rates through riders. Ameren Illinois’ existing riders remain effective and electric distribution service revenues continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year incorporates Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the resulting revenue requirement does not exceed the 105% reconciliation cap and the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. In addition, the ICC determines the ROE applicable to each year of the four-year period. Economic conditions could result in the annual predetermined ROE becoming inadequate over the four-year period. In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,162 million, $1,210 million, $1,242 million, and $1,255 million, respectively. These revenue requirements were established under an alternative methodology which used Ameren Illinois’ previously approved 2022 year-end rate base since the order rejected the Grid Plan that was filed by Ameren Illinois as a part of the MYRP proceeding. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The 2022 year-end rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement. In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements of $1,214 million, $1,300 million, $1,371 million, and $1,420 million, for 2024, 2025, 2026, and 2027, respectively. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District. Failure to limit capital expenditures and operation and maintenance expenses to amounts
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to which maintain revenue requirements under the reconciliation cap limit would adversely affect Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity.
Ameren Illinois’ electric distribution service business is also subject to performance metrics. Failure to achieve the metrics would result in a reduction in the company’s allowed ROE calculated under the MYRP. In 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points under the MYRP, allocated among seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, the allowed ROE on energy-efficiency investments can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings goals. Any adjustments to the allowed ROE for energy-efficiency investments will depend on annual performance for a historical period relative to energy savings goals.
Ameren Illinois’ QIP expired in December 2023, which will subject Ameren Illinois to increased regulatory lag with respect to certain natural gas infrastructure investments. In addition, reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP are still ongoing.
The QIP expired in December 2023. Previously, it provided Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that were placed in service between regulatory rate reviews. Infrastructure investments under the QIP earned a return at the applicable WACC. As a result of the expiration of the QIP, Ameren Illinois is 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. In addition, reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP from 2020 to 2023 are still ongoing. In October 2023, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow approximately $53 million in natural gas capital investments as improper and imprudent, providing a potential over-recovery of approximately $3 million in 2020. In October 2023, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2020. Ameren Illinois’ 2020 QIP rate recovery request under review by the ICC was within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding. Ameren Illinois cannot predict the ultimate outcome of this regulatory proceeding.
As a result of the election to use the PISA, effective in 2024, Ameren Missouri’s electric service business is subject to a limitation on increasing the annual revenue requirement due to the inclusion of incremental PISA deferrals in the revenue requirement.
Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through December 2028 and an additional extension through December 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things. This law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates, compared to the revenue requirement established in the immediately preceding rate order, due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024. Increased capital expenditures could cause incremental PISA deferrals to exceed the 2.5% limitation, and such amounts exceeding the 2.5% limitation would be excluded from recovery under future revenue requirements. Failure to limit capital investments to an amount which maintains PISA deferrals under the 2.5% limitation could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
We are subject to various environmental and permitting 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, and 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 by 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 energy-related 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, modifications to existing laws, new laws, new or modified permit terms, and enforcement of environmental laws and permits by federal, state, and local authorities.
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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, substations, and third-party sites, such as landfills. Additionally, individuals and non-governmental organizations may seek to enforce environmental laws against us, 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 purported contamination.
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, 2023, Ameren Missouri’s coal-fired energy centers represented 8% and 16% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations under the Clean Air Act 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. Regulations implementing the Clean Water Act govern both intake and discharges of water, as well as evaluation of the ecological and biological impact of those 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, capital expenditures associated with these modifications 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 surface impoundments at Ameren Missouri’s coal-fired energy centers. The individual or combined effects of compliance with 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 projects performed in 2007 and 2010 at the coal-fired Rush Island Energy Center 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. Following an appeal from Ameren Missouri, in August 2021, the United States Court of Appeals for the Eighth Circuit 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 September 2023, the district court granted Ameren Missouri’s request 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. In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri to operate the energy center as directed by the MISO. The United States Department of Justice is seeking an order from the district court providing for additional mitigation relief. Ameren Missouri could be required to implement mitigation relief measures, the costs of which could be material and which Ameren Missouri would not expect to recover. Ameren Missouri is challenging such mitigation claims, noting that the scope of any such potential additional mitigation relief should be limited by the August 2021 court of appeals decision and offset by emission reductions resulting from the accelerated retirement of the Rush Island Energy Center. The MISO designated the energy center as a system support resource in 2022 and concluded that certain reliability mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation through August 2024, and in September 2023, an agreement between Ameren Missouri and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the upgrades expected to be completed in the fall of 2024. Ameren Missouri expects to complete the last of the upgrades by mid-2025. Related to this matter, in November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed that Ameren Missouri’s prior actions that resulted in the adverse ruling discussed above were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If the remaining unrecovered net plant balance for the Rush Island Energy Center and an associated return are not recoverable through base rates or other regulatory mechanisms, Ameren Missouri would recognize an abandonment loss equal to the difference between the remaining net book value of the asset and the present value of the expected future cash flows. As of December 31, 2023, the Rush Island Energy Center had a net plant balance of $530 million included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net”. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling discussed above, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.
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In June 2022, the United States Supreme Court issued its decision in West Virginia v. EPA, clarifying that there are limits on how the EPA may regulate greenhouse gases absent further direction from the United States Congress. The court concluded that the EPA’s proposed rules were designed to shift generation from fossil-fuel-fired power plants to renewable energy facilities, which was improper absent specific congressional authorization. In May 2023, the EPA issued a new proposed rule that would set CO2 emission standards for new and existing fossil-fuel-fired power plants based on the adoption of carbon capture technology, natural gas co-firing, and co-firing hydrogen fuel to reduce emissions. If the proposed rule were adopted, the affected fossil-fuel-fired power plants would be required to comply with the rule through a phased-in approach or retire. Capacity restrictions for coal-fired units could apply as early as 2030. Larger natural gas-fired power plants would be required to co-fire with hydrogen by 2032, with additional requirements by 2038. The EPA expects to issue a final rule in 2024. Legal challenges to the final rule, if adopted as proposed, are expected. Ameren and Ameren Missouri cannot predict the results of any such challenges or potential impacts of any such regulations on their results of operations, financial position, and liquidity until final regulations are adopted and the merits of such legal challenges are determined.
The CEJA established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the CEJA, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service.
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. Also, state and local authorities have proposed restrictions on the use of natural gas, and the ICC has initiated a future of gas proceeding to explore issues involved with decarbonization of the natural gas distribution system in the state of Illinois. Further, federal, state, and local 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 made a 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 EPA has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions from 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.
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Ameren is targeting net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels. Ameren’s goals include both direct emissions from operations (scope 1), as well as electricity usage at Ameren buildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. 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; the ability to maintain system reliability during the transition to clean energy generation; and constructive energy and economic 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 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 regulatory compliance and proceedings, which could result in increasing costs, regulatory penalties, and/or 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 $1.5 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 be issued to customers for previously billed amounts, with interest.
Additionally, pursuant to the CEJA, Illinois utilities are subject to requirements and provisions related to ethical conduct, including submitting an annual ethics and compliance report to the ICC. The law authorizes the ICC to initiate an investigation into how customer funds were used if a violation of the law is determined to have occurred at an Illinois utility, potentially requiring the utility to issue refunds and imposing a penalty of up to $0.5 million per violation.
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 2023 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 $22.8 billion (Ameren Missouri – up to $13.5 billion; Ameren Illinois – up to $7.6 billion; ATXI – up to $1.7 billion) of capital expenditures from 2024 through 2028. 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; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment; escalating costs, including but not limited to changes to tariffs on materials or government actions; 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 connection agreements 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; geopolitical conflict and other events beyond our control, including construction delays due to weather. With respect to the transition of Ameren Missouri’s generation fleet and carbon emission reduction targets outlined in the 2023 IRP, factors also include Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources or natural gas-fired generation, retirement of energy centers, and new or continued customer energy-efficiency
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programs; the ability to enter into agreements for renewable or natural gas-fired generation and acquire or construct that generation at a reasonable cost; the ability to obtain NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date; the ability to qualify for, and use or transfer, federal production or investment tax credits; the cost of wind, solar, and other renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to maintain system reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; 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;
•aging infrastructure that may require significant expenditures to operate and maintain;
•lack of adequate water required for cooling plant operations and to operate hydroelectric energy centers;
•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;
•disruptions to the global supply chain as a result of shortages for labor, materials, or equipment, international trade relations, geopolitical conflict, delivery delays, economic pressures, including increased interest rates and inflation, among other things;
•suppliers and contractors who do not perform as required under their contracts, including those obligations that are affected by supply chain disruptions;
•failure of other operators’ facilities and the effect of that failure on our electric system and customers;
•inability to comply with regulatory requirements or obtain permits, 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, 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, which have increased in frequency and severity within the utility industry, acts of terrorism, civil unrest, pandemic health events, 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 97% 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. As of December 31, 2023, coal inventory at the Labadie Energy Center was below targeted levels and coal inventory at the Sioux Energy Center was at targeted levels. Additional delays or 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,
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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;
•uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway Energy Center or 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 primarily one NRC-licensed supplier of Callaway Energy Center’s assemblies;
•costly and extended outages for scheduled or unscheduled maintenance and refueling;
•uncertainties about the technological and financial aspects of decommissioning nuclear facilities at the end of their licensed lives;
•the ability to continue to attract and maintain qualified labor to operate the Callaway Energy Center;
•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 service businesses involve numerous risks that may result in accidents and increased operating costs.
Inherent in our natural gas distribution businesses, which includes transmission, distribution, and storage facilities, 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 transmission and 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 facilities 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
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began operating in 1984. The age of these energy centers increases the risks of unplanned outages, reduced generation output, and higher maintenance expense. Also, as discussed above, Ameren Missouri expects to retire the Rush Island Energy Center by October 15, 2024. 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. 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 CEJA 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, compounded by high interest rates and inflationary pressures, 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.
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. Under the IRA, a 15% minimum tax on adjusted financial statement income, as defined in the law, is assessed against corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. As Ameren files a consolidated income tax return, it is reliant on its subsidiaries to pay the minimum tax once the threshold is exceeded. The payments related to the minimum tax by Ameren Missouri, Ameren Illinois, and ATXI are expected to be recovered, subject to approval by their respective regulators. 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 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 inflationary pressures related to prices of labor, services, materials and supplies, and other costs. We are uncertain whether these inflationary pressures will continue and at what rate. These inflationary pressures, as well as high interest rates, 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
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frameworks established by our regulators, and/or to maintain affordability of our services for our customers. In addition, these inflationary pressures and high interest rates could adversely affect our customers’ usage of, or payment for, our services. Additionally, volatility in the commodities market could increase collateral postings and prepayments. Also, market volatility could significantly affect the investment performance of Ameren’s COLI. Significant increases in our costs could increase our financing needs and otherwise adversely affect our results of operations, financial position, and liquidity. For additional information on purchased power costs, see Outlook under Part II, Item 7, of this report.
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 $551 million as of December 31, 2023. 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, 2023, its investment performance in 2023, and its pension funding policy, Ameren does not expect to make material contributions in 2024 and 2025, and expects to make aggregate contributions of $120 million in 2026 through 2028. Ameren Missouri and Ameren Illinois estimate that their portion of the future funding requirements will be 40% and 50%, respectively. 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.
GENERAL RISKS
Customers’, investors’, legislators’, regulators’, and creditors’ 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, regulators, and creditors could harm our reputation.
Our results are influenced by the expectations of our customers, investors, legislators, regulators, and creditors. 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 physical or 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 regulator and customer satisfaction.
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 2023 IRP, may affect customers’, investors’, legislators’, regulators’, and creditors’ 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 and credit markets. Customers’, investors’, legislators’, regulators’, and creditors’ 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, regulators, or creditors 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 workforce 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, 2023, approximately 23% of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ total employees were 55 years old or older. We are also party to collective bargaining agreements that collectively represent about 46%, 58%, and 54% of Ameren’s, Ameren Missouri’s and Ameren Illinois’ total employees, respectively. The Ameren Missouri collective bargaining unit contracts expire in 2025 and 2026, and cover 4% and 96% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2026 and 2027, and cover 92% and 8% of represented employees, respectively. Remote working arrangements could increase our data security risks, including loss of data
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related to sensitive customer, employee, financial, and operating system information, through insider or outsider actions. 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 remote working arrangements, could adversely affect our operations.
Our operations are subject to acts of sabotage, 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 physical and cyber attacks, which could disrupt our ability to produce or distribute our energy products. In the industry, there continues to be attacks on energy infrastructure, such as substations and related assets. The threat landscape continues to expand, which may result in more attacks in the future. 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. Physical attacks could include sabotaging, vandalizing, or burglarizing transmission and distribution facilities, which are unmanned, widely dispersed, and often in isolated areas, or the theft of physical data and information. Cyber attacks could include viruses, malicious or destructive code, phishing attacks, denial of service attacks, supply chain attacks, ransomware and other extortion-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, including those attacks arising from or generated by artificial intelligence, among various other security breaches. A security breach of 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, availability of our services could be impacted, 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 physical or 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.
Our businesses are dependent on our ability to access the capital and credit 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. General economic factors beyond our control 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. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. 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.
ITEM 1C.CYBERSECURITY
The Ameren Companies have identified cybersecurity as an enterprise risk, which is managed through Ameren's integrated enterprise risk management program. The program is designed to continuously assess risk and evaluate the likelihood and probability of impact in order to determine the appropriate risk tolerance and risk management strategies that inform our cybersecurity policies, investments, practices, controls, and countermeasures. The program is a comprehensive, consistently applied management framework that is designed to ensure all forms of material risk and opportunity are identified, reported and managed in an effective manner overseen by the risk management steering
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committee. The risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight, oversees Ameren's enterprise risk management processes, which include the identification, assessment, mitigation, and monitoring of risks including strategic, operational, and cybersecurity risks.
Ameren's board of directors maintains a standing committee, the Cybersecurity and Digital Technology Committee, that is dedicated to the oversight of Ameren's cybersecurity and digital technology risks. The committee has primary responsibility for oversight of cybersecurity and digital technology risk management, including the programs, policies, practices, controls and safeguards for digital technology, information security, prevention and detection of cybersecurity incidents and information or data breaches, and cybersecurity and digital technology matters as they relate to crisis preparedness, incident response plans, and disaster recovery and business continuity capabilities. The committee receives regular updates from the Chief Customer and Technology Officer, the Chief Information Officer, the Chief Information Security Officer, and other members of senior management regarding Ameren’s cybersecurity program and key initiatives. The Cybersecurity and Digital Technology Committee regularly reports on its activities to Ameren’s board of directors, including reviewing and advising Ameren’s board of directors of any developments it believes should be considered.
Ameren's cybersecurity program and team are led by the Chief Information Security Officer, who possesses 25 years of critical infrastructure experience both managing and protecting information systems in concert with extensive cybersecurity operations and leadership roles. The Chief Information Security Officer regularly engages with senior-level Ameren officers, reports to the risk management steering committee, and has recurring meetings with the Cybersecurity and Digital Technology Committee as part of ongoing risk management and oversight of the cybersecurity program. Ameren’s board of directors is also regularly updated on its cybersecurity program. In addition, the board of directors participate in periodic cybersecurity drills to prepare for potential crisis scenarios.
To manage against existing conduct and new cybersecurity threats, we maintain enterprise-wide cybersecurity, crisis management, and information security policies and regular training and tests that reinforce the acceptable use of Ameren's information assets, protection of customer and employee data, and the role each employee plays in protecting Ameren against cybersecurity threats. Incident response plans and procedures are tested through recurring companywide cybersecurity exercises to promote readiness across the organization. The procedures are also designed to escalate incidents to appropriate members of management to guide the detection, response, and recovery from a material cybersecurity incident. To address cybersecurity threats, cybersecurity intelligence, as well as responding to cyber-related incidents, we work closely with law enforcement, cybersecurity consulting firms, and industry associations to enhance information sharing and guard against cybersecurity attacks.
We measure our cybersecurity effectiveness through formal cybersecurity scorecards and metrics reported to senior-level Ameren officers, the risk management steering committee, and the Cybersecurity and Digital Technology Committee. These metrics include but are not limited to measures around the effectiveness of our cybersecurity controls, our ability to manage cybersecurity events and incidents, cybersecurity incident response exercises, and results of our recurring internal assessments, external assessments, and audits that Ameren regularly undergoes. Ameren regularly engages external cybersecurity experts to assist with evaluating our cybersecurity program. These engagements provide insights into control performance, prioritized recommendations for enhancements to our cybersecurity strategy, and an overview of the cybersecurity threat landscape that collectively inform our investments and technical controls to protect Ameren's most critical assets. The results of these engagements are reviewed with senior-level Ameren officers and the Cybersecurity and Digital Technology Committee.
Ameren also deploys a third-party cybersecurity risk management program, which extends the governance elements described above to our third-party providers and suppliers. The supply chain and third-party risks introduced to Ameren are evaluated prior to the commencement of any new engagement or relationship, monitored closely throughout the lifecycle of the supplier and managed through privacy and cybersecurity provisions within the respective commercial contracts. Procedures have been established to address supplier incidents as well as supplier off-boarding at the expiration of the relationship.
We are not aware of any cybersecurity events that have materially affected or are reasonably likely to materially affect Ameren, including our business strategy, results of operations, financial position, or liquidity.
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.
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The following table shows the anticipated capability of our energy centers at the time of the expected 2024 peak summer electrical demand for all energy centers owned as of December 31, 2023:
| Primary Fuel Source | Energy Center | Location | Net Kilowatt Capability(a) | ||||||||
| Ameren Missouri: | |||||||||||
| Coal | Labadie(b) | Franklin County, Missouri | 2,372,000 | ||||||||
Rush Island(c) | Jefferson County, Missouri | 1,178,000 | |||||||||
Sioux(d) | St. Charles County, Missouri | 972,000 | |||||||||
| Total coal | 4,522,000 | ||||||||||
| Nuclear | Callaway(e) | Callaway County, Missouri | 1,194,000 | ||||||||
| Hydroelectric | Osage(e) | Lakeside, Missouri | 235,000 | ||||||||
| Keokuk | Keokuk, Iowa | 148,000 | |||||||||
| Total hydroelectric | 383,000 | ||||||||||
| Pumped-storage | Taum Sauk(e) | Reynolds County, Missouri | 440,000 | ||||||||
| Wind | High Prairie Renewable | Adair and Schuyler Counties, Missouri | 400,000 | ||||||||
| Atchison Renewable | Atchison County, Missouri | 298,800 | |||||||||
| Total wind | 698,800 | ||||||||||
| Natural gas (CTs) | Audrain | Audrain County, Missouri | 608,000 | ||||||||
Venice(f) | Venice, Illinois | 487,000 | |||||||||
Goose Creek(f) | Piatt County, Illinois | 438,000 | |||||||||
Pinckneyville(f) | Pinckneyville, Illinois | 316,000 | |||||||||
Raccoon Creek(f) | Clay County, Illinois | 304,000 | |||||||||
Kinmundy(f) | Kinmundy, Illinois | 210,000 | |||||||||
| Peno Creek | Bowling Green, Missouri | 172,000 | |||||||||
| Total natural gas | 2,535,000 | ||||||||||
| Oil (CTs) | Fairgrounds(g) | Jefferson City, Missouri | 55,000 | ||||||||
Mexico(g) | Mexico, Missouri | 54,000 | |||||||||
Moberly(g) | Moberly, Missouri | 54,000 | |||||||||
Moreau(g) | Jefferson City, Missouri | 54,000 | |||||||||
| Total oil | 217,000 | ||||||||||
| Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 9,000 | ||||||||
| Solar | Montgomery County | Montgomery County, Missouri | 5,700 | ||||||||
| O’Fallon | O’Fallon, Missouri | 4,500 | |||||||||
| BJC | St. Louis, Missouri | 1,600 | |||||||||
| Cape Girardeau | Cape Girardeau, Missouri | 1,200 | |||||||||
| Lambert | St. Louis County, Missouri | 900 | |||||||||
Other Solar(h) | Various | 1,400 | |||||||||
| Total solar | 15,300 | ||||||||||
| Total Ameren Missouri | 10,014,100 | ||||||||||
| Ameren Illinois: | |||||||||||
| Solar | East St. Louis | East St. Louis, Illinois | 2,500 | ||||||||
| Total Ameren | 10,016,600 | ||||||||||
(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 is scheduled to retire by October 15, 2024 per the remedy order of the United States District Court for the Eastern District of Missouri. For additional information, see NSR and Clean Air Act Litigation in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
(d)As noted in the 2023 IRP, Ameren Missouri plans to extend the retirement date of the Sioux Energy Center from 2030 to 2032, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC.
(e)The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively.
(f)The Venice Energy Center is scheduled to retire by the end of 2029 and the Goose Creek, Pinckneyville, Raccoon Creek, and Kinmundy energy centers are scheduled to retire by the end of 2039 as noted in the 2023 IRP. See Illinois Emissions Standards in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
(g)The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to be retired by the end of 2029 as noted in the 2023 IRP.
(h)Includes five solar energy centers that each have a nameplate capacity of 500 kilowatts or less.
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The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2023:
| Ameren Missouri | Ameren Illinois | ||||||||||
Circuit miles of electric transmission lines(a) | 3,140 | 4,761 | |||||||||
| Circuit miles of electric distribution lines | 33,927 | 45,984 | |||||||||
| Percentage of circuit miles of electric distribution lines underground | 24 | % | 16 | % | |||||||
| Miles of natural gas transmission and distribution mains | 3,532 | 18,713 | |||||||||
| Underground natural gas storage fields | — | 12 | |||||||||
| Total working capacity of underground natural gas storage fields in billion cubic feet | — | 24 | |||||||||
(a)ATXI owns 561 circuit miles of electric 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 as of December 31, 2023 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 and Atchison Renewable energy centers; Ameren Missouri’s BJC, Cape Girardeau, Lambert, and Maryland Heights 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 respective mortgage bonds.
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.
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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, 2023, all their positions and offices held with the Ameren Companies as of February 29, 2024, and their tenures as officers, and their titles for at least the last five years.
AMEREN CORPORATION:
| Name | Age | Positions | Period | ||||||||
| Martin J. Lyons, Jr. | 57 | Chairman, President, and Chief Executive Officer; Ameren | January 2022(a) – Present | ||||||||
| Chairman and President; Ameren Missouri | December 2019 – January 2022 | ||||||||||
| Chairman and President; Ameren Services | March 2016 – December 2019 | ||||||||||
| Executive Vice President and Chief Financial Officer; Ameren | January 2013 – December 2019 | ||||||||||
| Michael L. Moehn | 54 | Senior Executive Vice President and Chief Financial Officer; Ameren | March 2023 – Present | ||||||||
| Chairman and President; Ameren Services | December 2019 – Present | ||||||||||
| Executive Vice President and Chief Financial Officer; Ameren | December 2019 – February 2023 | ||||||||||
| Chairman and President; Ameren Missouri | April 2014 – December 2019 | ||||||||||
| Chonda J. Nwamu | 52 | Executive Vice President, General Counsel, and Secretary; Ameren | March 2023 – Present | ||||||||
| Senior Vice President, General Counsel, and Secretary; Ameren | August 2019 – February 2023 | ||||||||||
| Senior Vice President and Deputy General Counsel; Ameren Services | January 2019 – August 2019 | ||||||||||
| Theresa A. Shaw | 51 | Senior Vice President, Finance, and Chief Accounting Officer; Ameren | August 2021 – Present | ||||||||
| Senior Vice President, Regulatory Affairs and Financial Services; Ameren Illinois | September 2019 – August 2021 | ||||||||||
| Vice President, Regulatory Affairs and Financial Services; Ameren Illinois | July 2018 – August 2019 | ||||||||||
(a)Elected President and Chief Executive Officer of Ameren in January 2022, and Chairman of Ameren in November 2023.
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SUBSIDIARIES:
| Name | Age | Positions | Period | ||||||||
| Bhavani Amirthalingam | 48 | Executive Vice President and Chief Customer and Technology Officer; Ameren Services | March 2023 – Present | ||||||||
| Senior Vice President and Chief Digital Information Officer; Ameren Services | March 2018 – February 2023 | ||||||||||
| Mark C. Birk | 59 | Chairman and President; Ameren Missouri | January 2022 – Present | ||||||||
| Senior Vice President, Customer and Power Operations; Ameren Missouri | October 2017 – January 2022 | ||||||||||
| Fadi M. Diya | 61 | Senior Vice President and Chief Nuclear Officer; Ameren Missouri | January 2014 – Present | ||||||||
| Mark C. Lindgren | 56 | Executive Vice President, Corporate Communications, and Chief Human Resources Officer; Ameren Services | March 2023 – Present | ||||||||
| Senior Vice President, Corporate Communications, and Chief Human Resources Officer; Ameren Services | September 2015 – February 2023 | ||||||||||
| Gwendolyn G. Mizell | 62 | Senior Vice President and Chief Sustainability, Diversity, & Philanthropy Officer; Ameren Services | March 2023 – Present | ||||||||
| Vice President, Chief Sustainability, Diversity, & Philanthropy Officer; Ameren Services | March 2022 – February 2023 | ||||||||||
| Vice President, Innovation, and Chief Sustainability Officer; Ameren Services | January 2021 – March 2022 | ||||||||||
| Vice President, Sustainability and Electrification; Ameren Services | June 2019 – January 2021 | ||||||||||
| Senior Director, Corporate Social Responsibility; Ameren Services | March 2018 – June 2019 | ||||||||||
| Shawn E. Schukar | 62 | Chairman and President; ATXI | May 2017 – Present | ||||||||
| Leonard P. Singh | 54 | Chairman and President; Ameren Illinois | August 2022(a) – Present | ||||||||
(a)Leonard P. Singh served as Senior Vice President of Consolidated Edison Company of New York from December 2020 to June 2022 and as Vice President, Manhattan Electric Operations of Consolidated Edison Company of New York from June 2015 to December 2020.
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 arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor 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 officer or any director 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.
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PART II
ITEM 5.MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 35,157 on January 31, 2024. 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, 2023, to December 31, 2023.
Performance Graph
The following graph shows Ameren’s cumulative TSR during the five years ended December 31, 2023. 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, 2018, 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
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| December 31, | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | |||||||||||||||||||||||||||||
| Ameren (AEE) | $ | 100.00 | $ | 120.82 | $ | 125.98 | $ | 147.51 | $ | 151.26 | $ | 126.94 | |||||||||||||||||||||||
| S&P 500 Index | 100.00 | 131.47 | 155.65 | 200.29 | 163.98 | 207.04 | |||||||||||||||||||||||||||||
| S&P 500 Utility Index | 100.00 | 126.35 | 127.01 | 149.46 | 151.79 | 141.05 | |||||||||||||||||||||||||||||
| Philadelphia Utility Index | 100.00 | 126.82 | 130.27 | 154.03 | 155.03 | 140.83 | |||||||||||||||||||||||||||||
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 and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri’s subsidiaries were created for the ownership of renewable generation projects. Ameren Illinois has no subsidiaries. All tabular 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, 2021, including comparisons with the year ended December 31, 2022, is included in Item 7 of our Form 10-K for the year ended December 31, 2022.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per diluted share.
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OVERVIEW
Our core strategy is driven by the following three pillars, which allow us to capitalize on opportunities to benefit our customers, communities, shareholders, and the environment:
| Investing in rate-regulated energy infrastructure | Enhancing regulatory frameworks and advocating for responsible policies | Optimizing operating performance | ||||||||||||||||||
| To capitalize on opportunities to benefit our customers, communities, shareholders, and the environment | ||||||||||||||||||||
| We invest in rate-regulated energy infrastructure and seek to earn competitive returns on our investments. 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 and deliver 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. | 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 enhancing our regulatory frameworks is important to drive investment in our business segments, earn competitive returns on those investments, and realize timely recovery of our costs with the benefits accruing to both customers and shareholders. | Utilizing a continuous improvement mindset, we seek to optimize operating performance for the benefit of our customers. 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. 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. | ||||||||||||||||||
Rate Base ($ in billions)(a) | Regulatory Frameworks(c) | Improved Reliability(f) | ||||||||||||||||||
 | Segment | Regulatory Framework |  | |||||||||||||||||
| Ameren Transmission | Formula ratemaking Allowed ROE of 10.52% | |||||||||||||||||||
| Ameren Illinois Electric Distribution | Future test year ratemaking under an MYRP(d) Allowed ROE of 8.72%(e) | |||||||||||||||||||
| Ameren Illinois Natural Gas | Future test year ratemaking and PGA and VBA Allowed ROE of 9.44% | |||||||||||||||||||
| Ameren Missouri | Historical test year ratemaking and PISA, RESRAM, FAC, MEEIA, PGA Allowed ROE is not specified | |||||||||||||||||||
(a)Reflects year-end rate base except for Ameren Transmission, which is average rate base. Ameren Illinois Electric Distribution excludes electric energy-efficiency rate base. (b)Compound annual growth rate. (c)As of January 2024. (d)In January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order in its MYRP proceeding. For more information on the MYRP proceeding, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. (e)Ameren Illinois’ formula ratemaking framework related to energy-efficiency investments uses an allowed ROE of the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points, subject to performance standards discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. (f)As measured by Ameren Missouri’s and Ameren Illinois’ System Average Interruption Frequency Index. | ||||||||||||||||||||
Key announcements, updates, and regulatory outcomes
In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The approved revenue requirement was based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to 2030. The order did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard compliance costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker. It also includes a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023.
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In June 2023, Ameren Missouri filed for CCNs with the MoPSC for four solar generation facilities, including the Split Rail Solar Project (300-MW facility, build-transfer agreement), the Cass County Solar Project (150-MW facility, development-transfer agreement), the Vandalia Solar Project (50-MW facility, self-build), and the Bowling Green Solar Project (50-MW facility, self-build). In February 2024, Ameren Missouri, the MoPSC staff, and the MoOPC filed a nonunanimous stipulation and agreement requesting the MoPSC approve Ameren Missouri’s requests for CCNs for the Split Rail, Vandalia, and Bowling Green solar projects. The stipulation and agreement also requests MoPSC approval of the CCN request for the Cass County Solar Project conditioned upon the facility supporting the Renewable Solutions Program and full subscription of the portion of the program supported by this facility, subject to certain other terms and conditions. The remaining intervenors did not object to the agreement. Ameren Missouri expects a decision by the MoPSC in March 2024. Each project is expected to support Ameren Missouri’s transition to renewable generation and, in addition, the Cass County Solar Project is expected to support Ameren Missouri’s Renewable Solutions Program. In February and April 2023, the MoPSC issued orders approving requested CCNs for the Huck Finn and Boomtown solar projects, respectively.
In August 2023, the MoPSC issued an order approving a nonunanimous stipulation and agreement to extend Ameren Missouri’s MEEIA 2019 program for an additional year through 2024. For 2024, the order approved the establishment of a portfolio of customer energy-efficiency programs and performance incentives that will provide Ameren Missouri an opportunity to earn revenues, including $12 million of performance incentive revenues if Ameren Missouri achieves certain program spending goals. In 2024, Ameren Missouri expects to invest $76 million in energy-efficiency programs. In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA for 2025 through 2027. The proposed plan includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.
In November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.
In February 2024, 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 2024. 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 $12.4 billion over the five-year period from 2024 through 2028, with expenditures largely recoverable under the PISA. Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.
In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding. Rate changes consistent with the order became effective in January 2024. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027, using the 2022 year-end rate base approved by the ICC in its 2022 electric distribution service revenue requirement reconciliation adjustment order discussed below. This rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement.
In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include
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a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements and annual rate base amounts to reflect a base level of investments to maintain grid reliability for 2024 through 2027. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District.
The following table presents the approved revenue requirements, ROE, capital structure common equity percentage, and annual rate base in the ICC’s December 2023 order, as well as the proposed revenue requirements and annual rate base amounts in Ameren Illinois’ February 2024 rehearing request filing:
| Year | Revenue Requirement (in millions) | ROE | Capital Structure Common Equity Percentage | Annual Rate Base (in billions) | ||||||||||
| ICC’s December 2023 MYRP Order: | ||||||||||||||
| 2024 | $1,162 | 8.72% | 50% | $3.9 | ||||||||||
| 2025 | $1,210 | 8.72% | 50% | $3.9 | ||||||||||
| 2026 | $1,242 | 8.72% | 50% | $3.9 | ||||||||||
| 2027 | $1,255 | 8.72% | 50% | $3.9 | ||||||||||
| Ameren Illinois’ February 2024 Rehearing Request Filing: | ||||||||||||||
| 2024 | $1,214 | (a) | 50% | $4.2 | ||||||||||
| 2025 | $1,300 | (a) | 50% | $4.5 | ||||||||||
| 2026 | $1,371 | (a) | 50% | $4.7 | ||||||||||
| 2027 | $1,420 | (a) | 50% | $4.9 | ||||||||||
(a)The ROE is under appeal as discussed above.
The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase.
In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $110 million, which reflected Ameren Illinois’ actual 2022 recoverable costs, year-end rate base of $3.9 billion, and a capital structure composed of 50% common equity. The approved reconciliation adjustment will be collected from customers in 2024. In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base. The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.
In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million based on a 9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of approximately $2.85 billion. The order reflected a reduction of approximately $93 million of planned distribution and transmission capital investments included in Ameren Illinois’ requested revenue increase, which used a 2024 future test year. The new rates became effective on November 28, 2023. In December 2023, Ameren Illinois filed a request for rehearing of the ICC's November 2023 order. The filing requested the ICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request. Subsequently, in January 2024, Ameren Illinois filed an appeal of the November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal.
In November 2023, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $100 million beginning in January 2024, which represents an increase of $24 million from 2023 rates. The order was based on a projected 2024 year-end rate base of $394 million.
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In 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 July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade. In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects. In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion. The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024. In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed above that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025.
In February 2023, Ameren’s board of directors increased the quarterly common stock dividend to 63 cents per share, resulting in an annualized equivalent dividend rate of $2.52 per share. In February 2024, Ameren’s board of directors increased the quarterly common stock dividend to 67 cents per share, resulting in an annualized equivalent dividend rate of $2.68 per share.
For further information on the matters discussed above, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and the Outlook section below.
Earnings
Net income attributable to Ameren common shareholders was $1,152 million, or $4.38 per diluted share, for 2023, and $1,074 million, or $4.14 per diluted share, for 2022. Net income was favorably affected in 2023, compared with 2022, by increased infrastructure investments across all business segments and a higher recognized ROE at Ameren Illinois Electric Distribution as well as increased base rate revenues at Ameren Missouri pursuant to the June 2023 MoPSC electric rate order. Earnings were also favorably affected by decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase in the cash surrender value of COLI, at Ameren Missouri and Ameren Illinois Natural Gas. Net income was unfavorably affected in 2023, compared with 2022, by decreased retail sales at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to milder winter and summer temperatures. In addition, lower retail sales volumes, excluding the estimated effects of weather, decreased net income at Ameren Missouri in 2023, compared with 2022. Earnings in 2023, compared to 2022, were also unfavorably affected by increased financing costs at Ameren (parent), Ameren Missouri, and Ameren Illinois Natural Gas, primarily due to higher interest rates on increased levels of short-term borrowings at Ameren (parent), and higher long-term debt balances and higher interest rates on short-term borrowings and long-term debt, partially offset by higher levels of allowance for funds used during construction, at Ameren Missouri and Ameren Illinois Natural Gas.
Liquidity
At December 31, 2023, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $2.1 billion.
Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. As of December 31, 2023, Ameren had approximately $770 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2023. For information regarding long-term debt issuances and maturities, common stock issuances, and outstanding forward sale agreements entered into under the ATM program through the date of this report, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.
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Ameren remains focused on strategic capital allocation. The following chart presents 2023 capital expenditures by segment and the midpoint of projected cumulative capital expenditures for 2024 through 2028 by segment:
2023 Capital Expenditures by Segment (Total Ameren – $3.6 billion) (in billions) | Midpoint of 2024 – 2028 Projected Capital Expenditures by Segment (Total Ameren – $21.9 billion) (in billions) | |||||||
Ameren Missouri(a) | Ameren Illinois Natural Gas | |||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Transmission | |||||||||||||||||||
For 2024 through 2028, Ameren’s cumulative capital expenditures are projected to range from $21.0 billion to $22.8 billion. The following table presents the range of projected spending by segment:
| Range (in billions) | ||||||||||||||
Ameren Missouri(a) | $ | 12.5 | – | $ | 13.5 | |||||||||
Ameren Illinois Electric Distribution(b) | 2.8 | – | 3.1 | |||||||||||
Ameren Illinois Natural Gas(b) | 1.8 | – | 1.9 | |||||||||||
| Ameren Transmission | 3.9 | – | 4.3 | |||||||||||
Ameren(a)(b) | $ | 21.0 | – | $ | 22.8 | |||||||||
(a)Amounts include $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments, which includes $0.9 billion related to coal-fired generation, through 2028, consistent with Ameren Missouri’s 2023 IRP.
(b)Amounts include investments necessary to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained. Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Economic conditions, 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 and by weather conditions, such as storms, 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, our pension and postretirement benefits costs, the cash surrender value of COLI, and the asset value of Ameren Missouri’s nuclear decommissioning trust fund. Almost all of Ameren’s 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.
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We are observing inflationary pressures on the prices of labor, services, materials, and supplies, as well as high interest rates. 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, formula ratemaking, and future test years, as applicable, mitigates our exposure.
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, 2023 and 2022:
| 2023 | 2022 | ||||||||||
| Net income attributable to Ameren common shareholders | $ | 1,152 | $ | 1,074 | |||||||
| Earnings per common share – diluted | 4.38 | 4.14 | |||||||||
Net income attributable to Ameren common shareholders in 2023 increased $78 million, or $0.24 per diluted share, from 2022. The increase was due to net income increases of $56 million, $33 million, and $11 million at Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively. The increases in net income were partially offset by a net income decrease of $17 million at Ameren Missouri and an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent), of $5 million.
Earnings per share in 2023, compared with 2022, were favorably affected by:
•increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE due to a higher annual average of the monthly yields of the 30-year United States Treasury bonds at Ameren Illinois Electric Distribution, which increased revenues at these segments (25 cents per share);
•increased base rate revenues at Ameren Missouri effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, partially offset by the amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a lower base level of expenses included in trackers, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (12 cents per share);
•decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase in the cash surrender value of COLI, primarily at Ameren Missouri and Ameren Illinois Natural Gas (11 cents per share);
•decreased income tax expense not subject to formula rates or riders due, in part, to decreased income tax expense recognized at Ameren (parent) because of changes in the state income taxes apportioned to Missouri and Illinois, reflecting changes in revenues, as well as the effect of favorable market returns on COLI, compared with unfavorable returns in the year-ago period (6 cents per share);
•increased base rate revenues at Ameren Missouri for the inclusion of previously deferred PISA and RESRAM interest charges pursuant to the December 2021 and June 2023 MoPSC electric rate orders effective February 28, 2022, and July 9, 2023, respectively, partially offset by increased interest charges resulting from lower deferrals related to infrastructure investments associated with the PISA and RESRAM (6 cents per share);
•decreased taxes other than income taxes, primarily at Ameren Missouri, largely resulting from employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act in 2023 (3 cents per share);
•increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP (3 cents per share);
•increased other income, net, largely due to increased non-service cost components of net periodic benefit income not subject to formula rates or trackers (3 cents per share); and
•recovery of previously incurred expenses at Ameren Illinois Electric Distribution (2 cents per share).
Earnings per share in 2023, compared with 2022, were unfavorably affected by:
•decreased retail sales at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to milder winter and summer temperatures as well as lower sales volumes, excluding the estimated effects of weather, in 2023 (estimated at 25 cents per share);
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•increased financing costs at Ameren (parent), Ameren Missouri, and Ameren Illinois Natural Gas, primarily due to higher interest rates on increased levels of short-term borrowings at Ameren (parent), and higher long-term debt balances and higher interest rates on short-term borrowings and long-term debt, partially offset by higher levels of allowance for funds used during construction, at Ameren Missouri and Ameren Illinois Natural Gas (13 cents per share);
•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 (7 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 (4 cents per share); and
•lower MEEIA 2019 performance incentives recognized at Ameren Missouri (3 cents per share).
The cents per share variances above are presented on the weighted-average basic shares outstanding in 2022 and do not reflect the impact of dilution on earnings per share, unless otherwise noted. The amounts above other than variances related to income taxes have been presented net of income taxes using Ameren’s 2023 blended federal and state 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 Expenses, Taxes Other Than Income Taxes, Other Income, Net, Interest Charges, and Income Taxes, see the major headings below.
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Below is Ameren’s table of income statement components by segment for the years ended December 31, 2023 and 2022:
| 2023 | Ameren Missouri | Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Transmission | Other / Intersegment Eliminations | Ameren | |||||||||||||||||||||||||||||
| Electric revenues | $ | 3,694 | $ | 2,218 | $ | — | $ | 677 | $ | (150) | $ | 6,439 | |||||||||||||||||||||||
| Fuel | (514) | — | — | — | — | (514) | |||||||||||||||||||||||||||||
| Purchased power | (483) | (933) | — | — | 118 | (1,298) | |||||||||||||||||||||||||||||
| Electric margins | 2,697 | 1,285 | — | 677 | (32) | 4,627 | |||||||||||||||||||||||||||||
| Natural gas revenues | 165 | — | 897 | — | (1) | 1,061 | |||||||||||||||||||||||||||||
| Natural gas purchased for resale | (79) | — | (276) | — | — | (355) | |||||||||||||||||||||||||||||
| Natural gas margins | 86 | — | 621 | — | (1) | 706 | |||||||||||||||||||||||||||||
| Other operations and maintenance expenses | (1,003) | (532) | (237) | (60) | (34) | (1,866) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (783) | (351) | (108) | (138) | (7) | (1,387) | |||||||||||||||||||||||||||||
| Taxes other than income taxes | (360) | (75) | (67) | (8) | (12) | (522) | |||||||||||||||||||||||||||||
| Operating income (loss) | 637 | 327 | 209 | 471 | (86) | 1,558 | |||||||||||||||||||||||||||||
| Other income, net | 130 | 103 | 30 | 28 | 57 | 348 | |||||||||||||||||||||||||||||
| Interest charges | (227) | (89) | (55) | (96) | (99) | (566) | |||||||||||||||||||||||||||||
| Income (taxes) benefit | 8 | (82) | (50) | (106) | 47 | (183) | |||||||||||||||||||||||||||||
| Net income (loss) | 548 | 259 | 134 | 297 | (81) | 1,157 | |||||||||||||||||||||||||||||
| Noncontrolling interests – preferred stock dividends | (3) | (1) | — | (1) | — | (5) | |||||||||||||||||||||||||||||
| Net income (loss) attributable to Ameren common shareholders | $ | 545 | $ | 258 | $ | 134 | $ | 296 | $ | (81) | $ | 1,152 | |||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||||||||
| Electric revenues | $ | 3,849 | $ | 2,256 | $ | — | $ | 615 | $ | (139) | $ | 6,581 | |||||||||||||||||||||||
| Fuel | (473) | — | — | — | — | (473) | |||||||||||||||||||||||||||||
| Purchased power | (677) | (984) | — | — | 114 | (1,547) | |||||||||||||||||||||||||||||
| Electric margins | 2,699 | 1,272 | — | 615 | (25) | 4,561 | |||||||||||||||||||||||||||||
| Natural gas revenues | 197 | — | 1,180 | — | (1) | 1,376 | |||||||||||||||||||||||||||||
| Natural gas purchased for resale | (104) | — | (553) | — | — | (657) | |||||||||||||||||||||||||||||
| Natural gas margins | 93 | — | 627 | — | (1) | 719 | |||||||||||||||||||||||||||||
| Other operations and maintenance expenses | (1,028) | (580) | (253) | (60) | (16) | (1,937) | |||||||||||||||||||||||||||||
| Depreciation and amortization | (732) | (332) | (98) | (123) | (4) | (1,289) | |||||||||||||||||||||||||||||
| Taxes other than income taxes | (363) | (75) | (82) | (9) | (10) | (539) | |||||||||||||||||||||||||||||
| Operating income (loss) | 669 | 285 | 194 | 423 | (56) | 1,515 | |||||||||||||||||||||||||||||
| Other income, net | 99 | 60 | 19 | 17 | 31 | 226 | |||||||||||||||||||||||||||||
| Interest charges | (213) | (74) | (44) | (84) | (71) | (486) | |||||||||||||||||||||||||||||
| Income (taxes) benefit | 10 | (68) | (46) | (92) | 20 | (176) | |||||||||||||||||||||||||||||
| Net income (loss) | 565 | 203 | 123 | 264 | (76) | 1,079 | |||||||||||||||||||||||||||||
| Noncontrolling interests – preferred stock dividends | (3) | (1) | — | (1) | — | (5) | |||||||||||||||||||||||||||||
| Net income (loss) attributable to Ameren common shareholders | $ | 562 | $ | 202 | $ | 123 | $ | 263 | $ | (76) | $ | 1,074 | |||||||||||||||||||||||
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Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2023 and 2022:
| 2023 | Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Illinois Transmission | Other / Intersegment Eliminations | Ameren Illinois | ||||||||||||||||||||||||
| Electric revenues | $ | 2,218 | $ | — | $ | 480 | $ | (113) | $ | 2,585 | |||||||||||||||||||
| Purchased power | (933) | — | — | 113 | (820) | ||||||||||||||||||||||||
| Electric margins | 1,285 | — | 480 | — | 1,765 | ||||||||||||||||||||||||
| Natural gas revenues | — | 897 | — | — | 897 | ||||||||||||||||||||||||
| Natural gas purchased for resale | — | (276) | — | — | (276) | ||||||||||||||||||||||||
| Natural gas margins | — | 621 | — | — | 621 | ||||||||||||||||||||||||
| Other operations and maintenance expenses | (532) | (237) | (49) | — | (818) | ||||||||||||||||||||||||
| Depreciation and amortization | (351) | (108) | (97) | — | (556) | ||||||||||||||||||||||||
| Taxes other than income taxes | (75) | (67) | (4) | — | (146) | ||||||||||||||||||||||||
| Operating income | 327 | 209 | 330 | — | 866 | ||||||||||||||||||||||||
| Other income, net | 103 | 30 | 23 | — | 156 | ||||||||||||||||||||||||
| Interest charges | (89) | (55) | (60) | — | (204) | ||||||||||||||||||||||||
| Income taxes | (82) | (50) | (77) | — | (209) | ||||||||||||||||||||||||
| Net income | 259 | 134 | 216 | — | 609 | ||||||||||||||||||||||||
| Preferred stock dividends | (1) | — | (1) | — | (2) | ||||||||||||||||||||||||
| Net income attributable to common shareholder | $ | 258 | $ | 134 | $ | 215 | $ | — | $ | 607 | |||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Electric revenues | $ | 2,256 | $ | — | $ | 424 | $ | (104) | $ | 2,576 | |||||||||||||||||||
| Purchased power | (984) | — | — | 104 | (880) | ||||||||||||||||||||||||
| Electric margins | 1,272 | — | 424 | — | 1,696 | ||||||||||||||||||||||||
| Natural gas revenues | — | 1,180 | — | — | 1,180 | ||||||||||||||||||||||||
| Natural gas purchased for resale | — | (553) | — | — | (553) | ||||||||||||||||||||||||
| Natural gas margins | — | 627 | — | — | 627 | ||||||||||||||||||||||||
| Other operations and maintenance expenses | (580) | (253) | (49) | — | (882) | ||||||||||||||||||||||||
| Depreciation and amortization | (332) | (98) | (84) | — | (514) | ||||||||||||||||||||||||
| Taxes other than income taxes | (75) | (82) | (4) | — | (161) | ||||||||||||||||||||||||
| Operating income | 285 | 194 | 287 | — | 766 | ||||||||||||||||||||||||
| Other income, net | 60 | 19 | 17 | — | 96 | ||||||||||||||||||||||||
| Interest charges | (74) | (44) | (50) | — | (168) | ||||||||||||||||||||||||
| Income taxes | (68) | (46) | (65) | — | (179) | ||||||||||||||||||||||||
| Net income | 203 | 123 | 189 | — | 515 | ||||||||||||||||||||||||
| Preferred stock dividends | (1) | — | (1) | — | (2) | ||||||||||||||||||||||||
| Net income attributable to common shareholder | $ | 202 | $ | 123 | $ | 188 | $ | — | $ | 513 | |||||||||||||||||||
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.
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Electric Margins
Total by Segment(a) | Increase (Decrease) by Segment | |||||||||||||
| Overall Ameren Increase of $66 Million | ||||||||||||||
(a)Includes other/intersegment eliminations of $(32) million and $(25) million in 2023 and 2022, respectively.
| Ameren Missouri | Ameren Illinois Electric Distribution | Ameren Transmission | Other/Intersegment Eliminations | |||||||||||||||||||||||||||||||||||
Natural Gas Margins
Total by Segment(a) | Decrease by Segment | |||||||||||||
| Overall Ameren Decrease of $13 Million | ||||||||||||||
(a)Includes other/intersegment eliminations of $(1) million and $(1) million in 2023 and 2022, respectively.
| Ameren Missouri | Ameren Illinois Natural Gas | Other/Intersegment Eliminations | |||||||||||||||||||||||||||
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The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2023, compared with 2022:
| Electric and Natural Gas Margins | ||||||||||||||||||||||||||||||||||||||||||||||||||
| 2023 versus 2022 | Ameren Missouri | Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Transmission(a) | Other / Intersegment Eliminations | Ameren | ||||||||||||||||||||||||||||||||||||||||||||
| Electric revenue change: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Base rates (estimate)(b) | $ | 115 | $ | 30 | $ | — | $ | 62 | $ | — | $ | 207 | ||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate)(c) | (71) | — | — | — | — | (71) | ||||||||||||||||||||||||||||||||||||||||||||
| Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | (27) | — | — | — | — | (27) | ||||||||||||||||||||||||||||||||||||||||||||
| MEEIA 2019 performance incentives | (10) | — | — | — | — | (10) | ||||||||||||||||||||||||||||||||||||||||||||
| Off-system sales, capacity, and FAC revenues, net | (226) | — | — | — | — | (226) | ||||||||||||||||||||||||||||||||||||||||||||
| Transmission service charges | (9) | — | — | — | — | (9) | ||||||||||||||||||||||||||||||||||||||||||||
| Ameren Illinois customer energy-efficiency program investment revenues | — | 18 | — | — | — | 18 | ||||||||||||||||||||||||||||||||||||||||||||
| Other | 1 | (2) | — | — | (7) | (8) | ||||||||||||||||||||||||||||||||||||||||||||
Cost recovery mechanisms – offset in fuel and purchased power(d) | 82 | (51) | — | — | (4) | 27 | ||||||||||||||||||||||||||||||||||||||||||||
Other cost recovery mechanisms(e) | (10) | (33) | — | — | — | (43) | ||||||||||||||||||||||||||||||||||||||||||||
| Total electric revenue change | $ | (155) | $ | (38) | $ | — | $ | 62 | $ | (11) | $ | (142) | ||||||||||||||||||||||||||||||||||||||
| Fuel and purchased power change: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Energy costs (excluding the estimated effect of weather) | $ | 238 | $ | — | $ | — | $ | — | $ | — | $ | 238 | ||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate)(c) | 14 | — | — | — | — | 14 | ||||||||||||||||||||||||||||||||||||||||||||
| Effect of higher net energy costs included in base rates | (21) | — | — | — | — | (21) | ||||||||||||||||||||||||||||||||||||||||||||
| Transmission service charges | 4 | — | — | — | — | 4 | ||||||||||||||||||||||||||||||||||||||||||||
Cost recovery mechanisms – offset in electric revenue(d) | (82) | 51 | — | — | 4 | (27) | ||||||||||||||||||||||||||||||||||||||||||||
| Total fuel and purchased power change | $ | 153 | $ | 51 | $ | — | $ | — | $ | 4 | $ | 208 | ||||||||||||||||||||||||||||||||||||||
| Net change in electric margins | $ | (2) | $ | 13 | $ | — | $ | 62 | $ | (7) | $ | 66 | ||||||||||||||||||||||||||||||||||||||
| Natural gas revenue change: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Base rates (estimate) | $ | — | $ | — | $ | 6 | $ | — | $ | — | $ | 6 | ||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate)(c) | (17) | — | — | — | — | (17) | ||||||||||||||||||||||||||||||||||||||||||||
| Sales volume (excluding the estimated effect of weather) | — | — | (4) | — | — | (4) | ||||||||||||||||||||||||||||||||||||||||||||
| QIP rider | — | — | 14 | — | — | 14 | ||||||||||||||||||||||||||||||||||||||||||||
| Other | (2) | — | (4) | — | — | (6) | ||||||||||||||||||||||||||||||||||||||||||||
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | (12) | — | (277) | — | — | (289) | ||||||||||||||||||||||||||||||||||||||||||||
Other cost recovery mechanisms(e) | (1) | — | (18) | — | — | (19) | ||||||||||||||||||||||||||||||||||||||||||||
| Total natural gas revenue change | $ | (32) | $ | — | $ | (283) | $ | — | $ | — | $ | (315) | ||||||||||||||||||||||||||||||||||||||
| Natural gas purchased for resale change: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Effect of weather (estimate)(c) | $ | 13 | $ | — | $ | — | $ | — | $ | — | $ | 13 | ||||||||||||||||||||||||||||||||||||||
Cost recovery mechanisms – offset in natural gas revenue(d) | 12 | — | 277 | — | — | 289 | ||||||||||||||||||||||||||||||||||||||||||||
| Total natural gas purchased for resale change | $ | 25 | $ | — | $ | 277 | $ | — | $ | — | $ | 302 | ||||||||||||||||||||||||||||||||||||||
| Net change in natural gas margins | $ | (7) | $ | — | $ | (6) | $ | — | $ | — | $ | (13) | ||||||||||||||||||||||||||||||||||||||
(a)Includes an increase in transmission electric margins of $56 million in 2023, compared with 2022, at Ameren Illinois.
(b)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 for the recovery of lost electric margins resulting from the MEEIA customer energy-efficiency programs and a decrease in base rates for RESRAM. These changes in Ameren Missouri base rates are included in the “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” and “Cost recovery mechanisms - offset in fuel and purchased power” line items, respectively.
(c)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.
(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.
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Ameren
Ameren’s electric margins increased $66 million, or 1%, in 2023, compared with 2022, because of increased margins at Ameren Transmission and Ameren Illinois Electric Distribution, as discussed below. Ameren’s natural gas margins decreased $13 million, or 2%, between years because of decreased margins at Ameren Missouri and Ameren Illinois Natural Gas, as discussed below.
Ameren Transmission
Ameren Transmission’s margins increased $62 million, or 10%, in 2023, compared with 2022. Base rate revenues were favorably affected by higher recoverable expenses (+$38 million) and increased capital investment (+$24 million), as evidenced by a 10% increase in rate base used to calculate the revenue requirement.
Ameren Missouri
Ameren Missouri’s electric margins were comparable between years. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $82 million in 2023, compared with 2022, due to increased revenue related to the amortization of costs previously deferred under the FAC that were reflected in customer rates. 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 cost variances under the FAC is reflected within “Off-system sales, capacity, and FAC revenues, net” and “Energy costs (excluding the estimated effect of weather)”.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2023, compared with 2022:
•Winter temperatures were warmer as heating degree days decreased 22% while spring and summer temperatures were milder as cooling degree days decreased 3%. The aggregate effect of weather decreased margins by an estimated $57 million. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (-$71 million) and the “Effect of weather (estimate)” on fuel and purchased power (+$14 million) in the table above.
•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues decreased an estimated $27 million resulting from a decrease in retail sales volumes, due, in part, to customer outages resulting from major storms experienced throughout the service territory in July and August 2023, partially offset by an increase in customer demand charge revenues and an increase in the average retail price per kilowatthour related to changes in customer usage patterns.
•MEEIA 2019 performance incentives decreased revenues $10 million as performance incentives for program years 2021 and 2022 were recognized in 2022, whereas the performance incentive for program year 2023 was recognized in 2023.
•Revenues associated with other cost recovery mechanisms decreased $10 million, primarily due to a decrease in RESRAM revenues, partially offset by an increase in excise taxes and recoverable MEEIA program costs.
•Transmission service charge revenues decreased $9 million, primarily due to lower revenues related to reactive power.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2023, compared with 2022:
•Higher electric base rates, excluding the change in base rates for the MEEIA customer energy-efficiency programs and the RESRAM, resulting from the June 2023 MoPSC electric rate order effective July 9, 2023, partially offset by higher net energy costs included in base rates, increased margins an estimated $57 million. A similar effect resulting from the December 2021 MoPSC electric rate order effective February 28, 2022, increased margins an estimated $37 million. The change in electric base rates is the sum of the change in “Base rates (estimate)” (+$115 million) and the “Effect of higher net energy costs included in base rates” (-$21 million) in the table above.
•Ameren Missouri’s electric margins increased $12 million due to its 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” (-$226 million) and “Energy costs (excluding the estimated effect of weather)” (+$238 million) in the table above. Revenues decreased primarily due to lower off-system sales volumes (-$108 million) related to reduced generation at the Rush Island Energy Center, lower capacity prices (-$101 million) set by the annual MISO auction in April 2023, and lower market prices for energy (-$11 million). Energy costs decreased primarily due to lower fuel costs (+$130 million), lower purchased power costs (+$98 million), and lower capacity costs (+$95 million), partially offset by decreased deferral of expenses under the FAC (-$90 million).
•Transmission service charge expenses decreased $4 million, primarily due to a decrease in charges related to transmission network upgrades.
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Ameren Missouri’s natural gas margins decreased $7 million, or 8%, in 2023, compared with 2022. Purchased gas costs decreased $12 million in 2023, compared with 2022, due to lower commodity prices and decreased amortization of deferred natural gas costs related to the extremely cold weather in mid-February 2021. The decreased purchased gas costs are fully offset by a decrease in natural gas revenues under the PGA, resulting in no impact to margin. The decrease 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. Margins decreased $4 million due to warmer winter temperatures as heating degree days decreased 22%. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on natural gas revenues (-$17 million) and the “Effect of weather (estimate)” on natural gas purchased for resale (+$13 million) in the table above.
Ameren Illinois
Ameren Illinois’ electric margins increased $69 million, or 4%, in 2023, compared with 2022, driven by increased margins at Ameren Illinois Transmission and Ameren Illinois Electric Distribution. Ameren Illinois Natural Gas’ margins decreased $6 million, or 1%, between years.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $13 million, or 1%, in 2023, compared with 2022. Purchased power costs decreased $51 million in 2023, compared with 2022, primarily due to decreased energy prices (-$54 million), which largely reflect the results of IPA procurement events, and lower volumes due to decreased sales (-$39 million), partially offset by increased revenues related to the amortization of costs previously deferred under riders (+$28 million) and higher costs due to higher capacity prices (+$9 million). The decreased purchased power costs are fully offset by a decrease in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin. The decrease 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 2023, compared with 2022:
•The impact from base rates (+$30 million) increased due to a higher recognized ROE (+$21 million), as evidenced by an increase of 98 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, and increased capital investment (+$15 million), as evidenced by a 9% increase in year-end rate base, partially offset by lower recoverable non-purchased power expenses (-$4 million), and the results from 2021 and 2022 revenue requirement reconciliation adjustment true-ups recognized in the subsequent year (-$2 million).
•Revenues associated with customer energy-efficiency program investments increased $18 million due to the recovery of program expenses (+$12 million), increased investment (+$2 million), higher recognized ROE under formula ratemaking (+$2 million), and the results from the 2022 revenue requirement reconciliation adjustment true-up recognized in 2023 (+$2 million).
Revenues associated with other cost recovery mechanisms decreased $33 million in 2023, compared with 2022, primarily due to a lower amount of bad debt costs included in customer rates pursuant to the associated rider.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins decreased $6 million, or 1%, in 2023, compared with 2022. Purchased gas costs decreased $277 million in 2023, compared with 2022, primarily due to lower amortization of natural gas costs that were previously deferred under the PGA and lower natural gas prices in 2023. Deferred natural gas costs related to the extremely cold weather in mid-February 2021 were fully recovered from customers by the end of 2022. The decreased purchased natural gas costs are fully offset by a decrease in natural gas revenues under the PGA, resulting in no impact to margin. The decrease 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.
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The following items had an unfavorable effect on Ameren Illinois Natural Gas’ margins in 2023, compared with 2022:
•Revenues associated with other cost recovery mechanisms decreased $18 million, primarily due to decreased revenues for excise taxes.
•Revenues decreased $4 million primarily due to lower sales volumes related to large commercial, industrial, and transportation customers, and lower capacity revenues. Revenues from sales to large commercial, industrial, and transportation customers are excluded from the VBA. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the VBA.
•Other miscellaneous revenues decreased $4 million primarily related to the refund of over-recovered costs associated with the COVID-19 pandemic, beginning in April 2023.
The following items had a favorable effect on Ameren Illinois Natural Gas’ margins in 2023, compared with 2022:
•Revenues increased $14 million due to additional investment in natural gas infrastructure under the QIP.
•Revenues increased $6 million due to higher natural gas base rates as a result of the natural gas rate order effective November 28, 2023.
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the QIP and 2023 Natural Gas Delivery Service Rate Order.
Ameren Illinois Transmission
Ameren Illinois Transmission’s electric margins increased $56 million, or 13%, in 2023, compared with 2022. Base rate revenues were favorably affected by increased capital investment (+$25 million), as evidenced by a 15% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$31 million).
Other Operations and Maintenance Expenses
Total by Segment(a) | Increase (Decrease) by Segment | |||||||||||||
| Overall Ameren Decrease of $71 Million | ||||||||||||||
(a)Includes $60 million and $60 million at Ameren Transmission in 2023 and 2022, respectively, and other/intersegment eliminations of $34 million and $16 million in 2023 and 2022, respectively.
| Ameren Missouri | Ameren Illinois Natural Gas | Other/Intersegment Eliminations | |||||||||||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Transmission | ||||||||||||||||||||||||||||
Ameren
Other operations and maintenance expenses at Ameren decreased $71 million in 2023, compared with 2022. In addition to changes by segment as discussed below, other operations and maintenance expenses increased $18 million in 2023 for activity not reported as part of a
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segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of an increase in the elimination of the non-service cost component of net periodic benefit income at Ameren Services. The non-service cost component of net periodic benefit cost or income at Ameren Services is allocated to the segments and primarily included in the segments’ other operations and maintenance expenses. Other operations and maintenance expenses were comparable at Ameren Transmission between periods.
Ameren Missouri
The $25 million decrease in Ameren Missouri’s other operations and maintenance expenses in 2023, compared with 2022, was primarily due to the following items:
•The cash surrender value of COLI increased $21 million. The effect of changes in the cash surrender value of COLI resulted in gains of $7 million in 2023, compared with losses of $14 million in 2022.
•The recognition of regulatory assets for previously expensed costs approved for recovery pursuant to the June 2023 MoPSC rate order decreased other operations and maintenance expenses $14 million.
•Renewable development costs decreased $9 million, as the MoPSC order approving CCNs for the Boomtown and Huck Finn solar projects in the first half of 2023 led to increased capitalization of renewable development costs pursuant to anticipated recovery from customers.
•Energy center operating and maintenance costs decreased $3 million, primarily because of the retirement of the Meramec Energy Center in December 2022, partially offset by increased costs related to maintenance outages at other energy centers.
The following items partially offset the above decreases in other operations and maintenance expenses between years:
•Transmission and distribution storm-related costs increased $7 million because of the major storms experienced throughout the service territory in July and August 2023.
•Transmission and distribution expenditures, excluding storm costs, increased $7 million, primarily because of increased inspection and vegetation management expenditures.
•MEEIA customer energy-efficiency program spend increased $3 million, as approved by the MoPSC.
Ameren Illinois
Other operations and maintenance expenses decreased $64 million at Ameren Illinois in 2023, compared with 2022, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2023 and 2022.
Ameren Illinois Electric Distribution
The $48 million decrease in Ameren Illinois Electric Distribution’s other operations and maintenance expenses in 2023, compared with 2022, was primarily due to the following items:
•Bad debt costs decreased $43 million primarily because of a lower amount of costs recovered from customers pursuant to the associated rider.
•The cash surrender value of COLI increased $10 million in 2023, primarily because of favorable market returns, compared with unfavorable market returns in 2022.
•Pension and benefit costs decreased $8 million, primarily related to decreased pension service costs due to changes in actuarial assumptions.
The following items partially offset the above decreases in other operations and maintenance expenses between years:
•Amortization of regulatory assets associated with customer energy-efficiency investments under formula ratemaking increased $9 million.
•Amortization of previously deferred storm-related costs and costs related to major storm activity in 2023, increased $6 million.
Ameren Illinois Natural Gas
Other operations and maintenance costs decreased $16 million in 2023, compared with 2022, in part, because of a $5 million increase in the cash surrender value of COLI. In 2023, the effect of changes in the cash surrender value of COLI resulted in a gain of $2 million, compared with a loss of $3 million in 2022. Other operations and maintenance expenses also decreased $5 million in 2023 because of a decline in required environmental remediation work. Additionally, other operations and maintenance expenses decreased $4 million, primarily related to labor overhead costs.
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Depreciation and Amortization
Total by Segment(a) | Increase by Segment | |||||||||||||
| Overall Ameren Increase of $98 Million | ||||||||||||||
(a)Includes other/intersegment eliminations of $7 million and $4 million in 2023 and 2022, respectively.
| Ameren Missouri | Ameren Illinois Natural Gas | Other/Intersegment Eliminations | |||||||||||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Transmission | ||||||||||||||||||||||||||||
The $98 million, $51 million, and $42 million increases in depreciation and amortization expenses in 2023, compared with 2022, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, were primarily due to additional property, plant, and equipment across their respective segments.
In addition, Ameren’s and Ameren Missouri’s depreciation and amortization expenses were affected by the following, which include the effect of the additional investments in property, plant, and equipment:
•Increased depreciation and amortization of $51 million, due to the inclusion in base rates of amounts previously deferred under the PISA and RESRAM effective February 28, 2022, and July 9, 2023, pursuant to the December 2021 and June 2023 MoPSC electric rate orders, respectively.
•Depreciation and amortization rate changes pursuant to the electric rate orders noted above, which increased depreciation and amortization expenses by $17 million.
•Increased depreciation and amortization of $6 million, primarily because of electric system capital additions not eligible for deferral under PISA and RESRAM.
•The higher deferral, net of amortization of prior-period deferrals, pursuant to a tracker related to certain excess deferred income taxes, which decreased depreciation and amortization by $17 million.
•Depreciation and amortization expenses reflected a deferral to a regulatory asset of depreciation and amortization expenses pursuant to PISA and RESRAM. The amount of depreciation and amortization expenses included in base rates for PISA and RESRAM deferrals was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021; and when new customer rates became effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, which incorporated deferrals through December 31, 2022. The effect of higher deferrals, net of amortization of prior-period deferrals, decreased depreciation and amortization expenses by $5 million.
•The higher net under-recovery of RESRAM eligible expenses decreased depreciation and amortization expenses by $3 million.
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Taxes Other Than Income Taxes
Total by Segment(a) | Increase (Decrease) by Segment | |||||||||||||
| Overall Ameren Decrease of $17 Million | ||||||||||||||
(a)Includes $8 million and $9 million at Ameren Transmission in 2023 and 2022, respectively, and other/intersegment eliminations of $12 million and $10 million in 2023 and 2022, respectively.
| Ameren Missouri | Ameren Illinois Natural Gas | Other/Intersegment Eliminations | |||||||||||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Transmission | ||||||||||||||||||||||||||||
Taxes other than income taxes decreased $17 million in 2023, compared with 2022, largely because of a $14 million decrease in excise taxes at Ameren Illinois Natural Gas, primarily resulting from decreased sales revenues. Taxes other than income taxes also decreased $6 million and $2 million in 2023, at Ameren Missouri and Ameren Illinois, respectively, because of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act. The decreases in taxes other than income taxes at Ameren Missouri were partially offset by a $4 million increase in excise taxes, primarily related to increased retail electric rates pursuant to the June 2023 MoPSC electric rate order.
See Excise Taxes in Note 15 – Supplemental Information under Part II, Item 8, of this report for additional information.
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Other Income, Net
| Total by Segment | Increase by Segment | |||||||||||||
| Overall Ameren Increase of $122 Million | ||||||||||||||
| Ameren Missouri | Ameren Illinois Natural Gas | Other/Intersegment Eliminations | |||||||||||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Transmission | ||||||||||||||||||||||||||||
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.
Ameren
Other income, net, increased $122 million in 2023, compared with 2022. In addition to changes discussed below, other income, net, increased $26 million, primarily because of a $30 million increase in the non-service cost component of net periodic benefit income for activity not reported as part of a segment, partially offset by a $3 million increase in charitable contributions.
Ameren Transmission
Other income, net, increased $11 million in 2023, compared with 2022, largely because of a $5 million increase in the allowance for equity funds used during construction, primarily resulting from a higher average monthly equity-to-debt ratio at ATXI, and higher average construction work in progress balances. Other income, net, also increased $3 million because of an increase in the non-service cost component of net periodic benefit income.
Ameren Missouri
Other income, net, increased $31 million in 2023, compared with 2022, primarily because of a $42 million increase in the non-service cost component of net periodic benefit income pursuant to the June 2023 MoPSC electric rate order, which reflected the effect of such increase in electric service rates effective July 9, 2023. Other income, net, also increased $6 million because of higher allowance for equity funds used during construction, resulting from higher average construction work in progress balances. Additionally, other income, net increased $6 million because of higher interest income on under-recovered asset balances associated with regulatory recovery mechanisms. These increases in other income, net, were partially offset by a decrease of $23 million in interest income on industrial development revenue bonds, as these bonds were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements related to the investments in industrial development revenue bonds.
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Ameren Illinois
Other income, net, increased $60 million in 2023, compared with 2022, primarily because of increases in the non-service cost component of net periodic benefit income of $26 million, $11 million, and $3 million at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, respectively. Other income, net, also increased $13 million at Ameren Illinois Electric Distribution because of higher interest income on under-recovered balances associated with regulatory recovery mechanisms.
Interest Charges
| Total by Segment | Increase by Segment | |||||||||||||
| Overall Ameren Increase of $80 Million | ||||||||||||||
| Ameren Missouri | Ameren Illinois Natural Gas | Other/Intersegment Eliminations | |||||||||||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Transmission | ||||||||||||||||||||||||||||
Interest charges increased $80 million in 2023, compared with 2022, primarily because of the following items:
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report and the Long-term Debt and Equity section below for additional information on short-term borrowings and long-term debt, respectively, discussed below. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreement discussed below.
Ameren
Interest charges increased $80 million in 2023, compared with 2022. In addition to changes by segments discussed below, interest charges increased $28 million for activity not reported as part of a segment, primarily because of a $23 million increase related to higher interest rates on increased levels of short-term borrowings at Ameren (parent). Interest charges for activity not reported as part of a segment also increased $5 million because of issuances of long-term debt at Ameren (parent) in November and December 2023.
Ameren Transmission
Interest charges increased $12 million in 2023, compared with 2022, primarily because of issuances of long-term debt in August and November 2022 and May 2023, which collectively increased interest charges by $17 million. The increases in 2023 were partially offset by a $8 million reduction to interest charges because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to increased average construction work in progress balances and a higher applicable borrowing rate.
Ameren Missouri
Interest charges increased $14 million in 2023, compared with 2022. The following items increased interest charges between years:
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•Issuances of long-term debt in April 2022 and March 2023 collectively increased interest charges by $27 million.
•Interest charges increased $11 million because of higher interest rates on increased levels of short-term borrowings.
•Interest charges reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM. The amount of PISA and RESRAM deferrals included in base rates was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021, and when new customer rates became effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, which incorporated deferrals through December 31, 2022. Lower deferrals in 2023, due to the inclusion in base rates of interest associated with certain property, plant, and equipment previously deferred under the PISA and RESRAM, increased interest charges by $9 million.
The following items partially offset the above increases in interest charges between years:
•Interest charges decreased $23 million, primarily due to the termination of a financing obligation agreement related to the CT energy center in Audrain County. The decreases in interest charges associated with this agreement are offset by decreases in interest income on related industrial development revenue bonds, as discussed above.
•Interest charges decreased $14 million because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to higher average construction work in progress balances and a higher applicable borrowing rate.
Ameren Illinois
Interest charges increased $36 million in 2023, compared with 2022, primarily because of the issuances of long-term debt in 2022 and 2023. Issuances of long-term debt at Ameren Illinois in August and November 2022 and May 2023 collectively increased interest charges by $19 million at Ameren Illinois Electric Distribution, by $15 million at Ameren Illinois Transmission, and $12 million at Ameren Illinois Natural Gas. The increases in 2023 were partially offset by a $4 million reduction to interest charges at Ameren Illinois Transmission because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to higher average construction work in progress balances and a higher applicable borrowing rate.
Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2023 and 2022:
| 2023 | 2022 | |||||||||||||||||||
| Ameren | 14% | 14% | ||||||||||||||||||
| Ameren Missouri | (2)% | (2)% | ||||||||||||||||||
| Ameren Illinois | 26% | 26% | ||||||||||||||||||
| Ameren Illinois Electric Distribution | 24% | 25% | ||||||||||||||||||
| Ameren Illinois Natural Gas | 27% | 27% | ||||||||||||||||||
| Ameren Illinois Transmission | 26% | 26% | ||||||||||||||||||
| Ameren Transmission | 26% | 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.
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 $2.3 billion, $1.1 billion, and, $1.2 billion, respectively, which include $0.9 billion, $0.4 billion, and, $0.6 billion, respectively, in 2024.
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
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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 to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2028. Additionally, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. During 2023, Ameren issued a total of 3.2 million shares of common stock and received aggregate proceeds of $299 million under the ATM program. As of December 31, 2023, Ameren had multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 2.9 million shares of common stock. Ameren expects to settle approximately $230 million of the forward sale agreements with physical delivery of 2.9 million shares of common stock by December 31, 2024. Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue approximately $300 million of equity in 2024 and approximately $600 million of equity each year from 2025 to 2028. As of December 31, 2023, Ameren had approximately $770 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2023. Ameren expects its equity to total capitalization 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, including the forward sale agreements under the ATM program relating to common stock.
The following table presents net cash provided by (used in) operating, investing, and financing activities for the years ended December 31, 2023 and 2022:
| Net Cash Provided By Operating Activities | Net Cash Used In Investing Activities | Net Cash Provided By Financing Activities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | Variance | 2023 | 2022 | Variance | 2023 | 2022 | Variance | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ameren | $ | 2,564 | (a) | $ | 2,263 | (a) | $ | 301 | $ | (3,798) | $ | (3,370) | $ | (428) | $ | 1,290 | $ | 1,168 | $ | 122 | ||||||||||||||||||||||||||||||||||||||||||
| Ameren Missouri | 1,341 | 1,130 | 211 | (1,960) | (1,703) | (257) | 616 | 578 | 38 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ameren Illinois | 1,098 | (a) | 1,048 | (a) | 50 | (1,733) | (1,602) | (131) | 678 | 612 | 66 | |||||||||||||||||||||||||||||||||||||||||||||||||||
(a) Both Ameren and Ameren Illinois’ cash provided by operating activities included cash outflows of $123 million and $104 million for the FEJA electric energy-efficiency rider and $9 million and $5 million for the customer generation rebate program in 2023 and 2022, respectively.
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, 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.
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, Ameren Missouri and Ameren Illinois had under-recovered costs for the month of February 2021 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 under-recovery is being collected from customers over 36 months beginning November 2021, pursuant to an October 2021 MoPSC order, and the FAC under-recovery was collected over eight months beginning October 2021. Ameren Illinois collected the PGA under-recovery over 18 months beginning April 2021.
Ameren
Ameren’s cash provided by operating activities increased $301 million in 2023, compared with 2022. The following items contributed to the increase:
•A $372 million increase in customer collections, primarily from base rate increases effective February 28, 2022, and July 9, 2023, pursuant to Ameren Missouri’s December 2021 and June 2023 MoPSC electric rate orders, respectively, electric transmission rate base growth, and an increase attributable to non-PGA regulatory mechanisms, partially offset by a decrease under Ameren Illinois’ PGA resulting from the 2022 recovery of costs for the mid-February 2021 weather event discussed above.
•A $211 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.
•A $66 million decrease in the cost of natural gas held in storage, primarily at Ameren Illinois, because of lower commodity prices.
The following items partially offset the increase in Ameren’s cash from operating activities between periods:
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•A $70 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates. This $70 million increase in interest payments includes a $24 million decrease in interest payments from financing obligations at Ameren Missouri that were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements.
•A $65 million increase in coal inventory levels at Ameren Missouri, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes, which were affected by reduced generation at the Rush Island Energy Center, lower market prices for capacity and energy, and decreased retail load because of warmer winter and milder spring and summer temperatures.
•A $35 million increase in labor costs and payments to contractors primarily due to major storm restoration costs, primarily at Ameren Illinois, due to major storms in late June, July, and August 2023.
•A $25 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•A $25 million decrease due to the timing of payments received from the DOE for the annual reimbursement of spent nuclear fuel storage and related costs.
•A $24 million decrease in interest collections on industrial revenue bonds at Ameren Missouri, as these bonds were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements related to the investments in industrial development revenue bonds.
•A $23 million increase in workers’ compensation payments at Ameren Illinois.
•An $11 million increase in property tax payments at Ameren Missouri, primarily due to higher assessed property tax values.
Ameren Missouri
Ameren Missouri’s cash provided by operating activities increased $211 million in 2023, compared with 2022. The following items contributed to the increase:
•A $239 million increase in customer collections, primarily from base rate increases effective February 28, 2022, and July 9, 2023, pursuant to the December 2021 and June 2023 MoPSC electric rate orders, respectively, and an increase attributable to regulatory mechanisms.
•A $131 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.
•A $5 million decrease in interest payments, primarily due to a $24 million decrease in interest payments from financing obligations that were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements, partially offset by an increase in interest payments due to an increase in the average outstanding debt and an increase in interest rates.
The following items partially offset the increase in Ameren Missouri’s cash from operating activities between periods:
•A $65 million increase in coal inventory levels, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes, which were affected by reduced generation at the Rush Island Energy Center, lower market prices for capacity and energy, and decreased retail load because of warmer winter and milder spring and summer temperatures.
•A $25 million decrease due to the timing of payments received from the DOE for the annual reimbursement of spent nuclear fuel storage and related costs.
•A $24 million decrease in interest collections on industrial revenue bonds, as these bonds were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements related to the investments in industrial development revenue bonds.
•A $16 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•An $11 million increase in property tax payments, primarily due to higher assessed property tax values.
•A $7 million increase in major storm restoration costs, primarily due to major storms in July and August 2023.
Ameren Illinois
Ameren Illinois’ cash provided by operating activities increased $50 million in 2023, compared with 2022. The following items contributed to the increase:
•A $145 million increase in customer collections, primarily from electric transmission rate base growth and an increase attributable to non-PGA regulatory recovery mechanisms, partially offset by a decrease under the PGA resulting from the recovery in 2022 of costs for the mid-February 2021 weather event discussed above.
•An $83 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power and natural gas.
•A $63 million decrease in the cost of natural gas held in storage because of lower commodity prices.
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The following items partially offset the increase in Ameren Illinois’ cash from operating activities between periods:
•A $79 million decrease resulting from income tax payments to Ameren (parent) pursuant to the tax allocation agreement, primarily due to higher taxable income in 2023.
•A $64 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•A $43 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates.
•A $28 million increase in labor costs and payments to contractors primarily due to major storm restoration costs due to major storms in late June, July, and August 2023.
•A $23 million increase in workers’ compensation payments.
Cash Flows from Investing Activities
Ameren’s cash used in investing activities increased $428 million during 2023, compared with 2022, primarily as a result of a $246 million increase in capital expenditures, largely resulting from increased storm-related expenditures at Ameren Missouri and Ameren Illinois and electric transmission upgrades at ATXI. ATXI’s capital expenditures increased $56 million. Also, cash used in investing activities increased at Ameren Missouri, due to increased nuclear fuel expenditures of $145 million and the absence of receipt of $21 million in insurance proceeds in 2022 for the Callaway Energy Center’s generator.
Ameren Missouri’s cash used in investing activities increased $257 million during 2023, compared with 2022, primarily due to increased nuclear fuel expenditures for future refuels of $174 million in 2023 compared to $29 million in 2022. Also, cash used in investing activities increased $70 million as a result of increased capital expenditures, largely resulting from an increase in storm-related expenditures of $58 million. In addition, cash used in investing activities increased due to the absence of receipt of $21 million in insurance proceeds in 2022 for the Callaway Energy Center’s generator.
Ameren Illinois’ cash used in investing activities increased $131 million during 2023, compared with 2022, due to an increase in capital expenditures, largely resulting from increased storm-related expenditures of $103 million.
Capital Expenditures
The following charts present our capital expenditures for the years ended December 31, 2023 and 2022:
2023 – Total Ameren $3,597(a) | 2022 – Total Ameren $3,351(a) | |||||||
Ameren Missouri(b) | Ameren Illinois Natural Gas | ATXI and other electric transmission subsidiaries | |||||||||||||||||||||
| Ameren Illinois Electric Distribution | Ameren Illinois Transmission | ||||||||||||||||||||||
(a)Includes Other capital expenditures of $(18) million and $(9) million for the years ended December 31, 2023 and 2022, respectively, which includes amounts for the elimination of intercompany transfers.
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Ameren’s 2023 capital expenditures consisted of expenditures made by its subsidiaries, including $124 million by ATXI and other electric transmission subsidiaries. Ameren Illinois Natural Gas capital expenditures for 2023 included $165 million related to natural gas projects eligible for QIP recovery. Ameren’s 2022 capital expenditures consisted of expenditures made by its subsidiaries, including $69 million by ATXI and other electric transmission subsidiaries. Ameren Illinois Natural Gas capital expenditures for 2022 included $183 million related to natural gas projects eligible for QIP recovery. 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 in various software projects.
The following table presents Ameren’s estimate of capital expenditures that will be incurred from 2024 through 2028, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations:
| 2024 | 2025 – 2028 | Total | |||||||||||||||||||||||||||
| Ameren Missouri | $ | 2,855 | $ | 9,660 | – | $ | 10,680 | $ | 12,515 | – | $ | 13,535 | |||||||||||||||||
| Ameren Illinois Electric Distribution | 485 | 2,345 | – | 2,595 | 2,830 | – | 3,080 | ||||||||||||||||||||||
| Ameren Illinois Natural Gas | 305 | 1,450 | – | 1,605 | 1,755 | – | 1,910 | ||||||||||||||||||||||
| Ameren Illinois Transmission | 640 | 1,705 | – | 1,885 | 2,345 | – | 2,525 | ||||||||||||||||||||||
| ATXI and other electric transmission subsidiaries | 130 | 1,415 | – | 1,565 | 1,545 | – | 1,695 | ||||||||||||||||||||||
| Other | 10 | 30 | – | 35 | 40 | – | 45 | ||||||||||||||||||||||
| Ameren | $ | 4,425 | $ | 16,605 | – | $ | 18,365 | $ | 21,030 | – | $ | 22,790 | |||||||||||||||||
Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, including $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments through 2028, consistent with Ameren Missouri’s 2023 IRP, as well as expenditures for compliance with environmental regulations. Capital expenditures related to coal-fired generation of approximately $0.9 billion are included in Ameren Missouri’s estimated capital expenditures through 2028. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, including investments to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained. Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.
In 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 July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade. In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects. In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion. The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024.
In February 2024, 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 2024. 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 $12.4 billion over the five-year period from 2024 through 2028, with expenditures largely recoverable under the PISA. Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.
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, future rate orders, 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, compliance with the CCR Rule, and potential modifications to cooling water
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intake structures at existing power plants under Clean Water Act rules. 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.
Ameren’s cash provided by financing activities increased $122 million during 2023, compared with 2022. During 2023, Ameren utilized net proceeds of $2.3 billion of long-term debt for general corporate purposes, for capital expenditures, to repay then-outstanding short-term debt, and to repay $100 million of maturities of long-term debt. Ameren also repaid net commercial paper borrowings totaling $533 million. In addition, Ameren utilized aggregate cash proceeds of $346 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2022, Ameren utilized proceeds from the issuance of $1.5 billion of long-term debt to repay then-outstanding short-term debt, for capital expenditures, and to repay $505 million of maturities of long-term debt. Ameren also received aggregate cash proceeds of $333 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and $522 million from net commercial paper issuances. These proceeds were used to fund, in part, capital expenditures. During 2023, Ameren paid common stock dividends of $662 million, compared with $610 million in dividend payments in 2022.
Ameren Missouri’s cash provided by financing activities increased $38 million during 2023, compared with 2022. During 2023, Ameren Missouri utilized net proceeds of $499 million from the issuance of long-term debt for capital expenditures and to repay then-outstanding short-term debt. Ameren Missouri also repaid net commercial paper borrowings totaling $159 million. In addition, Ameren Missouri utilized net proceeds of $306 million from money pool borrowings along with cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2022, Ameren Missouri utilized net proceeds of $524 million from the issuance of long-term debt to repay then-outstanding short-term debt and for capital expenditures. Ameren Missouri also utilized proceeds from net commercial paper issuances of $164 million along with cash provided by operating activities to fund, in part, capital expenditures. During 2023, Ameren Missouri paid common stock dividends of $9 million, compared with $46 million in dividend payments in 2022.
Ameren Illinois’ cash provided by financing activities increased $66 million during 2023, compared with 2022. During 2023, Ameren Illinois utilized net proceeds of $498 million from the issuance of long-term debt to repay then-outstanding short-term debt and $100 million of long-term debt maturities. In addition, Ameren Illinois utilized proceeds from net commercial paper issuances of $102 million, proceeds of $135 million from money pool borrowings, and capital contributions from Ameren (parent) of $91 million along with cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2022, Ameren Illinois utilized net proceeds of $848 million from the issuance of long-term debt to repay $400 million of maturities of long-term debt and to repay a portion of then-outstanding short-term debt. Additionally, the proceeds from the issuance of long-term debt, proceeds from net commercial paper issuances of $161 million, capital contributions from Ameren (parent) of $15 million, and cash provided by operating activities were used to fund, in part, capital expenditures. During 2023, Ameren Illinois paid common stock dividends of $41 million.
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.
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The following table presents Ameren’s consolidated net available liquidity as of December 31, 2023:
Available at December 31, 2023 | ||||||||
Ameren (parent) and Ameren Missouri(a): | ||||||||
Missouri Credit Agreement – borrowing capacity | $ | 1,400 | ||||||
| Less: Ameren Missouri commercial paper outstanding | 170 | |||||||
| Less: Letters of credit | 2 | |||||||
Missouri Credit Agreement – subtotal | 1,228 | |||||||
Ameren (parent) and Ameren Illinois(b): | ||||||||
Illinois Credit Agreement – borrowing capacity | 1,200 | |||||||
| Less: Ameren Illinois commercial paper outstanding | 366 | |||||||
Illinois Credit Agreement – subtotal | 834 | |||||||
| Subtotal | $ | 2,062 | ||||||
| Cash and cash equivalents | 25 | |||||||
| Net available liquidity | $ | 2,087 | ||||||
(a) The maximum aggregate amount available to both Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $1 billion.
(b) The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the Illinois Credit Agreement is $700 million and $1 billion, respectively.
The Credit Agreements, among other things, provide $2.6 billion of credit until maturity in December 2027. 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, 2023, 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 January 2023, the FERC issued orders authorizing Ameren Missouri, Ameren Illinois, and ATXI to issue up to $1 billion, $1 billion, and $300 million, respectively, of short-term debt securities through January 2025.
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.
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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 for the years ended December 31, 2023 and 2022. 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 Matured | 2023 | 2022 | |||||||||||||||||||||
| Issuances of Long-term Debt | |||||||||||||||||||||||
| Ameren: | |||||||||||||||||||||||
| 5.70% Senior unsecured notes due 2026 | November | $ | 599 | $ | — | ||||||||||||||||||
| 5.00% Senior unsecured notes due 2029 | December | 699 | — | ||||||||||||||||||||
| Ameren Missouri: | |||||||||||||||||||||||
| 5.45% First mortgage bonds due 2053 | March | 499 | — | ||||||||||||||||||||
3.90% First mortgage bonds due 2052(a) | April | — | 524 | ||||||||||||||||||||
| Ameren Illinois: | |||||||||||||||||||||||
| 4.95% First mortgage bonds due 2033 | May | 498 | — | ||||||||||||||||||||
| 3.85% First mortgage bonds due 2032 | August | — | 499 | ||||||||||||||||||||
5.90% First mortgage bonds due 2052(a) | November | — | 349 | ||||||||||||||||||||
| ATXI: | |||||||||||||||||||||||
| 2.96% Senior unsecured notes Series B due 2052 | August | — | 95 | ||||||||||||||||||||
| Total Ameren long-term debt issuances | $ | 2,295 | $ | 1,467 | |||||||||||||||||||
| Issuances of Common Stock | |||||||||||||||||||||||
| Ameren: | |||||||||||||||||||||||
DRPlus and 401(k)(b)(c) | Various | $ | 47 | $ | 41 | ||||||||||||||||||
ATM program(d) | Various | 299 | 292 | ||||||||||||||||||||
Total Ameren common stock issuances(e) | $ | 346 | $ | 333 | |||||||||||||||||||
| Maturities of Long-term Debt | |||||||||||||||||||||||
| Ameren Missouri: | |||||||||||||||||||||||
| Audrain County agreement (Audrain County CT) due 2023 | January | $ | 240 | $ | — | ||||||||||||||||||
| 1.60% 1992 Series bonds due 2022 | November | — | 47 | ||||||||||||||||||||
| City of Bowling Green financing obligation (Peno Creek CT) | December | — | 8 | ||||||||||||||||||||
| Ameren Illinois: | |||||||||||||||||||||||
| 0.375% First mortgage bonds due 2023 | June | 100 | — | ||||||||||||||||||||
| 2.70% Senior secured notes due 2022 | September | — | 400 | ||||||||||||||||||||
| ATXI: | |||||||||||||||||||||||
| 3.43% Senior unsecured notes due 2050 | August | — | 50 | ||||||||||||||||||||
| Total long-term debt redemptions, repurchases, and maturities | $ | 340 | $ | 505 | |||||||||||||||||||
(a) Ameren Missouri and Ameren Illinois intend to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.
(b) Ameren issued a total of 0.6 million and 0.5 million shares of common stock under its DRPlus and 401(k) plan in 2023 and 2022, respectively.
(c) Excludes a $7 million and $8 million receivable at December 31, 2023 and 2022, respectively.
(d) Ameren issued 3.2 million and 3.4 million shares of common stock under the ATM program in 2023 and 2022, respectively.
(e) Excludes 0.5 million and 0.4 million shares of common stock valued at $40 million and $31 million issued for no cash consideration in connection with stock-based compensation in 2023 and 2022, respectively.
In January 2024, Ameren Missouri issued $350 million of 5.25% first mortgage bonds due January 2054, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2024. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.
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.
Indebtedness Provisions and Other Covenants
At December 31, 2023, 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
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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 and credit 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 and credit 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 and credit markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital and credit markets or make access to the capital and credit markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital and credit markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $662 million, or $2.52 per share, in 2023 and $610 million, or $2.36 per share, in 2022. 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 65% of earnings over the next few years. On February 9, 2024, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 67 cents per share, payable on March 29, 2024, to shareholders of record on March 13, 2024.
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, 2023, 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 $4.6 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:
| 2023 | 2022 | ||||||||||||||||
| Ameren | $ | 662 | $ | 610 | |||||||||||||
| Ameren Missouri | 9 | 46 | |||||||||||||||
| Ameren Illinois | 41 | — | |||||||||||||||
| ATXI | 123 | 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.
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Credit Ratings
Our credit ratings affect our liquidity, our access to the capital and credit 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’s | S&P | |||||||
| Ameren: | ||||||||
| Issuer/corporate credit rating | Baa1 | BBB+ | ||||||
| Senior unsecured debt | Baa1 | BBB | ||||||
| Commercial paper | P-2 | A-2 | ||||||
| Ameren Missouri: | ||||||||
| Issuer/corporate credit rating | Baa1 | BBB+ | ||||||
| Senior debt | A2 | A | ||||||
| Senior unsecured debt | Baa1 | Not Rated | ||||||
| Commercial paper | P-2 | A-2 | ||||||
| Ameren Illinois: | ||||||||
| Issuer/corporate credit rating | A3 | BBB+ | ||||||
| Senior debt | A1 | A | ||||||
| Senior unsecured debt | A3 | BBB+ | ||||||
| Commercial paper | P-2 | A-2 | ||||||
| ATXI: | ||||||||
| Issuer credit rating | A2 | Not Rated | ||||||
| Senior unsecured debt | A2 | Not 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 immaterial, and cash collateral posted by external parties were $53 million for Ameren and Ameren Illinois at December 31, 2023. A sub-investment-grade issuer or senior unsecured debt rating (below “Baa3” from Moody’s or below “BBB-” from S&P) at December 31, 2023, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade and contractual obligations amounting to $685 million, $604 million, and $81 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2023, if market prices were 15% higher or lower than December 31, 2023 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 and contractual 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 by 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 relate to climate change, that affect, or may affect, our facilities, operations, and capital expenditures to comply with such laws. The individual or combined effects of compliance with 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
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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 made a 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 EPA has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions from 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 a sustainability 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 2024 and beyond. 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
•We are observing inflationary pressures on the prices of labor, services, materials, and supplies, as well as high interest rates. 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, formula ratemaking, and future test years, as applicable, mitigates our exposure. The inflationary pressures and high interest rates 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. In addition, these inflationary pressures and high interest rates could adversely affect our customers’ usage of, or payment for, our services.
•The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense for investments in qualifying property, plant, and equipment placed in service and not included in base rates. Investments not eligible for recovery under the PISA include amounts related to new nuclear and natural gas generating units and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC until added to rate base prospectively. Ameren Missouri recognizes an offset to “Interest Charges” on its consolidated statement of income for its carrying cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its carrying cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service to comply with Missouri’s renewable energy standard. 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. Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through 2028 and an additional extension through 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things.
•In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023. As a result of this order, Ameren Missouri expects a year-over-year increase to 2024 earnings, compared to 2023, of approximately $22��million ($11 million, $8 million, and $3 million expected in the first, second, and third quarter, respectively).
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•In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency and demand response programs through December 2024. Ameren Missouri intends to invest approximately $420 million over the life of the plan, including $76 million in 2024. 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 revenues by achieving certain customer energy-efficiency goals. If the target program spending goal is achieved for 2024, the performance incentive would result in revenues of $12 million in 2024.
•In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA. This filing proposed a three-year plan, which includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider discussed above. If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.
•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 that will be included in 2024 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $549 million and $223 million, respectively. These revenue requirements represent increases in Ameren Illinois’ and ATXI’s revenue requirements of $73 million and $29 million, respectively, from the revenue requirements reflected in 2023 rates, primarily due to higher expected rate base. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2024, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2024 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 has been the subject of pending proceedings since 2013. Depending on the outcome of the proceedings, the transmission rates charged during previous periods and the currently effective rates may be subject to change and refund. In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which increased the incentive 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 proposed 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 ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $16 million and $11 million, respectively, based on each company’s 2024 projected rate base.
•Pursuant to December 2022 and March 2021 ICC orders, Ameren Illinois used the IEIMA formula framework to establish annual electric distribution service rates effective through 2023, and will reconcile the related revenue requirement for customer rates established for 2023. As such, Ameren Illinois’ 2023 revenues reflected 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. By law, the decoupling provisions extend beyond 2023, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $110 million. The approved reconciliation adjustment will be collected from customers in 2024. In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base. The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.
•Pursuant to the CEJA, 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. The base rates for a particular calendar year are 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 for each calendar year of the four-year period is subject to annual adjustments based on certain performance incentives and penalties. An MYRP allows Ameren Illinois to
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reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to a reconciliation cap and adjustments to the ROE. If a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the applicable annual period. Ameren Illinois’ existing riders will remain effective under the MYRP discussed below, and will continue to remain effective beyond 2027 whether it elects to file an MYRP or a traditional regulatory rate review. Additionally, electric distribution service revenues continue to be decoupled from sales volumes under either election.
•In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,162 million, $1,210 million, $1,242 million, and $1,255 million, respectively. These revenue requirements were established under an alternative methodology which used Ameren Illinois’ previously approved 2022 year-end rate base since the order rejected the Grid Plan that was filed by Ameren Illinois as a part of the MYRP proceeding. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The 2022 year-end rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement. The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase. In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements of $1,214 million, $1,300 million, $1,371 million, and $1,420 million, for 2024, 2025, 2026, and 2027, respectively. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District. Ameren Illinois intends to take prudent steps to align its 2024 operations with the ICC order, while continuing to ensure safe and adequate service is maintained. This will include significant reductions to Ameren Illinois’ capital expenditure and operations and maintenance expense plans.
•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 $120 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 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.
•In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million. The new rates became effective on November 28, 2023. In December 2023, Ameren Illinois filed a request for rehearing with the ICC to revise the approved ROE and capital structure common equity percentage, and reverse an approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request. Subsequently, in January 2024, Ameren Illinois filed an appeal of the November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal.
•The ICC’s November 2023 natural gas delivery service rate order also required Ameren Illinois to submit a plan outlining how it expects to comply with new PHMSA rules for natural gas transmission pipelines, including proposing a capital expenditures plan necessary to meet the new rules. In February 2024, Ameren Illinois filed its plan with the ICC, which included its proposal of natural gas transmission capital expenditures necessary to achieve compliance with the PHMSA rules. The plan includes delays to certain natural gas
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transmission capital expenditures from 2024 to subsequent years to align with the November 2023 ICC order. The ICC is under no obligation to issue an order regarding Ameren Illinois’ plan.
•The November 2023 order also directed the ICC staff to develop a plan for a future of gas proceeding. All of the Illinois natural gas utilities subject to ICC regulation will be included in this proceeding, which will explore issues involved with decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA. Some of the issues expected to be addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others.
•Ameren Missouri’s next refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2025. 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 September 2023, the United States District Court for the Eastern District of Missouri granted Ameren Missouri’s request to modify a September 2019 remedy order issued by the district court in 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. In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri to operate the energy center as directed by the MISO. The MISO designated the energy center as a system support resource in 2022 and concluded that certain reliability mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation through August 2024, and in September 2023, an agreement between Ameren Missouri and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the upgrades expected to be completed in the fall of 2024. Ameren Missouri expects to complete the last of the upgrades by mid-2025. For additional information on the NSR and Clean Air Act litigation, see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report. 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. See below for information regarding Ameren Missouri’s petition filed with the MoPSC requesting the securitization of costs associated with the planned accelerated retirement of the Rush Island Energy Center.
•Pursuant to Illinois law, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the CEJA, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service.
•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, regulatory and 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, increasing inflation, higher cost of debt, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective advancements in innovative energy technologies, including private generation and energy storage. However, we expect the decreased demand to be offset by increased demand resulting from increased electrification of the economy, including in the transportation sector, 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.
Liquidity and Capital Resources
•In September 2023, Ameren Missouri filed its 2023 IRP with the MoPSC, which includes Ameren Missouri’s preferred plan for meeting customers’ projected long-term energy needs in a manner that maintains system reliability and customer affordability while transitioning to clean energy generation in an environmentally responsible manner. In connection with this plan, Ameren is continuing to target net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels. Ameren’s
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goals include both direct emissions from operations (scope 1), as well as electricity usage at Ameren buildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. Achieving these goals will be dependent on a variety of factors, including cost-effective advancements in innovative clean energy technologies and constructive federal and state energy and economic policies. The preferred plan includes, among other things, the following:
•adding an 800-MW natural gas-fired simple-cycle energy center by 2027 and an additional 1,200-MW natural gas-fired combined-cycle energy center by 2033;
•adding 2,800 MWs of renewable generation by 2030, which includes the solar generation facilities discussed below, and an additional 1,900 MWs by 2036;
•adding 400 MWs of battery storage by 2030 and an additional 400 MWs by 2035;
•adding 1,200 MWs of other clean dispatchable generation resources by 2040 and an additional 1,200 MWs by 2043;
•retiring all of Ameren Missouri’s coal-fired energy centers by 2042;
•accelerating the retirement date of the Rush Island coal-fired energy center from 2025 to 2024;
•extending the retirement date of the Sioux coal-fired energy center from 2030 to 2032 to ensure reliability during the transition to clean energy generation, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC;
•retiring 1,800 MWs of Ameren Missouri’s natural gas-fired energy centers by 2040 to comply with Illinois law;
•the continued implementation of customer energy-efficiency and demand response programs; and
•the expectation that Ameren Missouri will seek and receive NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date.
Expected capital expenditures through 2028 related to the facilities discussed above are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below. Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources or natural gas-fired generation, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability to enter into agreements for renewable or natural gas-fired generation and acquire or construct that generation at a reasonable cost; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment, geopolitical conflict, or government actions, among other things; changes in the scope and timing of projects; the ability to qualify for, and use or transfer, federal production or investment tax credits; the cost of wind, solar, and other renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to maintain system reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; energy prices and demand; Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion; the ability to earn an adequate return on invested capital; and the ability to raise capital on reasonable terms. The next integrated resource plan is expected to be filed in September 2026.
•Pursuant to Missouri law, in November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.
•During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities, with various regulatory approvals pending. All of the solar generation facilities are aligned with the 2023 IRP discussed above, and expected capital expenditures related to these facilities are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below.
•Ameren Missouri's 2023 IRP targets cleaner and more diverse sources of energy generation, including solar generation. While rights to acquire build-transfer solar facilities and supplies for development-transfer and self-build solar facilities discussed above were secured through agreements, supply chain disruptions, including solar panel shortages and increasing material costs as a result of government tariffs and other factors, could affect the costs, as well as the timing, of these projects and other solar generation projects. The supply of
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solar panel components to the United States was significantly disrupted as a result of an investigation conducted by the United States Department of Commerce that concluded in August 2023 and found that exporters and producers of solar panel components from four Southeast Asian countries, with several exceptions, have been circumventing tariffs imposed on imports from China. As a result of the investigation, importers and exporters may submit certain certifications to the United States Department of Commerce to avoid the imposition of increased tariffs. Failure to submit the applicable certifications, or denial of the submitted certifications by the United States Department of Commerce, could result in increased tariffs on solar panel components that were subject to the investigation and entered the United States on or after April 1, 2022. Additionally, certain solar panel components from China have been subject to detention by the United States Customs and Border Protection Agency as a result of the Uyghur Forced Labor Prevention Act that became effective in June 2022. Also, in June 2022, President Biden took executive action to temporarily lift certain tariffs on solar panel components imported from the four Southeast Asian countries investigated by the United States Department of Commerce for 24 months in order to allow the United States access to a sufficient supply of solar panel components. Any future tariffs or actions by the United States Customs and Border Protection Agency could affect the cost and the availability of solar panel components and the timing and amount of Ameren Missouri's estimated capital expenditures associated with solar generation investments.
•Through 2028, 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 $22.8 billion (Ameren Missouri – up to $13.5 billion; Ameren Illinois – up to $7.6 billion; ATXI – up to $1.7 billion) of capital expenditures during the period from 2024 through 2028. Ameren’s and Ameren Missouri’s estimates include $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments through 2028, consistent with Ameren Missouri’s 2023 IRP. Ameren’s and Ameren Illinois’ estimates include investments necessary to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained. Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.
•In 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 July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade. In October 2023, the FERC issued an order that approved transmission rate incentives relating to the projects assigned to Ameren. The incentives will allow construction work in progress to be included in rate base for projects constructed by ATXI, thereby improving the timeliness of cash recovery, and would allow recovery of prudently incurred costs, subject to FERC approval, for any portion of the projects if they are abandoned for reasons beyond the control of Ameren. As a result of the order, ATXI will not capitalize allowance for funds used during construction on the related projects. In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects. In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion. The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024. In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed above that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025. In November 2022, the MISO released plans for a second tranche of projects and began the process of identifying a list of projects for consideration under this tranche. Ameren expects the second tranche of projects to be approved in the first half of 2024. In July 2022, a group of industrial customers filed a complaint with the FERC, challenging provisions of a MISO tariff that exclude regional transmission projects from the MISO’s competitive bid process based on state laws related to the right of first refusal, which provide an incumbent utility the right to build, maintain, and own transmission lines located within its service territory. The complaint seeks to require MISO to revise its tariff to prohibit the application of state laws related to the right of first refusal in the MISO’s long-range transmission planning and require projects to be bid on a competitive basis, to the maximum extent possible. It also is asking for refunds related to any costs under the tariff that would not comply with the sought-after revisions. The FERC is under no deadline to issue an order in this proceeding.
•In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from the MISO’s April 2022 capacity auction, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study of continued participation in the MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a period of five to 10 years beginning June 2024. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study.
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•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, could result in significant increases in capital expenditures and operating costs. Regulations can be reviewed and repealed, and replacement or alternative regulations can be proposed or adopted by the current federal administration, including the EPA. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, for additional information on environmental matters, including the NSR and Clean Air Act litigation. The ultimate implementation of any of these new 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 $2.6 billion of credit through December 2027, 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 $3.2 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for outstanding forward sale agreements under the ATM, long-term debt issuances through the date of this report, and maturities of long-term debt from 2024 to 2028 and beyond at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI. 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, 2023, for Ameren, Ameren Missouri, and Ameren Illinois. Ameren, Ameren Missouri, and Ameren Illinois each believe that their liquidity is adequate given their respective expected operating cash flows, capital expenditures, and financing plans, and expect to continue to have access to the capital and credit 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 to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2028. Additionally, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. As of December 31, 2023, Ameren had multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 2.9 million shares of common stock. Ameren expects to settle approximately $230 million of the forward sale agreements with physical delivery of 2.9 million shares of common stock by December 31, 2024. Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue approximately $300 million of equity in 2024 and approximately $600 million of equity each year from 2025 to 2028. As of December 31, 2023, Ameren had approximately $770 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2023. Ameren expects its equity to total capitalization 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).
•The IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates clean energy tax credits for projects placed in service after 2024. The clean energy tax credits will apply to renewable energy production and investments, along with certain nuclear energy production, and will be phased out beginning in 2033, at the earliest. The phase-out is triggered when greenhouse gas emissions from the electric generation industry are reduced by at least 75% from the annual 2022 emission rate or at the beginning of 2033, whichever is later. The law allows for transferability to an unrelated party for cash of up to 100% of certain tax credits generated after 2022. In addition, the new law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the IRA have been and are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren as discussed below.
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•Pursuant to the IRA discussed above, Ameren expects to transfer production tax credits generated by Ameren Missouri’s High Prairie Renewable and Atchison Renewable energy centers, as well as the solar facilities included in Ameren Missouri’s 2023 IRP discussed above, to unrelated parties from 2024 to 2028.
•In April 2023, the IRS issued guidance providing a safe harbor method of accounting for the capitalization or deduction of certain expenditures to maintain, repair, replace, or improve natural gas distribution property. The safe harbor method of accounting may be implemented in the first, second, or third taxable year ending after May 1, 2023. Ameren is currently evaluating the potential impact of this guidance, including the timing of adoption.
•As of December 31, 2023, Ameren had $176 million in tax benefits from federal and state income tax credit carryforwards and $42 million in tax benefits from state net operating loss carryforwards, which will be utilized in future periods. Future expected income tax payments are based on expected taxable income, available income tax credit and net operating loss carryforwards, and current tax law. Expected taxable income is affected by expected capital expenditures, when property, plant, and equipment is placed in-service or retired, and the timing of regulatory reviews, among other things. Based on preliminary calculations, Ameren does not expect to be subject to the 15% minimum tax on adjusted financial statement income imposed by the IRA through 2028. Ameren expects annual federal income tax payments to be immaterial through 2028.
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 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.
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| 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 Illinois, 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 the MYRP process, effective in 2024, which includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap •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, enacted 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 or refund, and are collected or refunded within 24 months following the end of the annual period in which they are recognized. Under the MYRP, Ameren Illinois' base rates for a particular calendar year are based on the forecasts of recoverable costs, average annual rate base, and capital structure. An ICC-determined ROE is applied to determine the base rates for a particular calendar year. Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Variations in investments made or orders by the ICC can result in a subsequent change in Ameren Illinois’ resulting estimated regulatory assets or liabilities. 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. Variations in investments made or orders by the FERC or courts can result in a subsequent change in Ameren Illinois’ and ATXI’s estimated regulatory assets or liabilities. 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.
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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, 2023:
| Ameren | Ameren Missouri | Ameren Illinois | ||||||||||||||||||
| Gains | $ | 3,078 | $ | 1,916 | $ | 1,058 | ||||||||||||||
| Other comprehensive income (before taxes) - pension and other postretirement benefit plan activity | 346 | 202 | 144 | |||||||||||||||||
| 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 •Health care cost trend rates •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, future compensation, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies, including 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, 2023:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||
| Net Periodic Benefit Cost | Projected Pension Benefit Obligation | Net Periodic Benefit Cost | Projected Postretirement Benefit Obligation | |||||||||||||||||||||||||||||
| 0.25% decrease in discount rate | $ | 12 | $ | 121 | $ | 2 | $ | 23 | ||||||||||||||||||||||||
| 0.25% decrease in return on assets | 12 | (a) | 4 | (a) | ||||||||||||||||||||||||||||
| 0.25% increase in future compensation | 3 | 11 | (a) | (a) | ||||||||||||||||||||||||||||
(a)Not applicable.
| 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 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 | |||||||
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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 | |||||||
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. Additional interpretations, regulations, amendments, or technical corrections related to the federal income tax code as a result of the IRA, may impact the estimates for income taxes discussed above. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information on the IRA and the amount of deferred income taxes recorded at December 31, 2023.
| 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
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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, 2023.
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, 2023:
| Change in Callaway Energy Center’s Key ARO Assumptions | Increase (Decrease) to ARO | ||||
| Discount rate decreased by 0.10% | $ | 12 | |||
| Cost escalation rate increased by 0.25% | 28 | ||||
| Increase in the estimated decommissioning costs by 10% | 45 | ||||
| Two-year deferral in timing of cash expenditures | (30) | ||||
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 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 the 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 AROs, 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 AROs, 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, 2023 is immaterial.
The allowed ROE under Ameren Illinois’ 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’
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annual ROE for its electric energy-efficiency investments is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. 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, 2023.
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 subject to credit risk primarily consist of trade accounts receivables and executory contracts with market risk exposures. Credit risk associated with trade receivables is mitigated by our diversified customer base. At December 31, 2023, 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 from the alternative retail electric suppler. As of December 31, 2023, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $42 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 economic conditions, including inflationary pressures, on customer collections and customer account balances. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances. See Note 15 – Supplemental Information under Part II, Item 8, 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, 2023.
Investment Price Risk
Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and COLI 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 2024 assumed return on plan assets of 6.75%.
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, 2023, this fund was invested in domestic equity securities (68%) and debt securities (31%). 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.
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Additionally, Ameren and Ameren Illinois have COLI contracts with net cash surrender values of $144 million and $7 million, respectively, as of December 31, 2023. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest. As of December 31, 2023, that separate account is comprised of approximately 50% equity securities and 50% debt securities. To the extent not recovered through customer 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. 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 2023, Ameren Illinois procured power on behalf of its customers for 28% of its total kilowatthour sales. Ameren Illinois purchases energy and capacity through bilateral contracts resulting from IPA procurement events, with any remaining needs procured through the MISO marketplace. Ameren Illinois has purchased approximately 15% of its June 2024 to May 2025 capacity needs bilaterally, however, this percentage beyond May 2025 will be dependent on the results of future IPA procurement events. Daily energy balancing is also handled through the MISO marketplace. The IPA has proposed and the ICC has approved multiple procurement events covering portions of years through 2027 for capacity and energy. Ameren Illinois has also entered into ICC-approved contracts for zero emission credits through May 2027 and for renewable energy credits with various terms, including contracts with 20-year terms ending 2032, and contracts entered into beginning in 2018 through 2024 with 15- to 20-year terms. 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, 2023, 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 2024 through 2028. 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.
| 2024 | 2025 | 2026 – 2028 | |||||||||||||||
| Ameren: | |||||||||||||||||
Coal(a) | 98 | % | 85 | % | 48 | % | |||||||||||
Coal transportation(a) | 100 | 100 | 98 | ||||||||||||||
| Nuclear fuel | (b) | 100 | 100 | ||||||||||||||
Natural gas for distribution(c) | 97 | 50 | 27 | ||||||||||||||
Purchased power for Ameren Illinois(d) | 77 | 37 | 11 | ||||||||||||||
| Ameren Missouri: | |||||||||||||||||
Coal(a) | 98 | % | 85 | % | 48 | % | |||||||||||
Coal transportation(a) | 100 | 100 | 98 | ||||||||||||||
| Nuclear fuel | (b) | 100 | 100 | ||||||||||||||
Natural gas for distribution(c) | 90 | 57 | 31 | ||||||||||||||
| Ameren Illinois: | |||||||||||||||||
Natural gas for distribution(c) | 98 | % | 49 | % | 26 | % | |||||||||||
Purchased power(d) | 77 | 37 | 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.
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(b)The Callaway Energy Center requires 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 2024.
(c)Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2024 represents January 2024 through March 2024. The year 2025 represents November 2024 through March 2025. This continues each successive year through March 2028.
(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 2028 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. 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 for contingency purposes. Ameren Missouri is awaiting approval from the NRC, which is under no deadline to issue the approval.
Ameren Missouri received a planned delivery of enriched uranium from a Russian supplier in the spring of 2023. The planned delivery concluded the nuclear fuel supply agreement with this Russian supplier with no future deliveries planned with any Russian suppliers. Ameren Missouri has sufficient inventory and supply contracts with non-Russian suppliers that adequately meet all of the nuclear fuel needs of the Callaway Energy Center through the spring 2028 refueling.
Ameren Missouri's 2023 IRP targets cleaner and more diverse sources of energy generation, including solar generation. While rights to acquire build-transfer solar facilities and supplies for development-transfer and self-build solar facilities totaling 900 MWs were secured through agreements, supply chain disruptions, including solar panel shortages and increasing material costs as a result of government tariffs and other factors, could affect the costs, as well as the timing, of these projects and other solar generation projects. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on the solar facilities. See Outlook under Part II, Item 7, of this report for additional information on the United States Department of Commerce investigation into the supply of solar panels and the actions taken by the United States Customs and Border Protection Agency to detain certain solar panel shipments from China. Any future tariffs or actions by the United States Customs and Border Protection Agency could affect the cost and the availability of solar panel components and the timing and amount of Ameren Missouri's estimated capital expenditures associated with solar generation investments.
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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 sheet of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, 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, 2023, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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.
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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, 2023, there were approximately $2.2 billion of regulatory assets and approximately $5.6 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 29, 2024
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
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 consolidated balance sheet of Union Electric Company and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related consolidated statements of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated 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 consolidated 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 consolidated 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 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. 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 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, 2023, there were approximately $0.9 billion of regulatory assets and approximately $3.0 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
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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 29, 2024
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.
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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 sheet of Ameren Illinois Company (the “Company”) as of December 31, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, there were approximately $1.3 billion of regulatory assets and approximately $2.5 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
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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 29, 2024
We have served as the Company’s auditor since 1998.
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AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions, except per share amounts)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Electric | $ | 6,439 | $ | 6,581 | $ | 5,297 | |||||||||||
| Natural gas | 1,061 | 1,376 | 1,097 | ||||||||||||||
| Total operating revenues | 7,500 | 7,957 | 6,394 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 514 | 473 | 581 | ||||||||||||||
| Purchased power | 1,298 | 1,547 | 606 | ||||||||||||||
| Natural gas purchased for resale | 355 | 657 | 442 | ||||||||||||||
| Other operations and maintenance | 1,866 | 1,937 | 1,774 | ||||||||||||||
| Depreciation and amortization | 1,387 | 1,289 | 1,146 | ||||||||||||||
| Taxes other than income taxes | 522 | 539 | 512 | ||||||||||||||
| Total operating expenses | 5,942 | 6,442 | 5,061 | ||||||||||||||
| Operating Income | 1,558 | 1,515 | 1,333 | ||||||||||||||
| Other Income, Net | 348 | 226 | 202 | ||||||||||||||
| Interest Charges | 566 | 486 | 383 | ||||||||||||||
| Income Before Income Taxes | 1,340 | 1,255 | 1,152 | ||||||||||||||
| Income Taxes | 183 | 176 | 157 | ||||||||||||||
| Net Income | 1,157 | 1,079 | 995 | ||||||||||||||
| Less: Net Income Attributable to Noncontrolling Interests | 5 | 5 | 5 | ||||||||||||||
| Net Income Attributable to Ameren Common Shareholders | $ | 1,152 | $ | 1,074 | $ | 990 | |||||||||||
| Net Income | $ | 1,157 | $ | 1,079 | $ | 995 | |||||||||||
| Other Comprehensive Income (Loss), Net of Taxes | |||||||||||||||||
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(2), $(4), and $4, respectively | (5) | (14) | 14 | ||||||||||||||
| Comprehensive Income | 1,152 | 1,065 | 1,009 | ||||||||||||||
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 5 | 5 | 5 | ||||||||||||||
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 1,147 | $ | 1,060 | $ | 1,004 | |||||||||||
| Earnings per Common Share – Basic | $ | 4.39 | $ | 4.16 | $ | 3.86 | |||||||||||
| Earnings per Common Share – Diluted | $ | 4.38 | $ | 4.14 | $ | 3.84 | |||||||||||
| Weighted-average Common Shares Outstanding – Basic | 262.8 | 258.4 | 256.3 | ||||||||||||||
| Weighted-average Common Shares Outstanding – Diluted | 263.4 | 259.5 | 257.6 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 25 | $ | 10 | |||||||
| Accounts receivable – trade (less allowance for doubtful accounts of $30 and $31, respectively) | 494 | 600 | |||||||||
| Unbilled revenue | 319 | 446 | |||||||||
| Miscellaneous accounts receivable | 106 | 54 | |||||||||
| Inventories | 733 | 667 | |||||||||
| Current regulatory assets | 365 | 354 | |||||||||
| Investments in industrial development revenue bonds | — | 240 | |||||||||
| Current collateral assets | 14 | 142 | |||||||||
| Other current assets | 125 | 155 | |||||||||
| Total current assets | 2,181 | 2,668 | |||||||||
| Property, Plant, and Equipment, Net | 33,776 | 31,262 | |||||||||
| Investments and Other Assets: | |||||||||||
| Nuclear decommissioning trust fund | 1,150 | 958 | |||||||||
| Goodwill | 411 | 411 | |||||||||
| Regulatory assets | 1,810 | 1,426 | |||||||||
| Pension and other postretirement benefits | 581 | 411 | |||||||||
| Other assets | 921 | 768 | |||||||||
| Total investments and other assets | 4,873 | 3,974 | |||||||||
| TOTAL ASSETS | $ | 40,830 | $ | 37,904 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Current maturities of long-term debt | $ | 849 | $ | 340 | |||||||
| Short-term debt | 536 | 1,070 | |||||||||
| Accounts and wages payable | 1,136 | 1,159 | |||||||||
| Customer deposits | 176 | 115 | |||||||||
| Other current liabilities | 648 | 682 | |||||||||
| Total current liabilities | 3,345 | 3,366 | |||||||||
| Long-term Debt, Net | 15,121 | 13,685 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes and investment tax credits, net | 4,176 | 3,804 | |||||||||
| Regulatory liabilities | 5,512 | 5,309 | |||||||||
| Asset retirement obligations | 772 | 763 | |||||||||
| Other deferred credits and liabilities | 426 | 340 | |||||||||
| Total deferred credits and other liabilities | 10,886 | 10,216 | |||||||||
| Commitments and Contingencies (Notes 2, 9, and 14) | |||||||||||
| Shareholders’ Equity: | |||||||||||
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 266.3 and 262.0, respectively | 3 | 3 | |||||||||
| Other paid-in capital, principally premium on common stock | 7,216 | 6,860 | |||||||||
| Retained earnings | 4,136 | 3,646 | |||||||||
| Accumulated other comprehensive loss | (6) | (1) | |||||||||
| Total shareholders’ equity | 11,349 | 10,508 | |||||||||
| Noncontrolling Interests | 129 | 129 | |||||||||
| Total equity | 11,478 | 10,637 | |||||||||
| TOTAL LIABILITIES AND EQUITY | $ | 40,830 | $ | 37,904 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
89
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash Flows From Operating Activities: | |||||||||||||||||
| Net income | $ | 1,157 | $ | 1,079 | $ | 995 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | 1,432 | 1,373 | 1,219 | ||||||||||||||
| Amortization of nuclear fuel | 68 | 65 | 58 | ||||||||||||||
| Amortization of debt issuance costs and premium/discounts | 16 | 21 | 23 | ||||||||||||||
| Deferred income taxes and investment tax credits, net | 229 | 170 | 156 | ||||||||||||||
| Allowance for equity funds used during construction | (54) | (43) | (43) | ||||||||||||||
| Stock-based compensation costs | 26 | 24 | 22 | ||||||||||||||
| Other | 16 | 68 | 19 | ||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||
| Receivables | 144 | (317) | (74) | ||||||||||||||
| Inventories | (67) | (77) | (71) | ||||||||||||||
| Accounts and wages payable | (104) | 136 | 28 | ||||||||||||||
| Taxes accrued | (4) | (13) | 1 | ||||||||||||||
| Regulatory assets and liabilities | (165) | (72) | (439) | ||||||||||||||
| Assets, other | (109) | (74) | (71) | ||||||||||||||
| Liabilities, other | 115 | 52 | (75) | ||||||||||||||
| Pension and other postretirement benefits | (283) | (65) | (33) | ||||||||||||||
| Counterparty collateral, net | 147 | (64) | (54) | ||||||||||||||
| Net cash provided by operating activities | 2,564 | 2,263 | 1,661 | ||||||||||||||
| Cash Flows From Investing Activities: | |||||||||||||||||
| Capital expenditures | (3,597) | (3,351) | (3,479) | ||||||||||||||
| Nuclear fuel expenditures | (174) | (29) | (44) | ||||||||||||||
| Purchases of securities – nuclear decommissioning trust fund | (266) | (229) | (452) | ||||||||||||||
| Sales and maturities of securities – nuclear decommissioning trust fund | 240 | 216 | 439 | ||||||||||||||
| Other | (1) | 23 | 8 | ||||||||||||||
| Net cash used in investing activities | (3,798) | (3,370) | (3,528) | ||||||||||||||
| Cash Flows From Financing Activities: | |||||||||||||||||
| Dividends on common stock | (662) | (610) | (565) | ||||||||||||||
| Dividends paid to noncontrolling interest holders | (5) | (5) | (5) | ||||||||||||||
| Short-term debt, net | (533) | 522 | 55 | ||||||||||||||
| Maturities of long-term debt | (100) | (505) | (8) | ||||||||||||||
| Issuances of long-term debt | 2,295 | 1,467 | 1,997 | ||||||||||||||
| Issuances of common stock | 346 | 333 | 308 | ||||||||||||||
| Redemptions of Ameren Illinois preferred stock | — | — | (13) | ||||||||||||||
| Employee payroll taxes related to stock-based compensation | (20) | (16) | (17) | ||||||||||||||
| Debt issuance costs | (21) | (18) | (18) | ||||||||||||||
| Other | (10) | — | (13) | ||||||||||||||
| Net cash provided by financing activities | 1,290 | 1,168 | 1,721 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | 56 | 61 | (146) | ||||||||||||||
| Cash, cash equivalents, and restricted cash at beginning of year | 216 | 155 | 301 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at end of year | $ | 272 | $ | 216 | $ | 155 | |||||||||||
| Cash Paid (Refunded) During the Year: | |||||||||||||||||
| Interest (net of $48, $26, and $17 capitalized, respectively) | $ | 546 | $ | 476 | $ | 426 | |||||||||||
| Income taxes, net (includes production tax credit sale proceeds of $49, $—, and $—, respectively) | (24) | (8) | (1) | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
90
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Common Stock | $ | 3 | $ | 3 | $ | 3 | |||||||||||
| Other Paid-in Capital: | |||||||||||||||||
| Beginning of year | 6,860 | 6,502 | 6,179 | ||||||||||||||
| Settlement of non-ATM program forward sale agreement through common shares issuance | — | — | 113 | ||||||||||||||
| Shares issued under the ATM program | 299 | 292 | 148 | ||||||||||||||
| Shares issued under the DRPlus and 401(k) plan | 46 | 49 | 47 | ||||||||||||||
| Stock-based compensation activity | 11 | 17 | 15 | ||||||||||||||
| Other paid-in capital, end of year | 7,216 | 6,860 | 6,502 | ||||||||||||||
| Retained Earnings: | |||||||||||||||||
| Beginning of year | 3,646 | 3,182 | 2,757 | ||||||||||||||
| Net income attributable to Ameren common shareholders | 1,152 | 1,074 | 990 | ||||||||||||||
| Dividends on common stock | (662) | (610) | (565) | ||||||||||||||
| Retained earnings, end of year | 4,136 | 3,646 | 3,182 | ||||||||||||||
| Accumulated Other Comprehensive Income (Loss): | |||||||||||||||||
| Deferred retirement benefit costs, beginning of year | (1) | 13 | (1) | ||||||||||||||
| Change in deferred retirement benefit costs | (5) | (14) | 14 | ||||||||||||||
| Deferred retirement benefit costs, end of year | (6) | (1) | 13 | ||||||||||||||
| Total accumulated other comprehensive gain (loss), end of year | (6) | (1) | 13 | ||||||||||||||
| Total Shareholders’ Equity | $ | 11,349 | $ | 10,508 | $ | 9,700 | |||||||||||
| Noncontrolling Interests: | |||||||||||||||||
| Beginning of year | 129 | 129 | 142 | ||||||||||||||
| Net income attributable to noncontrolling interest holders | 5 | 5 | 5 | ||||||||||||||
| Dividends paid to noncontrolling interest holders | (5) | (5) | (5) | ||||||||||||||
| Redemptions of Ameren Illinois preferred stock | — | — | (13) | ||||||||||||||
| Noncontrolling interests, end of year | 129 | 129 | 129 | ||||||||||||||
| Total Equity | $ | 11,478 | $ | 10,637 | $ | 9,829 | |||||||||||
| Common stock shares outstanding at beginning of year | 262.0 | 257.7 | 253.3 | ||||||||||||||
| Shares issued under non-ATM program forward sale agreement | — | — | 1.6 | ||||||||||||||
| Shares issued under the ATM program | 3.2 | 3.4 | 1.8 | ||||||||||||||
| Shares issued under the DRPlus and 401(k) plan | 0.6 | 0.5 | 0.5 | ||||||||||||||
| Shares issued for stock-based compensation | 0.5 | 0.4 | 0.5 | ||||||||||||||
| Common stock shares outstanding at end of year | 266.3 | 262.0 | 257.7 | ||||||||||||||
| Dividends per common share | $ | 2.52 | $ | 2.36 | $ | 2.20 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
91
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Electric | $ | 3,694 | $ | 3,849 | $ | 3,212 | |||||||||||
| Natural gas | 165 | 197 | 141 | ||||||||||||||
| Total operating revenues | 3,859 | 4,046 | 3,353 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 514 | 473 | 581 | ||||||||||||||
| Purchased power | 483 | 677 | 227 | ||||||||||||||
| Natural gas purchased for resale | 79 | 104 | 60 | ||||||||||||||
| Other operations and maintenance | 1,003 | 1,028 | 948 | ||||||||||||||
| Depreciation and amortization | 783 | 732 | 632 | ||||||||||||||
| Taxes other than income taxes | 360 | 363 | 343 | ||||||||||||||
| Total operating expenses | 3,222 | 3,377 | 2,791 | ||||||||||||||
| Operating Income | 637 | 669 | 562 | ||||||||||||||
| Other Income, Net | 130 | 99 | 99 | ||||||||||||||
| Interest Charges | 227 | 213 | 137 | ||||||||||||||
| Income Before Income Taxes | 540 | 555 | 524 | ||||||||||||||
| Income Taxes (Benefit) | (8) | (10) | 3 | ||||||||||||||
| Net Income | 548 | 565 | 521 | ||||||||||||||
| Preferred Stock Dividends | 3 | 3 | 3 | ||||||||||||||
| Net Income Attributable to Ameren Common Shareholders | $ | 545 | $ | 562 | $ | 518 | |||||||||||
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
92
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | — | $ | — | |||||||
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | 204 | 244 | |||||||||
| Accounts receivable – affiliates | 72 | 51 | |||||||||
| Unbilled revenue | 163 | 184 | |||||||||
| Miscellaneous accounts receivable | 26 | 18 | |||||||||
| Inventories | 508 | 434 | |||||||||
| Current regulatory assets | 101 | 254 | |||||||||
| Investments in industrial development revenue bonds | — | 240 | |||||||||
| Current collateral assets | 5 | 101 | |||||||||
| Other current assets | 63 | 66 | |||||||||
| Total current assets | 1,142 | 1,592 | |||||||||
| Property, Plant, and Equipment, Net | 17,250 | 16,124 | |||||||||
| Investments and Other Assets: | |||||||||||
| Nuclear decommissioning trust fund | 1,150 | 958 | |||||||||
| Regulatory assets | 755 | 594 | |||||||||
| Pension and other postretirement benefits | 157 | 98 | |||||||||
| Other assets | 152 | 140 | |||||||||
| Total investments and other assets | 2,214 | 1,790 | |||||||||
| TOTAL ASSETS | $ | 20,606 | $ | 19,506 | |||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Current maturities of long-term debt | $ | 350 | $ | 240 | |||||||
| Short-term debt | 170 | 329 | |||||||||
| Borrowings from money pool | 306 | — | |||||||||
| Accounts and wages payable | 618 | 606 | |||||||||
| Accounts payable – affiliates | 53 | 43 | |||||||||
| Other current liabilities | 250 | 352 | |||||||||
| Total current liabilities | 1,747 | 1,570 | |||||||||
| Long-term Debt, Net | 5,991 | 5,846 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes and investment tax credits, net | 2,122 | 1,982 | |||||||||
| Regulatory liabilities | 2,959 | 2,871 | |||||||||
| Asset retirement obligations | 768 | 759 | |||||||||
| Other deferred credits and liabilities | 56 | 51 | |||||||||
| Total deferred credits and other liabilities | 5,905 | 5,663 | |||||||||
| 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 stock | 2,725 | 2,725 | |||||||||
| Preferred stock | 80 | 80 | |||||||||
| Retained earnings | 3,647 | 3,111 | |||||||||
| Total shareholders’ equity | 6,963 | 6,427 | |||||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 20,606 | $ | 19,506 | |||||||
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
93
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash Flows From Operating Activities: | |||||||||||||||||
| Net income | $ | 548 | $ | 565 | $ | 521 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | 827 | 816 | 704 | ||||||||||||||
| Amortization of nuclear fuel | 68 | 65 | 58 | ||||||||||||||
| Amortization of debt issuance costs and premium/discounts | 7 | 7 | 6 | ||||||||||||||
| Deferred income taxes and investment tax credits, net | 28 | 21 | 3 | ||||||||||||||
| Allowance for equity funds used during construction | (30) | (24) | (26) | ||||||||||||||
| Other | (8) | 14 | 19 | ||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||
| Receivables | 39 | (68) | (60) | ||||||||||||||
| Inventories | (74) | (15) | (32) | ||||||||||||||
| Accounts and wages payable | (8) | 19 | 28 | ||||||||||||||
| Taxes accrued | (17) | (21) | (27) | ||||||||||||||
| Regulatory assets and liabilities | (7) | (206) | (207) | ||||||||||||||
| Assets, other | (25) | 1 | 28 | ||||||||||||||
| Liabilities, other | 3 | 7 | (29) | ||||||||||||||
| Pension and other postretirement benefits | (106) | (16) | (2) | ||||||||||||||
| Counterparty collateral, net | 96 | (35) | (55) | ||||||||||||||
| Net cash provided by operating activities | 1,341 | 1,130 | 929 | ||||||||||||||
| Cash Flows From Investing Activities: | |||||||||||||||||
| Capital expenditures | (1,760) | (1,690) | (2,015) | ||||||||||||||
| Nuclear fuel expenditures | (174) | (29) | (44) | ||||||||||||||
| Purchases of securities – nuclear decommissioning trust fund | (266) | (229) | (452) | ||||||||||||||
| Sales and maturities of securities – nuclear decommissioning trust fund | 240 | 216 | 439 | ||||||||||||||
| Money pool advances, net | — | — | 139 | ||||||||||||||
| Other | — | 29 | 11 | ||||||||||||||
| Net cash used in investing activities | (1,960) | (1,703) | (1,922) | ||||||||||||||
| Cash Flows From Financing Activities: | |||||||||||||||||
| Dividends on common stock | (9) | (46) | (24) | ||||||||||||||
| Dividends on preferred stock | (3) | (3) | (3) | ||||||||||||||
| Short-term debt, net | (159) | 164 | 165 | ||||||||||||||
| Money pool borrowings, net | 306 | — | — | ||||||||||||||
| Maturities of long-term debt | — | (55) | (8) | ||||||||||||||
| Issuances of long-term debt | 499 | 524 | 524 | ||||||||||||||
| Debt issuance costs | (8) | (6) | (5) | ||||||||||||||
| Capital contribution from parent | — | — | 207 | ||||||||||||||
| Other | (10) | — | — | ||||||||||||||
| Net cash provided by financing activities | 616 | 578 | 856 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | (3) | 5 | (137) | ||||||||||||||
| Cash, cash equivalents, and restricted cash at beginning of year | 13 | 8 | 145 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at end of year | $ | 10 | $ | 13 | $ | 8 | |||||||||||
| Cash Paid (Refunded) During the Year: | |||||||||||||||||
| Interest (net of $27, $13, and $10 capitalized, respectively) | $ | 225 | $ | 230 | $ | 205 | |||||||||||
| Income taxes, net (includes production tax credit sale proceeds of $49, $—, and $—, respectively) | (19) | (20) | 19 | ||||||||||||||
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
94
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Common Stock | $ | 511 | $ | 511 | $ | 511 | |||||||||||
| Other Paid-in Capital: | |||||||||||||||||
| Beginning of year | 2,725 | 2,725 | 2,518 | ||||||||||||||
| Capital contribution from parent | — | — | 207 | ||||||||||||||
| Other paid-in capital, end of year | 2,725 | 2,725 | 2,725 | ||||||||||||||
| Preferred Stock | 80 | 80 | 80 | ||||||||||||||
| Retained Earnings: | |||||||||||||||||
| Beginning of year | 3,111 | 2,595 | 2,101 | ||||||||||||||
| Net income | 548 | 565 | 521 | ||||||||||||||
| Dividends on common stock | (9) | (46) | (24) | ||||||||||||||
| Dividends on preferred stock | (3) | (3) | (3) | ||||||||||||||
| Retained earnings, end of year | 3,647 | 3,111 | 2,595 | ||||||||||||||
| Total Shareholders’ Equity | $ | 6,963 | $ | 6,427 | $ | 5,911 | |||||||||||
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
95
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF INCOME
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Electric | $ | 2,585 | $ | 2,576 | $ | 1,938 | |||||||||||
| Natural gas | 897 | 1,180 | 957 | ||||||||||||||
| Total operating revenues | 3,482 | 3,756 | 2,895 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Purchased power | 820 | 880 | 400 | ||||||||||||||
| Natural gas purchased for resale | 276 | 553 | 382 | ||||||||||||||
| Other operations and maintenance | 818 | 882 | 820 | ||||||||||||||
| Depreciation and amortization | 556 | 514 | 472 | ||||||||||||||
| Taxes other than income taxes | 146 | 161 | 153 | ||||||||||||||
| Total operating expenses | 2,616 | 2,990 | 2,227 | ||||||||||||||
| Operating Income | 866 | 766 | 668 | ||||||||||||||
| Other Income, Net | 156 | 96 | 66 | ||||||||||||||
| Interest Charges | 204 | 168 | 164 | ||||||||||||||
| Income Before Income Taxes | 818 | 694 | 570 | ||||||||||||||
| Income Taxes | 209 | 179 | 143 | ||||||||||||||
| Net Income | 609 | 515 | 427 | ||||||||||||||
| Preferred Stock Dividends | 2 | 2 | 2 | ||||||||||||||
| Net Income Attributable to Ameren Common Shareholders | $ | 607 | $ | 513 | $ | 425 | |||||||||||
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
96
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
BALANCE SHEET
(In millions)
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| ASSETS | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | — | $ | — | |||||||
| Accounts receivable – trade (less allowance for doubtful accounts of $18 and $18, respectively) | 273 | 341 | |||||||||
| Accounts receivable – affiliates | 35 | 12 | |||||||||
| Unbilled revenue | 156 | 262 | |||||||||
| Miscellaneous accounts receivable | 44 | 23 | |||||||||
| Inventories | 225 | 233 | |||||||||
| Current regulatory assets | 252 | 87 | |||||||||
| Other current assets | 62 | 98 | |||||||||
| Total current assets | 1,047 | 1,056 | |||||||||
| Property, Plant, and Equipment, Net | 14,632 | 13,353 | |||||||||
| Investments and Other Assets: | |||||||||||
| Goodwill | 411 | 411 | |||||||||
| Regulatory assets | 1,035 | 821 | |||||||||
| Pension and other postretirement benefits | 394 | 318 | |||||||||
| Other assets | 603 | 482 | |||||||||
| Total investments and other assets | 2,443 | 2,032 | |||||||||
| TOTAL ASSETS | $ | 18,122 | $ | 16,441 | |||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||||
| Current Liabilities: | |||||||||||
| Current maturities of long-term debt | $ | — | $ | 100 | |||||||
| Short-term debt | 366 | 264 | |||||||||
| Borrowings from money pool | 135 | — | |||||||||
| Accounts and wages payable | 370 | 451 | |||||||||
| Accounts payable – affiliates | 52 | 93 | |||||||||
| Customer deposits | 141 | 87 | |||||||||
| Current regulatory liabilities | 71 | 64 | |||||||||
| Other current liabilities | 298 | 232 | |||||||||
| Total current liabilities | 1,433 | 1,291 | |||||||||
| Long-term Debt, Net | 5,232 | 4,735 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes and investment tax credits, net | 1,906 | 1,699 | |||||||||
| Regulatory liabilities | 2,418 | 2,313 | |||||||||
| Other deferred credits and liabilities | 308 | 235 | |||||||||
| Total deferred credits and other liabilities | 4,632 | 4,247 | |||||||||
| 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 capital | 3,020 | 2,929 | |||||||||
| Preferred stock | 49 | 49 | |||||||||
| Retained earnings | 3,756 | 3,190 | |||||||||
| Total shareholders’ equity | 6,825 | 6,168 | |||||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 18,122 | $ | 16,441 | |||||||
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
97
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF CASH FLOWS
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash Flows From Operating Activities: | |||||||||||||||||
| Net income | $ | 609 | $ | 515 | $ | 427 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | 557 | 514 | 471 | ||||||||||||||
| Amortization of debt issuance costs and premium/discounts | 5 | 11 | 13 | ||||||||||||||
| Deferred income taxes and investment tax credits, net | 177 | 117 | 165 | ||||||||||||||
| Allowance for equity funds used during construction | (19) | (18) | (17) | ||||||||||||||
| Other | 40 | 29 | 10 | ||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||
| Receivables | 129 | (250) | (17) | ||||||||||||||
| Inventories | 7 | (62) | (40) | ||||||||||||||
| Accounts and wages payable | (107) | 117 | 2 | ||||||||||||||
| Taxes accrued | (73) | 34 | 22 | ||||||||||||||
| Regulatory assets and liabilities | (152) | 134 | (222) | ||||||||||||||
| Assets, other | (123) | (67) | (75) | ||||||||||||||
| Liabilities, other | 106 | 42 | (46) | ||||||||||||||
| Pension and other postretirement benefits | (112) | (39) | (32) | ||||||||||||||
| Counterparty collateral, net | 54 | (29) | 1 | ||||||||||||||
| Net cash provided by operating activities | 1,098 | 1,048 | 662 | ||||||||||||||
| Cash Flows From Investing Activities: | |||||||||||||||||
| Capital expenditures | (1,731) | (1,601) | (1,432) | ||||||||||||||
| Other | (2) | (1) | (5) | ||||||||||||||
| Net cash used in investing activities | (1,733) | (1,602) | (1,437) | ||||||||||||||
| Cash Flows From Financing Activities: | |||||||||||||||||
| Dividends on common stock | (41) | — | — | ||||||||||||||
| Dividends on preferred stock | (2) | (2) | (2) | ||||||||||||||
| Short-term debt, net | 102 | 161 | 103 | ||||||||||||||
| Money pool borrowings, net | 135 | — | (19) | ||||||||||||||
| Maturities of long-term debt | (100) | (400) | — | ||||||||||||||
| Redemption of preferred stock | — | — | (13) | ||||||||||||||
| Issuances of long-term debt | 498 | 848 | 449 | ||||||||||||||
| Debt issuance costs | (5) | (10) | (6) | ||||||||||||||
| Capital contribution from parent | 91 | 15 | 262 | ||||||||||||||
| Other | — | — | (13) | ||||||||||||||
| Net cash provided by financing activities | 678 | 612 | 761 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | 43 | 58 | (14) | ||||||||||||||
| Cash, cash equivalents, and restricted cash at beginning of year | 191 | 133 | 147 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at end of year | $ | 234 | $ | 191 | $ | 133 | |||||||||||
| Cash Paid (Refunded) During the Year: | |||||||||||||||||
| Interest (net of $17, $12, and $7 capitalized, respectively) | $ | 195 | $ | 152 | $ | 148 | |||||||||||
| Income taxes, net | 102 | 23 | (41) | ||||||||||||||
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
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AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Common Stock | $ | — | $ | — | $ | — | |||||||||||
| Other Paid-in Capital: | |||||||||||||||||
| Beginning of year | 2,929 | 2,914 | 2,652 | ||||||||||||||
| Capital contribution from parent | 91 | 15 | 262 | ||||||||||||||
| Other paid-in capital, end of year | 3,020 | 2,929 | 2,914 | ||||||||||||||
| Preferred Stock: | |||||||||||||||||
| Beginning of year | 49 | 49 | 62 | ||||||||||||||
| Redemptions of preferred stock | — | — | (13) | ||||||||||||||
| Preferred stock, end of year | 49 | 49 | 49 | ||||||||||||||
| Retained Earnings: | |||||||||||||||||
| Beginning of year | 3,190 | 2,677 | 2,252 | ||||||||||||||
| Net income | 609 | 515 | 427 | ||||||||||||||
| Dividends on common stock | (41) | — | — | ||||||||||||||
| Dividends on preferred stock | (2) | (2) | (2) | ||||||||||||||
| Retained earnings, end of year | 3,756 | 3,190 | 2,677 | ||||||||||||||
| Total Shareholders’ Equity | $ | 6,825 | $ | 6,168 | $ | 5,640 | |||||||||||
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
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AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated) (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2023
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.
•ATXI operates a FERC rate-regulated electric transmission business in the MISO. ATXI was incorporated in Illinois in 2006. ATXI operates, among other assets, the Spoon River, Mark Twain, and Illinois Rivers transmission lines.
Ameren’s and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri’s subsidiaries were created for the ownership of renewable generation projects. Ameren Illinois has no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Our customer rates are regulated by the MoPSC, the ICC, and the FERC. We defer certain costs as assets pursuant to actions of rate regulators or because of expectations that we will be able to recover such costs in future rates charged to customers. We also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See Note 2 – Rate and Regulatory Matters for additional information on our regulatory frameworks, regulatory recovery mechanisms, and regulatory assets and liabilities recorded at December 31, 2023 and 2022.
We continually assess the recoverability of our regulatory assets and probability of refund of our regulatory liabilities. 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 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.
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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.
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 using the weighted-average cost method. 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 expenses related to scheduled Callaway nuclear refueling and maintenance outages 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. Other maintenance expenditures are expensed as incurred. 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 and Removal Costs 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 Ameren and Ameren Missouri’s balance sheets and then amortized to “Operating Expenses – Fuel” in their respective statements of income on a unit-of-production basis. Nuclear fuel amortization is reflected as a part of “Depreciation and amortization” on their respective statements of cash flow.
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 recovery of the remaining net book value of the asset to be abandoned. We recognize a loss on abandonment when it becomes probable that all or part of the cost of an asset, including a return at the applicable WACC, will be disallowed from recovery either through customer rates or through the issuance of securitized utility tariff bonds and such amount is reasonably estimable. An abandonment loss, if any, would equal the difference between the remaining net book value of the asset and the present value of the expected future cash flows. If the asset is still in service, the net book value is classified as plant to be abandoned, net, within “Property, Plant, and Equipment, Net” on the balance sheet. The net book value will be classified as a regulatory asset on the balance sheet when the asset is no longer in service or as required by a rate order.
In relation to the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies, in December 2021, Ameren Missouri filed a motion with the United States District Court for the Eastern District of Missouri to modify a previously issued remedy order to allow the retirement of the Rush Island Energy Center in lieu of installing a flue gas desulfurization system, which was granted to establish an October 15, 2024 retirement date. As of December 31, 2023 and 2022, 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, 2023 and 2022. Ameren Missouri concluded no abandonment loss was required for the Rush Island Energy Center as of December 31, 2023. 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. See Note 2 – Rate and Regulatory Matters for Ameren Missouri’s November 2023 petition filed with the MoPSC seeking securitization of the Rush Island Energy Center.
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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. See Asset Retirement Obligation and Removal Costs section below for additional information. The provision for depreciation for the Ameren Companies in 2023, 2022, and 2021 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, 2023 and 2022. 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, 2023 and 2022. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 2023 and 2022.
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, 2023. As part of this qualitative assessment, Ameren and Ameren Illinois evaluated, among other things, macroeconomic conditions, industry and market considerations such as observable industry market multiples, regulatory frameworks, cost factors, overall financial performance, and entity-specific events. The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was more likely than not that the fair value of each reporting unit exceeded its carrying value as of October 31, 2023, 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 material long-lived assets may not be recoverable in 2023, 2022, or 2021.
Variable Interest Entities
As of December 31, 2023 and 2022, Ameren had unconsolidated variable interests in various equity method investments, primarily to advance clean and resilient energy technologies, totaling $73 million and $68 million, respectively, included in “Other assets” on Ameren’s
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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, 2023, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $73 million plus associated outstanding funding commitments of $14 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. Depreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $9 million, $7 million, and $14 million for the years ended December 31, 2023, 2022, and 2021, 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.
COLI
Ameren (parent) and Ameren Illinois have COLI, 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, 2023, the cash surrender value of COLI at Ameren and Ameren Illinois was $248 million (December 31, 2022 – $246 million) and $111 million (December 31, 2022 – $118 million), respectively, while total borrowings against the policies were $104 million (December 31, 2022 – $110 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets. The net cash surrender value of Ameren’s COLI 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
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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, 2023 and 2022, 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 2023, 2022, or 2021.
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 an adjustment to compensation expense and recorded in the period that estimates are revised. Compensation cost is ultimately recognized only for awards for which the requisite service was provided. See Note 11 – Stock-based Compensation for additional information.
Unamortized Debt Discounts, Premiums, and Issuance Costs
Long-term debt discounts, premiums, and issuance costs are amortized over the lives of the related issuances. Credit agreement fees are amortized over the term of the agreement.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We expect that regulators will reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in certain excess 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.
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 subsidiary be allocated an amount of tax using a stand-alone calculation ratio to the total amount of tax owed by the consolidated group. Any net benefit attributable to Ameren (parent) is reallocated to the other subsidiaries. This reallocation is treated as a capital contribution to the subsidiary receiving the benefit. See Note 13 – Related-party Transactions for information regarding capital contributions under the tax allocation agreement.
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NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of our regulatory frameworks and significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.
Regulatory Frameworks
The following table presents the regulatory frameworks and significant regulatory recovery mechanisms for each of Ameren’s rate-regulated businesses, which are discussed in more detail below:
| Ameren Missouri | Ameren Illinois’ electric distribution business | Ameren Illinois’ natural gas delivery business | Ameren Illinois’ and ATXI’s electric transmission businesses | |||||||||||
| Regulatory framework | •Historical test year ratemaking •Natural gas revenues for residential customers adjusted for sales volume deviations resulting from weather through the WNAR | •MYRP(a) •Initial rates based on future test years •Revenues decoupled from sales volumes | •Future test year ratemaking •Revenues for residential and small nonresidential customers decoupled from sales volumes through the VBA | •Formula ratemaking •Initial rates based on future test year •Revenues decoupled from sales volumes | ||||||||||
| Regulatory mechanisms | •PISA Riders: •RESRAM •FAC •MEEIA •PGA •WNAR Trackers: •Pension and postretirement benefit costs •Certain excess deferred income taxes •Renewable energy standard costs •Property taxes •Production and investment tax credits or proceeds from the sale of certain tax credits allowed under the IRA | •Electric distribution service and energy-efficiency revenue requirement reconciliation adjustments(b) Riders: •Power procurement •Transmission services •Renewable energy credit compliance •Zero emission credits •Certain environmental costs •Bad debt write-offs •Costs of certain asbestos-related claims | Riders: •QIP(c) •PGA •VBA •Energy-efficiency program costs •Certain environmental costs •Bad debt write-offs •Invested capital taxes | •Revenue requirement reconciliation adjustment | ||||||||||
(a)Ameren Illinois used the IEIMA performance-based formula ratemaking framework to establish annual electric distribution customer rates effective through 2023. In December 2023, the ICC approved an MYRP to establish rates effective 2024 through 2027. See below for additional information regarding the MYRP approved in December 2023.
(b)Reconciliation adjustments under an MYRP are subject to a reconciliation cap which limits annual adjustment to 105%. See below for additional information regarding the reconciliation cap.
(c)The QIP expired in December 2023. Reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP from 2020 to 2023 are ongoing.
Missouri
The MoPSC regulates rates and other matters for Ameren Missouri’s electric service and natural gas distribution businesses. The rates Ameren Missouri charges customers for these services are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a historical test year and the revenue requirement established in the review.
Ameren Missouri has recovery mechanisms, including the RESRAM, FAC, MEEIA, PGA, and WNAR, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, along with the PISA, each described in more detail below, partially mitigate the effects of regulatory lag. Ameren Missouri also employs other recovery mechanisms, including a renewable energy standard cost tracker, as well as electric and natural gas trackers for uncertain income tax positions, certain excess deferred income taxes, property taxes, and pension and postretirement benefit costs. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability, with the difference expected to be reflected in base rates in a subsequent MoPSC rate order. Ameren Missouri also employs a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. Production and investment tax credits produced by renewable energy centers that support compliance with the state of Missouri’s renewable energy standard, such as the High Prairie Renewable and Atchison Renewable energy centers, are not eligible for tracking under this mechanism as they are included in the RESRAM. Ameren Missouri’s cost recovery under any of its recovery mechanisms is subject to MoPSC prudence reviews.
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The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense for investments in qualifying property, plant, and equipment placed in service and not included in base rates. Investments not eligible for recovery under the PISA include amounts related to new nuclear and natural gas generating units and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC until added to rate base prospectively. Ameren Missouri recognizes an offset to “Interest Charges” on its consolidated statement of income for its carrying cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its carrying cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service to comply with Missouri’s renewable energy standard. The RESRAM deferrals are a regulatory asset until they are included in customer rates and collected in a subsequent period. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. The rate increase approved by the June 2023 MoPSC electric rate order discussed below did not exceed the rate increase limitation applicable through 2023. Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through December 2028 and an additional extension through December 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things. This law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates, compared to the revenue requirement established in the immediately preceding rate order, due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024.
The RESRAM permits Ameren Missouri to recover or refund, through customer rates, the difference between the cost of compliance, net of federal production and investment tax credits, with Missouri’s renewable energy standard and the amount set in base rates. Effective February 28, 2022, all sales from the High Prairie Renewable and Atchison Renewable energy centers are included in the RESRAM. Previously, 95% of these sales were included in the FAC and 5% were included in the RESRAM. Customer rates are adjusted for the RESRAM on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. The difference between actual compliance costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. RESRAM regulatory assets earn carrying costs at short-term interest rates. The RESRAM permits Ameren Missouri to recover investments in wind generation and other renewables related to compliance with Missouri’s renewable energy standard, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism, such as the renewable energy standard cost tracker. The renewable energy standard cost tracker allows Ameren Missouri to defer differences between actual costs primarily associated with the Maryland Heights Energy Center and renewable energy credits obtained through a 102-MW power purchase agreement with a wind farm operator, which expires in August 2024, and those costs included in customer rates.
The FAC permits Ameren Missouri to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional regulatory rate review, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. As such, Ameren Missouri’s results of operations are affected by the 5% not recovered or refunded under the FAC. The 95% variance in net energy costs in a given period is deferred as a regulatory asset or liability, and either billed or refunded to customers in a subsequent period. FAC regulatory assets earn carrying costs at short-term interest rates. Ameren Missouri’s base rates for electric service are required to be reset at least every four years to allow for continued use of the FAC.
The MEEIA permits Ameren Missouri to recover customer energy-efficiency program costs, the related lost electric margins, and any performance incentive through the MEEIA without a traditional regulatory rate review, subject to MoPSC prudence reviews. MEEIA assets earn carrying costs at short-term interest rates.
Ameren Missouri is a member of the MISO, and its transmission rate is calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. The FERC regulates the rates charged and the terms and conditions for wholesale electric transmission service. The transmission rate update each June is based on Ameren Missouri’s actual historical cost from the prior calendar year. This rate is not directly charged to Missouri retail customers because, in Missouri, the revenue requirement used to set bundled retail base rates includes an amount for transmission-related costs and revenues.
The PGA allows Ameren Missouri to recover costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review, subject to MoPSC prudence reviews. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The WNAR allows Ameren Missouri to adjust natural gas delivery service rates charged to residential customers without a traditional regulatory rate review when
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deviations from normal weather conditions cause natural gas revenues to vary from the related revenue requirement approved by the MoPSC in the previous regulatory rate review. The impact of deviations from normal weather on natural gas delivery service revenues billed to residential customers in a given period are deferred as a regulatory asset or liability. WNAR regulatory assets earn carrying costs at short-term interest rates. The deferred amount is either billed or refunded to residential customers in a subsequent period.
Illinois
The ICC regulates rates and other matters for Ameren Illinois’ electric distribution service and natural gas distribution businesses. Ameren Illinois used the IEIMA formula framework to establish annual customer electric distribution service rates effective through 2023. Under the framework, Ameren Illinois is allowed to reconcile its revenue requirement for customer rates established through 2023. Ameren Illinois’ 2021, 2022, and 2023 revenues reflected each year’s actual recoverable costs, year-end rate base, and a return at the applicable WACC, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The 2022 and 2023 revenue requirement reconciliation adjustments will be collected from customers within two years from the end of the reconciled year. By law, the decoupling provisions extend beyond 2023, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. The rates Ameren Illinois charges customers for natural gas distribution service are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a future test year and the revenue requirement established in the review.
Ameren Illinois’ electric distribution service has cost recovery mechanisms in place that allow customer rates to be adjusted without an MYRP or a traditional regulatory rate review. Ameren Illinois’ electric distribution service business has riders for power procurement and transmission services incurred on behalf of its customers, renewable energy credit compliance, zero emission credits, and certain environmental costs, as well as bad debt write-offs and the costs of certain asbestos-related claims not recovered in base rates. These pass-through costs do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
Pursuant to the CEJA, Ameren Illinois may elect to establish electric distribution service rates through either an MYRP or a traditional regulatory rate review for 2024 and beyond. See below for additional information regarding the MYRP approved by the ICC in December 2023, which established rates effective 2024 through 2027. Under the MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs are excluded from the reconciliation cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and amortization of certain assets. The reconciliation cap also excludes costs recovered outside of base rates through riders, such as those described above and the electric energy-efficiency rider discussed below, among others. Ameren Illinois’ existing riders remain effective and electric distribution service revenues continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year incorporates Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the resulting revenue requirement does not exceed the 105% reconciliation cap and the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. Subject to the reconciliation cap, if a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the applicable annual period. Regulatory assets applicable to the MYRP earn a return at the applicable WACC. However, Ameren Illinois recognizes the carrying cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates.
Ameren Illinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for its electric energy-efficiency investments, the revenue requirements are based on recoverable costs, year-end rate base, and a year-end ratemaking capital structure, and earn a return at the applicable WACC. The ROE component of the applicable WACC is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points and any performance-related basis-point adjustments, described in more detail below. Therefore, Ameren Illinois’ annual ROE for its electric energy-efficiency investments is directly correlated to the yields on such bonds. Regulatory assets applicable to formula ratemaking for electric energy-efficiency investments earn a return at the applicable WACC. However, Ameren Illinois recognizes the carrying cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates.
Ameren Illinois’ electric distribution service business is also subject to performance metrics. Failure to achieve the metrics would result in a reduction in the company’s allowed ROE calculated under the MYRP. In 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points under the MYRP, allocated among seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of
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spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, the allowed ROE on energy-efficiency investments can be increased or decreased up to 200 basis points, depending on the achievement of annual energy savings goals. Any adjustments to the allowed ROE for energy-efficiency investments will depend on annual performance for a historical period relative to energy savings goals. In 2023, 2022, and 2021, there were no performance-related basis-point adjustments that materially affected financial results.
Ameren Illinois’ natural gas distribution business has recovery mechanisms, including the PGA and VBA, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, described in more detail below, mitigate the effects of regulatory lag. Ameren Illinois employs other riders for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt write-offs and invested capital taxes not recovered in base rates. Pass-through costs under the riders do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
The PGA allows Ameren Illinois to recover costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review, subject to ICC prudence reviews. These pass-through purchased gas costs do not affect Ameren Illinois natural gas margins, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The VBA ensures recoverability of the natural gas distribution service revenue requirement that is dependent on sales volumes for residential and small nonresidential customers. For these rate classes, the VBA allows Ameren Illinois to adjust natural gas distribution service rates without a traditional regulatory rate review when changes occur in sales volumes from those volumes approved by the ICC in a previous regulatory rate review. The difference between allowed sales revenues and amounts billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is collected from, or refunded to, customers in a subsequent period. VBA regulatory assets for a given year that are not fully collected by the end of the following year begin earning carrying costs at short-term interest rates.
The QIP expired in December 2023. Previously, it provided Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that were placed in service between regulatory rate reviews. Infrastructure investments under the QIP earned a return at the applicable WACC. Eligible natural gas investments included projects to improve safety and reliability and modernization investments, such as smart meters. The deferrals were recorded as a regulatory asset, with recovery beginning two months after the qualifying natural gas plant was placed in service and continuing until such plant was included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP was subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. Ameren Illinois did not exceed the rate impact limitation in 2023. Upon issuance of a natural gas delivery service rate order, QIP rate base was transferred to base rates and the QIP was reset to zero. Reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP are still ongoing. See below for additional information on the recovery of capital investments that were made during 2020.
Federal
The FERC regulates rates and other matters for Ameren Illinois’ transmission business and ATXI, as well as for Ameren Missouri. See the discussion above related to Ameren Missouri. Both Ameren Illinois and ATXI are members of the MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated annually and become effective each January with forecasted information. The formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed ROE. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is collected from, or refunded to, customers within two years from the end of the year. FERC revenue requirement reconciliation adjustment regulatory assets earn carrying costs at each company’s short-term interest rates. In addition, the FERC has approved transmission rate incentives, including a 50-basis-point incentive adder to the allowed base ROE for Ameren Illinois and ATXI for participation in an RTO.
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Proceedings and Updates
Missouri
June 2023 MoPSC Electric Rate Order
In June 2023, the MoPSC issued an order in Ameren Missouri’s 2022 electric service regulatory rate review, approving a nonunanimous stipulation and agreement. The order resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The approved revenue requirement was based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to 2030. The order did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard compliance costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker. It also includes a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. Production and investment tax credits produced by renewable energy centers that support compliance with the state of Missouri’s renewable energy standard, such as the High Prairie Renewable and Atchison Renewable energy centers, are not eligible for tracking under this mechanism as they are included in the RESRAM. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023.
Solar Generation Facilities
During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities, which, if placed in-service, would be eligible for recovery under the PISA. The following table provides information with respect to each agreement:
Huck Finn Solar Project(a)(b) | Boomtown Solar Project(b)(c) | Split Rail Solar Project(d) | Cass County Solar Project(c) | Vandalia Solar Project(d) | Bowling Green Solar Project(d) | |||||||||||||||
| Agreement type | Build-transfer | Build-transfer | Build-transfer(e) | Development-transfer(e)(f) | Self-build(e)(g) | Self-build(e)(g) | ||||||||||||||
| Facility size | 200-MW | 150-MW | 300-MW | 150-MW | 50-MW | 50-MW | ||||||||||||||
| Status of MoPSC CCN | Approved February 2023 | Approved April 2023 | Filed June 2023(h) | Filed June 2023(h) | Filed June 2023(h) | Filed June 2023(h) | ||||||||||||||
| Status of FERC approval of acquisition | Received March 2023 | Received October 2023 | Expect to request by mid-2024 | Not applicable | Not applicable | Not applicable | ||||||||||||||
Earliest completion date(i) | Fourth quarter 2024 | Fourth quarter 2024 | Mid-2026 | Fourth quarter 2024 | Fourth quarter 2025 | First quarter 2026 | ||||||||||||||
(a)The Huck Finn Solar Project is expected to support Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Investments in the project will be eligible for recovery under the RESRAM.
(b)These projects collectively represent approximately $0.65 billion of expected capital expenditures.
(c)The Boomtown and Cass County solar projects are expected to support Ameren Missouri’s transition to renewable energy generation and serve customers under the Renewable Solutions Program discussed below.
(d)These solar projects are expected to support Ameren Missouri’s transition to renewable energy generation.
(e)These projects, and applicable agreements, are subject to the issuance of a CCN by the MoPSC.
(f)Ameren Missouri entered into an agreement to acquire the Cass County Solar Project, which includes project design, land rights, and engineering, procurement, and construction agreements for a solar generation facility. Ameren Missouri will construct the facility after obtaining a CCN from the MoPSC and acquiring the project. Acquisition of the project is expected by mid-2024.
(g)Ameren Missouri entered into engineering, procurement, and construction agreements to construct these solar projects.
(h)In February 2024, Ameren Missouri, the MoPSC staff, and the MoOPC filed a nonunanimous stipulation and agreement requesting the MoPSC approve Ameren Missouri’s requests for CCNs for the Split Rail, Vandalia, and Bowling Green solar projects. The stipulation and agreement also requests MoPSC approval of the CCN request for the Cass County Solar Project conditioned upon the facility supporting the Renewable Solutions Program discussed below and full subscription of the portion of the program supported by this facility, subject to certain other terms and conditions. The remaining intervenors did not object to the agreement. Ameren Missouri expects a decision by the MoPSC in March 2024.
(i)Expected completion dates are dependent on the timing of regulatory approvals, among other things.
Renewable Solutions Program
The April 2023 MoPSC order approving the CCN for the Boomtown Solar Project also approved Ameren Missouri’s Renewable Solutions Program and a tariff related to participation in the program. The program allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. Separate enrollment occurs for each
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renewable resource serving customers under the program. Collection under the tariff will not begin until the Boomtown Solar Project is placed in service.
MoPSC Staff Review of Planned Rush Island Energy Center Retirement
In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center as a result of the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies. The MoPSC staff’s review includes potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. Ameren Missouri is unable to predict the results of this matter. Results of the review could be used in the securitization proceeding discussed below, which could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri if Ameren Missouri is not allowed to recover Rush Island costs through securitization.
Securitization of Rush Island Energy Center Costs
In November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.
MEEIA
In August 2023, the MoPSC issued an order approving a nonunanimous stipulation and agreement to extend Ameren Missouri’s MEEIA 2019 program for an additional year through 2024. For 2024, the order approved the establishment of a portfolio of customer energy-efficiency programs and performance incentives that will provide Ameren Missouri an opportunity to earn revenues, including $12 million of performance incentive revenues if Ameren Missouri achieves certain program spending goals. In 2024, Ameren Missouri expects to invest $76 million in energy-efficiency programs.
In December 2023 and 2022, Ameren Missouri achieved certain energy-efficiency spending goals for the MEEIA 2019 program. As a result of achieving these spending goals and MoPSC orders issued in August 2022 and September 2021, Ameren Missouri recognized performance incentive revenues of $12 million, $22 million, and $9 million in 2023, 2022, and 2021, respectively.
In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA. This filing proposed a three-year plan, which includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.
Illinois
MYRP
In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding. Rate changes consistent with the order became effective in January 2024. The ICC concluded that the proposed Grid Plan did not meet certain statutory
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requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The ICC will be under no deadline to act on the revised Grid Plan when filed. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027, using the 2022 year-end rate base approved by the ICC in its 2022 electric distribution service revenue requirement reconciliation adjustment order discussed below. This rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement.
In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements and annual rate base amounts to reflect a base level of investments to maintain grid reliability for 2024 through 2027. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District.
The following table presents the approved revenue requirements, ROE, capital structure common equity percentage, and annual rate base in the ICC’s December 2023 order, as well as the proposed revenue requirements and annual rate base amounts in Ameren Illinois’ February 2024 rehearing request filing:
| Year | Revenue Requirement (in millions) | ROE | Capital Structure Common Equity Percentage | Annual Rate Base (in billions) | ||||||||||
| ICC’s December 2023 MYRP Order: | ||||||||||||||
| 2024 | $1,162 | 8.72% | 50% | $3.9 | ||||||||||
| 2025 | $1,210 | 8.72% | 50% | $3.9 | ||||||||||
| 2026 | $1,242 | 8.72% | 50% | $3.9 | ||||||||||
| 2027 | $1,255 | 8.72% | 50% | $3.9 | ||||||||||
| Ameren Illinois’ February 2024 Rehearing Request Filing: | ||||||||||||||
| 2024 | $1,214 | (a) | 50% | $4.2 | ||||||||||
| 2025 | $1,300 | (a) | 50% | $4.5 | ||||||||||
| 2026 | $1,371 | (a) | 50% | $4.7 | ||||||||||
| 2027 | $1,420 | (a) | 50% | $4.9 | ||||||||||
(a)The ROE is under appeal as discussed above.
The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase.
2022 Electric Distribution Revenue Requirement Reconciliation Adjustment Order
In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $110 million, which reflected Ameren Illinois’ actual 2022 recoverable costs, year-end rate base of $3.9 billion, and a capital structure composed of 50% common equity. The approved reconciliation adjustment will be collected from customers in 2024. In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base. The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.
Electric Customer Energy-Efficiency Investments
In November 2023, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $100 million beginning in January 2024, which represents an increase of $24 million from 2023 rates. The order was based on a projected 2024 year-end rate base of $394 million.
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2023 Natural Gas Delivery Service Rate Order
In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million based on a 9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of approximately $2.85 billion. The order reflected a reduction of approximately $93 million of planned distribution and transmission capital investments included in Ameren Illinois’ requested revenue increase, which used a 2024 future test year. The new rates became effective on November 28, 2023.
In December 2023, Ameren Illinois filed a request for rehearing of the ICC's November 2023 order. The filing requested the ICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request. Subsequently, in January 2024, Ameren Illinois filed an appeal of the November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal.
The ICC’s November 2023 natural gas delivery service rate order also required Ameren Illinois to submit a plan outlining how it expects to comply with new PHMSA rules for natural gas transmission pipelines, including proposing a capital expenditures plan necessary to meet the new rules. In February 2024, Ameren Illinois filed its plan with the ICC, which included its proposal of natural gas transmission capital expenditures necessary to achieve compliance with the PHMSA rules. The plan includes delays to certain natural gas transmission capital expenditures from 2024 to subsequent years to align with the November 2023 ICC order. The ICC is under no obligation to issue an order regarding Ameren Illinois’ plan.
Future of Gas Proceeding
The ICC’s November 2023 natural gas delivery service rate order discussed above directed the ICC staff to develop a plan for a future of gas proceeding. All of the Illinois natural gas utilities subject to ICC regulation will be included in this proceeding, which will explore issues involved with decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA. Some of the issues expected to be addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others.
QIP Reconciliation Hearing
In March 2021, Ameren Illinois filed a request with the ICC for a reconciliation hearing to determine the accuracy and prudence of natural gas capital investments recovered under the QIP rider during 2020. In October 2023, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow approximately $53 million in natural gas capital investments as improper and imprudent, providing a potential over-recovery of approximately $3 million in 2020. In October 2023, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2020. Ameren Illinois’ 2020 QIP rate recovery request under review by the ICC was within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding. Ameren Illinois cannot predict the ultimate outcome of this regulatory proceeding.
RTO Cost-Benefit Study
In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from the MISO’s April 2022 capacity auction, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study of continued participation in the MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a period of five to 10 years beginning June 2024. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. Intervenor comments on the study were filed in October 2023 and reply comments were filed in November 2023. In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study.
MISO Long-Range Transmission Projects CCN
In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed below that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025.
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Federal
MISO Transmission Rate Incentives
In July 2022, the MISO approved the first tranche of projects related to a preliminary long-range transmission planning roadmap of projects through 2039. A portion of these projects were assigned to various utilities, including Ameren. The projects assigned to Ameren are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. In October 2023, the FERC issued an order that approved transmission rate incentives relating to the projects assigned to Ameren. The incentives will allow construction work in progress to be included in rate base for projects constructed by ATXI, thereby improving the timeliness of cash recovery, and would allow recovery of prudently incurred costs, subject to FERC approval, for any portion of the projects if they are abandoned for reasons beyond the control of Ameren. As a result of the order, ATXI will not capitalize allowance for funds used during construction on the related projects.
FERC Complaint Cases
Since November 2013, the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff has been subject to customer complaint cases and has been changed by various FERC orders. In May 2020, the FERC issued an order, which set the allowed base ROE to 10.02%, and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. Ameren and Ameren Illinois paid these refunds, including interest, by March 31, 2022. In June and July 2020, Ameren Missouri, Ameren Illinois, and ATXI, as well as various customers, petitioned the United States Court of Appeals for the District of Columbia Circuit for review of the May 2020 order, challenging certain aspects of the new ROE methodology established. The petition filed by Ameren Missouri, Ameren Illinois, and ATXI challenged the refunds required for the period from September 2016 to May 2020. In August 2022, the court issued a ruling that granted the customers’ petition for review, vacated the FERC’s previous MISO ROE-determining orders, and remanded the proceedings to the FERC. The court elected not to rule on the issues raised by Ameren Missouri, Ameren Illinois, and ATXI. The currently allowed base ROE of 10.02% will remain effective for customer billings, but the transmission rates charged during previous periods and the currently effective rates may be subject to refund if the base ROE is changed by the FERC in a future order. The FERC is under no deadline to issue an order related to these proceedings. A 50-basis-point change in the FERC-allowed ROE would affect Ameren’s and Ameren Illinois’ annual revenue by an estimated $21 million and $15 million, respectively, based on each company’s 2024 projected rate base.
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Regulatory Assets and Liabilities
The following table presents our regulatory assets and regulatory liabilities at December 31, 2023 and 2022:
| 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||
| Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | ||||||||||||||||||||||||||||||||||||
| Regulatory assets: | |||||||||||||||||||||||||||||||||||||||||
Under-recovered FAC(a) | $ | 72 | $ | — | $ | 72 | $ | 140 | $ | — | $ | 140 | |||||||||||||||||||||||||||||
Under-recovered Illinois electric power costs(b) | — | 10 | 10 | — | 33 | 33 | |||||||||||||||||||||||||||||||||||
Under-recovered PGA(b)(c) | 6 | — | 6 | 23 | — | 23 | |||||||||||||||||||||||||||||||||||
MTM derivative losses(d) | 25 | 143 | 168 | 68 | 68 | 136 | |||||||||||||||||||||||||||||||||||
IEIMA revenue requirement reconciliation adjustment(e)(f) | — | 239 | 239 | — | 134 | 134 | |||||||||||||||||||||||||||||||||||
FERC revenue requirement reconciliation adjustment(g) | — | 25 | 54 | — | 11 | 33 | |||||||||||||||||||||||||||||||||||
Under-recovered VBA(h) | — | 49 | 49 | — | — | — | |||||||||||||||||||||||||||||||||||
Income taxes(i) | 126 | 78 | 207 | 111 | 72 | 185 | |||||||||||||||||||||||||||||||||||
Bad debt rider(j) | — | 43 | 43 | — | 5 | 5 | |||||||||||||||||||||||||||||||||||
Callaway refueling and maintenance outage costs(k) | 37 | — | 37 | 33 | — | 33 | |||||||||||||||||||||||||||||||||||
Unamortized loss on reacquired debt(l) | 45 | 5 | 50 | 47 | 7 | 54 | |||||||||||||||||||||||||||||||||||
Environmental cost riders(m) | — | 50 | 50 | — | 64 | 64 | |||||||||||||||||||||||||||||||||||
Storm costs(f)(n) | — | 27 | 27 | — | 14 | 14 | |||||||||||||||||||||||||||||||||||
Allowance for funds used during construction for pollution control equipment(f)(o) | 10 | — | 10 | 11 | — | 11 | |||||||||||||||||||||||||||||||||||
Customer generation rebate program(f)(p) | — | 54 | 54 | — | 50 | 50 | |||||||||||||||||||||||||||||||||||
PISA(f)(q) | 386 | — | 386 | 320 | — | 320 | |||||||||||||||||||||||||||||||||||
RESRAM(r) | 48 | — | 48 | 6 | — | 6 | |||||||||||||||||||||||||||||||||||
Certain Meramec Energy Center costs(s) | 39 | — | 39 | 51 | — | 51 | |||||||||||||||||||||||||||||||||||
FEJA energy-efficiency rider(f)(t) | — | 500 | 500 | — | 416 | 416 | |||||||||||||||||||||||||||||||||||
Property tax tracker(u) | 13 | — | 13 | 3 | — | 3 | |||||||||||||||||||||||||||||||||||
| Other | 49 | 64 | 113 | 35 | 34 | 69 | |||||||||||||||||||||||||||||||||||
| Total regulatory assets | $ | 856 | $ | 1,287 | $ | 2,175 | $ | 848 | $ | 908 | $ | 1,780 | |||||||||||||||||||||||||||||
| Less: current regulatory assets | (101) | (252) | (365) | (254) | (87) | (354) | |||||||||||||||||||||||||||||||||||
| Noncurrent regulatory assets | $ | 755 | $ | 1,035 | $ | 1,810 | $ | 594 | $ | 821 | $ | 1,426 | |||||||||||||||||||||||||||||
| Regulatory liabilities: | |||||||||||||||||||||||||||||||||||||||||
Over-recovered Illinois electric power costs(b) | — | 36 | 36 | — | — | — | |||||||||||||||||||||||||||||||||||
Over-recovered PGA(b) | 7 | 33 | 40 | — | 10 | 10 | |||||||||||||||||||||||||||||||||||
MTM derivative gains(d) | 19 | 3 | 22 | 51 | 40 | 91 | |||||||||||||||||||||||||||||||||||
Income taxes(i) | 999 | 724 | 1,809 | 1,095 | 749 | 1,931 | |||||||||||||||||||||||||||||||||||
Cost of removal(v) | 1,098 | 1,038 | 2,186 | 1,064 | 989 | 2,091 | |||||||||||||||||||||||||||||||||||
AROs(w) | 524 | — | 524 | 365 | — | 365 | |||||||||||||||||||||||||||||||||||
Bad debt rider(j) | — | 7 | 7 | — | 21 | 21 | |||||||||||||||||||||||||||||||||||
Pension and postretirement benefit costs(x) | 202 | 144 | 346 | 242 | 162 | 404 | |||||||||||||||||||||||||||||||||||
Pension and postretirement benefit costs tracker(y) | 111 | — | 111 | 60 | — | 60 | |||||||||||||||||||||||||||||||||||
Renewable energy credits and zero emission credits(z) | — | 489 | 489 | — | 373 | 373 | |||||||||||||||||||||||||||||||||||
| Other | 14 | 15 | 29 | 64 | 33 | 99 | |||||||||||||||||||||||||||||||||||
| Total regulatory liabilities | $ | 2,974 | $ | 2,489 | $ | 5,599 | $ | 2,941 | $ | 2,377 | $ | 5,445 | |||||||||||||||||||||||||||||
| Less: current regulatory liabilities | (15) | (71) | (87) | (70) | (64) | (136) | |||||||||||||||||||||||||||||||||||
| Noncurrent regulatory liabilities | $ | 2,959 | $ | 2,418 | $ | 5,512 | $ | 2,871 | $ | 2,313 | $ | 5,309 | |||||||||||||||||||||||||||||
(a)Under-recovered fuel and purchased power costs to be recovered through the FAC. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.
(b)Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(c)As a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, for the month of February 2021, Ameren Missouri had under-recovered costs under its PGA clause of $53 million. Pursuant to an October 2021 MoPSC order, the collection period for Ameren Missouri’s cumulative PGA under-recovery as of August 2021, which included the February 2021 under-recovery, was extended from 12 months to 36 months, beginning November 2021.
(d)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.
(e)The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the IEIMA performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. The under-recovery will be recovered from customers with a return at the applicable WACC within two years.
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(f)These assets earn a return at the applicable WACC.
(g)Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years.
(h)Under-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in rate regulatory reviews. Each year’s amount will be recovered from customers from April through December of the following year.
(i)The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction and the effects of tax rate increases. The regulatory liabilities represent amounts that will be refunded to customers for excess deferred income taxes related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits all recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 36, 28, and 43 years.
(j)A rider for the difference between the level of bad debt write-offs, net of any subsequent recoveries, incurred by Ameren Illinois and the level of such costs included in electric distribution and natural gas delivery service rates. Under-recovered or over-recovered costs for each year are collected from, or refunded to, customers over a twelve-month period beginning in June of the following year.
(k)Maintenance expenses related to scheduled refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. Amounts are amortized over the period between refueling and maintenance outages, which has historically been approximately 18 months.
(l)Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued.
(m)The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information.
(n)Storm costs from 2020 through 2023 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred.
(o)The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux Energy Center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux Energy Center, currently through 2030.
(p)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid.
(q)Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on investments in certain property, plant, and equipment placed in service and not included in base rates. Accumulated PISA deferrals, which also earn a return at the applicable WACC, are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.
(r)Under-recovered costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Under-recovered or over-recovered costs are aggregated over a twelve-month period beginning each August and are amortized over a twelve-month period beginning in February of the following year.
(s)Certain costs associated with the Meramec Energy Center, which were authorized for recovery by a December 2021 MoPSC electric rate order. These costs are being collected over five years beginning in February 2022.
(t)The electric energy-efficiency investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from three to 12 years.
(u)A regulatory recovery mechanism for the difference between actual property taxes incurred by Ameren Missouri and the related taxes included in customer rates. The period of recovery, or refund, varies based on MoPSC approval in a regulatory rate review. Amounts accumulated through 2022 are being collected over two years beginning July 2023. The amortization period for amounts accumulated after 2022 will be determined in a future regulatory rate review.
(v)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment when retired from service, net of salvage.
(w)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,150 million and $958 million at December 31, 2023 and 2022, respectively), net of recoverable removal costs for AROs ($626 million and $593 million at December 31, 2023 and 2022, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations and Removal Costs.
(x)Over-recovered costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information.
(y)A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For electric and natural gas related costs incurred prior to 2023 and 2022, respectively, the weighted-average remaining amortization period is three years. For electric and natural gas related costs incurred after 2023 and 2022, respectively, the amortization period will be determined in a future regulatory rate review.
(z)Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to a reconciliation proceeding, the first of which was initiated in August 2023. Based on amounts collected from customers and renewable energy credit purchases under contract, the August 2023 reconciliation proceeding did not result in refunds to customers.
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NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET
The following table presents components of “Property, plant, and equipment, net” at December 31, 2023 and 2022:
| Ameren Missouri | Ameren Illinois | Other | Ameren | |||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||
Property, plant, and equipment at original cost(a): | ||||||||||||||||||||||||||
| Electric generation: | ||||||||||||||||||||||||||
Coal(b) | $ | 3,452 | $ | — | $ | — | $ | 3,452 | ||||||||||||||||||
| Natural gas | 921 | — | — | 921 | ||||||||||||||||||||||
| Nuclear | 5,879 | — | — | 5,879 | ||||||||||||||||||||||
Renewable(c) | 1,973 | 11 | — | 1,984 | ||||||||||||||||||||||
| Electric distribution | 8,638 | 7,820 | — | 16,458 | ||||||||||||||||||||||
| Electric transmission | 2,134 | 5,381 | 1,993 | 9,508 | ||||||||||||||||||||||
| Natural gas | 688 | 4,186 | — | 4,874 | ||||||||||||||||||||||
Other(d) | 2,191 | 1,657 | 255 | 4,103 | ||||||||||||||||||||||
| 25,876 | 19,055 | 2,248 | 47,179 | |||||||||||||||||||||||
| Less: Accumulated depreciation and amortization | 10,243 | 4,783 | 400 | 15,426 | ||||||||||||||||||||||
| 15,633 | 14,272 | 1,848 | 31,753 | |||||||||||||||||||||||
| Construction work in progress: | ||||||||||||||||||||||||||
| Nuclear fuel in progress | 173 | — | — | 173 | ||||||||||||||||||||||
| Other | 914 | 360 | 46 | 1,320 | ||||||||||||||||||||||
Plant to be abandoned, net(e) | 530 | — | — | 530 | ||||||||||||||||||||||
| Property, plant, and equipment, net | $ | 17,250 | $ | 14,632 | $ | 1,894 | $ | 33,776 | ||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||
Property, plant, and equipment at original cost(a): | ||||||||||||||||||||||||||
| Electric generation: | ||||||||||||||||||||||||||
Coal(b)(f) | $ | 3,454 | $ | — | $ | — | $ | 3,454 | ||||||||||||||||||
| Natural gas | 961 | — | — | 961 | ||||||||||||||||||||||
| Nuclear | 5,725 | — | — | 5,725 | ||||||||||||||||||||||
Renewable(c) | 1,957 | 11 | — | 1,968 | ||||||||||||||||||||||
| Electric distribution | 7,993 | 7,351 | — | 15,344 | ||||||||||||||||||||||
| Electric transmission | 1,884 | 4,617 | 1,815 | 8,316 | ||||||||||||||||||||||
| Natural gas | 640 | 3,883 | — | 4,523 | ||||||||||||||||||||||
Other(d) | 1,904 | 1,395 | 249 | 3,548 | ||||||||||||||||||||||
| 24,518 | 17,257 | 2,064 | 43,839 | |||||||||||||||||||||||
Less: Accumulated depreciation and amortization(f) | 9,682 | 4,418 | 365 | 14,465 | ||||||||||||||||||||||
| 14,836 | 12,839 | 1,699 | 29,374 | |||||||||||||||||||||||
| Construction work in progress: | ||||||||||||||||||||||||||
| Nuclear fuel in progress | 108 | — | — | 108 | ||||||||||||||||||||||
| Other | 598 | 514 | 86 | 1,198 | ||||||||||||||||||||||
Plant to be abandoned, net(e) | 582 | — | — | 582 | ||||||||||||||||||||||
| Property, plant, and equipment, net | $ | 16,124 | $ | 13,353 | $ | 1,785 | $ | 31,262 | ||||||||||||||||||
(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 of oil-fired generation at December 31, 2023 and 2022.
(c)Renewable includes hydroelectric, wind, solar, and methane gas generation facilities.
(d)Other property, plant, and equipment includes assets used to support electric and natural gas services.
(e)Represents the net book value of the Rush Island Energy Center 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, NSR and Clean Air Act Litigation under Note 14 – Commitments and Contingencies, and Securitization of the Rush Island Energy Center under Note 2 – Rate and Regulatory Matters for additional information on the planned accelerated retirement of the Rush Island Energy Center.
(f)Original cost amounts include two CTs that had related financing obligations. The financing obligation for the Peno Creek CT Energy Center was settled in December 2022, while the financing obligation for the Audrain CT Energy Center was settled in January 2023. The gross cumulative plant asset values related to outstanding financing obligations as of December 31, 2022 was $125 million and the related accumulated depreciation was $54 million. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.
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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, with the amortization expense included in “Depreciation and amortization” on the statement of income. Deferred cloud implementation costs are classified within “Other Assets” on the balance sheet and are amortized on a straight-line basis over the term of the associated hosting arrangement, ranging from 5 to 15 years, with the amortization expense included in “Other operations and maintenance” on the statement of income. The following table presents the amortization expense, gross carrying value, and related accumulated amortization of capitalized software and deferred cloud implementation costs by year:
| Amortization Expense | Gross Carrying Value | Accumulated Amortization | ||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||
| Capitalized software costs: | ||||||||||||||||||||||||||||||||
| Ameren | $ | 212 | $ | 159 | $ | 125 | $ | 1,823 | $ | 1,443 | $ | (1,126) | $ | (914) | ||||||||||||||||||
| Ameren Missouri | 114 | 85 | 66 | 795 | 613 | (453) | (339) | |||||||||||||||||||||||||
| Ameren Illinois | 92 | 69 | 53 | 786 | 601 | (452) | (360) | |||||||||||||||||||||||||
| Deferred cloud implementation costs: | ||||||||||||||||||||||||||||||||
| Ameren | $ | 17 | $ | 15 | $ | 13 | $ | 142 | $ | 106 | $ | (51) | $ | (34) | ||||||||||||||||||
| Ameren Missouri | 8 | 7 | 6 | 63 | 48 | (23) | (15) | |||||||||||||||||||||||||
| Ameren Illinois | 9 | 8 | 6 | 76 | 54 | (26) | (17) | |||||||||||||||||||||||||
Annual amortization expense for capitalized software placed in service as of December 31, 2023, is estimated to be as follows:
| 2024 | 2025 | 2026 | 2027 | 2028 | ||||||||||||||||||||||||||||
| Ameren | $ | 202 | $ | 147 | $ | 106 | $ | 79 | $ | 45 | ||||||||||||||||||||||
| Ameren Missouri | 106 | 76 | 52 | 38 | 22 | |||||||||||||||||||||||||||
| Ameren Illinois | 90 | 65 | 51 | 38 | 23 | |||||||||||||||||||||||||||
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
The Credit Agreements provide $2.6 billion of credit cumulatively through maturity in December 2027. The total facility size of the Missouri Credit Agreement and Illinois Credit Agreement is $1.4 billion and $1.2 billion, respectively. The maturity date of each Credit Agreement may be extended for two additional one-year periods upon the mutual consent of the respective borrowers and the lenders. Credit available under the agreements is provided by 21 international, national, and regional lenders, with no single lender providing more than $156 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) | $ | 1,000 | $ | 700 | |||||||
| Ameren Missouri | 1,000 | (a) | |||||||||
| Ameren Illinois | (a) | 1,000 | |||||||||
(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 $1.7 billion for the Missouri Credit Agreement and $1.5 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
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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 $2.6 billion overall combined facility borrowing limitations of the Credit Agreements.
The borrowers will use the proceeds from any borrowings under the Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, loan funding under the Ameren money pool arrangements, and other short-term affiliate loan arrangements. The Missouri Credit Agreement and the Illinois Credit Agreement are available to support issuances under Ameren (parent)’s, Ameren Missouri’s and Ameren Illinois’ commercial paper programs, respectively, subject to borrowing sublimits, as well as to support issuance of letters of credit for the borrowers. As of December 31, 2023, based on credit capacity available under the Credit Agreements, along with cash and cash equivalents, the net liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $2.1 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, 2023 and 2022:
| Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated | ||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Average daily amount outstanding | $ | 726 | $ | 274 | $ | 166 | $ | 1,166 | |||||||||||||||||||||
| Commercial paper issuances outstanding at period-end | — | 170 | 366 | 536 | |||||||||||||||||||||||||
| Weighted-average interest rate | 5.38 | % | 5.22 | % | 5.23 | % | 5.32 | % | |||||||||||||||||||||
Peak amount outstanding during period(a) | $ | 1,298 | $ | 592 | $ | 450 | $ | 1,526 | |||||||||||||||||||||
| Peak interest rate | 5.65 | % | 5.68 | % | 5.68 | % | 5.68 | % | |||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||
| Average daily amount outstanding | $ | 485 | $ | 229 | $ | 138 | $ | 852 | |||||||||||||||||||||
| Commercial paper issuances outstanding at period-end | 477 | 329 | 264 | 1,070 | |||||||||||||||||||||||||
| Weighted-average interest rate | 2.41 | % | 1.71 | % | 2.79 | % | 2.28 | % | |||||||||||||||||||||
Peak amount outstanding during period(a) | $ | 718 | $ | 539 | $ | 404 | $ | 1,267 | |||||||||||||||||||||
| Peak interest rate | 4.80 | % | 4.95 | % | 4.80 | % | 4.95 | % | |||||||||||||||||||||
(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.
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, 2023, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 59%, 50%, and 46%, 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
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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, 2023.
Money Pools
Ameren (parent) 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, 2023, was 5.29% (2022 – 1.95%).
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, 2023, 2022, and 2021.
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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, 2023 and 2022:
| 2023 | 2022 | ||||||||||
| Ameren (Parent): | |||||||||||
| 2.50% Senior unsecured notes due 2024 | $ | 450 | $ | 450 | |||||||
| 3.65% Senior unsecured notes due 2026 | 350 | 350 | |||||||||
| 5.70% Senior unsecured notes due 2026 | 600 | — | |||||||||
| 1.95% Senior unsecured notes due 2027 | 500 | 500 | |||||||||
| 1.75% Senior unsecured notes due 2028 | 450 | 450 | |||||||||
| 5.00% Senior unsecured notes due 2029 | 700 | — | |||||||||
| 3.50% Senior unsecured notes due 2031 | 800 | 800 | |||||||||
| Total long-term debt, gross | 3,850 | 2,550 | |||||||||
| Less: Unamortized discount and premium | (4) | (2) | |||||||||
| Less: Unamortized debt issuance costs | (17) | (12) | |||||||||
| Less: Maturities due within one year | (450) | — | |||||||||
| Long-term debt, net | $ | 3,379 | $ | 2,536 | |||||||
| Ameren Missouri: | |||||||||||
| Bonds and notes: | |||||||||||
3.50% Senior secured notes due 2024(a) | $ | 350 | $ | 350 | |||||||
2.95% Senior secured notes due 2027(a) | 400 | 400 | |||||||||
3.50% First mortgage bonds due 2029(b) | 450 | 450 | |||||||||
2.95% First mortgage bonds due 2030(b) | 465 | 465 | |||||||||
2.15% First mortgage bonds due 2032(b) | 525 | 525 | |||||||||
2.90% 1998 Series A bonds due 2033(c) | 60 | 60 | |||||||||
2.90% 1998 Series B bonds due 2033(c) | 50 | 50 | |||||||||
2.75% 1998 Series C bonds due 2033(c) | 50 | 50 | |||||||||
5.50% Senior secured notes due 2034(a) | 184 | 184 | |||||||||
5.30% Senior secured notes due 2037(a) | 300 | 300 | |||||||||
8.45% Senior secured notes due 2039(a)(d) | 350 | 350 | |||||||||
3.90% Senior secured notes due 2042(a)(d) | 485 | 485 | |||||||||
3.65% Senior secured notes due 2045(a) | 400 | 400 | |||||||||
4.00% First mortgage bonds due 2048(b) | 425 | 425 | |||||||||
3.25% First mortgage bonds due 2049(b) | 330 | 330 | |||||||||
2.625% First mortgage bonds due 2051(b) | 550 | 550 | |||||||||
3.90% First mortgage bonds due 2052(b) | 525 | 525 | |||||||||
5.45% First mortgage bonds due 2053(b) | 500 | — | |||||||||
| Finance obligations: | |||||||||||
Audrain County agreement (Audrain County CT) due 2023(e) | — | 240 | |||||||||
| Total long-term debt, gross | 6,399 | 6,139 | |||||||||
| Less: Unamortized discount and premium | (13) | (12) | |||||||||
| Less: Unamortized debt issuance costs | (45) | (41) | |||||||||
| Less: Maturities due within one year | (350) | (240) | |||||||||
| Long-term debt, net | $ | 5,991 | $ | 5,846 | |||||||
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| 2023 | 2022 | ||||||||||
| Ameren Illinois: | |||||||||||
| Bonds and notes: | |||||||||||
0.375% First mortgage bonds due 2023(f) | $ | — | $ | 100 | |||||||
3.25% Senior secured notes due 2025(g) | 300 | 300 | |||||||||
6.125% Senior secured notes due 2028(g) | 60 | 60 | |||||||||
3.80% First mortgage bonds due 2028(f) | 430 | 430 | |||||||||
1.55% First mortgage bonds due 2030(f) | 375 | 375 | |||||||||
3.85% First mortgage bonds due 2032(f) | 500 | 500 | |||||||||
4.95% First mortgage bonds due 2033(f) | 500 | — | |||||||||
6.70% Senior secured notes due 2036(g) | 61 | 61 | |||||||||
6.70% Senior secured notes due 2036(g) | 42 | 42 | |||||||||
4.80% Senior secured notes due 2043(g) | 280 | 280 | |||||||||
4.30% Senior secured notes due 2044(g) | 250 | 250 | |||||||||
4.15% Senior secured notes due 2046(g) | 490 | 490 | |||||||||
3.70% First mortgage bonds due 2047(f) | 500 | 500 | |||||||||
4.50% First mortgage bonds due 2049(f) | 500 | 500 | |||||||||
3.25% First mortgage bonds due 2050(f) | 300 | 300 | |||||||||
2.90% First mortgage bonds due 2051(f) | 350 | 350 | |||||||||
5.90% First mortgage bonds due 2052(f) | 350 | 350 | |||||||||
| Total long-term debt, gross | 5,288 | 4,888 | |||||||||
| Less: Unamortized discount and premium | (9) | (9) | |||||||||
| Less: Unamortized debt issuance costs | (47) | (44) | |||||||||
| Less: Maturities due within one year | — | (100) | |||||||||
| Long-term debt, net | $ | 5,232 | $ | 4,735 | |||||||
| ATXI: | |||||||||||
2.45% Senior unsecured notes due 2036(h) | $ | 75 | $ | 75 | |||||||
3.43% Senior unsecured notes due 2050(i) | 400 | 400 | |||||||||
2.96% Senior unsecured notes due 2052(j) | 95 | 95 | |||||||||
| Total long-term debt, gross | 570 | 570 | |||||||||
| Less: Unamortized debt issuance costs | (2) | (2) | |||||||||
| Less: Maturities due within one year | (49) | — | |||||||||
| Long-term debt, net | $ | 519 | $ | 568 | |||||||
| Ameren consolidated long-term debt, net | $ | 15,121 | $ | 13,685 | |||||||
(a)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 2053 maturity of the 5.45% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (d) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.
(b)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.
(c)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.
(d)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.
(e)No cash was exchanged associated with the termination of the Audrain County agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri. The balance of the financing obligation and the related investment in debt securities was $240 million as of December 31, 2022. The investment was recorded in “Investments in industrial development revenue bonds” as of December 31, 2022. See below for additional information on this financing obligation.
(f)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.
(g)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 2052 maturity date of the 5.90% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.
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(h)The following table presents the principal maturities schedule for the 2.45% senior unsecured notes due 2036:
| Payment Date | Principal Payment | |||||||
| November 2029 | $ | 30 | ||||||
| November 2036 | 45 | |||||||
| Total | $ | 75 | ||||||
(i)The following table presents the principal maturities schedule for the 3.43% senior unsecured notes due 2050:
| Payment Date | Principal Payment | |||||||
| August 2024 | $ | 49 | ||||||
| August 2027 | 50 | |||||||
| August 2030 | 49 | |||||||
| August 2032 | 50 | |||||||
| August 2038 | 49 | |||||||
| August 2043 | 77 | |||||||
| August 2050 | 76 | |||||||
| Total | $ | 400 | ||||||
(j)The following table presents the principal maturities schedule for the 2.96% senior unsecured notes due 2052:
| Payment Date | Principal Payment | |||||||
| August 2040 | $ | 45 | ||||||
| August 2052 | 50 | |||||||
| Total | $ | 95 | ||||||
The following table presents the aggregate maturities of long-term debt, including current maturities, at December 31, 2023:
Ameren (parent)(a) | Ameren Missouri(a) | Ameren Illinois(a) | ATXI(a) | Ameren Consolidated(a) | |||||||||||||||||||||||||
| 2024 | $ | 450 | $ | 350 | $ | — | $ | 49 | $ | 849 | |||||||||||||||||||
| 2025 | — | — | 300 | — | 300 | ||||||||||||||||||||||||
| 2026 | 950 | — | — | — | 950 | ||||||||||||||||||||||||
| 2027 | 500 | 400 | — | 50 | 950 | ||||||||||||||||||||||||
| 2028 | 450 | — | 490 | — | 940 | ||||||||||||||||||||||||
| Thereafter | 1,500 | 5,649 | 4,498 | 471 | 12,118 | ||||||||||||||||||||||||
| Total | $ | 3,850 | $ | 6,399 | $ | 5,288 | $ | 570 | $ | 16,107 | |||||||||||||||||||
(a)Excludes unamortized discount, premium, and debt issuance costs of $21 million, $58 million, $56 million, and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI, respectively.
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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, 2023 and 2022:
| Shares Outstanding | Redemption Price (per share) | 2023 | 2022 | ||||||||||||||||||||
| Ameren Missouri: | |||||||||||||||||||||||
| Without par value and stated value of $100 per share, 25 million shares authorized | |||||||||||||||||||||||
| $3.50 Series | 130,000 shares | $ | 110.00 | $ | 13 | $ | 13 | ||||||||||||||||
| $3.70 Series | 40,000 shares | 104.75 | 4 | 4 | |||||||||||||||||||
| $4.00 Series | 150,000 shares | 105.625 | 15 | 15 | |||||||||||||||||||
| $4.30 Series | 40,000 shares | 105.00 | 4 | 4 | |||||||||||||||||||
| $4.50 Series | 213,595 shares | 110.00 | (a) | 21 | 21 | ||||||||||||||||||
| $4.56 Series | 200,000 shares | 102.47 | 20 | 20 | |||||||||||||||||||
| $4.75 Series | 20,000 shares | 102.176 | 2 | 2 | |||||||||||||||||||
| $5.50 Series A | 14,000 shares | 110.00 | 1 | 1 | |||||||||||||||||||
| Total | $ | 80 | $ | 80 | |||||||||||||||||||
| Ameren Illinois: | |||||||||||||||||||||||
| With par value of $100 per share, 2 million shares authorized | |||||||||||||||||||||||
| 4.00% Series | 144,275 shares | $ | 101.00 | $ | 14 | $ | 14 | ||||||||||||||||
| 4.08% Series | 45,224 shares | 103.00 | 5 | 5 | |||||||||||||||||||
| 4.20% Series | 23,655 shares | 104.00 | 2 | 2 | |||||||||||||||||||
| 4.25% Series | 50,000 shares | 102.00 | 5 | 5 | |||||||||||||||||||
| 4.26% Series | 16,621 shares | 103.00 | 2 | 2 | |||||||||||||||||||
| 4.42% Series | 16,190 shares | 103.00 | 2 | 2 | |||||||||||||||||||
| 4.70% Series | 18,429 shares | 104.30 | 2 | 2 | |||||||||||||||||||
| 4.90% Series | 73,825 shares | 102.00 | 7 | 7 | |||||||||||||||||||
| 4.92% Series | 49,289 shares | 103.50 | 5 | 5 | |||||||||||||||||||
| 5.16% Series | 50,000 shares | 102.00 | 5 | 5 | |||||||||||||||||||
| Total | $ | 49 | $ | 49 | |||||||||||||||||||
| Total Ameren | $ | 129 | $ | 129 | |||||||||||||||||||
(a)In the event of voluntary liquidation, $105.50.
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 0.6 million, 0.5 million, and 0.5 million shares of common stock in 2023, 2022, and 2021, respectively, received proceeds of $39 million, $41 million, and $47 million for the respective years, and had a receivable of $7 million and $8 million as of December 31, 2023 and 2022. In addition, Ameren issued 0.5 million, 0.4 million, and 0.5 million shares of common stock valued at $40 million, $31 million, and $33 million in 2023, 2022, 2021, respectively, for no cash consideration in connection with stock-based compensation.
In May 2023, Ameren filed a Form S-3 registration statement with the SEC, authorizing the offering of 3 million additional shares of its common stock under the DRPlus, which expires in May 2026. 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 contracts.
In October 2023, 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 2026.
In May 2022, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 7.5 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 contracts.
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Ameren has entered into an equity distribution sales agreement pursuant to which Ameren may offer and sell from time to time up to $1.75 billion of its common stock through an ATM program, which includes the ability to enter into forward sale agreements. Under the ATM, Ameren issued 3.2 million, 3.4 million, and 1.8 million shares of common stock and received proceeds of $299 million, $292 million, and $148 million in 2023, 2022 and 2021, respectively. These proceeds were net of $3 million, $3 million and $2 million, respectively, in compensation paid to selling agents. As of December 31, 2023, Ameren had approximately $770 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2023, discussed below.
The forward sale agreements outstanding as of December 31, 2023, can be settled at Ameren’s discretion on or prior to dates ranging from October 3, 2024 to February 28, 2025. On a settlement date or dates, if Ameren elects to physically settle a forward sale agreement, Ameren will issue shares of common stock to the counterparties at the then-applicable forward sale price. The initial forward sale price for the agreements ranged from $76.69 to $89.31, with an average initial forward sale price of $80.45. Each 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, 2023, Ameren could have settled the forward sale agreements with physical delivery of 2.9 million shares of common stock to the respective counterparties in exchange for cash of $230 million. Alternatively, the forward sale agreements could have also been settled at December 31, 2023, with the counterparties delivering approximately $24 million of cash or approximately 0.3 million shares of common stock to Ameren. In connection to the forward sale agreements, the various counterparties, or their affiliates, borrowed from third parties and sold 2.9 million shares of common stock. The gross sales price of these shares totaled $232 million. Ameren has not received any proceeds from such sales of borrowed shares. The forward sale agreements have been classified as equity transactions.
In February 2021, Ameren settled the remainder of a forward sale agreement entered into in August 2019, 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.
In November 2023, Ameren (parent) issued $600 million of 5.70% senior unsecured notes due December 2026, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2024. Net proceeds from this issuance were used to repay short-term debt.
In December 2023, Ameren (parent) issued $700 million of 5.00% senior unsecured notes due January 2029, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2024. Net proceeds from this issuance were used for general corporate purposes, including the repayment of short-term debt.
Ameren Missouri
In January 2024, Ameren Missouri issued $350 million of 5.25% first mortgage bonds due January 2054, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2024. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.
In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri. Ownership of the energy center was transferred to Ameren Missouri in January 2023, at which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture.
In March 2023, Ameren Missouri issued $500 million of 5.45% first mortgage bonds due March 2053, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2023. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.
In April 2022, Ameren Missouri issued $525 million of 3.90% green first mortgage bonds due April 2052, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2022. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt. Ameren Missouri intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.
In November 2022, $47 million principal amount of Ameren Missouri’s 1.60% 1992 Series bonds matured and were repaid with commercial paper borrowings.
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In December 2022, Ameren Missouri repaid $8 million of the remaining principal amount of the financing obligation related to the Peno Creek CT Energy Center 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 of Bowling Green and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the agreement were equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. Under the terms of this agreement, Ameren Missouri was responsible for all operation and maintenance for the energy center. Ownership of the energy center transferred to Ameren Missouri in December 2022, at which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture.
For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
Ameren Illinois
In May 2023, Ameren Illinois issued $500 million of 4.95% first mortgage bonds due June 2033, with interest payable semiannually on June 1 and December 1 of each year, beginning December 1, 2023. Net proceeds from this issuance were used to repay $100 million principal amount of its 0.375% first mortgage bonds that matured in June 2023 and short-term debt.
In August 2022, Ameren Illinois issued $500 million of 3.85% first mortgage bonds due September 2032, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2023. Net proceeds from this issuance were used to repay $400 million principal amount of its 2.70% senior secured notes that matured in September 2022 and short-term debt.
In November 2022, Ameren Illinois issued $350 million of 5.90% first mortgage bonds due December 2052, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2023. Net proceeds from this issuance 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.
For information on Ameren Illinois’ capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
ATXI
In August 2022, ATXI issued $95 million of its 2.96% senior unsecured notes due 2052 pursuant to a November 2021 note purchase agreement, 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. Net proceeds from this issuance were 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 in August 2022, 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, 2023, at an assumed interest rate of 7% and dividend rate of 8%.
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 | 3.3 | $4,209 | >2.5 | 160.5 | $2,701 | ||||||||||||||||||||
| Ameren Illinois | >2.0 | 6.9 | 8,517 | >1.5 | 3.8 | 203 | (d) | |||||||||||||||||||
(a)Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $1,959 million and $1,143 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.
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Ameren Missouri and Ameren Illinois and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on their respective stock unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois has made a commitment to the FERC to maintain a minimum 30% ratio of common stock equity to total capitalization. As of December 31, 2023, using the FERC-agreed upon calculation method, Ameren Illinois’ ratio of common stock equity to total capitalization was 53%.
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, 2023, 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, 2023, none of the Ameren Companies had any material off-balance-sheet financing arrangements, other than their investments in variable interest entities and the multiple forward sale agreements under the ATM program relating to common stock. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.
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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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Ameren: | ||||||||||||||||||||
| Other Income, Net | ||||||||||||||||||||
| Allowance for equity funds used during construction | $ | 54 | $ | 43 | $ | 43 | ||||||||||||||
| Interest income on industrial development revenue bonds | 1 | 24 | 25 | |||||||||||||||||
| Other interest income | 32 | 11 | 2 | |||||||||||||||||
Non-service cost components of net periodic benefit income(a) | 295 | 184 | 136 | |||||||||||||||||
| Miscellaneous income | 7 | 10 | 10 | |||||||||||||||||
| Earnings related to equity method investments | 1 | 2 | 12 | |||||||||||||||||
| Donations | (24) | (26) | (9) | |||||||||||||||||
| Miscellaneous expense | (18) | (22) | (17) | |||||||||||||||||
| Total Other Income, Net | $ | 348 | $ | 226 | $ | 202 | ||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||
| Other Income, Net | ||||||||||||||||||||
| Allowance for equity funds used during construction | $ | 30 | $ | 24 | $ | 26 | ||||||||||||||
| Interest income on industrial development revenue bonds | 1 | 24 | 25 | |||||||||||||||||
| Other interest income | 10 | 4 | 1 | |||||||||||||||||
Non-service cost components of net periodic benefit income(a) | 97 | 55 | 55 | |||||||||||||||||
| Miscellaneous income | 3 | 4 | 3 | |||||||||||||||||
| Donations | (2) | (3) | (4) | |||||||||||||||||
| Miscellaneous expense | (9) | (9) | (7) | |||||||||||||||||
| Total Other Income, Net | $ | 130 | $ | 99 | $ | 99 | ||||||||||||||
| Ameren Illinois: | ||||||||||||||||||||
| Other Income, Net | ||||||||||||||||||||
| Allowance for equity funds used during construction | $ | 19 | $ | 18 | $ | 17 | ||||||||||||||
| Interest income | 21 | 7 | 1 | |||||||||||||||||
| Non-service cost components of net periodic benefit income | 124 | 84 | 55 | |||||||||||||||||
| Miscellaneous income | 4 | 5 | 6 | |||||||||||||||||
| Donations | (4) | (8) | (5) | |||||||||||||||||
| Miscellaneous expense | (8) | (10) | (8) | |||||||||||||||||
| Total Other Income, Net | $ | 156 | $ | 96 | $ | 66 | ||||||||||||||
(a)For the years ended December 31, 2023, 2022, and 2021, the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $27 million, $22 million, and $(7) million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
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.
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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 non-derivative 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, 2023 and 2022, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. The cash flows from our derivative financial instruments follow the cash flow classification of the hedged item.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2023 and 2022. As of December 31, 2023, these contracts extended through October 2026, October 2029, May 2032, and March 2024 for fuel oils, natural gas, power, and uranium, respectively.
| Quantity (in millions, except as indicated) | ||||||||||||||||||||
| 2023 | 2022 | |||||||||||||||||||
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | ||||||||||||||
| Fuel oils (in gallons) | 17 | — | 17 | 18 | — | 18 | ||||||||||||||
| Natural gas (in mmbtu) | 53 | 218 | 271 | 48 | 157 | 205 | ||||||||||||||
| Power (in MWhs) | — | 5 | 5 | 1 | 6 | 7 | ||||||||||||||
| Uranium (pounds in thousands) | 186 | — | 186 | 514 | — | 514 | ||||||||||||||
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, 2023 and 2022:
| 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity | Balance Sheet Location | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fuel oils | Other current assets | $ | 2 | $ | — | $ | 2 | $ | 13 | $ | — | $ | 13 | ||||||||||||||||||||||||||||||||||||||||||||||
| Other assets | — | — | — | 3 | — | 3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | Other current assets | — | — | — | 7 | 23 | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other assets | 3 | 3 | 6 | 9 | 11 | 20 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Power | Other current assets | 5 | — | 5 | 14 | 2 | 16 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other assets | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Uranium | Other current assets | 9 | — | 9 | 2 | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other assets | — | — | — | 1 | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 19 | $ | 3 | $ | 22 | $ | 49 | $ | 40 | $ | 89 | |||||||||||||||||||||||||||||||||||||||||||||||
| Fuel oils | Other current liabilities | $ | 1 | $ | — | $ | 1 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||||||||||||||||||
| Other deferred credits and liabilities | 1 | — | 1 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | Other current liabilities | 12 | 45 | 57 | 7 | 20 | 27 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other deferred credits and liabilities | 10 | 30 | 40 | 2 | 9 | 11 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Power | Other current liabilities | 1 | 12 | 13 | 59 | 2 | 61 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other deferred credits and liabilities | — | 56 | 56 | — | 37 | 37 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | 25 | $ | 143 | $ | 168 | $ | 68 | $ | 68 | $ | 136 | |||||||||||||||||||||||||||||||||||||||||||||||
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.
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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, 2023 and 2022:
| Gross Amounts Not Offset in the Balance Sheet | ||||||||||||||||||||||||||
| Commodity Contracts Eligible to be Offset | Gross Amounts Recognized in the Balance Sheet | Derivative Instruments | Cash Collateral Received/Posted(a) | Net Amount | ||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Ameren Missouri | $ | 19 | $ | 6 | $ | — | $ | 13 | ||||||||||||||||||
| Ameren Illinois | 3 | 1 | — | 2 | ||||||||||||||||||||||
| Ameren | $ | 22 | $ | 7 | $ | — | $ | 15 | ||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Ameren Missouri | $ | 25 | $ | 6 | $ | — | $ | 19 | ||||||||||||||||||
| Ameren Illinois | 143 | 1 | 6 | 136 | ||||||||||||||||||||||
| Ameren | $ | 168 | $ | 7 | $ | 6 | $ | 155 | ||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||
| Ameren Missouri | $ | 49 | $ | 9 | $ | — | $ | 40 | ||||||||||||||||||
| Ameren Illinois | 40 | 20 | — | 20 | ||||||||||||||||||||||
| Ameren | $ | 89 | $ | 29 | $ | — | $ | 60 | ||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||
| Ameren Missouri | $ | 68 | $ | 9 | $ | 56 | $ | 3 | ||||||||||||||||||
| Ameren Illinois | 68 | 20 | — | 48 | ||||||||||||||||||||||
| Ameren | $ | 136 | $ | 29 | $ | 56 | $ | 51 | ||||||||||||||||||
(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 “Current collateral assets” and “Other assets” on the balance sheet for Ameren and Ameren Missouri and “Other current assets” and “Other assets” for Ameren Illinois.
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, 2023, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets, predominantly from financial institutions, would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.
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. The following table presents, as of December 31, 2023, the aggregate fair value of all 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:
Aggregate Fair Value of Derivative Liabilities(a) | Cash Collateral Posted | Potential Aggregate Amount of Additional Collateral Required(b) | |||||||||||||||
| Ameren Missouri | $ | 24 | $ | — | $ | 19 | |||||||||||
| Ameren Illinois | 74 | 6 | 66 | ||||||||||||||
| Ameren | $ | 98 | $ | 6 | $ | 85 | |||||||||||
(a)Before consideration of master netting arrangements or similar agreements.
(b)As collateral requirements with certain counterparties are based on master netting arrangements or similar agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such arrangements.
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NOTE 8 – FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1 (quoted prices in active markets for identical assets or liabilities): Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives, cash and cash equivalents, and listed equity securities.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants, and the trustee and investment managers. The S&P 500 index comprises stocks of large-capitalization companies.
Level 2 (significant other observable inputs): Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including United States Treasury and agency securities, corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.
Fixed income securities are valued by using prices from independent industry-recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed-income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices.
Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the bid/ask spreads to the midpoints. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoints. The value of natural gas derivative contracts is based upon exchange closing prices without significant unobservable adjustments. The value of power derivative contracts is based upon exchange closing prices or the use of multiple forward prices provided by third parties.
Level 3 (significant other unobservable inputs): Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, such as certain internal assumptions, quotes or prices from outside sources not supported by a liquid market, or trend rates.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by considering any credit enhancements (e.g., collateral). Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in 2023, 2022, or 2021. At December 31, 2023 and 2022, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.
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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, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||
| Assets: | ||||||||||||||||||||||||||||||||||||||
| Ameren Missouri | ||||||||||||||||||||||||||||||||||||||
| Derivative assets – commodity contracts: | ||||||||||||||||||||||||||||||||||||||
| Fuel oils | $ | 2 | $ | — | $ | — | $ | 2 | $ | 16 | $ | — | $ | — | $ | 16 | ||||||||||||||||||||||
| Natural gas | — | 3 | — | 3 | 1 | 15 | — | 16 | ||||||||||||||||||||||||||||||
| Power | — | — | 5 | 5 | — | — | 14 | 14 | ||||||||||||||||||||||||||||||
| Uranium | — | — | 9 | 9 | — | — | 3 | 3 | ||||||||||||||||||||||||||||||
| Total derivative assets – commodity contracts | $ | 2 | $ | 3 | $ | 14 | $ | 19 | $ | 17 | $ | 15 | $ | 17 | $ | 49 | ||||||||||||||||||||||
| Nuclear decommissioning trust fund: | ||||||||||||||||||||||||||||||||||||||
| Equity securities: | ||||||||||||||||||||||||||||||||||||||
| U.S. large capitalization | $ | 787 | $ | — | $ | — | $ | 787 | $ | 618 | $ | — | $ | — | $ | 618 | ||||||||||||||||||||||
| Debt securities: | ||||||||||||||||||||||||||||||||||||||
| U.S. Treasury and agency securities | — | 150 | — | 150 | — | 137 | — | 137 | ||||||||||||||||||||||||||||||
| Corporate bonds | — | 136 | — | 136 | — | 122 | — | 122 | ||||||||||||||||||||||||||||||
| Other | — | 68 | — | 68 | — | 70 | — | 70 | ||||||||||||||||||||||||||||||
| Total nuclear decommissioning trust fund | $ | 787 | $ | 354 | $ | — | $ | 1,141 | (a) | $ | 618 | $ | 329 | $ | — | $ | 947 | (a) | ||||||||||||||||||||
| Total Ameren Missouri | $ | 789 | $ | 357 | $ | 14 | $ | 1,160 | $ | 635 | $ | 344 | $ | 17 | $ | 996 | ||||||||||||||||||||||
| Ameren Illinois | ||||||||||||||||||||||||||||||||||||||
| Derivative assets – commodity contracts: | ||||||||||||||||||||||||||||||||||||||
| Natural gas | $ | — | $ | 1 | $ | 2 | $ | 3 | $ | 1 | $ | 28 | $ | 5 | $ | 34 | ||||||||||||||||||||||
| Power | — | — | — | — | — | — | 6 | 6 | ||||||||||||||||||||||||||||||
| Total Ameren Illinois | $ | — | $ | 1 | $ | 2 | $ | 3 | $ | 1 | $ | 28 | $ | 11 | $ | 40 | ||||||||||||||||||||||
| Ameren | ||||||||||||||||||||||||||||||||||||||
Derivative assets – commodity contracts(b) | $ | 2 | $ | 4 | $ | 16 | $ | 22 | $ | 18 | $ | 43 | $ | 28 | $ | 89 | ||||||||||||||||||||||
Nuclear decommissioning trust fund(c) | 787 | 354 | — | 1,141 | (a) | 618 | 329 | — | 947 | (a) | ||||||||||||||||||||||||||||
| Total Ameren | $ | 789 | $ | 358 | $ | 16 | $ | 1,163 | $ | 636 | $ | 372 | $ | 28 | $ | 1,036 | ||||||||||||||||||||||
| Liabilities: | ||||||||||||||||||||||||||||||||||||||
| Ameren Missouri | ||||||||||||||||||||||||||||||||||||||
| Derivative liabilities – commodity contracts: | ||||||||||||||||||||||||||||||||||||||
| Fuel oils | $ | 2 | $ | — | $ | — | $ | 2 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
| Natural gas | $ | — | $ | 19 | $ | 3 | $ | 22 | $ | — | $ | 6 | $ | 3 | $ | 9 | ||||||||||||||||||||||
| Power | — | — | 1 | 1 | 57 | — | 2 | 59 | ||||||||||||||||||||||||||||||
| Total Ameren Missouri | $ | 2 | $ | 19 | $ | 4 | $ | 25 | $ | 57 | $ | 6 | $ | 5 | $ | 68 | ||||||||||||||||||||||
| Ameren Illinois | ||||||||||||||||||||||||||||||||||||||
| Derivative liabilities – commodity contracts: | ||||||||||||||||||||||||||||||||||||||
| Natural gas | $ | 4 | $ | 60 | $ | 11 | $ | 75 | $ | — | $ | 19 | $ | 10 | $ | 29 | ||||||||||||||||||||||
| Power | — | — | 68 | 68 | — | — | 39 | 39 | ||||||||||||||||||||||||||||||
| Total Ameren Illinois | $ | 4 | $ | 60 | $ | 79 | $ | 143 | $ | — | $ | 19 | $ | 49 | $ | 68 | ||||||||||||||||||||||
| Ameren | ||||||||||||||||||||||||||||||||||||||
Derivative liabilities – commodity contracts(b) | $ | 6 | $ | 79 | $ | 83 | $ | 168 | $ | 57 | $ | 25 | $ | 54 | $ | 136 | ||||||||||||||||||||||
(a)Balance excludes $9 million and $11 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2023 and 2022, 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, 2023 and 2022.
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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, 2023 and 2022:
| 2023 | 2022 | |||||||||||||||||||||||||
| Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | |||||||||||||||||||||
| Beginning balance at January 1 | $ | 12 | $ | (33) | $ | (21) | $ | (15) | $ | (117) | $ | (132) | ||||||||||||||
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | 1 | (48) | (47) | (45) | 92 | 47 | ||||||||||||||||||||
| Settlements | (9) | 13 | 4 | 72 | (8) | 64 | ||||||||||||||||||||
| Ending balance at December 31 | $ | 4 | $ | (68) | $ | (64) | $ | 12 | $ | (33) | $ | (21) | ||||||||||||||
| Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | 4 | $ | (36) | $ | (32) | $ | 12 | $ | 75 | $ | 87 | ||||||||||||||
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, 2023 and 2022:
| Fair Value | Weighted Average(b) | |||||||||||||||||||||||||
| Commodity | Assets | Liabilities | Valuation Technique(s) | Unobservable Input(a) | Range | |||||||||||||||||||||
| 2023 | Power(c) | $ | 5 | $ | (69) | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 31 – 65 | 43 | |||||||||||||||||
| Nodal basis ($/MWh) | (8) – (1) | (5) | ||||||||||||||||||||||||
| 2022 | Power(d) | $ | 20 | $ | (41) | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 38 – 89 | 51 | |||||||||||||||||
| Nodal basis ($/MWh) | (10) – (1) | (4) | ||||||||||||||||||||||||
| Trend rate (%) | 0– 1 | 0 | ||||||||||||||||||||||||
(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 use visible forward prices adjusted for nodal-to-hub basis differentials.
(d)Valuations through 2031 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2031 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
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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, 2023 and 2022:
| Carrying Amount | Fair Value | ||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||
| December 31, 2023 | |||||||||||||||||||||||||||||
| Ameren: | |||||||||||||||||||||||||||||
| Cash, cash equivalents, and restricted cash | $ | 272 | $ | 272 | $ | — | $ | — | $ | 272 | |||||||||||||||||||
| Short-term debt | 536 | — | 536 | — | 536 | ||||||||||||||||||||||||
| Long-term debt (including current portion) | 15,970 | (a) | — | 14,366 | 467 | (b) | 14,833 | ||||||||||||||||||||||
| Ameren Missouri: | |||||||||||||||||||||||||||||
| Cash, cash equivalents, and restricted cash | $ | 10 | $ | 10 | $ | — | $ | — | $ | 10 | |||||||||||||||||||
| Short-term debt | 170 | — | 170 | — | 170 | ||||||||||||||||||||||||
| Borrowings from money pool | 306 | — | 306 | — | 306 | ||||||||||||||||||||||||
| Long-term debt (including current portion) | 6,341 | (a) | — | 5,800 | — | 5,800 | |||||||||||||||||||||||
| Ameren Illinois: | |||||||||||||||||||||||||||||
| Cash, cash equivalents, and restricted cash | $ | 234 | $ | 234 | $ | — | $ | — | $ | 234 | |||||||||||||||||||
| Short-term debt | 366 | — | 366 | — | 366 | ||||||||||||||||||||||||
| Borrowings from money pool | 135 | — | 135 | — | 135 | ||||||||||||||||||||||||
| Long-term debt (including current portion) | 5,232 | (a) | — | 4,867 | — | 4,867 | |||||||||||||||||||||||
| December 31, 2022 | |||||||||||||||||||||||||||||
| Ameren: | |||||||||||||||||||||||||||||
| Cash, cash equivalents, and restricted cash | $ | 216 | $ | 216 | $ | — | $ | — | $ | 216 | |||||||||||||||||||
Investments in industrial development revenue bonds(c) | 240 | — | 240 | — | 240 | ||||||||||||||||||||||||
| Short-term debt | 1,070 | — | 1,070 | — | 1,070 | ||||||||||||||||||||||||
Long-term debt (including current portion)(c) | 14,025 | (a) | — | 11,989 | 464 | (b) | 12,453 | ||||||||||||||||||||||
| Ameren Missouri: | |||||||||||||||||||||||||||||
| Cash, cash equivalents, and restricted cash | $ | 13 | $ | 13 | $ | — | $ | — | $ | 13 | |||||||||||||||||||
Investments in industrial development revenue bonds(c) | 240 | — | 240 | — | 240 | ||||||||||||||||||||||||
| Short-term debt | 329 | — | 329 | — | 329 | ||||||||||||||||||||||||
Long-term debt (including current portion)(c) | 6,086 | (a) | — | 5,365 | — | 5,365 | |||||||||||||||||||||||
| Ameren Illinois: | |||||||||||||||||||||||||||||
| Cash, cash equivalents, and restricted cash | $ | 191 | $ | 191 | $ | — | $ | — | $ | 191 | |||||||||||||||||||
| Short-term debt | 264 | — | 264 | — | 264 | ||||||||||||||||||||||||
| Long-term debt (including current portion) | 4,835 | (a) | — | 4,320 | — | 4,320 | |||||||||||||||||||||||
(a)Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $111 million, $45 million, and $47 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2023. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $99 million, $41 million, and $44 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2022.
(b)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.
(c)Ameren and Ameren Missouri had investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Investments in industrial development revenue bonds,” as of December 31, 2022, respectively, that were equal to the finance obligation for the Audrain CT energy center. As of December 31, 2022, the carrying amount of the investments in industrial development revenue bonds and the finance obligations approximated fair value. The financing obligation for the Audrain CT Energy Center was settled in January 2023. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.
NOTE 9 – CALLAWAY ENERGY CENTER
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, 2023, 2022, and 2021. 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.
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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 December 2023 and reflected within the ARO. Ameren Missouri’s filing supported no change in electric service rates for decommissioning costs. There is no deadline by which the MoPSC must issue an order regarding the filing.
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, 2023 and 2022. 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, 2023. 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 sales 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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | |||||||||||||||
| Proceeds from sales and maturities | $ | 240 | $ | 216 | $ | 439 | |||||||||||
| Gross realized gains | 6 | 40 | 32 | ||||||||||||||
| Gross realized losses | 11 | 10 | 6 | ||||||||||||||
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, 2023 and 2022:
| Security Type | Cost | Gross Unrealized Gain | Gross Unrealized Loss | Fair Value | |||||||||||||||||||
| 2023 | |||||||||||||||||||||||
| Debt securities | $ | 382 | $ | 3 | $ | 31 | $ | 354 | |||||||||||||||
| Equity securities | 191 | 603 | 7 | 787 | |||||||||||||||||||
| Cash and cash equivalents | 5 | — | — | 5 | |||||||||||||||||||
Other(a) | 4 | — | — | 4 | |||||||||||||||||||
| Total | $ | 582 | $ | 606 | $ | 38 | $ | 1,150 | |||||||||||||||
| 2022 | |||||||||||||||||||||||
| Debt securities | $ | 374 | $ | — | $ | 45 | $ | 329 | |||||||||||||||
| Equity securities | 177 | 455 | 14 | 618 | |||||||||||||||||||
| Cash and cash equivalents | 8 | — | — | 8 | |||||||||||||||||||
Other(a) | 3 | — | — | 3 | |||||||||||||||||||
| Total | $ | 562 | $ | 455 | $ | 59 | $ | 958 | |||||||||||||||
(a)Represents net receivables and payables relating to pending securities sales, interest, and securities purchases.
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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, 2023:
| Cost | Fair Value | ||||||||||
| Less than 5 years | $ | 101 | $ | 98 | |||||||
| 5 years to 10 years | 163 | 156 | |||||||||
| Due after 10 years | 118 | 100 | |||||||||
| Total | $ | 382 | $ | 354 | |||||||
Insurance
The following table presents insurance coverage at Ameren Missouri’s Callaway Energy Center at January 1, 2024:
| Type and Source of Coverage | Most Recent Renewal Date | Maximum Coverages | Maximum Assessments for Single Incidents | ||||||||||||||
| Public liability and nuclear worker liability: | |||||||||||||||||
| American Nuclear Insurers | January 1, 2024 | $ | 500 | $ | — | ||||||||||||
| Pool participation | (a) | 15,763 | (a) | 166 | (b) | ||||||||||||
| $ | 16,263 | (c) | $ | 166 | |||||||||||||
| Property damage: | |||||||||||||||||
| NEIL and EMANI | April 1, 2023 | $ | 3,200 | (d) | $ | 28 | (e) | ||||||||||
| Accidental outage: | |||||||||||||||||
| NEIL | April 1, 2023 | $ | 490 | (f) | $ | 9 | (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 $500 million in the event of an incident at any licensed United States commercial reactor, payable at $24.7 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 October 2023. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share the limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination, resulting from terrorist attacks. The EMANI policies are not subject to industrywide aggregates in the event of terrorist attacks on nuclear facilities.
If losses from a nuclear incident at the Callaway Energy Center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.
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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 non-union 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 $551 million and $377 million in the aggregate as of December 31, 2023 and 2022, 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 2023 was primarily the result of gains on plan assets of the pension and postretirement trusts during 2023 offset by a 30-basis-point decrease 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, 2023 and 2022:
| 2023 | 2022 | ||||||||||
Ameren(a) | $ | (551) | $ | (377) | |||||||
Ameren Missouri(a) | (142) | (84) | |||||||||
Ameren Illinois(a) | (351) | (263) | |||||||||
(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.
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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, 2023 and 2022. It also provides the amounts included in regulatory assets or liabilities and accumulated OCI at December 31, 2023 and 2022, that have not been recognized in net periodic benefit costs.
| 2023 | 2022 | ||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | Pension Benefits | Postretirement Benefits | ||||||||||||||||||||
| Accumulated benefit obligation at end of year | $ | 4,102 | $ | (a) | $ | 3,911 | $ | (a) | |||||||||||||||
| Change in benefit obligation: | |||||||||||||||||||||||
| Net benefit obligation at beginning of year | $ | 4,061 | $ | 838 | $ | 5,457 | $ | 1,129 | |||||||||||||||
| Service cost | 79 | 12 | 128 | 20 | |||||||||||||||||||
| Interest cost | 221 | 45 | 163 | 34 | |||||||||||||||||||
| Participant contributions | — | 7 | — | 8 | |||||||||||||||||||
| Actuarial (gain) loss | 170 | 17 | (1,425) | (289) | |||||||||||||||||||
| Benefits paid | (273) | (63) | (262) | (64) | |||||||||||||||||||
| Net benefit obligation at end of year | 4,258 | 856 | 4,061 | 838 | |||||||||||||||||||
| Change in plan assets: | |||||||||||||||||||||||
| Fair value of plan assets at beginning of year | 4,027 | 1,249 | 5,745 | 1,558 | |||||||||||||||||||
| Actual return on plan assets | 514 | 197 | (1,461) | (255) | |||||||||||||||||||
| Employer contributions | 4 | 3 | 5 | 2 | |||||||||||||||||||
| Participant contributions | — | 7 | — | 8 | |||||||||||||||||||
| Benefits paid | (273) | (63) | (262) | (64) | |||||||||||||||||||
| Fair value of plan assets at end of year | 4,272 | 1,393 | 4,027 | 1,249 | |||||||||||||||||||
| Funded status – deficiency (surplus) | (14) | (537) | 34 | (411) | |||||||||||||||||||
| Accrued benefit cost (asset) at December 31 | $ | (14) | $ | (537) | $ | 34 | $ | (411) | |||||||||||||||
| Amounts recognized in the balance sheet consist of: | |||||||||||||||||||||||
| Noncurrent asset | $ | (44) | $ | (537) | $ | — | $ | (411) | |||||||||||||||
Current liability(b) | 2 | — | 3 | — | |||||||||||||||||||
Noncurrent liability(c) | 28 | — | 31 | — | |||||||||||||||||||
| Net liability (asset) recognized | $ | (14) | $ | (537) | $ | 34 | $ | (411) | |||||||||||||||
| Amounts recognized in regulatory assets or liabilities consist of: | |||||||||||||||||||||||
| Net actuarial gain | $ | (10) | $ | (311) | $ | (107) | $ | (268) | |||||||||||||||
| Prior service credit | — | (25) | — | (29) | |||||||||||||||||||
| Amounts recognized in accumulated OCI (pretax) consist of: | |||||||||||||||||||||||
| Net actuarial (gain) loss | 22 | (4) | 15 | (4) | |||||||||||||||||||
| Total | $ | 12 | $ | (340) | $ | (92) | $ | (301) | |||||||||||||||
(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.
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The following table presents the assumptions used to determine our benefit obligations at December 31, 2023 and 2022:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||
| Discount rate at measurement date | 5.25 | % | 5.55 | % | 5.25 | % | 5.55 | % | ||||||||||||||||||
| Increase in future compensation | 3.50 | (a) | 3.50 | (a) | 3.50 | (a) | 3.50 | (a) | ||||||||||||||||||
| Cash balance pension plan interest crediting rate | 5.50 | 5.00 | (b) | (c) | (c) | |||||||||||||||||||||
Medical cost trend rate (initial)(d) | (c) | (c) | (e) | (e) | ||||||||||||||||||||||
Medical cost trend rate (ultimate)(d) | (c) | (c) | 5.00 | 5.00 | ||||||||||||||||||||||
(a)As of December 31, 2023, increase in future compensation is 4.00% in 2024, and 3.50% thereafter. As of December 31, 2022, increase in future compensation was 4.50% for 2023, 4.00% in 2024, and 3.50% thereafter.
(b)Cash balance pension plan interest crediting rate was 5.50% for 2023 and 2024, and 5.00% thereafter.
(c)Not applicable.
(d)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants was 2.50% at December 31, 2023 and 2022.
(e)Initial medical cost trend rates of 6.93% and 7.25% for pre-Medicare plan participants and 6.50% and 6.75% for post-Medicare plan participants at December 31, 2023 and 2022, respectively, trend down to the ultimate rate by 2030, with a 3.00% upward adjustment to the post-Medicare trend rate in 2025.
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 860 high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan’s benefit payments that equates to the market value of the selected bonds. In 2023, 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, 2023, its investment performance in 2023, and its pension funding policy, Ameren does not expect to make material contributions in 2024 and 2025, and expects to make aggregate contributions of $120 million in 2026 through 2028. Ameren Missouri and Ameren Illinois estimate that their portion of the future funding requirements will be 40% and 50%, respectively. 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 2023, 2022, and 2021:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Ameren Missouri | $ | 1 | $ | 1 | $ | 22 | $ | 2 | $ | 1 | $ | 1 | ||||||||||||||||||||||||||
| Ameren Illinois | 2 | 3 | 28 | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||
| Ameren Services | 1 | 1 | 10 | — | — | — | ||||||||||||||||||||||||||||||||
| Ameren | $ | 4 | $ | 5 | $ | 60 | $ | 3 | $ | 2 | $ | 2 | ||||||||||||||||||||||||||
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 6.75% in 2024.
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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.
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 103% 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 $234 million and $239 million as of December 31, 2023 and 2022, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2023 and 2022.
The following table presents our target allocations and our pension and postretirement plans’ asset categories as of December 31, 2023 and 2022:
| Asset Category | Target Allocation 2023 | Percentage of Plan Assets at December 31, | ||||||||||||||||||
| 2023 | 2022 | |||||||||||||||||||
| Pension Plan: | ||||||||||||||||||||
| Cash and cash equivalents | 0% – 5% | 1 | % | 1 | % | |||||||||||||||
| Equity securities: | ||||||||||||||||||||
| U.S. large-capitalization | 11% – 21% | 15 | % | 15 | % | |||||||||||||||
| U.S. small- and mid-capitalization | 3% – 13% | 8 | % | 8 | % | |||||||||||||||
| Global | 10% – 20% | 16 | % | 12 | % | |||||||||||||||
| International | 6% – 16% | 12 | % | 16 | % | |||||||||||||||
| Total equity | 45% – 55% | 51 | % | 51 | % | |||||||||||||||
| Debt securities | 35% – 45% | 35 | % | (a) | 35 | % | (a) | |||||||||||||
| Diversified credit | 0% – 10% | 7 | % | 7 | % | |||||||||||||||
| Real estate | 0% – 10% | 6 | % | 6 | % | |||||||||||||||
| Private equity | 0% – 5% | (b) | (b) | |||||||||||||||||
| Total | 100 | % | 100 | % | ||||||||||||||||
| Postretirement Plans: | ||||||||||||||||||||
| Cash and cash equivalents | 0% – 7% | 1 | % | 2 | % | |||||||||||||||
| Equity securities: | ||||||||||||||||||||
| U.S. large-capitalization | 23% – 33% | 32 | % | 29 | % | |||||||||||||||
| U.S. small- and mid-capitalization | 3% – 13% | 8 | % | 8 | % | |||||||||||||||
| Global | 9% – 19% | 15 | % | 10 | % | |||||||||||||||
| International | 5% – 15% | 8 | % | 13 | % | |||||||||||||||
| Total equity | 55% – 65% | 63 | % | 60 | % | |||||||||||||||
| Debt securities | 33% – 43% | 36 | % | 38 | % | |||||||||||||||
| Total | 100 | % | 100 | % | ||||||||||||||||
(a)Includes interest rate futures derivative instruments.
(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. Diversified credit investments include but are not limited to, sub-investment grade rated bonds and loans, securitized credit, and emerging market debt. 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.
139
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2023. Fair value is defined as the price that would be received for an asset in the principal or most advantageous market for the asset in an orderly transaction between market participants on the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the measurement date or, if that is not a business day, on the last business day before that date. Securities traded in over-the-counter markets are valued by quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Investments measured under NAV as a practical expedient are based on the fair values of the underlying assets provided by the funds and their administrators. The fair value of real estate investments is based on NAV; it is determined by annual appraisal reports prepared by an independent real estate appraiser. Investments measured at NAV often provide for daily, monthly, or quarterly redemptions with 60 or less days of notice depending on the fund. For some funds, redemption may also require approval from the fund’s board of directors. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the pension plans’ assets measured at fair value and NAV as of December 31, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Total | Level 1 | Level 2 | NAV | Total | |||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | — | $ | — | $ | 90 | $ | 90 | $ | — | $ | — | $ | 172 | $ | 172 | ||||||||||||||||||||||||||||||||||||||||
| Equity securities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. large-capitalization | — | — | 663 | 663 | — | — | 658 | 658 | ||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. small- and mid-capitalization | 353 | — | — | 353 | 321 | — | — | 321 | ||||||||||||||||||||||||||||||||||||||||||||||||
| International | 316 | — | 229 | 545 | 266 | — | 395 | 661 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Global | — | — | 721 | 721 | — | — | 493 | 493 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate bonds | — | 479 | — | 479 | — | 397 | — | 397 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal bonds | — | 43 | — | 43 | — | 41 | — | 41 | ||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Treasury and agency securities | — | 994 | — | 994 | — | 859 | — | 859 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Diversified credit | — | — | 305 | 305 | — | — | 281 | 281 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other | 49 | 13 | — | 62 | (3) | 7 | — | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Real estate | — | — | 248 | 248 | — | — | 271 | 271 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Private equity | — | — | — | — | — | — | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 718 | $ | 1,529 | $ | 2,256 | $ | 4,503 | $ | 584 | $ | 1,304 | $ | 2,271 | $ | 4,159 | ||||||||||||||||||||||||||||||||||||||||
Less: Medical benefit assets(a) | (196) | (172) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Plus: Net receivables (payables)(b) | (35) | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair value of pension plans’ assets | $ | 4,272 | $ | 4,027 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(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)Net of receivables related to pending securities sales and payables related to pending securities purchases.
140
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, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Total | Level 1 | Level 2 | NAV | Total | |||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 10 | $ | — | $ | — | $ | 10 | $ | 14 | $ | — | $ | — | $ | 14 | ||||||||||||||||||||||||||||||||||||||||
| Equity securities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. large-capitalization | 302 | — | 81 | 383 | 221 | — | 87 | 308 | ||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. small- and mid-capitalization | 96 | — | — | 96 | 92 | — | — | 92 | ||||||||||||||||||||||||||||||||||||||||||||||||
| International | 51 | — | 49 | 100 | 43 | — | 98 | 141 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Global | — | — | 174 | 174 | — | — | 110 | 110 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal bonds | — | 161 | — | 161 | — | 123 | — | 123 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | 271 | 271 | — | — | 287 | 287 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 459 | $ | 161 | $ | 575 | $ | 1,195 | $ | 370 | $ | 123 | $ | 582 | $ | 1,075 | ||||||||||||||||||||||||||||||||||||||||
Plus: Medical benefit assets(a) | 196 | 172 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Plus: Net receivables(b) | 2 | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair value of postretirement benefit plans’ assets | $ | 1,393 | $ | 1,249 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(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)Net of receivables related to pending securities sales and payables related to pending securities purchases.
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost (income) of Ameren’s pension and postretirement benefit plans during 2023, 2022, and 2021:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
Service cost(a) | $ | 79 | $ | 128 | $ | 134 | $ | 12 | $ | 20 | $ | 23 | ||||||||||||||||||||||||||
| Non-service cost components: | ||||||||||||||||||||||||||||||||||||||
| Interest cost | 221 | 163 | 152 | 45 | 34 | 33 | ||||||||||||||||||||||||||||||||
Expected return on plan assets(b) | (333) | (320) | (297) | (91) | (85) | (80) | ||||||||||||||||||||||||||||||||
Amortization of(b): | ||||||||||||||||||||||||||||||||||||||
| Prior service credit | — | — | — | (4) | (4) | (4) | ||||||||||||||||||||||||||||||||
| Actuarial (gain) loss | (115) | 25 | 73 | (45) | (19) | (6) | ||||||||||||||||||||||||||||||||
Total non-service cost components(c) | $ | (227) | $ | (132) | $ | (72) | $ | (95) | $ | (74) | $ | (57) | ||||||||||||||||||||||||||
Net periodic benefit cost (income)(d) | $ | (148) | $ | (4) | $ | 62 | $ | (83) | $ | (54) | $ | (34) | ||||||||||||||||||||||||||
(a)Service cost, net of capitalization, is reflected in “Operating Expenses - Other operations and maintenance” on Ameren’s statement of income.
(b)Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. Net actuarial gains or losses related to the net benefit obligation subject to amortization are amortized on a straight-line basis over 10 years. The difference between the actual and expected return on plan assets is amortized over 4 years.
(c)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.
(d)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs (income). The following table presents the pension and postretirement benefit costs (income) incurred for the years ended December 31, 2023, 2022, and 2021:
| Pension Costs | Postretirement Costs | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
Ameren Missouri(a) | $ | (76) | $ | (3) | $ | 29 | $ | (30) | $ | (14) | $ | (4) | |||||||||||||||||||||||
| Ameren Illinois | (62) | 3 | 34 | (54) | (41) | (31) | |||||||||||||||||||||||||||||
| Other | (10) | (4) | (1) | 1 | 1 | 1 | |||||||||||||||||||||||||||||
| Ameren | $ | (148) | $ | (4) | $ | 62 | $ | (83) | $ | (54) | $ | (34) | |||||||||||||||||||||||
(a)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in customer rates.
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The expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, as of December 31, 2023, are as follows:
| Pension Benefits | Postretirement Benefits | ||||||||||||||||||||||||||||
| Paid from Qualified Trust Funds | Paid from Company Funds | Paid from Qualified Trust Funds | Paid from Company Funds | ||||||||||||||||||||||||||
| 2024 | $ | 277 | $ | 3 | $ | 56 | $ | 3 | |||||||||||||||||||||
| 2025 | 281 | 3 | 58 | 3 | |||||||||||||||||||||||||
| 2026 | 287 | 3 | 58 | 3 | |||||||||||||||||||||||||
| 2027 | 290 | 3 | 58 | 3 | |||||||||||||||||||||||||
| 2028 | 293 | 2 | 58 | 3 | |||||||||||||||||||||||||
| 2029 – 2033 | 1,488 | 13 | 289 | 15 | |||||||||||||||||||||||||
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, 2023, 2022, and 2021:
| Pension Benefits | Postretirement Benefits | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| Discount rate at measurement date | 5.55 | % | 3.00 | % | 2.75 | % | 5.55 | % | 3.00 | % | 2.75 | % | |||||||||||||||||||||||
| Expected return on plan assets | 6.75 | 6.50 | 6.50 | 6.75 | 6.50 | 6.50 | |||||||||||||||||||||||||||||
| Increase in future compensation | 3.50 | (a) | 3.50 | 3.50 | 3.50 | (a) | 3.50 | 3.50 | |||||||||||||||||||||||||||
| Cash balance pension plan interest crediting rate | 5.00 | (b) | 5.00 | 5.00 | (c) | (c) | (c) | ||||||||||||||||||||||||||||
Medical cost trend rate (initial)(d) | (c) | (c) | (c) | (e) | 5.00 | 5.00 | |||||||||||||||||||||||||||||
Medical cost trend rate (ultimate)(d) | (c) | (c) | (c) | 5.00 | 5.00 | 5.00 | |||||||||||||||||||||||||||||
(a)Increase in future compensation is 4.50% for 2023, 4.00% in 2024, and 3.50% thereafter for the year ended December 31, 2023.
(b)Cash balance pension plan interest crediting rate is 5.50% for 2023 and 2024, and 5.00% thereafter for the year ended December 31, 2023.
(c)Not applicable.
(d)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 2.50% for the year ended December 31, 2023 and 3.00% for the years ended December 31, 2022 and 2021.
(e)Initial medical cost trend rates of 7.25% for pre-Medicare plan participants and 6.75% for post-Medicare plan participants trend down to the ultimate rate by 2030, with a 3.00% upward adjustment to the post-Medicare trend rate in 2025.
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible Ameren employees at December 31, 2023. 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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | |||||||||||||||
| Ameren Missouri | $ | 27 | $ | 23 | $ | 21 | |||||||||||
| Ameren Illinois | 21 | 19 | 16 | ||||||||||||||
| Other | 1 | 1 | 1 | ||||||||||||||
| Ameren | $ | 49 | $ | 43 | $ | 38 | |||||||||||
NOTE 11 – STOCK-BASED COMPENSATION
The 2022 Omnibus Incentive Compensation Plan is Ameren’s long-term incentive plan available for eligible employees and directors. It provides for a maximum of 8.8 million common shares to be available for grant to eligible employees and directors. At December 31, 2023, there were 8.2 million common shares remaining for grant. Awards may be restricted stock, restricted stock units, stock options (incentive stock options and nonqualified stock options), stock appreciation rights, performance awards, cash-based awards and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2023, 2022, and 2021, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2024.
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The following table summarizes Ameren’s outstanding performance share unit and restricted stock unit activity for the year ended December 31, 2023:
Performance Share Units – Market Condition(a) | Performance Share Units – Performance Condition(b) | Restricted Stock Units | |||||||||||||||||||||||||||||||||
| Share Units | Weighted-average Fair Value per Share Unit | Share Units | Weighted-average Fair Value per Share Unit | Stock Units | Weighted-average Fair Value per Stock Unit | ||||||||||||||||||||||||||||||
Outstanding at January 1, 2023(c) | 744,273 | $ | 87.23 | 119,737 | $ | 80.65 | 436,812 | $ | 80.94 | ||||||||||||||||||||||||||
| Granted | 311,674 | 88.52 | 40,118 | 84.70 | 130,600 | 84.44 | |||||||||||||||||||||||||||||
| Forfeitures | (45,080) | 90.97 | (7,389) | 84.73 | (22,566) | 84.75 | |||||||||||||||||||||||||||||
Dividend equivalents(d) | 14,749 | 89.79 | 2,372 | 82.66 | 9,132 | 82.44 | |||||||||||||||||||||||||||||
| Vested and distributed | (263,904) | 82.50 | (42,447) | 76.70 | (176,114) | 76.94 | |||||||||||||||||||||||||||||
Outstanding at December 31, 2023(c) | 761,712 | $ | 89.22 | 112,391 | $ | 83.36 | 377,864 | $ | 83.82 | ||||||||||||||||||||||||||
(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.
(c)Outstanding awards include awards that vest on a pro-rata basis due to attainment of retirement eligibility by certain employees, but have not yet been distributed. In these cases, the pro-rata basis awards have not yet been distributed as the entire performance period has not been completed. The number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.
(d)Dividend equivalents represent the right to receive shares measured by the dividend payable with respect to the corresponding number of outstanding share units. Dividend equivalents will accrue and be reinvested in additional share units throughout the performance period.
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 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 key 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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | |||||||||
| Fair value of share units awarded | $91.07 | $92.75 | $87.11 | ||||||||
| Three-year risk-free rate | 4.19% | 1.80% | 0.17% | ||||||||
Ameren’s common stock volatility(a) | 26% | 29% | 28% | ||||||||
Volatility range for the peer group(a) | 24% – 32% | 26% – 35% | 26% – 36% | ||||||||
(a)Based on a historical period that is equal to the remaining term of the performance period as of the grant date.
In addition to the market condition performance share units described above, there are an immaterial number of market condition performance share units with different vesting conditions and target payout percentages.
143
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 in each award year 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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | |||||||||||||||
| Ameren Missouri | $ | 6 | $ | 4 | $ | 5 | |||||||||||
| Ameren Illinois | 4 | 2 | 3 | ||||||||||||||
Other(a) | 16 | 18 | 14 | ||||||||||||||
| Ameren | 26 | 24 | 22 | ||||||||||||||
| Less: Income tax benefit | 7 | 6 | 6 | ||||||||||||||
| Stock-based compensation expense, net | $ | 19 | $ | 18 | $ | 16 | |||||||||||
(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 $60 million, $47 million, and $50 million for the years ended December 31, 2023, 2022, and 2021, respectively. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2023, 2022, and 2021. As of December 31, 2023, total compensation cost of $41 million related to outstanding awards not yet recognized is expected to be recognized over a weighted-average period of 26 months.
For the years ended December 31, 2023, 2022, and 2021, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $6 million, $5 million, and $5 million, respectively.
NOTE 12 – INCOME TAXES
IRA
The IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates clean energy tax credits for projects placed in service after 2024. The clean energy tax credits will apply to renewable energy production and investments, along with certain nuclear energy production, and will be phased out beginning in 2033, at the earliest. The phase-out is triggered when greenhouse gas emissions from the electric generation industry are reduced by at least 75% from the annual 2022 emission rate or at the beginning of 2033, whichever is later. The law allows for transferability to an unrelated party for cash of up to 100% of certain tax credits generated after 2022. In addition, the new law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the IRA have been and are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren.
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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, 2023, 2022, and 2021:
| Ameren Missouri | Ameren Illinois | Ameren | ||||||||||||||||||
| 2023 | ||||||||||||||||||||
| Federal statutory corporate income tax rate | 21 | % | 21 | % | 21 | % | ||||||||||||||
| Increases (decreases) from: | ||||||||||||||||||||
Amortization of excess deferred income taxes(a) | (15) | (2) | (8) | |||||||||||||||||
| Amortization of deferred investment tax credit | (1) | — | — | |||||||||||||||||
Production and other tax credits(b) | (10) | — | (4) | |||||||||||||||||
| State tax | 3 | 7 | 5 | |||||||||||||||||
| Effective income tax rate | (2) | % | 26 | % | 14 | % | ||||||||||||||
| 2022 | ||||||||||||||||||||
| Federal statutory corporate income tax rate | 21 | % | 21 | % | 21 | % | ||||||||||||||
| Increases (decreases) from: | ||||||||||||||||||||
Amortization of excess deferred income taxes(a) | (15) | (2) | (8) | |||||||||||||||||
| Amortization of deferred investment tax credit | (1) | — | — | |||||||||||||||||
Production and other tax credits(b) | (10) | — | (4) | |||||||||||||||||
| State tax | 3 | 7 | 5 | |||||||||||||||||
| Effective income tax rate | (2) | % | 26 | % | 14 | % | ||||||||||||||
| 2021 | ||||||||||||||||||||
| Federal statutory corporate income tax rate | 21 | % | 21 | % | 21 | % | ||||||||||||||
| Increases (decreases) from: | ||||||||||||||||||||
Amortization of excess deferred income taxes(a) | (15) | (3) | (8) | |||||||||||||||||
| Amortization of deferred investment tax credit | (1) | — | — | |||||||||||||||||
Production and other tax credits(b) | (7) | — | (3) | |||||||||||||||||
| State tax | 3 | 7 | 5 | |||||||||||||||||
| Stock-based compensation | — | — | (1) | |||||||||||||||||
| Effective income tax rate | 1 | % | 25 | % | 14 | % | ||||||||||||||
(a)Reflects the amortization of amounts resulting from the revaluation of deferred income taxes subject to regulatory ratemaking, which are being 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.
(b)The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM.
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The following table presents the components of income tax expense (benefit) for the years ended December 31, 2023, 2022, and 2021:
| Ameren Missouri | Ameren Illinois | Other | Ameren | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||
| Current taxes: | |||||||||||||||||||||||
| Federal | $ | (37) | $ | 27 | $ | (37) | $ | (47) | |||||||||||||||
| State | 1 | 5 | (5) | 1 | |||||||||||||||||||
| Deferred taxes: | |||||||||||||||||||||||
| Federal | 102 | 123 | 35 | 260 | |||||||||||||||||||
| State | 9 | 71 | (10) | 70 | |||||||||||||||||||
| Amortization of excess deferred income taxes | (80) | (17) | (1) | (98) | |||||||||||||||||||
| Amortization of deferred investment tax credits | (3) | — | — | (3) | |||||||||||||||||||
| Total income tax expense (benefit) | $ | (8) | $ | 209 | $ | (18) | $ | 183 | |||||||||||||||
| 2022 | |||||||||||||||||||||||
| Current taxes: | |||||||||||||||||||||||
| Federal | $ | (26) | $ | 46 | $ | (15) | $ | 5 | |||||||||||||||
| State | (5) | 16 | (10) | 1 | |||||||||||||||||||
| Deferred taxes: | |||||||||||||||||||||||
| Federal | 93 | 82 | 19 | 194 | |||||||||||||||||||
| State | 18 | 48 | 14 | 80 | |||||||||||||||||||
| Amortization of excess deferred income taxes | (86) | (13) | (1) | (100) | |||||||||||||||||||
| Amortization of deferred investment tax credits | (4) | — | — | (4) | |||||||||||||||||||
| Total income tax expense (benefit) | $ | (10) | $ | 179 | $ | 7 | $ | 176 | |||||||||||||||
| 2021 | |||||||||||||||||||||||
| Current taxes: | |||||||||||||||||||||||
| Federal | $ | — | $ | (15) | $ | 22 | $ | 7 | |||||||||||||||
| State | — | (7) | 1 | (6) | |||||||||||||||||||
| Deferred taxes: | |||||||||||||||||||||||
| Federal | 65 | 120 | (15) | 170 | |||||||||||||||||||
| State | 23 | 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 | |||||||||||||||
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, 2023 and 2022:
| Ameren Missouri | Ameren Illinois | Other | Ameren | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||
| Accumulated deferred income taxes, net liability (asset): | |||||||||||||||||||||||
| Plant-related | $ | 2,370 | $ | 2,030 | $ | 246 | $ | 4,646 | |||||||||||||||
| Regulatory assets and liabilities, net | (206) | (184) | (23) | (413) | |||||||||||||||||||
| Deferred employee benefit costs | (48) | 55 | (33) | (26) | |||||||||||||||||||
| Tax carryforwards | (124) | (33) | (61) | (218) | |||||||||||||||||||
| Other | 104 | 38 | 19 | 161 | |||||||||||||||||||
| Total net accumulated deferred income tax liabilities (assets) | 2,096 | 1,906 | 148 | 4,150 | |||||||||||||||||||
| Accumulated deferred investment tax credits | 26 | — | — | 26 | |||||||||||||||||||
| Accumulated deferred income taxes and investment tax credits | $ | 2,122 | $ | 1,906 | $ | 148 | $ | 4,176 | |||||||||||||||
| 2022 | |||||||||||||||||||||||
| Accumulated deferred income taxes, net liability (asset): | |||||||||||||||||||||||
| Plant-related | $ | 2,297 | $ | 1,880 | $ | 239 | $ | 4,416 | |||||||||||||||
| Regulatory assets and liabilities, net | (233) | (193) | (23) | (449) | |||||||||||||||||||
| Deferred employee benefit costs | (55) | 28 | (43) | (70) | |||||||||||||||||||
| Tax carryforwards | (122) | (34) | (72) | (228) | |||||||||||||||||||
| Other | 70 | 18 | 22 | 110 | |||||||||||||||||||
| Total net accumulated deferred income tax liabilities (assets) | 1,957 | 1,699 | 123 | 3,779 | |||||||||||||||||||
| Accumulated deferred investment tax credits | 25 | — | — | 25 | |||||||||||||||||||
| Accumulated deferred income taxes and investment tax credits | $ | 1,982 | $ | 1,699 | $ | 123 | $ | 3,804 | |||||||||||||||
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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, 2023 and 2022:
| Ameren Missouri | Ameren Illinois | Other | Ameren | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||
| Net operating loss carryforwards: | |||||||||||||||||||||||
State(a) | $ | — | $ | 26 | $ | 16 | $ | 42 | |||||||||||||||
| Total net operating loss carryforwards | $ | — | $ | 26 | $ | 16 | $ | 42 | |||||||||||||||
| Tax credit carryforwards: | |||||||||||||||||||||||
Federal(b) | $ | 124 | $ | 5 | $ | 45 | $ | 174 | |||||||||||||||
State(c) | — | 2 | — | 2 | |||||||||||||||||||
| Total tax credit carryforwards | $ | 124 | $ | 7 | $ | 45 | $ | 176 | |||||||||||||||
| 2022 | |||||||||||||||||||||||
| Net operating loss carryforwards: | |||||||||||||||||||||||
| Federal | $ | 3 | $ | 4 | $ | 4 | $ | 11 | |||||||||||||||
| State | 1 | 26 | 9 | 36 | |||||||||||||||||||
| Total net operating loss carryforwards | $ | 4 | $ | 30 | $ | 13 | $ | 47 | |||||||||||||||
| Tax credit carryforwards: | |||||||||||||||||||||||
| Federal | $ | 118 | $ | 3 | $ | 55 | $ | 176 | |||||||||||||||
| State | — | 1 | 4 | 5 | |||||||||||||||||||
| Total tax credit carryforwards | $ | 118 | $ | 4 | $ | 59 | $ | 181 | |||||||||||||||
(a)Will expire between 2032 and 2043.
(b)Will expire between 2030 and 2043.
(c)Will expire between 2025 and 2028.
Uncertain Tax Positions
As of December 31, 2023 and 2022, 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 2020, 2021, and 2022 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.
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. 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.
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, average price per MWh, and amount of MWhs included in the agreements:
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| IPA Procurement Event | Performance Period | MWhs | Average Price per MWh | |||||||||||
| April 2019 | January 2020 – December 2021 | 288,000 | $ | 35 | ||||||||||
| September 2019 | April 2020 – November 2021 | 170,800 | 29 | |||||||||||
| September 2020 | September 2021 – November 2022 | 204,800 | 31 | |||||||||||
| April 2021 | July 2022 – November 2022 | 33,600 | 34 | |||||||||||
| September 2021 | January 2022 – September 2023 | 136,000 | 37 | |||||||||||
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.
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.
Ameren Missouri and Ameren Illinois had long-term receivables included in “Other assets” from Ameren Services of $31 million and $34 million, respectively, as of December 31, 2023, and $41 million and $43 million, respectively, as of December 31, 2022, related to Ameren Services’ allocated portion of Ameren’s pension and postretirement benefit plans.
Transmission Services
Ameren Missouri and Ameren Illinois each receives transmission services from ATXI for their respective retail loads.
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.
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, 2023 and 2022:
| 2023 | 2022 | |||||||||||||||||||
| Ameren Missouri | Ameren Illinois | Ameren Missouri | Ameren Illinois | |||||||||||||||||
Income taxes payable to parent(a) | $ | — | $ | 2 | $ | — | $ | 50 | ||||||||||||
Income taxes receivable from parent(b) | 56 | 22 | 39 | — | ||||||||||||||||
(a)Included in “Accounts payable – affiliates” on the balance sheet.
(b)Included in “Accounts receivable – affiliates” on the balance sheet.
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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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | ||||||||||||||||||
Ameren Missouri(a) | $ | — | $ | — | $ | 207 | ||||||||||||||
Ameren Illinois(a) | 91 | 15 | 262 | |||||||||||||||||
(a)Includes capital contributions made as a result of the tax allocation agreement.
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, 2023, 2022, and 2021. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 – Short-term Debt and Liquidity.
| Agreement | Income Statement Line Item | Ameren Missouri | Ameren Illinois | ||||||||||||||||||||
| Ameren Missouri power supply agreements | Operating Revenues | 2023 | $ | 2 | $ | (a) | |||||||||||||||||
| with Ameren Illinois | 2022 | 9 | (a) | ||||||||||||||||||||
| 2021 | 16 | (a) | |||||||||||||||||||||
| Ameren Missouri and Ameren Illinois | Operating Revenues | 2023 | 32 | (b) | |||||||||||||||||||
| rent and facility services | 2022 | 25 | (b) | ||||||||||||||||||||
| 2021 | 26 | 1 | |||||||||||||||||||||
| Ameren Missouri and Ameren Illinois | Operating Revenues | 2023 | (b) | 2 | |||||||||||||||||||
| miscellaneous support services | 2022 | (b) | 2 | ||||||||||||||||||||
| 2021 | (b) | 5 | |||||||||||||||||||||
| Total Operating Revenues | 2023 | $ | 34 | $ | 2 | ||||||||||||||||||
| 2022 | 34 | 2 | |||||||||||||||||||||
| 2021 | 42 | 6 | |||||||||||||||||||||
| Ameren Illinois power supply | Purchased Power | 2023 | $ | (a) | $ | 2 | |||||||||||||||||
| agreements with Ameren Missouri | 2022 | (a) | 9 | ||||||||||||||||||||
| 2021 | (a) | 16 | |||||||||||||||||||||
| Ameren Missouri and Ameren Illinois | Purchased Power | 2023 | 2 | 1 | |||||||||||||||||||
| transmission services from ATXI | 2022 | 1 | (b) | ||||||||||||||||||||
| 2021 | 4 | 1 | |||||||||||||||||||||
| Total Purchased Power | 2023 | $ | 2 | $ | 3 | ||||||||||||||||||
| 2022 | 1 | 9 | |||||||||||||||||||||
| 2021 | 4 | 17 | |||||||||||||||||||||
| Ameren Missouri and Ameren Illinois | Other Operations and | 2023 | $ | (b) | $ | 3 | |||||||||||||||||
| rent and facility services | Maintenance | 2022 | (b) | 3 | |||||||||||||||||||
| 2021 | 1 | 4 | |||||||||||||||||||||
| Ameren Services support services | Other Operations and | 2023 | 148 | 138 | |||||||||||||||||||
| agreement | Maintenance | 2022 | 150 | 141 | |||||||||||||||||||
| 2021 | 147 | 137 | |||||||||||||||||||||
| Total Other Operations and | 2023 | $ | 148 | $ | 141 | ||||||||||||||||||
| Maintenance Expenses | 2022 | 150 | 144 | ||||||||||||||||||||
| 2021 | 148 | 141 | |||||||||||||||||||||
| Money pool borrowings (advances) | (Interest Charges) | 2023 | $ | (b) | $ | (b) | |||||||||||||||||
| Other Income, Net | 2022 | (b) | (b) | ||||||||||||||||||||
| 2021 | (b) | (b) | |||||||||||||||||||||
(a)Not applicable.
(b)Amount less than $1 million.
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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.
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 by 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 energy-related 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 requirements of environmental laws.
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. Regulations under the Clean Air Act 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. Regulations implementing the Clean Water Act govern both intake and discharges of water, as well as evaluation of the ecological and biological impact of those 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, capital expenditures associated with these modifications 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 surface impoundments at Ameren Missouri’s coal-fired energy centers. The individual or combined effects of compliance with 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.
Additionally, Ameren Missouri’s wind generation facilities may be subject to operating restrictions to limit the impact on protected species. Since 2021, Ameren Missouri’s High Prairie Renewable Energy Center curtailed nighttime operations from April through October to limit impacts on protected species during the critical biological season. The extent and duration of future curtailments are unknown at this time as assessment of mitigation technologies is ongoing. Ameren Missouri does not anticipate these operating curtailments will have a material impact on its results of operations, financial position, or liquidity.
Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $90 million to $120 million from 2024 through 2028 in order to comply with existing environmental regulations. Additional capital expenditures for environmental controls beyond 2028 could be required. This estimate of capital expenditures includes surface impoundment closure and corrective action measures required by the CCR Rule and 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 2023 IRP filed with the MoPSC in September 2023 and as noted below with respect to the NSR and Clean Air Act litigation and Illinois emissions standards, Ameren Missouri’s current plan for compliance with existing air emission regulations includes 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 by state regulators and the EPA, revisions to regulatory obligations, and varying cost of potential compliance strategies, among other things.
The following sections describe the more significant environmental statutes and regulations and environmental enforcement and remediation matters that affect or could affect our operations. The EPA periodically amends and revises its regulations and proposes amendments to regulations and guidelines, which could ultimately result in the revision of all or part of such regulations.
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Clean Air Act
Federal and state laws, including the CSAPR, regulate emissions of SO2 and NOx through the reduction of emissions at their source and the use and retirement of emission allowances. In April 2022, the EPA proposed plans for additional NOx emission reductions from power plants in Missouri, Illinois, and other states through revisions to the CSAPR. In January 2023, the EPA issued its final disapproval of Missouri’s proposed state implementation plan for addressing the transport of ozone under the Good Neighbor Plan of the Clean Air Act. The disapproval of the state plan allows the EPA to implement revisions to the CSAPR through a federal implementation plan. In March 2023, the EPA announced federal implementation plan requirements, which were subsequently published to the Federal Register in June 2023, reducing the amount of NOx allowances available for state budgets and imposing NOx emission limits on electric generating units for Missouri, Illinois, and other states under the Good Neighbor Plan of the Clean Air Act. In April 2023, the Missouri Attorney General and Ameren Missouri separately filed lawsuits in the United States Court of Appeals for the Eighth Circuit challenging the EPA’s disapproval of the Missouri state plan and sought a stay of the EPA’s disapproval of the Missouri state plan. The United States Court of Appeals for the Eighth Circuit in May 2023 granted those stay motions thereby preventing the EPA from imposing the federal implementation plan until the court of appeals issues a ruling. In December 2023, the United States Supreme Court agreed to hear challenges to the Good Neighbor Plan and scheduled oral argument for February 2024, with a decision expected by June 2024. Ameren Missouri complies with the 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 existing NOx air pollution control equipment. Reducing the amount of state budget NOx allowances for compliance with NOx emission limits could result in additional controls being required on Ameren Missouri’s generating units and/or the reduction of operations. Any additional costs for compliance are expected to be recovered from customers, subject to MoPSC prudence review, through the FAC or higher base rates.
CO2 Emissions Standards
In June 2022, the United States Supreme Court issued its decision in West Virginia v. EPA, clarifying that there are limits on how the EPA may regulate greenhouse gases absent further direction from the United States Congress. The court concluded that the EPA’s proposed rules were designed to shift generation from fossil-fuel-fired power plants to renewable energy facilities, which was improper absent specific congressional authorization. In May 2023, the EPA issued a new proposed rule that would set CO2 emission standards for new and existing fossil-fuel-fired power plants based on the adoption of carbon capture technology, natural gas co-firing, and co-firing hydrogen fuel to reduce emissions. If the proposed rule were adopted, the affected fossil-fuel-fired power plants would be required to comply with the rule through a phased-in approach or retire. Capacity restrictions for coal-fired units could apply as early as 2030. Larger natural gas-fired power plants would be required to co-fire with hydrogen by 2032, with additional requirements by 2038. The EPA expects to issue a final rule in 2024. Legal challenges to the final rule, if adopted as proposed, are expected. Ameren and Ameren Missouri cannot predict the results of any such challenges or potential impacts of any such regulations on their results of operations, financial position, and liquidity until final regulations are adopted and the merits of such legal challenges are determined.
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 projects performed in 2007 and 2010 at the coal-fired Rush Island Energy Center 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. Following an appeal from Ameren Missouri, in August 2021, the United States Court of Appeals for the Eighth Circuit 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 September 2023, the district court granted Ameren Missouri’s request 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. In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri to operate the energy center as directed by the MISO. The United States Department of Justice is seeking an order from the district court providing for additional mitigation relief. Ameren Missouri could be required to implement mitigation relief measures, the costs of which could be material and which Ameren Missouri would not expect to recover. Ameren Missouri is challenging such mitigation claims, noting that the scope of any such potential additional mitigation relief should be limited by the August 2021 court of appeals decision and offset by emission reductions resulting from the accelerated retirement of the Rush Island Energy Center.
The MISO designated the energy center as a system support resource in 2022 and concluded that certain reliability mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation through August 2024, and in September 2023, an agreement between Ameren Missouri and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies. The system support resource
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designation and the related agreement are subject to annual renewal and revision. Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the upgrades expected to be completed in the fall of 2024. Ameren Missouri expects to complete the last of the upgrades by mid-2025. In addition, in August 2023, the FERC approved a settlement agreement for Ameren Missouri’s request for recovery of non-energy costs under the related MISO tariff between Ameren Missouri and certain intervenors, which provided for recovery of substantially all of Ameren Missouri’s requested non-energy costs through August 2023. In October 2023, Ameren Missouri received FERC approval for the recovery of non-energy costs under the related MISO tariff from September 2023 to August 2024. Revenues and costs under the MISO tariff are included in the FAC. 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 accelerated retirement of the Rush Island Energy Center, Ameren Missouri is seeking 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 Missouri’s securitization statute. See Note 2 – Rate and Regulatory Matters for additional information. As of December 31, 2023, the Rush Island Energy Center had a net plant balance of $530 million included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net”. See Note 1 – Summary of Significant Accounting Policies for additional information regarding plant to be abandoned, net.
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
Among other items, the Clean Water Act requires 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 this 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. Permits for Ameren Missouri’s coal-fired and nuclear energy centers have been issued or are in the process of renewal.
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 by 2025. To comply with these guidelines, Ameren Missouri installed dry ash handling systems and wastewater treatment facilities at its coal-fired energy centers.
CCR Management
The EPA’s CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and has resulted in the closure of surface impoundments at Ameren Missouri’s energy centers, with closures of surface impoundments in process at its Sioux Energy Center and retired Meramec Energy Center. Ameren Missouri plans to substantially complete the closures of remaining surface impoundments by the end of 2026. Ameren Missouri’s CCR management compliance plan includes installation of groundwater monitoring equipment and groundwater treatment facilities. Ameren and Ameren Missouri have AROs of $40 million recorded on their respective balance sheets as of December 31, 2023, associated with CCR storage 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, 2023, Ameren Illinois has remediated the majority of the 44 former MGP sites in Illinois with an estimated remaining obligation primarily related to three of these former MGP sites at $51 million to $96 million. Ameren and Ameren Illinois recorded a liability of $51 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate. Ameren cannot estimate the completion date of the estimated remaining obligation due to site accessibility, among other things. 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.
The ICC allows Ameren Illinois to recover MGP 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.
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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, including additional or more stringent cleanup standards, or will affect our results of operations, financial position, or liquidity.
Illinois Emission Standards
The CEJA established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the CEJA, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service. Ameren Missouri filed its 2023 IRP with the MoPSC in September 2023 to reflect, among other things, the updated scheduled retirement dates of the natural gas-fired energy centers located in the state of Illinois.
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, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Ameren | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | |||||||||||||||||||||
| Cash and cash equivalents | $ | 25 | $ | — | $ | — | $ | 10 | $ | — | $ | — | ||||||||||||||
| Restricted cash included in “Other current assets” | 13 | 5 | 5 | 13 | 5 | 6 | ||||||||||||||||||||
| Restricted cash included in “Other assets” | 229 | — | 229 | 185 | — | 185 | ||||||||||||||||||||
| Restricted cash included in “Nuclear decommissioning trust fund” | 5 | 5 | — | 8 | 8 | — | ||||||||||||||||||||
| Total cash, cash equivalents, and restricted cash | $ | 272 | $ | 10 | $ | 234 | $ | 216 | $ | 13 | $ | 191 | ||||||||||||||
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, 2023 and 2022, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $42 million and $31 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, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||
| Ameren Missouri | Ameren Illinois(a) | Ameren | Ameren Missouri | Ameren Illinois(a) | Ameren | ||||||||||||||||||||||||
| Beginning balance at January 1 | $ | 13 | $ | 18 | $ | 31 | $ | 13 | $ | 16 | $ | 29 | |||||||||||||||||
| Bad debt expense | 11 | 40 | 51 | 9 | 25 | 34 | |||||||||||||||||||||||
Charged to other accounts(b) | — | 5 | 5 | — | 4 | 4 | |||||||||||||||||||||||
| Net write-offs | (12) | (45) | (57) | (9) | (27) | (36) | |||||||||||||||||||||||
| Ending balance at December 31 | $ | 12 | $ | 18 | $ | 30 | $ | 13 | $ | 18 | $ | 31 | |||||||||||||||||
(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)Amounts associated with the allowance for doubtful accounts related to receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.
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As of December 31, 2023, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 22%, 16%, and 27%, or $114 million, $35 million, and $79 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. In comparison, as of December 31, 2022, these percentages were 17%, 14%, and 20%, or $107 million, $35 million, and $71 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
Inventories
The following table presents the components of inventories for each of the Ameren Companies at December 31, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | |||||||||||||||||||||
Fuel(a) | $ | 109 | $ | — | $ | 109 | $ | 79 | $ | — | $ | 79 | ||||||||||||||
| Natural gas stored underground | 8 | 87 | 95 | 10 | 120 | 130 | ||||||||||||||||||||
| Materials, supplies, and other | 391 | 138 | 529 | 345 | 113 | 458 | ||||||||||||||||||||
| Total inventories | $ | 508 | $ | 225 | $ | 733 | $ | 434 | $ | 233 | $ | 667 | ||||||||||||||
(a)Consists of coal, oil, and propane.
Asset Retirement Obligations
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years ended December 31, 2023 and 2022:
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||
| Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | |||||||||||||||||||||||||||||||||||||||
| Beginning balance at January 1 | $ | 782 | (a) | $ | 4 | (b) | $ | 786 | (a) | $ | 760 | $ | 4 | $ | 764 | |||||||||||||||||||||||||||||
| Liabilities incurred | — | — | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||
| Liabilities settled | (10) | — | (10) | (4) | — | (4) | ||||||||||||||||||||||||||||||||||||||
Accretion(c) | 33 | — | 33 | 32 | — | 32 | ||||||||||||||||||||||||||||||||||||||
| Change in estimates | (18) | — | (18) | (7) | — | (7) | ||||||||||||||||||||||||||||||||||||||
| Ending balance at December 31 | $ | 787 | (a)(d) | $ | 4 | (b) | $ | 791 | (a)(d) | $ | 782 | (a) | $ | 4 | (b) | $ | 786 | (a) | ||||||||||||||||||||||||||
(a)Balance included $19 million and $23 million in “Other current liabilities” on the balance sheet as of December 31, 2023 and 2022, respectively.
(b)Included in “Other deferred credits and liabilities” on the balance sheet.
(c)Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.
(d)The balance as of December 31, 2023, included an ARO related to the decommissioning of the Callaway Enter Center of $619 million.
Deferred Compensation
As of December 31, 2023, and 2022, the present value of benefits to be paid for deferred compensation obligations was $85 million and $87 million, respectively, which was primarily reflected in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. Deferred compensation obligations are primarily recorded on the balance sheet of Ameren (parent).
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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Ameren Missouri | $ | 166 | $ | 162 | $ | 150 | ||||||||||||||
| Ameren Illinois | 121 | 133 | 125 | |||||||||||||||||
| Ameren | $ | 287 | $ | 295 | $ | 275 | ||||||||||||||
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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 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Average rate: | ||||||||||||||||||||
| Ameren Missouri | 6 | % | 5 | % | 6 | % | ||||||||||||||
| Ameren Illinois | 6 | % | 5 | % | 5 | % | ||||||||||||||
| Ameren: | ||||||||||||||||||||
| Allowance for equity funds used during construction | $ | 54 | $ | 43 | $ | 43 | ||||||||||||||
| Allowance for borrowed funds used during construction | 48 | 26 | 17 | |||||||||||||||||
| Total Ameren | $ | 102 | $ | 69 | $ | 60 | ||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||
| Allowance for equity funds used during construction | $ | 30 | $ | 24 | $ | 26 | ||||||||||||||
| Allowance for borrowed funds used during construction | 27 | 13 | 10 | |||||||||||||||||
| Total Ameren Missouri | $ | 57 | $ | 37 | $ | 36 | ||||||||||||||
| Ameren Illinois: | ||||||||||||||||||||
| Allowance for equity funds used during construction | $ | 19 | $ | 18 | $ | 17 | ||||||||||||||
| Allowance for borrowed funds used during construction | 17 | 12 | 7 | |||||||||||||||||
| Total Ameren Illinois | $ | 36 | $ | 30 | $ | 24 | ||||||||||||||
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, 2023, 2022, and 2021:
| 2023 | 2022 | 2021 | |||||||||||||||
| Weighted-average Common Shares Outstanding – Basic | 262.8 | 258.4 | 256.3 | ||||||||||||||
| Assumed settlement of performance share units and restricted stock units | 0.6 | 1.0 | 1.3 | ||||||||||||||
| Dilutive effect of forward sale agreements | — | 0.1 | — | ||||||||||||||
Weighted-average Common Shares Outstanding – Diluted(a) | 263.4 | 259.5 | 257.6 | ||||||||||||||
(a)There was an immaterial number of anti-dilutive securities excluded from the earnings per diluted share calculations for the years ended December 31, 2023, 2022, and 2021 related to performance share units and restricted stock units. The outstanding forward sale agreements as of December 31, 2023, were anti-dilutive for the year ended December 31, 2023, and excluded from the earnings per diluted share calculation as calculated using the treasury stock method.
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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, 2023, 2022, and 2021:
| December 31, 2023 | December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||
| Ameren | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | ||||||||||||||||||||||||||||||
| Investing | ||||||||||||||||||||||||||||||||||||||
Accrued capital expenditures, including nuclear fuel expenditures | $ | 518 | $ | 270 | $ | 212 | $ | 441 | $ | 243 | $ | 181 | $ | 524 | $ | 301 | $ | 215 | ||||||||||||||||||||
| Net realized and unrealized gain (loss) – nuclear decommissioning trust fund | 167 | 167 | — | (218) | (218) | — | 163 | 163 | — | |||||||||||||||||||||||||||||
Return of investment in industrial development revenue bonds(a) | 240 | 240 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Financing | ||||||||||||||||||||||||||||||||||||||
| Issuance of common stock for stock-based compensation | $ | 40 | $ | — | $ | — | $ | 31 | $ | — | $ | — | $ | 33 | $ | — | $ | — | ||||||||||||||||||||
| Issuance of common stock under the DRPlus | 7 | — | — | 8 | — | — | — | — | — | |||||||||||||||||||||||||||||
Termination of a financing agreement(a) | 240 | 240 | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||
(a)In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri.
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.
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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, 2023, 2022, and 2021. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.
Ameren
| Ameren Missouri | Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Transmission | Other | Intersegment Eliminations | Ameren | |||||||||||||||||||||||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||||||||||||||||||||
| External revenues | $ | 3,825 | $ | 2,217 | $ | 897 | $ | 561 | $ | — | $ | — | $ | 7,500 | |||||||||||||||||||||||||||||||||
| Intersegment revenues | 34 | 1 | — | 116 | — | (151) | — | ||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | 783 | 351 | 108 | 138 | 7 | — | 1,387 | ||||||||||||||||||||||||||||||||||||||||
| Interest income | 11 | 19 | 1 | 2 | 5 | (5) | 33 | ||||||||||||||||||||||||||||||||||||||||
| Interest charges | 227 | 89 | 55 | 96 | (a) | 104 | (5) | 566 | |||||||||||||||||||||||||||||||||||||||
| Income taxes (benefit) | (8) | 82 | 50 | 106 | (47) | — | 183 | ||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Ameren common shareholders | 545 | 258 | 134 | 296 | (81) | — | 1,152 | ||||||||||||||||||||||||||||||||||||||||
| Capital expenditures | 1,760 | 752 | 299 | 804 | 9 | (27) | 3,597 | ||||||||||||||||||||||||||||||||||||||||
| 2022 | |||||||||||||||||||||||||||||||||||||||||||||||
| External revenues | $ | 4,012 | $ | 2,255 | $ | 1,180 | $ | 510 | $ | — | $ | — | $ | 7,957 | |||||||||||||||||||||||||||||||||
| Intersegment revenues | 34 | 1 | — | 105 | — | (140) | — | ||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | 732 | 332 | 98 | 123 | 4 | — | 1,289 | ||||||||||||||||||||||||||||||||||||||||
| Interest income | 28 | 7 | — | — | 1 | (1) | 35 | ||||||||||||||||||||||||||||||||||||||||
| Interest charges | 213 | 74 | 44 | 84 | (a) | 72 | (1) | 486 | |||||||||||||||||||||||||||||||||||||||
| Income taxes (benefit) | (10) | 68 | 46 | 92 | (20) | — | 176 | ||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Ameren common shareholders | 562 | 202 | 123 | 263 | (76) | — | 1,074 | ||||||||||||||||||||||||||||||||||||||||
| Capital expenditures | 1,690 | 621 | 308 | 741 | 7 | (16) | 3,351 | ||||||||||||||||||||||||||||||||||||||||
| 2021 | |||||||||||||||||||||||||||||||||||||||||||||||
| External revenues | $ | 3,311 | $ | 1,635 | $ | 957 | $ | 491 | $ | — | $ | — | $ | 6,394 | |||||||||||||||||||||||||||||||||
| Intersegment revenues | 42 | 4 | — | 71 | — | (117) | — | ||||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | 632 | 309 | 90 | 111 | 4 | — | 1,146 | ||||||||||||||||||||||||||||||||||||||||
| Interest income | 26 | 1 | — | — | 3 | (3) | 27 | ||||||||||||||||||||||||||||||||||||||||
| Interest charges | 137 | 74 | 42 | 83 | (a) | 50 | (3) | 383 | |||||||||||||||||||||||||||||||||||||||
| Income taxes (benefit) | 3 | 53 | 39 | 82 | (20) | — | 157 | ||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Ameren common shareholders | 518 | 165 | 108 | 230 | (31) | — | 990 | ||||||||||||||||||||||||||||||||||||||||
| Capital expenditures | 2,015 | 579 | 278 | 616 | 4 | (13) | 3,479 | ||||||||||||||||||||||||||||||||||||||||
(a)Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent).
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Ameren Illinois
| Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Illinois Transmission | Intersegment Eliminations | Ameren Illinois | ||||||||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||||||||
| External revenues | $ | 2,218 | $ | 897 | $ | 367 | $ | — | $ | 3,482 | ||||||||||||||||||||||
| Intersegment revenues | — | — | 113 | (113) | — | |||||||||||||||||||||||||||
| Depreciation and amortization | 351 | 108 | 97 | — | 556 | |||||||||||||||||||||||||||
| Interest income | 19 | 1 | 1 | — | 21 | |||||||||||||||||||||||||||
| Interest charges | 89 | 55 | 60 | — | 204 | |||||||||||||||||||||||||||
| Income taxes | 82 | 50 | 77 | — | 209 | |||||||||||||||||||||||||||
| Net income available to common shareholder | 258 | 134 | 215 | — | 607 | |||||||||||||||||||||||||||
| Capital expenditures | 752 | 299 | 680 | — | 1,731 | |||||||||||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||||||||
| External revenues | $ | 2,256 | $ | 1,180 | $ | 320 | $ | — | $ | 3,756 | ||||||||||||||||||||||
| Intersegment revenues | — | — | 104 | (104) | — | |||||||||||||||||||||||||||
| Depreciation and amortization | 332 | 98 | 84 | — | 514 | |||||||||||||||||||||||||||
| Interest income | 7 | — | — | — | 7 | |||||||||||||||||||||||||||
| Interest charges | 74 | 44 | 50 | — | 168 | |||||||||||||||||||||||||||
| Income taxes | 68 | 46 | 65 | — | 179 | |||||||||||||||||||||||||||
| Net income available to common shareholder | 202 | 123 | 188 | — | 513 | |||||||||||||||||||||||||||
| Capital expenditures | 621 | 308 | 672 | — | 1,601 | |||||||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||||||||
| External revenues | $ | 1,639 | $ | 957 | $ | 299 | $ | — | $ | 2,895 | ||||||||||||||||||||||
| Intersegment revenues | — | — | 66 | (66) | — | |||||||||||||||||||||||||||
| Depreciation and amortization | 309 | 90 | 73 | — | 472 | |||||||||||||||||||||||||||
| Interest income | 1 | — | — | — | 1 | |||||||||||||||||||||||||||
| Interest charges | 74 | 42 | 48 | — | 164 | |||||||||||||||||||||||||||
| Income taxes | 53 | 39 | 51 | — | 143 | |||||||||||||||||||||||||||
| Net income available to common shareholder | 165 | 108 | 152 | — | 425 | |||||||||||||||||||||||||||
| Capital expenditures | 579 | 278 | 575 | — | 1,432 | |||||||||||||||||||||||||||
158
The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the years ended December 31, 2023, 2022, and 2021. 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 sales and capacity revenues.
Ameren
| Ameren Missouri | Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Transmission | Intersegment Eliminations | Ameren | |||||||||||||||||||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||||||||||||||||||||
| Residential | $ | 1,577 | $ | 1,344 | $ | — | $ | — | $ | — | $ | 2,921 | ||||||||||||||||||||||||||||||||
| Commercial | 1,280 | 747 | — | — | — | 2,027 | ||||||||||||||||||||||||||||||||||||||
| Industrial | 306 | 186 | — | — | — | 492 | ||||||||||||||||||||||||||||||||||||||
| Other | 531 | (59) | — | 677 | (150) | 999 | ||||||||||||||||||||||||||||||||||||||
| Total electric revenues | $ | 3,694 | $ | 2,218 | $ | — | $ | 677 | $ | (150) | $ | 6,439 | ||||||||||||||||||||||||||||||||
| Residential | $ | 100 | $ | — | $ | 657 | $ | — | $ | — | $ | 757 | ||||||||||||||||||||||||||||||||
| Commercial | 46 | — | 164 | — | — | 210 | ||||||||||||||||||||||||||||||||||||||
| Industrial | 5 | — | 14 | — | — | 19 | ||||||||||||||||||||||||||||||||||||||
| Other | 14 | — | 62 | — | (1) | 75 | ||||||||||||||||||||||||||||||||||||||
| Total gas revenues | $ | 165 | $ | — | $ | 897 | $ | — | $ | (1) | $ | 1,061 | ||||||||||||||||||||||||||||||||
Total revenues(a) | $ | 3,859 | $ | 2,218 | $ | 897 | $ | 677 | $ | (151) | $ | 7,500 | ||||||||||||||||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||||||||||||||||||||
| Residential | $ | 1,578 | $ | 1,325 | $ | — | $ | — | $ | — | $ | 2,903 | ||||||||||||||||||||||||||||||||
| Commercial | 1,219 | 768 | — | — | — | 1,987 | ||||||||||||||||||||||||||||||||||||||
| Industrial | 290 | 199 | — | — | — | 489 | ||||||||||||||||||||||||||||||||||||||
| Other | 762 | (36) | — | 615 | (139) | 1,202 | ||||||||||||||||||||||||||||||||||||||
| Total electric revenues | $ | 3,849 | $ | 2,256 | $ | — | $ | 615 | $ | (139) | $ | 6,581 | ||||||||||||||||||||||||||||||||
| Residential | $ | 119 | $ | — | $ | 846 | $ | — | $ | — | $ | 965 | ||||||||||||||||||||||||||||||||
| Commercial | 56 | — | 221 | — | — | 277 | ||||||||||||||||||||||||||||||||||||||
| Industrial | 7 | — | 41 | — | — | 48 | ||||||||||||||||||||||||||||||||||||||
| Other | 15 | — | 72 | — | (1) | 86 | ||||||||||||||||||||||||||||||||||||||
| Total gas revenues | $ | 197 | $ | — | $ | 1,180 | $ | — | $ | (1) | $ | 1,376 | ||||||||||||||||||||||||||||||||
Total revenues(a) | $ | 4,046 | $ | 2,256 | $ | 1,180 | $ | 615 | $ | (140) | $ | 7,957 | ||||||||||||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||||||||||||||||||||
| Residential | $ | 1,445 | $ | 933 | $ | — | $ | — | $ | — | $ | 2,378 | ||||||||||||||||||||||||||||||||
| Commercial | 1,126 | 545 | — | — | — | 1,671 | ||||||||||||||||||||||||||||||||||||||
| Industrial | 280 | 135 | — | — | — | 415 | ||||||||||||||||||||||||||||||||||||||
| Other | 361 | 26 | — | 562 | (116) | 833 | ||||||||||||||||||||||||||||||||||||||
| Total electric revenues | $ | 3,212 | $ | 1,639 | $ | — | $ | 562 | $ | (116) | $ | 5,297 | ||||||||||||||||||||||||||||||||
| Residential | $ | 79 | $ | — | $ | 657 | $ | — | $ | — | $ | 736 | ||||||||||||||||||||||||||||||||
| Commercial | 34 | — | 172 | — | — | 206 | ||||||||||||||||||||||||||||||||||||||
| Industrial | 4 | — | 35 | — | — | 39 | ||||||||||||||||||||||||||||||||||||||
| Other | 24 | — | 93 | — | (1) | 116 | ||||||||||||||||||||||||||||||||||||||
| Total gas revenues | $ | 141 | $ | — | $ | 957 | $ | — | $ | (1) | $ | 1,097 | ||||||||||||||||||||||||||||||||
Total revenues(a) | $ | 3,353 | $ | 1,639 | $ | 957 | $ | 562 | $ | (117) | $ | 6,394 | ||||||||||||||||||||||||||||||||
(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, 2023, 2022, and 2021:
159
| Ameren Missouri | Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Transmission | Ameren | ||||||||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||||||||
| Revenues from alternative revenue programs | $ | (5) | $ | 116 | $ | 49 | $ | 19 | $ | 179 | ||||||||||||||||||||||
| Other revenues not from contracts with customers | (9) | (a) | 7 | 2 | — | — | (a) | |||||||||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||||||||
| Revenues from alternative revenue programs | $ | 17 | $ | 89 | $ | (19) | $ | (9) | $ | 78 | ||||||||||||||||||||||
| Other revenues not from contracts with customers | (103) | (a)(b) | 6 | 3 | — | (94) | (a)(b) | |||||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||||||||
| Revenues from alternative revenue programs | $ | (16) | $ | 77 | $ | 5 | $ | 11 | $ | 77 | ||||||||||||||||||||||
| Other revenues not from contracts with customers | 56 | (a)(b) | 10 | 2 | — | 68 | (a)(b) | |||||||||||||||||||||||||
(a)Includes net realized gains and losses on derivative power contracts.
(b)Includes $10 million and $78 million for insurance recoveries related to lost sales associated with the Callaway Energy Center maintenance outage for the years ended December 31, 2022 and 2021, respectively.
Ameren Illinois
| Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Illinois Transmission | Intersegment Eliminations | Ameren Illinois | ||||||||||||||||||||||||||||
| 2023 | ||||||||||||||||||||||||||||||||
| Residential | $ | 1,344 | $ | 657 | $ | — | $ | — | $ | 2,001 | ||||||||||||||||||||||
| Commercial | 747 | 164 | — | — | 911 | |||||||||||||||||||||||||||
| Industrial | 186 | 14 | — | — | 200 | |||||||||||||||||||||||||||
| Other | (59) | 62 | 480 | (113) | 370 | |||||||||||||||||||||||||||
Total revenues(a) | $ | 2,218 | $ | 897 | $ | 480 | $ | (113) | $ | 3,482 | ||||||||||||||||||||||
| 2022 | ||||||||||||||||||||||||||||||||
| Residential | $ | 1,325 | $ | 846 | $ | — | $ | — | $ | 2,171 | ||||||||||||||||||||||
| Commercial | 768 | 221 | — | — | 989 | |||||||||||||||||||||||||||
| Industrial | 199 | 41 | — | — | 240 | |||||||||||||||||||||||||||
| Other | (36) | 72 | 424 | (104) | 356 | |||||||||||||||||||||||||||
Total revenues(a) | $ | 2,256 | $ | 1,180 | $ | 424 | $ | (104) | $ | 3,756 | ||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||||||||
| Residential | $ | 933 | $ | 657 | $ | — | $ | — | $ | 1,590 | ||||||||||||||||||||||
| Commercial | 545 | 172 | — | — | 717 | |||||||||||||||||||||||||||
| Industrial | 135 | 35 | — | — | 170 | |||||||||||||||||||||||||||
| Other | 26 | 93 | 365 | (66) | 418 | |||||||||||||||||||||||||||
Total revenues(a) | $ | 1,639 | $ | 957 | $ | 365 | $ | (66) | $ | 2,895 | ||||||||||||||||||||||
(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, 2023, 2022, and 2021:
| Ameren Illinois Electric Distribution | Ameren Illinois Natural Gas | Ameren Illinois Transmission | Ameren Illinois | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||
| Revenues from alternative revenue programs | $ | 116 | $ | 49 | $ | 12 | $ | 177 | |||||||||||||||
| Other revenues not from contracts with customers | 7 | 2 | — | 9 | |||||||||||||||||||
| 2022 | |||||||||||||||||||||||
| Revenues from alternative revenue programs | $ | 89 | $ | (19) | $ | (7) | $ | 63 | |||||||||||||||
| Other revenues not from contracts with customers | 6 | 3 | — | 9 | |||||||||||||||||||
| 2021 | |||||||||||||||||||||||
| Revenues from alternative revenue programs | $ | 77 | $ | 5 | $ | 9 | $ | 91 | |||||||||||||||
| Other revenues not from contracts with customers | 10 | 2 | — | 12 | |||||||||||||||||||
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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ITEM 9A.CONTROLS AND PROCEDURES
(a)Evaluation of Disclosure Controls and Procedures
As of December 31, 2023, 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, 2023, 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, 2023. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2023, 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
Insider Adoption or Termination of Trading Arrangements
During the fiscal quarter ended December 31, 2023, none of our directors or officers informed us of the adoption or termination of a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Regulation S-K, Item 408.
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 2024 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 2024 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” and “Corporate Governance.”
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.
161
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 Noelle K. Eder, Rafael Flores, Richard J. Harshman, and Leo S. Mackay, Jr. serve as members. The board of directors of Ameren has determined that J. Edward Coleman and Richard J. Harshman 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 Ameren’s Director Nomination Policy, 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 2024 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 2024 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, 2023, 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)(b) | |||||||||||||||||
| Equity compensation plans approved by security holders | 1,376,597 | (c) | 8,201,140 | |||||||||||||||||
| Equity compensation plans not approved by security holders | — | — | — | |||||||||||||||||
| Total | 1,376,597 | (c) | 8,201,140 | |||||||||||||||||
(a)Of the securities to be issued, 874,103 of the securities represent the target number of outstanding performance share units (PSUs) and 377,864 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 2024 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. The remaining 124,630 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)Includes shares remaining available for issuance pursuant to awards under the Ameren Corporation 2022 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.
162
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 2024 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 2024 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 statements: “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 2024 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 2024 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 2024 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 statements: “Selection of Independent Registered Public Accounting Firm.”
163
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, 2023, 2022, and 2021 | |||||
| Consolidated Balance Sheet – December 31, 2023 and 2022 | |||||
| Consolidated Statement of Cash Flows – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Ameren Missouri | |||||
| Report of Independent Registered Public Accounting Firm – | |||||
| (PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238) | |||||
| Consolidated Statement of Income – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Consolidated Balance Sheet – December 31, 2023 and 2022 | |||||
| Consolidated Statement of Cash Flows – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2023, 2022, and 2021 | |||||
| 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, 2023, 2022, and 2021 | |||||
| Balance Sheet – December 31, 2023 and 2022 | |||||
| Statement of Cash Flows – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Statement of Shareholders’ Equity – Years Ended December 31, 2023, 2022, and 2021 | |||||
| (a)(2) Financial Statement Schedules | |||||
| Schedule I | |||||
| Condensed Financial Information of Parent – Ameren: | |||||
| Condensed Statement of Income and Comprehensive Income – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Condensed Balance Sheet – December 31, 2023 and 2022 | |||||
| Condensed Statement of Cash Flows – Years Ended December 31, 2023, 2022, and 2021 | |||||
| Schedule II | |||||
| Ameren | |||||
| Valuation and Qualifying Accounts for the years ended December 31, 2023, 2022, and 2021 | |||||
| Ameren Missouri | |||||
| Valuation and Qualifying Accounts for the years ended December 31, 2023, 2022, and 2021 | |||||
| Ameren Illinois | |||||
| Valuation and Qualifying Accounts for the years ended December 31, 2023, 2022, and 2021 | |||||
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.
164
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME For the Years Ended December 31, 2023, 2022, and 2021 | |||||||||||||||||
| (In millions) | 2023 | 2022 | 2021 | ||||||||||||||
| Operating revenues | $ | — | $ | — | $ | — | |||||||||||
| Operating expenses | 22 | 15 | 13 | ||||||||||||||
| Operating loss | (22) | (15) | (13) | ||||||||||||||
| Equity in earnings of subsidiaries | 1,245 | 1,161 | 1,039 | ||||||||||||||
| Interest income from affiliates | 10 | 2 | 3 | ||||||||||||||
| Total other expense, net | (11) | (13) | — | ||||||||||||||
| Interest charges | (119) | (86) | (64) | ||||||||||||||
| Income tax benefit | 49 | 25 | 25 | ||||||||||||||
| Net Income Attributable to Ameren Common Shareholders | $ | 1,152 | $ | 1,074 | $ | 990 | |||||||||||
| Net Income Attributable to Ameren Common Shareholders | $ | 1,152 | $ | 1,074 | $ | 990 | |||||||||||
| Other Comprehensive Income (Loss), Net of Taxes: | |||||||||||||||||
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(2), $(4), and $4, respectively | (5) | (14) | 14 | ||||||||||||||
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 1,147 | $ | 1,060 | $ | 1,004 | |||||||||||
165
| SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED BALANCE SHEET | |||||||||||
| (In millions, except per share amounts) | December 31, 2023 | December 31, 2022 | |||||||||
| Assets: | |||||||||||
| Cash and cash equivalents | $ | 16 | $ | — | |||||||
| Advances to money pool | 598 | 68 | |||||||||
| Accounts receivable – affiliates | 20 | 59 | |||||||||
| Miscellaneous accounts and notes receivable | 31 | 11 | |||||||||
| Total current assets | 665 | 138 | |||||||||
| Investments in subsidiaries | 14,573 | 13,394 | |||||||||
| Accumulated deferred income taxes, net | 44 | 46 | |||||||||
| Other assets | 149 | 137 | |||||||||
| Total assets | $ | 15,431 | $ | 13,715 | |||||||
| Liabilities and Shareholders’ Equity: | |||||||||||
| Current maturities of long-term debt | $ | 450 | $ | — | |||||||
| Short-term debt | — | 477 | |||||||||
| Accounts payable | 2 | — | |||||||||
| Taxes accrued | 10 | 5 | |||||||||
| Accounts payable – affiliates | 100 | 52 | |||||||||
| Other current liabilities | 45 | 41 | |||||||||
| Total current liabilities | 607 | 575 | |||||||||
| Long-term debt, net | 3,379 | 2,536 | |||||||||
| Pension and other postretirement benefits | 19 | 19 | |||||||||
| Other deferred credits and liabilities | 77 | 77 | |||||||||
| Total liabilities | 4,082 | 3,207 | |||||||||
| Commitments and Contingencies (Note 4) | |||||||||||
| Shareholders’ Equity: | |||||||||||
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 266.3 and 262.0, respectively | 3 | 3 | |||||||||
| Other paid-in capital, principally premium on common stock | 7,216 | 6,860 | |||||||||
| Retained earnings | 4,136 | 3,646 | |||||||||
| Accumulated other comprehensive income (loss) | (6) | (1) | |||||||||
| Total shareholders’ equity | 11,349 | 10,508 | |||||||||
| Total liabilities and shareholders’ equity | $ | 15,431 | $ | 13,715 | |||||||
166
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2023, 2022, and 2021 | ||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2021 | |||||||||||||||||
| Net cash flows provided by operating activities | $ | 171 | $ | 44 | $ | 79 | ||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||
| Money pool advances, net | (530) | 40 | (92) | |||||||||||||||||
| Notes receivable – ATXI | — | 35 | 40 | |||||||||||||||||
| Investments in subsidiaries | (109) | (30) | (489) | |||||||||||||||||
| Other | 5 | 3 | 7 | |||||||||||||||||
| Net cash flows provided by (used in) investing activities | (634) | 48 | (534) | |||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||
| Dividends on common stock | (662) | (610) | (565) | |||||||||||||||||
| Short-term debt, net | (475) | 198 | (213) | |||||||||||||||||
| Issuances of long-term debt | 1,298 | — | 949 | |||||||||||||||||
| Issuances of common stock | 346 | 333 | 308 | |||||||||||||||||
| Employee payroll taxes related to stock-based compensation | (20) | (16) | (17) | |||||||||||||||||
| Debt issuance costs | (8) | (1) | (7) | |||||||||||||||||
| Net cash flows provided by (used in) financing activities | 479 | (96) | 455 | |||||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | $ | 16 | $ | (4) | $ | — | ||||||||||||||
| Cash, cash equivalents, and restricted cash at beginning of year | — | 4 | 4 | |||||||||||||||||
| Cash, cash equivalents, and restricted cash at end of year | $ | 16 | $ | — | $ | 4 | ||||||||||||||
| Supplemental information: | ||||||||||||||||||||
| Cash dividends received from consolidated subsidiaries | $ | 173 | $ | 76 | $ | 123 | ||||||||||||||
| Noncash financing activity – Issuance of common stock for stock-based compensation | 40 | 31 | 33 | |||||||||||||||||
| Noncash financing activity – Issuance of common stock under the DRPlus | 7 | 8 | — | |||||||||||||||||
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS December 31, 2023
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 and Note 15 – Supplemental Information under Part II, Item 8, of this report for additional information.
NOTE 2 – 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 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 related to non-state-regulated money pool advances were $10 million in 2023 and immaterial in 2022 and 2021. Interest charges related to non-state-regulated money pool borrowings were immaterial in 2021, 2022, and 2023.
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).
167
NOTE 3 – 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 4 – 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 5 – 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, 2023, 2022, and 2021:
| (In millions) | 2023 | 2022 | 2021 | ||||||||||||||
| Total Other Expense, Net | |||||||||||||||||
| Non-service cost components of net periodic benefit income | $ | 8 | $ | 3 | $ | 1 | |||||||||||
| Donations | (18) | (15) | — | ||||||||||||||
| Other expense, net | (1) | (1) | (1) | ||||||||||||||
| Total Other Expense, Net | $ | (11) | $ | (13) | $ | — | |||||||||||
168
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2023, 2022, AND 2021 | ||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||||||||||||||
| Description | Balance 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: | ||||||||||||||||||||||||||||||||
| 2023 | $ | 31 | $ | 51 | $ | 5 | $ | 57 | $ | 30 | ||||||||||||||||||||||
| 2022 | 29 | 34 | 4 | 36 | 31 | |||||||||||||||||||||||||||
| 2021 | 50 | 9 | — | 30 | 29 | |||||||||||||||||||||||||||
| Ameren Missouri: | ||||||||||||||||||||||||||||||||
| Deducted from assets – allowance for doubtful accounts: | ||||||||||||||||||||||||||||||||
| 2023 | $ | 13 | $ | 11 | $ | — | $ | 12 | $ | 12 | ||||||||||||||||||||||
| 2022 | 13 | 9 | — | 9 | 13 | |||||||||||||||||||||||||||
| 2021 | 16 | 5 | — | 8 | 13 | |||||||||||||||||||||||||||
| Ameren Illinois: | ||||||||||||||||||||||||||||||||
| Deducted from assets – allowance for doubtful accounts: | ||||||||||||||||||||||||||||||||
| 2023 | $ | 18 | $ | 40 | $ | 5 | $ | 45 | $ | 18 | ||||||||||||||||||||||
| 2022 | 16 | 25 | 4 | 27 | 18 | |||||||||||||||||||||||||||
| 2021 | 34 | 4 | — | 22 | 16 | |||||||||||||||||||||||||||
(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.
169
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 Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| Articles of Incorporation/ By-Laws | |||||||||||
| 3.1(i) | Ameren | Annex 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 | |||||||||||
| 4.1 | Ameren | Exhibit 4.5, File No. 333-81774 | |||||||||
| 4.2 | Ameren | June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756 | |||||||||
| 4.3 | Ameren | November 24, 2015 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-14756 | |||||||||
| 4.4 | Ameren | September 16, 2019 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 | |||||||||
| 4.5 | Ameren | April 3, 2020 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 | |||||||||
| 4.6 | Ameren | March 5, 2021 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 | |||||||||
| 4.7 | Ameren | November 18, 2021 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 | |||||||||
| 4.8 | Ameren | November 20, 2023 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 | |||||||||
| 4.9 | Ameren | December 21, 2023 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 | |||||||||
| 4.10 | Ameren | June 26, 2017 Form 8-K, Exhibit 4.1, File No. 1-14756 | |||||||||
| 4.11 | Ameren | 2021 Form 10-K, Exhibit 4.9, File No. 1-14756 | |||||||||
| 4.12 | Ameren 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, 1941 | Exhibit B-1, File No. 2-4940 | ||||||||
| 4.13 | Ameren Ameren Missouri | Exhibit 4.22, File No. 333-222108 | |||||||||
| 4.14 | Ameren Ameren Missouri | Exhibit 4.23, File No. 333-222108 | |||||||||
| 4.15 | Ameren Ameren Missouri | Exhibit 4.24, File No. 333-222108 | |||||||||
| 4.16 | Ameren Ameren Missouri | Exhibit 4.25, File No. 333-222108 | |||||||||
| 4.17 | Ameren Ameren Missouri | 1993 Form 10-K, Exhibit 4.8, File No. 1-2967 | |||||||||
| 4.18 | Ameren Ameren Missouri | 2000 Form 10-K, Exhibit 99, File No. 1-2967 | |||||||||
170
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| 4.19 | Ameren Ameren Missouri | August 23, 2002 Form 8-K, Exhibit 4.3, File No. 1-2967 | |||||||||
| 4.20 | Ameren Ameren Missouri | March 11, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 | |||||||||
| 4.21 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967 | |||||||||
| 4.22 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.23 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967 | |||||||||
| 4.24 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.8, 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 | March 23, 2009 Form 8-K, Exhibit 4.5, File No. 1-2967 | |||||||||
| 4.27 | Ameren Ameren Missouri | Exhibit 4.45, File No. 333-182258 | |||||||||
| 4.28 | Ameren Ameren Missouri | September 11, 2012 Form 8-K, Exhibit 4.4, File No. 1-2967 | |||||||||
| 4.29 | Ameren Ameren Missouri | April 4, 2014 Form 8-K, Exhibit 4.5, File No. 1-2967 | |||||||||
| 4.30 | Ameren Ameren Missouri | April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967 | |||||||||
| 4.31 | Ameren Ameren Missouri | June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967 | |||||||||
| 4.32 | Ameren Ameren Missouri | April 6, 2018 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.33 | Ameren Ameren Missouri | March 6, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.34 | Ameren Ameren Missouri | October 1, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.35 | Ameren Ameren Missouri | March 20, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.36 | Ameren Ameren Missouri | October 9, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.37 | Ameren Ameren Missouri | June 22, 2021 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.38 | Ameren Ameren Missouri | April 1, 2022 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.39 | Ameren Ameren Missouri | March 13, 2023 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.40 | Ameren Ameren Missouri | January 9, 2024 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||||||||
| 4.41 | 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 | ||||||||
| 4.42 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.10, File No. 1-2967 | |||||||||
| 4.43 | Ameren Ameren Missouri | September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967 | |||||||||
| 4.44 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.11, File No. 1-2967 | |||||||||
| 4.45 | Ameren Ameren Missouri | September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967 | |||||||||
171
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| 4.46 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.12, File No. 1-2967 | |||||||||
| 4.47 | Ameren Ameren Missouri | September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967 | |||||||||
| 4.48 | Ameren Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.13, File No. 1-2967 | |||||||||
| 4.49 | Ameren Ameren Missouri | August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967 | |||||||||
| 4.50 | Ameren Ameren Missouri | Exhibit 4.48, File No. 333-182258 | |||||||||
| 4.51 | Ameren Ameren Missouri | March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 | |||||||||
| 4.52 | Ameren Ameren Missouri | July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 | |||||||||
| 4.53 | Ameren Ameren Missouri | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 | |||||||||
| 4.54 | 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 | |||||||||
| 4.55 | Ameren Ameren Missouri | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 | |||||||||
| 4.56 | Ameren Ameren Missouri | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 | |||||||||
| 4.57 | Ameren Ameren Missouri | June 23, 2016 Form 8-K, Exhibits 4.3, and 4.4, File No. 1-2967 | |||||||||
| 4.58 | Ameren Ameren Missouri | June 15, 2017 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 | |||||||||
| 4.59 | Ameren Ameren Illinois | Exhibit 4.4, File No. 333-59438 | |||||||||
| 4.60 | Ameren Ameren Illinois | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.61 | Ameren Ameren Illinois | Exhibit 4.17, File No. 333-166095 | |||||||||
| 4.62 | Ameren Ameren Illinois | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 | |||||||||
| 4.63 | Ameren Ameren Illinois | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 | |||||||||
| 4.64 | Ameren Ameren Illinois | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 | |||||||||
| 4.65 | Ameren Ameren Illinois | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-14756 | |||||||||
| 4.66 | Ameren Ameren Illinois | October 7, 2010 Form 8-K, Exhibit 4.1, File No. 1-3672 | |||||||||
| 4.67 | Ameren Ameren Illinois | September 30, 2011 Form 10-Q, Exhibit 4.1, File No. 1-3672 | |||||||||
| 4.68 | Ameren Ameren Illinois | September 30, 2019 Form 10-Q, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.69 | Ameren Ameren Illinois | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-14756 | |||||||||
| 4.70 | 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 | ||||||||
| 4.71 | Ameren Ameren Illinois | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 | |||||||||
172
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| 4.72 | Ameren Ameren Illinois | October 7, 2010 Form 8-K, Exhibit 4.9, File No. 1-3672 | |||||||||
| 4.73 | Ameren Ameren Illinois | Exhibit 4.78, File No. 333-182258 | |||||||||
| 4.74 | Ameren Ameren Illinois | August 20, 2012 Form 8-K, Exhibit 4.5, File No. 1-3672 | |||||||||
| 4.75 | Ameren Ameren Illinois | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 | |||||||||
| 4.76 | Ameren Ameren Illinois | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 | |||||||||
| 4.77 | Ameren Ameren Illinois | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 | |||||||||
| 4.78 | Ameren Ameren Illinois | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 | |||||||||
| 4.79 | Ameren Ameren Illinois | September 30, 2017 Form 10-Q, Exhibit 4.1, File No. 1-3672 | |||||||||
| 4.80 | Ameren Ameren Illinois | November 28, 2017 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.81 | Ameren Ameren Illinois | May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.82 | Ameren Ameren Illinois | November 15, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.83 | Ameren Ameren Illinois | September 30, 2019 Form 10-Q, Exhibit 4.3, File No. 1-3672 | |||||||||
| 4.84 | Ameren Ameren Illinois | November 26, 2019 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.85 | Ameren Ameren Illinois | 2019 Form 10-K, Exhibit 4.79, File No. 1-3672 | |||||||||
| 4.86 | Ameren Ameren Illinois | November 23, 2020 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.87 | Ameren Ameren Illinois | June 29, 2021 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.88 | Ameren Ameren Illinois | August 29, 2022 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.89 | Ameren Ameren Illinois | November 22, 2022 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.90 | Ameren Ameren Illinois | May 31, 2023 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.91 | Ameren Ameren Illinois | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-14756 | |||||||||
| 4.92 | Ameren Ameren Illinois | October 7, 2010 Form 8-K, Exhibit 4.5, File No. 1-14756 | |||||||||
| 4.93 | Ameren Ameren Illinois | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 | |||||||||
| 4.94 | Ameren Ameren Illinois | Exhibit 4.83, File No. 333-182258 | |||||||||
| 4.95 | Ameren Ameren Illinois | September 30, 2019 Form 10-Q, Exhibit 4.4, File No. 1-3672 | |||||||||
| 4.96 | Ameren Ameren Illinois | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 | |||||||||
| 4.97 | Ameren Ameren Illinois | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 | |||||||||
| 4.98 | Ameren Ameren Illinois | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 | |||||||||
| 4.99 | Ameren Ameren Illinois | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 | |||||||||
173
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| 4.100 | Ameren Ameren Illinois | December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 | |||||||||
| 4.101 | Ameren Ameren Illinois | September 30, 2019 Form 10-Q, Exhibits 4.5 and 4.6, File No. 1-3672 | |||||||||
| 4.102 | Ameren | 2021 Form 10-K, Exhibit 4.98, File No. 1-14756 | |||||||||
| 4.103 | Ameren Missouri | 2021 Form 10-K, Exhibit 4.99, File No. 1-14756 | |||||||||
| 4.104 | Ameren Illinois | 2021 Form 10-K, Exhibit 4.100, File No. 1-14756 | |||||||||
| Material Contracts | |||||||||||
| 10.1 | Ameren Companies | June 30, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756 | |||||||||
| 10.2 | Ameren Ameren Missouri | December 6, 2022 Form 8-K, Exhibit 10.1, File No. 1-2967 | |||||||||
| 10.3 | Ameren Ameren Missouri | August 3, 2023 Form 10-Q, Exhibit 10.1, File No. 1-2967 | |||||||||
| 10.4 | Ameren Ameren Illinois | December 6, 2022 Form 8-K, Exhibit 10.2, File No. 1-3672 | |||||||||
| 10.5 | Ameren Ameren Illinois | August 3, 2023 Form 10-Q, Exhibit 10.2, File No. 1-3672 | |||||||||
| 10.6 | Ameren | 2021 Form 10-K, Exhibit 10.6, File No. 1-14756 | |||||||||
| 10.7 | Ameren | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 | |||||||||
| 10.8 | Ameren | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 | |||||||||
| 10.9 | Ameren | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 | |||||||||
| 10.10 | Ameren | ||||||||||
| 10.11 | Ameren Companies | 2019 Form 10-K, Exhibit 10.17, File No. 1-14756 | |||||||||
| 10.12 | Ameren Companies | 2020 Form 10-K, Exhibit 10.16, File No. 1-14756 | |||||||||
| 10.13 | Ameren Companies | 2021 Form 10-K, Exhibit 10.16, File No., 1-14756 | |||||||||
| 10.14 | Ameren Companies | 2022 Form 10-K, Exhibit 10.17, File No. 1-14756 | |||||||||
| 10.15 | Ameren Companies | ||||||||||
| 10.16 | Ameren Companies | 2020 Form 10-K, Exhibit 10.23, File No. 1-14756 | |||||||||
| 10.17 | Ameren Companies | 2021 Form 10-K, Exhibit 10.20, File No. 1-14756 | |||||||||
| 10.18 | Ameren Companies | 2022 Form 10-K, Exhibit 10.21, File No. 1-14756 | |||||||||
| 10.19 | Ameren Companies | ||||||||||
| 10.20 | Ameren Companies | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 | |||||||||
| 10.21 | Ameren Companies | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 | |||||||||
| 10.22 | Ameren Companies | ||||||||||
| 10.23 | Ameren Companies | 2017 Form 10-K, Exhibit 10.24, File No. 1-14756 | |||||||||
| 10.24 | Ameren Companies | 2018 Form 10-K, Exhibit 10.27, File No. 1-14756 | |||||||||
| 10.25 | Ameren Companies | 2019 Form 10-K, Exhibit 10.32, File No. 1-14756 | |||||||||
| 10.26 | Ameren Companies | 2020 Form 10-K, Exhibit 10.33, File No. 1-14756 | |||||||||
174
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| 10.27 | Ameren Companies | 2021 Form 10-K, Exhibit 10.30, File No. 1-14756 | |||||||||
| 10.28 | Ameren Companies | 2022 Form 10-K, Exhibit 10.31, File No. 1-14756 | |||||||||
| 10.29 | Ameren Companies | ||||||||||
| 10.30 | Ameren Companies | Exhibit 99, File No. 333-196515 | |||||||||
| 10.31 | Ameren Companies | December 13, 2017 Form 8-K, Exhibit 10.1, File No. 1-14756 | |||||||||
| 10.32 | Ameren Companies | December 13, 2017 Form 8-K, Exhibit 10.2, File No. 1-14756 | |||||||||
| 10.33 | Ameren Companies | 2018 Form 10-K, Exhibit 10.34, File No. 1-14756 | |||||||||
| 10.34 | Ameren Companies | 2018 Form 10-K, Exhibit 10.35, File No. 1-14756 | |||||||||
| 10.35 | Ameren Companies | 2019 Form 10-K, Exhibit 10.41, File No. 1-14756 | |||||||||
| 10.36 | Ameren Companies | 2019 Form 10-K, Exhibit 10.42, File No. 1-14756 | |||||||||
| 10.37 | Ameren Companies | 2020 Form 10-K, Exhibit 10.44, File No. 1-14756 | |||||||||
| 10.38 | Ameren Companies | 2020 Form 10-K, Exhibit 10.45, File No. 1-14756 | |||||||||
| 10.39 | Ameren Companies | 2021 Form 10-K, Exhibit 10.42, File No. 1-14756 | |||||||||
| 10.40 | Ameren Companies | 2021 Form 10-K, Exhibit 10.43, File No. 1-14756 | |||||||||
| 10.41 | Ameren Companies | May 13, 2022 Form 8-K, Exhibit 10.1, File No. 1-14756 | |||||||||
| 10.42 | Ameren Companies | 2022 Form 10-K, Exhibit 10.45, File No. 1-14756 | |||||||||
| 10.43 | Ameren Companies | 2022 Form 10-K, Exhibit 10.46, File No. 1-14756 | |||||||||
| 10.44 | Ameren Companies | 2022 Form 10-K, Exhibit 10.47, File No. 1-14756 | |||||||||
| 10.45 | Ameren Companies | ||||||||||
| 10.46 | Ameren Companies | ||||||||||
| 10.47 | Ameren Companies | ||||||||||
| 10.48 | Ameren Companies | ||||||||||
| 10.49 | Ameren Companies | 2018 Form 10-K, Exhibit 10.36, File No. 1-14756 | |||||||||
| 10.50 | Ameren Companies | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 | |||||||||
| 10.51 | Ameren Companies | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 | |||||||||
| 10.52 | Ameren Companies | ||||||||||
| 10.53 | Ameren Companies | ||||||||||
| 10.54 | Ameren Companies | ||||||||||
| 10.55 | Ameren Companies | ||||||||||
| Subsidiaries of the Registrant | |||||||||||
| 21.1 | Ameren Companies | ||||||||||
| Consent of Experts and Counsel | |||||||||||
175
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | ||||||||
| 23.1 | Ameren | ||||||||||
| 23.2 | Ameren Missouri | ||||||||||
| 23.3 | Ameren Illinois | ||||||||||
| Power of Attorney | |||||||||||
| 24.1 | Ameren | ||||||||||
| 24.2 | Ameren Missouri | ||||||||||
| 24.3 | Ameren Illinois | ||||||||||
| Rule 13a-14(a)/15d-14(a) Certifications | |||||||||||
| 31.1 | Ameren | ||||||||||
| 31.2 | Ameren | ||||||||||
| 31.3 | Ameren Missouri | ||||||||||
| 31.4 | Ameren Missouri | ||||||||||
| 31.5 | Ameren Illinois | ||||||||||
| 31.6 | Ameren Illinois | ||||||||||
| Section 1350 Certifications | |||||||||||
| 32.1 | Ameren | ||||||||||
| 32.2 | Ameren Missouri | ||||||||||
| 32.3 | Ameren Illinois | ||||||||||
| Policy Relating to Recovery of Erroneously Awarded Compensation | |||||||||||
| 97.1 | Ameren Companies | ||||||||||
| Additional Exhibits | |||||||||||
| 99.1 | Ameren Companies | 2022 Form 10-K, Exhibit 99.1, File No. 1-14756 | |||||||||
| Interactive Data Files | |||||||||||
| 101.INS | Ameren Companies | Inline 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.SCH | Ameren Companies | XBRL Taxonomy Extension Schema Document | |||||||||
| 101.CAL | Ameren Companies | XBRL Taxonomy Extension Calculation Linkbase Document | |||||||||
| 101.LAB | Ameren Companies | XBRL Taxonomy Extension Label Linkbase Document | |||||||||
| 101.PRE | Ameren Companies | XBRL Taxonomy Extension Presentation Linkbase Document | |||||||||
| 101.DEF | Ameren Companies | XBRL Taxonomy Extension Definition Document | |||||||||
| 104 | Ameren Companies | Cover 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.
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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 29, 2024 | By | /s/ Martin J. Lyons, Jr. | |||||||||||
| Martin J. Lyons, Jr. Chairman, 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. | Chairman, President, and Chief Executive Officer, and Director (Principal Executive Officer) | February 29, 2024 | |||||||||||||||
| Martin J. Lyons, Jr. | |||||||||||||||||
| /s/ Michael L. Moehn | Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer) | February 29, 2024 | |||||||||||||||
| Michael L. Moehn | |||||||||||||||||
| /s/ Theresa A. Shaw | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | February 29, 2024 | |||||||||||||||
| Theresa A. Shaw | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Cynthia J. Brinkley | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Catherine S. Brune | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| J. Edward Coleman | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Ward H. Dickson | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Noelle K. Eder | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Ellen M. Fitzsimmons | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Rafael Flores | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Kimberly J. Harris | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Richard J. Harshman | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Craig S. Ivey | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| James C. Johnson | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Steven H. Lipstein | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Leo S. Mackay, Jr. | |||||||||||||||||
| *By | /s/ Michael L. Moehn | February 29, 2024 | |||||||||||||||
| Michael L. Moehn | |||||||||||||||||
| Attorney-in-Fact | |||||||||||||||||
177
UNION ELECTRIC COMPANY (registrant) | ||||||||||||||
| Date: | February 29, 2024 | By | /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. Birk | Chairman and President, and Director (Principal Executive Officer) | February 29, 2024 | |||||||||||||||
| Mark C. Birk | |||||||||||||||||
/s/ Michael L. Moehn | Senior Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | February 29, 2024 | |||||||||||||||
| Michael L. Moehn | |||||||||||||||||
| /s/ Theresa A. Shaw | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | February 29, 2024 | |||||||||||||||
| Theresa A. Shaw | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Bhavani Amirthalingam | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Fadi M. Diya | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Chonda J. Nwamu | |||||||||||||||||
| *By | /s/ Michael L. Moehn | February 29, 2024 | |||||||||||||||
| Michael L. Moehn | |||||||||||||||||
| Attorney-in-Fact | |||||||||||||||||
178
AMEREN ILLINOIS COMPANY (registrant) | ||||||||||||||
| Date: | February 29, 2024 | By | /s/ Leonard P. Singh | |||||||||||
| Leonard P. Singh 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/ Leonard P. Singh | Chairman and President, and Director (Principal Executive Officer) | February 29, 2024 | |||||||||||||||
| Leonard P. Singh | |||||||||||||||||
| /s/ Michael L. Moehn | Senior Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | February 29, 2024 | |||||||||||||||
| Michael L. Moehn | |||||||||||||||||
| /s/ Theresa A. Shaw | Senior Vice President, Finance, and Chief Accounting Officer, and Director (Principal Accounting Officer) | February 29, 2024 | |||||||||||||||
| Theresa A. Shaw | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Chonda J. Nwamu | |||||||||||||||||
| * | Director | February 29, 2024 | |||||||||||||||
| Patrick E. Smith | |||||||||||||||||
| *By | /s/ Michael L. Moehn | February 29, 2024 | |||||||||||||||
| Michael L. Moehn | |||||||||||||||||
| Attorney-in-Fact | |||||||||||||||||
179