0001002910aee:CommercialMemberus-gaap:IntersegmentEliminationMemberaee:AmerenIllinoisCompanyMember2019-01-012019-12-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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(X)☒ | | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
for the fiscal year ended December 31, 2020
OR
for the fiscal year ended December 31, 2018.
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( ) | | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the transition period from to . |
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Commission
File Number
| | Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number
| | IRS Employer
Identification No.
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| 1-14756 | | Ameren Corporation | 43-1723446 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
| 43-1723446 | | | | | | | |
| 1-2967 | | (Missouri Corporation) | | |
| | 1901 Chouteau Avenue | | |
| | St. Louis, Missouri 63103 | | |
| | (314) 621-3222 | | |
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1-2967 | | Union Electric Company | 43-0559760 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
| 43-0559760 | | | | | | | |
| 1-3672 | | (Missouri Corporation) | | |
| | 1901 Chouteau Avenue | | |
| | St. Louis, Missouri 63103 | | |
| | (314) 621-3222 | | |
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1-3672 | | Ameren Illinois Company | | 37-0211380 |
| | (Illinois Corporation) | | |
| | 10 Executive Drive | | |
| | Collinsville, Illinois 62234 | | |
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(Illinois Corporation)
10 Executive Drive
Collinsville, Illinois 62234
(618) 343-8150
| | Securities Registered Pursuant to Section 12(b) of the Act:
The following security is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:
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Registrant | Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Ameren Corporation | Common Stock, $0.01 par value per share | AEE | New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act:
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| Registrant | | Title of each class |
| Union Electric Company | | Preferred Stock, cumulative, no par value, stated value $100 per share
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| Ameren Illinois Company | | Preferred Stock, cumulative, $100 par value per share Depositary Shares, each representing one-fourth1/4 of a share of 6.625% Preferred Stock, cumulative, $100 par value per share |
Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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| Ameren Corporation | Yes | ý
☒ | No | ¨
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| Union Electric Company | Yes | ¨
☒ | No | ý
☐ |
| Ameren Illinois Company | Yes | ¨
☒ | No | ý
☐ |
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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| Ameren Corporation | Yes | ¨
☐ | No | ý
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| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
Indicate by checkmark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
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| Ameren Corporation | Yes | ý
☒ | No | ¨
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| Union Electric Company | Yes | ý
☒ | No | ¨
☐ |
| Ameren Illinois Company | Yes | ý
☒ | No | ¨
☐ |
Indicate by checkmark whether each registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
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| Ameren Corporation | Yes | ý
☒ | No | ¨
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| Union Electric Company | Yes | ý
☒ | No | ¨
☐ |
| Ameren Illinois Company | Yes | ý
☒ | No | ¨
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Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
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Ameren Corporation | | ý
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Union Electric Company | | ý
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Ameren Illinois Company | | ý
☐ |
Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| Ameren Corporation | Large accelerated filer | Large
Accelerated
Filer
☒ | Accelerated filer | Accelerated
Filer
☐ | Non-accelerated filer | Non-accelerated
Filer
| | Smaller
Reporting
Company
| | Emerging Growth Company☐ |
Ameren Corporation | | ý | Smaller reporting company | ¨☐ | Emerging growth company | ¨
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| Union Electric Company | Large accelerated filer | ¨
☐ | Accelerated filer | ¨
☐ | Non-accelerated filer | ý
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| | | Smaller reporting company | ☐ | Emerging growth company | ☐ |
| Ameren Illinois Company | Large accelerated filer | ¨
☐ | Accelerated filer | ¨
☐ | Non-accelerated filer | ý
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| | ¨ | 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. |
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| 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.
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| Ameren Corporation | | | | ☒ |
| Union Electric Company | | | | ☐ |
| Ameren Illinois Company | | | | ☐ |
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
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| Ameren Corporation | Yes | ¨
☐ | No | ý
☒ |
| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
As of June 29, 2018,30, 2020, 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 29, 2018)30, 2020) held by nonaffiliates was $14,783,320,074.$17,299,078,950. All of the shares of common stock of the other registrants were held by Ameren Corporation as of June 29, 2018.30, 2020.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2019,29, 2021, were as follows:
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| Registrant | Title of each class of common stock | Shares |
| Ameren Corporation | Common stock, $0.01 par value per share: 244,638,879share | 253,355,105 | |
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| Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): | 102,123,834 | |
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| Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation (parent company of the registrant): | 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 20192021 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,” 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.
2014 Incentive Plan – The 2014 Omnibus Incentive Compensation Plan, which provides for compensatory stock-based awards to eligible employees and directors.
20172020 IRP – Integrated Resource Plan, a 20-yearlong-term nonbinding plan that Ameren Missouri filed with the MoPSC in September 2017,2020, which includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability.reliability and achieving a goal of net-zero CO2 emissions by 2050.
Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies – Ameren Corporation, Ameren Missouri, and Ameren Illinois, collectively, which are individual registrants within the Ameren consolidated group.
Ameren Illinois Electric Distribution – An Ameren Corporation and Ameren Illinois financial reporting segment consisting of the rate-regulated electric 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 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 – 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 also defined as a financial reporting segment of Ameren.
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.
AMIL – A MISO balancing authority area operated by Ameren, which includes the load of Ameren Illinois and ATXI.
AMMO – A MISO balancing authority area operated by Ameren, which includes the load and energy centers of Ameren Missouri.
ARO – Asset retirement obligations.
ATXI – Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engagedoperates a FERC rate-regulated electric transmission business in the construction and operation of electric transmission assets.MISO.
Baseload – The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
CCR – Coal combustion residuals, which include fly ash, bottom ash, boiler slag, and flue gas desulfurization materials generated from burning coal to generate electricity.
CCR Rule – Coal Combustion Residuals Rule, a rule promulgated by the EPA that established regulations for the disposal of CCR in landfills and surface impoundments, and the operation and closure of such landfills and surface impoundments.
CILCO – Central Illinois Light Company, a former Ameren Corporation subsidiary that was merged with CIPS and IP to form Ameren Illinois.
CIPS – Central Illinois Public Service Company, a predecessor to Ameren Illinois.
Clean Power Plan – “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” an EPA rule, which would have established emission guidelines for states to follow in developing plans to reduce CO2 emissions from existing fossil-fuel-fired electric generating units. In August 2018, the EPA proposed to repeal and replace the Clean Power Plan with a proposed new rule known as the Affordable Clean Energy Rule.
CO2 – Carbon dioxide.
COVID-19 pandemic – The global pandemic resulting from the outbreak of the 2019 novel coronavirus, which causes coronavirus disease 2019 (COVID-19).
Customer demand charges – Revenues from nonresidential customers based on their peak demand during a specified time interval.
Cooling degree days – The summation of positive differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of electricity demand by residential and commercial customers for summer cooling.
Credit Agreements – The Illinois Credit Agreement and the Missouri Credit Agreement, collectively.
CSAPR – Cross-State Air Pollution Rule, an EPA rule that requires states that contribute to air pollution in downwind states to limit air emissions from fossil-fuel-fired electric generating units.
CT – Combustion turbine, used primarily for peaking electric generation capacity.
DCA – Delivery charge adjustment, a rate-adjustment mechanism that decouples natural gas revenues from actual sales volumes for Ameren Missouri’s natural gas business and allows Ameren Missouri to adjust customer rates without a traditional regulatory rate review, subject to MoPSC prudence reviews. The decoupling provisions ensure that Ameren Missouri’s natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions.
Deferred payment arrangement – A payment option that allows certain Ameren Missouri and Ameren Illinois retail customers to pay a utility bill balance over a period of time, generally over a period of up to 12 months. On a temporary basis through January 31, 2021, Ameren Illinois’ residential retail customers could have elected to pay a utility bill balance over a period of up to 24 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.
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.
Excess deferred income taxes – The amountAmounts resulting from the revaluation of deferred income taxes previouslysubject to regulatory ratemaking, which will be collected from, customers that will beor returned to, customers over periodscustomers. Deferred income taxes are revalued when federal or state income tax rates change, and the offset to the revaluation of time determined by our regulators.deferred income taxes subject to regulatory ratemaking is recorded to a regulatory asset or liability.
Exchange Act – Securities Exchange Act of 1934, as amended.
FAC – Fuel adjustment clause, a fuel and purchased power cost recoveryrate-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 proceeding,review, subject to MoPSC prudence reviews.
FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.
FEJA – Future Energy Jobs Act,a 2016an Illinois law affecting electric distribution utilities. This lawthat 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.agency that regulates utility businesses and associated activities of holding and related service companies, including Ameren, Ameren Missouri, Ameren Illinois, ATXI, and Ameren Services.
FTR – Financial transmission right, a financial instrument that specifies whether the holder shall pay or receive compensation for certain congestion-related transmission charges between two designated points.
GAAP – Generally accepted accounting principles in the United States.
Heating degree days – The summation of negative differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter heating by residential and commercial customers.
ICC – Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including Ameren Illinois and ATXI.
IEIMA – Illinois Energy Infrastructure Modernization Act, an Illinois law that established a performance-based formula process for determining electric distribution service rates. The formula ratemaking process expires in 2022, unless extended.
Illinois Credit Agreement –Ameren’s and Ameren Illinois’ $1.1 billion senior unsecured credit agreement, which expires in December 2022,2024, unless extended.
IP – Illinois Power Company, a former Ameren Corporation subsidiary that merged with CIPS and CILCO to form Ameren Illinois.
IPA – Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and small commercial customers.
IRS – Internal Revenue Service, a United States government agency.
ISRS – Infrastructure system replacement surcharge, a cost recoveryrate-adjustment mechanism that allowsprovides Ameren Missouri to recoverMissouri’s natural gas business with recovery of, and a return on, qualifying infrastructure replacement costs from customersinvestments that are placed in service without a traditional regulatory rate proceeding.review, subject to MoPSC prudence reviews.
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 related to MoPSC-approved customer energy-efficiency programs.programs without a traditional regulatory rate review, subject to MoPSC prudence reviews.
MEEIA 2013 –Ameren Missouri’s portfolio of customer energy-efficiency programs, recovery of lost electric margins, and performance incentive for 2013 through 2015, pursuant to the MEEIA,Missouri law, as approved by the MoPSC in August 2012.
MEEIA 2016 –Ameren Missouri’s portfolio of customer energy-efficiency programs, recovery of lost electric margins, and performance incentive for March 2016 through February 2019, pursuant to the MEEIA,Missouri law, as approved by the MoPSC in February 2016.
MEEIA 2019 –Ameren Missouri’s portfolio of customer energy-efficiency programs, recovery of lost electric margins, and performance incentive for March 2019 through December 2024, pursuant to the MEEIA,Missouri law, as approved by the MoPSC in December 2018.
Megawatthour or MWh – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midcontinent Independent System Operator, Inc., an RTO.
Missouri Credit Agreement –Ameren’s and Ameren Missouri’s $1$1.2 billion senior unsecured credit agreement, which expires in December 2022,2024, unless extended.
Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.
Missouri Senate Bill 564 – A 2018 Missouri law that resulted in certain changes to the regulation of Ameren Missouri’s electric service business. These changes include a reduction of customer rates to pass through the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA and, at each electric utility's election, the use of PISA, among other things.
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, a state agency.
MoPSC – Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including Ameren Missouri.
MTM – Mark-to-market.
MW – Megawatt.
Native load – End-use retail customers whom we are 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, certain fuel additives, ash disposal costs and revenues, emission allowances, and purchased power costs, including transportation, net of off-system sales and capacity revenues. Substantially all transmission revenues and charges are excluded from net energy costs. The MoPSC’s March 2020 electric rate order changed the FAC to include certain fuel additives and ash disposal costs and revenues, as of April 1, 2020.
Net metering – Net metering allows customers who generate their own electricity or subscribe to receive output from eligible facilities to feed electricity they do not use back into the grid. The customers receive a credit for the energy they add to the grid.
New Madrid Smelter – A former aluminum smelter located in southeast Missouri.
NOx – Nitrogen oxides.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a United States government agency.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.
NWPA – Nuclear Waste Policy Act of 1982, as amended.
NYMEX – New York Mercantile Exchange.
NYSE – New York Stock Exchange, Inc.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 Adjustmentgas adjustment tariffs, which permita rate-adjustment mechanism that permits prudently incurred natural gas costs to be recovered directly from utility customers without a traditional regulatory rate proceeding.review, subject to regulatory prudence reviews.
PHMSA – Pipeline and Hazardous Materials Safety Administration.
PISA – Plant-in-service accounting regulatory mechanism, an election under Missouri Senate Bill 564law that permits electric utilities to defer and recover 85% of the depreciation expense and earn a weighted-average cost of capital return at the applicable WACC on rate base onfor certain property, plant, and equipment placed in service after the PISA election date.date, subject to MoPSC prudence reviews. The rate base on which the return is calculated incorporates qualifying capital expenditures since the PISA election date as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes. AccumulatedThe regulatory asset for accumulated PISA deferrals earn carrying costsearns a return at the weighted-average cost of capital.applicable WACC. The PISA was elected by Ameren Missouri, effective September 1, 2018.2018, and is effective through December 2023, unless extended by the MoPSC.
QIP – Qualifying infrastructure plant, whicha rate-adjustment mechanism that provides Ameren Illinois’ natural gas business with recovery of, and a weighted-average cost of capital return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews, subject to ICC prudence reviews. Without legislative action, the QIP will expire in December 2023.
Rate base –The basis on which a public utility is permitted to earn an allowed rate of return.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 volume levelsvolumes 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 behind changing costs and sales volume levelsvolumes when based on historical periods.
RESRAM – Renewable energy standard rate adjustmentrate-adjustment mechanism, a cost recoveryregulatory mechanism allowed under stateMissouri law that enables Ameren Missouri to recover costs relating to compliance with Missouri'sMissouri’s renewable energy standard, including recovery of investments in wind generation and other renewables, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism by adjusting customer rates on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. RESRAM regulatory assets will earn carrying costs at short-term interest rates.
Revenue requirement – The cost of providing utility service to customers, which is calculated as the sum of a utility’s recoverable operating expenses, and an alloweda return at the weighted-average cost of capital on rate base, which includes a return on invested capital, both debt and equity, and an amount for income taxes, based on the currently applicable statutory income tax rates and amortization associated with excess deferred income taxes.
RFPRFP – Request for proposal.
Rider – a rate-adjustment mechanism that allows for the recovery or refund of differences between actual costs incurred and base level expenses included in customer rates without a traditional regulatory rate review.
ROE – Return on common equity.
RTO – Regional transmission organization.
S&P – S&P Global Ratings, a credit rating agency.
SEC – Securities and Exchange Commission, a United States government agency.
SERC – SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.
Smart Energy Plan – Ameren Missouri'sMissouri’s plan to upgrade Missouri’s electric grid through 2023.at least 2024, which assumes continuation of the PISA. Upgrades include investments to improve reliability and accommodate more renewable energy.
SO2– Sulfur dioxide.
STEM – Science, technology, engineering, and math.
TCJA – The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities. The TCJA includes specific provisions related to regulated public utilities. Substantially all of the provisions of the TCJA affecting the Ameren Companies, other than certain transition depreciation rules, were effective for taxable years beginning after December 31, 2017.
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 appropriate revenue requirement.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 – A volumeVolume balancing adjustment, a rate-adjustment mechanism for Ameren Illinois’ natural gas business. As a result of this adjustment,business that decouples natural gas revenues from residentialactual sales volumes and small nonresidential customers will increase or decrease as billing determinants differ from filed amounts. This adjustment ensuresallows Ameren Illinois to adjust customer rates without a traditional regulatory rate review, subject to ICC prudence reviews. The decoupling provisions ensure that Ameren Illinois’ natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions, do not result in an over- or under-collectionfor residential and small nonresidential customers.
WACC – Weighted-average cost of natural gas revenues for these rate classes.capital, which is the weighted-average cost of debt and equity, as allowed by the applicable regulator.
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, 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 a potential change infuture orders and the July 2020 appeal filed by Ameren Missouri, Ameren Illinois, and ATXI challenging the refund period related to the May 2020 FERC order determining the allowed base return on common equityROE under the MISO tariff, from either the complaint caseJuly 2020 appeal filed by Ameren Missouri, Ameren Illinois, and ATXI challenging the FERC’s rehearing denials in February 2015the transmission formula rate revision cases, Ameren Illinois’ electric distribution service rate reconciliation request filed with the FERC or a new methodology proposed byICC in April 2020, Ameren Illinois’ QIP reconciliation hearing with the FERCICC requested in November 2018, Ameren Missouri’s requested certificate of convenienceMarch 2019, and necessity for a wind generation facilityrequests filed with the MoPSC in October 2018,2020 for accounting authority orders related to Ameren Missouri’s electric and natural gas regulatory rate review filed withservices to allow Ameren Missouri to accumulate certain costs incurred related to the MoPSCCOVID-19 pandemic;
•the length and severity of the COVID-19 pandemic, and its impacts on our business continuity plans and our results of operations, financial position, and liquidity, including but not limited to changes in December 2018, an appeal filed by the MoOPCcustomer demand resulting in January 2019 in Ameren Missouri’s RESRAM case,changes to sales volumes, customers’ payment for our services and their use of deferred payment arrangements, future regulatory judicial, or legislative actions that change regulatory recovery mechanisms;could require suspension of customer disconnections and/or late fees, among other things, for an extended period of time, the health and welfare of our workforce and contractors, supplier disruptions, delays in the completion of construction projects, which could impact our planned capital expenditures and expected planned rate base growth, Ameren Missouri’s ability to recover any forgone customer late fee revenues or incremental costs, our ability to meet customer energy-efficiency program goals and earn performance incentives related to those programs, changes in how we operate our business and increased data security risks as a result of the transition to remote working arrangements for a significant portion of our workforce, and our ability to access the capital markets on reasonable terms and when needed;
•the effect and duration of Ameren Illinois’ participationelection to participate in performance-based formula ratemaking frameworks underframework for its electric distribution service, which, unless extended, expires at the IEIMAend of 2022, and the FEJA,its participation in electric energy-efficiency programs, including the direct relationship between Ameren Illinois' return on common equityIllinois’ ROE and the 30-year United States Treasury bond yields, and the related financial commitments;yields;
•the effect of Missouri Senate Bill 564 on Ameren Missouri including as a result of any customer rate caps pursuant to Ameren Missouri’s election to use the PISA, including an extension of use beyond 2023, if requested by Ameren Missouri and approved by the resulting customer rate caps;MoPSC;
•the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, and energy policies;
•the effects of changes in federal, state, or local tax laws, regulations, interpretations, or rates, amendments or technical corrections to the TCJA, and challenges to the tax positions taken by the Ameren Companies, if any;any, as well as resulting effects on customer rates;
•the effects on energy prices and demand for our services resulting from technological advances, including advances in customer energy efficiency, electric vehicles, electrification of various industries, energy storage, and private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;
•the effectiveness of Ameren Missouri’s customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA programs;
•Ameren Illinois’ ability to achieve the performance standards applicable to its electric distribution business and the FEJA electric customer energy-efficiency goals and the resulting impact on its allowed return on program investments;ROE;
•our ability to align overall spending, both operatingcontrol costs and capital, withmake substantial investments in our businesses, including our ability to recover costs, investments, and our allowed ROEs within frameworks established by our regulators, and to recover these costs in a timely manner inwhile maintaining affordability of our attempt to earnservices for our allowed returns on equity;customers;
•the cost and availability of fuel, such as ultra-low-sulfurlow-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, zero emission credits, renewable energy credits, and natural gas for distribution; and the level and volatility of future market prices for such commodities and credits, including our ability to recover the costs for such commodities and credits and our customers’ tolerance for any related price increases;credits;
•disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from the one NRC-licensed supplier of Ameren Missouri'sMissouri’s Callaway energy center’sEnergy Center assemblies;
•the cost and availability of transmission capacity for the energy generated by Ameren Missouri'sMissouri’s energy centers or required to satisfy Ameren Missouri’s energy sales;
•the effectiveness of our risk management strategies and our use of financial and derivative instruments;
•the ability to obtain sufficient insurance, including insurance for Ameren Missouri’s Callawaynuclear and coal-fired energy center,centers, or, in the absence of insurance, the ability to timely recover uninsured losses from our customers;
•the impact of cyberattacks on us or our suppliers, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information;
•business and economic conditions, which have been affected by, and will be affected by the length and severity of, the COVID-19 pandemic, including theirthe impact of such conditions on interest rates, collection of our receivable balances, and demand for our products;rates;
•disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, including as a result of the implementation of the TCJA, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;
•the actions of credit rating agencies and the effects of such actions;actions, including any impacts on our credit ratings that may result from the economic conditions of the COVID-19 pandemic;
•the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments;instruments, including as it relates to the construction and acquisition of electric and natural gas utility infrastructure and the ability of counterparties to complete projects which is dependent upon the availability of necessary materials and equipment, including those that are affected by the disruptions in the global supply chain caused by the COVID-19 pandemic;
•the impact of weather conditions and other natural phenomena on us and our customers, including the impact of system outages;outages and the level of wind and solar resources;
•the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;
•the effects of breakdowns or failures of equipment in the operation of natural gas transmission and distribution systems and storage facilities, such as leaks, explosions, and mechanical problems, and compliance with natural gas safety regulations;
the effects of breakdowns or failures of electric generation, electric and natural gas transmission or distribution, equipment 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,Energy Center, including planned and unplanned outages, such as the current outage that began in December 2020 related to its generator, and 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;
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• | the impact of current environmental laws and new, more stringent, or changing requirements, including those related to CO2 and the proposed repeal and replacement of the Clean Power Plan and potential adoption and implementation of the Affordable Clean Energy Rule, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, 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;
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•the impact of current environmental laws and new, more stringent, or changing requirements, including those related to NSR and CO2, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, 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 requirementsstandards in Missouri and Illinois and with the zero emission standard in Illinois;
•Ameren Missouri’s ability to construct and/or acquire wind, solar, and other renewable energy generation facilities, retire energy centers, and implement new or existing customer energy efficiency programs, including any such construction, acquisition, retirement, or implementation in connection with its Smart Energy Plan, the 2020 IRP, or our emissions reduction goals, and to recover its cost of investment, and related return, and, in the case of customer energy-efficiency programs, any lost margins in a timely manner, which is affected by the ability to obtain all necessary regulatory and project approvals; approvals, including a certificate of convenience and necessity from the MoPSC or any other required approvals for the addition of renewable resources;
•the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind, solar, and solarother renewable generation and storage technologies; and Ameren Missouri’sour ability to obtain timely interconnection agreements with the MISO or other RTOs including the costsat an acceptable cost for each facility;
•advancements in carbon-free generation and storage technologies, and constructive federal and state energy and economic policies with respect to those technologies;
•labor disputes, work force reductions, changes in future wage and employee benefits costs, including those resulting from changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;
•the impact of negative opinions of us or our utility services that our customers, investors, legislators, or regulators 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, or negative media coverage;coverage, or concerns about environmental, social, and/or governance practices;
•the impact of adopting new accounting guidance;
•the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
•legal and administrative proceedings; and
•acts of sabotage, war, terrorism, or other intentionally disruptive acts.
New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.
PART I
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 which includes– 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.ATXI is constructing MISO-approved electric transmission projects, includingbusiness in the Illinois Rivers and Mark Twain projects, and operates the Spoon River project, which was placed in service in February 2018. Ameren also evaluates competitive electric transmission investment opportunities as they arise.
The following table presents our total employees at December 31, 2018:
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Ameren Missouri | 3,798 |
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Ameren Illinois | 3,458 |
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Ameren Services | 1,582 |
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Ameren | 8,838 |
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Labor unions 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. At December 31, 2018, these labor unions collectively represented about 51% of Ameren’s total employees. They represented 61% and 57% of the employees at Ameren Missouri and Ameren Illinois, respectively. The collective bargaining agreements expire between 2019 and 2021.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, of this report 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.below:
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(a) | The Ameren Transmission segment also includes allocated Ameren (parent) interest charges, Ameren Transmission Company, LLC, ATX East, LLC, and ATX Southwest, LLC. |
(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 gettingobtaining approval for new customer rates, approved, could have a material adverse effect on the results of operations, financial position, and liquidity of the Ameren Companies. The extent of the regulatory lag varies for each of Ameren’s electric and natural gas jurisdictions, with the Ameren Transmission and Ameren Illinois Electric Distribution businesses experiencing the least amount of regulatory lag. Depending on the jurisdiction, the effects of regulatory lag are mitigated by various means, including the use of a future test year, the use of trackers and riders, the level and timing of expenditures, annual revenue requirement reconciliations, the decoupling of revenues from sales volumes andto ensure revenues approved in a regulatory rate review are not affected by changes in sales volumes, the recovery of certain capital investments under PISA,between traditional regulatory rate reviews, the RESRAM,level and timing of expenditures, the use of a future test year, and the QIP rider.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, 2019: |
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| | Rate Regulator | Allowed
Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren’s 2018 Operating Revenues(a) |
| Ameren Missouri | | | | | |
Electric service(b) | MoPSC | 9.2% – 9.7%(c) | (c) | (c) | 54% |
| Natural gas delivery service | MoPSC | (d) | (d) | (d) | 2% |
| Ameren Illinois | | | | | |
Electric distribution delivery service(e) | ICC | 8.69% | 50.0% | $3.0 | 25% |
Natural gas delivery service(f) | ICC | 9.87% | 50.0% | $1.6 | 13% |
Electric transmission service(g) | FERC | 10.82% | 52.0% | $1.9 | 3% |
| ATXI | | | | | |
Electric transmission service(g) | FERC | 10.82% | 56.1% | $1.3 | 3% |
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(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. |
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(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. |
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(c) | Based on the MoPSC’s March 2017 rate order. This rate order specified that an implicit return on equity was within a range of 9.2% to 9.7%. The rate order did not specify a percent of common equity or rate base. The return on equity used for allowance for equity funds used during construction is 9.53%. |
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(d) | Based on the MoPSC’s January 2011 rate order. This rate order did not specify the allowed return on equity, the percent of common equity, or rate base. |
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(e) | Based on the ICC’s November 2018 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The November 2018 rate order was based on 2017 recoverable costs, expected net plant additions for 2018, and the annual average of the monthly yields during 2017 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ 2019 electric distribution delivery service revenues will be based on its 2019 actual recoverable costs, rate base, common equity percentage, and return on common equity, as calculated under the IEIMA’s performance-based formula ratemaking framework. |
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(f) | Based on the ICC’s November 2018 rate order. The rate order was based on a 2019 future test year. |
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(g) | Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking based on each year’s forecasted information. The 10.82% return, which includes a 50 basis points incentive adder for participation in an RTO, could be lowered as a result of a FERC complaint proceeding filed in February 2015 that challenged the allowed return on common equity for MISO transmission owners and will require customer refunds if the FERC approves a return on equity lower than that previously collected through rates. The return on equity applicable to investments in ATXI’s Mark Twain project includes an additional 50 basis points incentive adder related to the unique nature of risks involved in completing the project. |
Ameren Missouri
Ameren Missouri’s electric operating revenues are regulated by the MoPSC. Ameren Missouri’s electric service and natural gas distribution service rates are established in a traditional regulatory rate review based on a historical test year and an allowed return on equity. If specific criteria are met, certain of Ameren Missouri’s electric rates may be adjusted without a traditional rate proceeding. For example, Ameren Missouri’s MEEIA customer energy-efficiency program costs, lost electric margins, and any performance incentive are recoverable through a rider that may be adjusted without a traditional rate proceeding, subject to MoPSC prudence reviews. Likewise, 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 rate proceeding, subject to MoPSC prudence reviews.
In addition to the MEEIA and the FAC recovery mechanisms, Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a tracker on certain excess deferred taxes, a renewable energy standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and the costs included in customer rates as a regulatory asset or regulatory liability. The difference will be included in base rates in a subsequent MoPSC rate order. Ameren Missouri also employs PISA and the RESRAM, as discussed below.
Under PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Eligible PISA deferrals exclude amounts related to new coal-fired, nuclear, and natural gas generating units and service to new customer premises. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, and all approved PISA deferrals will be added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. PISA mitigates the impacts of regulatory lag between regulatory rate reviews. Costs not included in the PISA deferral, including the remaining 15% of certain property, plant, and equipment not eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions under Missouri Senate Bill 564 apply to Ameren Missouri, including limitations on electric customer rate increases and an electric base rate freeze until April 2020. Customer rates under the MEEIA, the FAC, and the RESRAM riders have not been frozen. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the 2.85% rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review will be subject to the rate cap. Any deferred overages approved for recovery will be recovered in a manner consistent with costs recovered under PISA. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the amount of deferred
overage that would cause customer rates to exceed the 2.85% rate cap. Both the rate increase limitation and PISA are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.
The RESRAM allows Ameren Missouri to mitigate the impacts of regulatory lag for the cost of compliance with renewable energy requirements, including recovery of investments in wind and other renewable generation, and to earn a return 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. Under the RESRAM, Ameren Missouri is permitted to recover the 15% of renewable generation plant placed in service not recovered under PISA. RESRAM regulatory assets earn carrying costs at short-term interest rates.
Ameren Missouri is a member of MISO, and its transmission rate is calculated in accordance with the MISO Open Access Transmission 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 filings with the FERC. This rate is not directly charged to Missouri retail customers because, in Missouri, bundled retail rates include an amount for transmission-related costs and revenues.
Ameren Missouri’s natural gas operating revenues are regulated by the MoPSC. If specific criteria are met, Ameren Missouri’s natural gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas supply costs to be passed directly to customers. The ISRS also permits certain prudently incurred natural gas infrastructure replacement costs to be recovered from customers on a timely basis between regulatory rate reviews. Ameren Missouri is not currently recovering any infrastructure replacement costs under the ISRS. The return on equity for purposes of the ISRS tariff will be determined in the pending natural gas rate review. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information on the pending natural gas rate review.
Ameren Illinois
Ameren Illinois Electric Distribution
Ameren Illinois’ electric distribution delivery service operating revenues are regulated by the ICC. In 2018, Ameren Illinois’ electric distribution delivery service revenues accounted for 88%of Ameren Illinois’ total electric operating revenues.
Ameren Illinois participates in the performance-based formula ratemaking framework established pursuant to the IEIMA, which is available through 2022 unless extended. This framework provides for the recovery of actual costs of electric delivery service that are prudently incurred and the use of the utility’s actual regulated capital structure through a formula for calculating the return on equity component of the cost of capital. A common equity ratio up to and including 50% is considered prudent under the framework. The return on equity component of the formula rate is equal to the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The revenue requirement included in customer rates is reconciled annually with the revenue requirement necessary to reflect the actual costs incurred in a given year, including an allowed return on equity. This annual revenue requirement reconciliation adjustment will be collected from, or refunded to, customers within two years.
Beginning in 2017, the FEJA allowed Ameren Illinois to recover within the following two years its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to 2017, Ameren Illinois’ revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This portion of the law extends beyond the end of formula ratemaking in 2022. Through 2022, revenue differences will be included in the annual formula rate revenue requirement reconciliation. Additionally, this law implemented a customer surcharge, based on zero emission credit purchases, relating to certain nuclear energy centers located in Illinois. The surcharge, like the cost of power purchased by Ameren Illinois on behalf of its customers, is passed through to electric distribution customers with no effect on Ameren Illinois’ earnings.
Ameren Illinois plans to invest approximately $100 million per year in electric energy-efficiency programs through 2023, consistent with targets established by the FEJA. The electric energy-efficiency program investments and the formulaic return on those investments will be collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework.
Ameren Illinois is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed return on equity calculated under the formulas. The performance standards applicable to electric distribution service include improvements in service reliability to reduce both the frequency and duration of outages, a reduction in the number of estimated bills, a reduction of consumption from inactive meters, and a reduction in bad debt expense. The electric distribution service regulatory framework provides for return on equity penalties up to 38 basis points in each year from 2019 through 2022, if these performance standards are not met. Beginning in 2018, the rider for electric energy-efficiency investments provides for increases or decreases of up to 200 basis points to the return on equity. Any adjustments to the return on equity for energy-efficiency investments will depend on annual performance of a historical period relative to energy savings goals. In 2018, there were no performance-related basis point adjustments.
Under the IEIMA, Ameren Illinois is also subject to minimum capital spending levels. Between 2012 and 2021, Ameren Illinois is required to invest a minimum of $625 million in capital projects to modernize its distribution system incremental to its average annual electric distribution service capital projects of $228 million for calendar years 2008 through 2010. Through 2018, Ameren Illinois has invested $592 million in IEIMA capital projects toward its $625 million requirement.
Ameren Illinois employs cost recovery mechanisms for power procurement, renewable energy credits, zero emission credits, and certain environmental costs, as well as bad debt expense and the costs of certain asbestos-related claims not recovered in base rates.
Ameren Illinois Natural Gas
Ameren Illinois’ natural gas operating revenues are regulated by the ICC. In November 2018, the ICC issued a rate order that approved an annual revenue increase of $32 million for Ameren Illinois’ natural gas delivery service, based on a 2019 future test year. If specific criteria are met, Ameren Illinois’ natural gas rates may be adjusted without a traditional rate proceeding, as PGA clauses permit prudently incurred natural gas costs to be passed directly to customers. Ameren Illinois employs a VBA to ensure recoverability of the natural gas distribution service revenue requirement for residential and small nonresidential customers that is dependent on sales volumes. 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 normalized sales volumes approved by the ICC in a previous regulatory rate review. Also, Ameren Illinois employs cost recovery mechanisms for customer energy-efficiency program costs, certain environmental costs, and bad debt expenses not recovered in base rates.
Illinois has a law that encourages natural gas utilities to accelerate modernization of the state’s natural gas infrastructure through a QIP rider. Without legislative action, the QIP rider will expire in December 2023. Ameren Illinois’ QIP rider allows a surcharge to be added to customers’ bills to recover depreciation expenses and to earn a return on qualifying natural gas investments that were not previously included in base rates. Eligible natural gas investments include projects to improve safety and reliability and modernization investments, such as smart meters. Recovery begins two months after the qualifying natural gas plant is placed in service and continues until such plant is included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP rider is subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. Upon issuance of a natural gas delivery service rate order, QIP rate base is transferred to base rates and the QIP rider is reset to zero, which mitigates the risk that the QIP rider will exceed its statutory limitations in future years and ensures timely recovery of capital investment.
Ameren Illinois Transmission
Ameren Illinois’ transmission operating revenues are regulated by the FERC. In 2018, Ameren Illinois’ transmission operating revenues accounted for 12% of Ameren Illinois’ electric operating revenues. See Ameren Transmission below for additional information regarding Ameren Illinois’ transmission business.
Ameren Transmission
Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. Both Ameren Illinois and ATXI are members of MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission 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. A reconciliation at the end of the year, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates in a subsequent year. 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.
The FERC-allowed return on common equity for MISO transmission owners was challenged by customer groups in two complaint cases filed in November 2013 and February 2015. In September 2016, the FERC issued a final order in the November 2013 complaint case, which became immediately effective, and lowered the allowed base return on common equity to 10.32%, or a 10.82% total allowed return on equity with the inclusion of a 50 basis point adder for participation in an RTO.In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case. If approved by the FERC, it would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. It would also require customer refunds, with interest, for that 15-month period. A final FERC order would also establish the allowed return on common equity that will apply prospectively from the effective date of such order, replacing the current 10.82% total return on common equity.In November 2018, the FERC issued an order related to the February 2015 complaint case and the September 2016 final order, which required briefs from the participants to be filed in February 2019 regarding a new methodology for determining the base return on common equity and whether and how to apply the new methodology to the two MISO complaint cases.
Ameren is unable to predict the ultimate impact of the proposed methodology on these complaint cases at this time. As the FERC is under no deadline to issue a final order, the timing of the issuance of the final order in the February 2015 complaint case, or any potential impact to the amounts refunded as a result of the September 2016 final order, is uncertain.
ATXI has three MISO-approved multi-value projects: the Spoon River, Illinois Rivers, and Mark Twain projects. The Spoon River project, which is located in northwest Illinois, was placed in service in February 2018. The Illinois Rivers project involves the construction of a 345-kilovolt line from eastern Missouri across Illinois to western Indiana. Construction of the Illinois Rivers project is substantially complete, with the last section awaiting the outcome of certain legal proceedings, which will delay the expected completion date to 2020. This delay is not expected to materially affect 2019 rate base or earnings. The Mark Twain project is located in northeast Missouri and connects Iowa to the Illinois Rivers project. ATXI plans to complete the Mark Twain project by the end of 2019. As of December 31, 2018, ATXI’s expected remaining investment in both the Illinois Rivers and Mark Twain projects was approximately $150 million, with the total investment in all three projects expected to be more than $1.6 billion.
The FERC has approved transmission rate incentives relating to the three MISO-approved multi-value projects, which allow construction work in progress to be included in rate base, thereby improving the timeliness of cash recovery. Additionally, the Mark Twain project earns an additional 50 basis point return on equity incentive adder, effective as of February 14, 2018, based on the unique nature of risks involved in the project.
For additional information on Ameren Missouri, Ameren Illinois, and ATXI rate matters, including the FERC complaint case challenging the allowed return on common equity for MISO transmission owners, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
The following table summarizes the key terms of the rate orders in effect for customer billings for each of Ameren’s rate-regulated utilities as of January 2021:
| | | | | | | | | | | | | | | | | | | | |
| Rate Regulator | Effective
Rate Order
Issued In | Allowed
ROE | Percent of
Common Equity | Rate Base
(in billions) | Portion of Ameren’s 2020 Operating Revenues(a) |
| Ameren Missouri | | | | | | |
Electric service(b) | MoPSC | March 2020(c) | 9.4% – 9.8%(c) | (c) | (c) | 51% |
| Natural gas delivery service | MoPSC | August 2019(d) | 9.4% – 9.95%(d) | 52.0% | (d) | 2% |
| Ameren Illinois | | | | | | |
Electric distribution delivery service(e) | ICC | December 2020 | 8.38% | 50.0% | $3.4 | 26% |
Natural gas delivery service(f) | ICC | January 2021 | 9.67% | 52.0% | $2.1 | 13% |
Electric transmission service(g) | FERC | (g) | 10.52% | 54.0% | $2.6 | 5% |
| ATXI | | | | | | |
Electric transmission service(g) | FERC | (g) | 10.52% | 60.1% | $1.4 | 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.
(c)This rate order specified that an implicit ROE was within a range of 9.4% to 9.8%. This rate order did not specify a percent of common equity or rate base. The ROE used for allowance for equity funds used during construction is 9.53%.
(d)This rate order specified that an implicit ROE was within a range of 9.4% to 9.95%. This rate order did not specify rate base. The ROE used for allowance for equity funds used during construction is 9.53%.
(e)Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. This rate order was based on 2019 actual costs, expected net plant additions for 2020, and the annual average of the monthly yields during 2019 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ allowed ROE for 2020 and 2019 was based on an annual average of the monthly yields of the 30-year United States Treasury bonds of 1.56% and 2.58%, respectively. Ameren Illinois’ 2021 electric distribution delivery service revenues will be based on its 2021 actual recoverable costs, rate base, common equity percentage, and an allowed ROE, as calculated under the IEIMA’s performance-based formula ratemaking framework.
(f)This rate order was based on a 2021 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 points incentive adder for participation in an RTO, is based on the FERC’s May 2020 order. For additional information regarding this order and related requests for rehearing, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
General Regulatory Matters
Ameren Missouri, Ameren Illinois, and ATXI must receive FERC approval to enter into various transactions, such as issuing short-term debt securities and conducting certain acquisitions, mergers, and consolidations involving electric utility holding companies. In addition, Ameren Missouri, Ameren Illinois, and ATXI must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities and to conduct mergers, affiliate transactions, and various other activities.
Ameren Missouri, Ameren Illinois, and ATXI are also subject to mandatory reliability standards, including cybersecurity standards adopted by the FERC, to ensure the reliability of the bulk electric power system. These standards are developed and enforced by the NERC, pursuant to authority delegated to it by the FERC. Ameren Missouri, Ameren Illinois, and ATXI are members of the SERC. The SERC is one of eight regional entities representing all or portions of 16 central and southeastern states under authority from the NERC for the purpose of implementing and enforcing reliability standards approved by the FERC. The regional entities of the NERC work to safeguard the reliability of the bulk power systems throughout North America. If any of Ameren Missouri, Ameren Illinois, or ATXI is found not to be in compliance with these mandatory reliability standards, it could incur substantial monetary penalties and other sanctions.
Under the Public Utility Holding Company Act of 2005, the FERC and anythe state public utility regulatory agencyagencies 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 companies.
Operation of Ameren Missouri’s Callaway energy centerEnergy Center is subject to regulation by the NRC. The license for the Callaway energy centerEnergy Center expires in 2044. Ameren Missouri’s hydroelectric Osage Energy Center and pumped-storage hydroelectric energy center and Taum Sauk pumped-storage hydroelectric energy center,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 hydroelectric energy centerEnergy Center and the Taum Sauk pumped-storage hydroelectric energy centerEnergy Center expire in 2047 and 2044, respectively. Ameren Missouri’s Keokuk energy centerEnergy Center and its dam in 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
CertainOur generation, transmission, and electric and natural gas distribution operations must comply with a variety of our operations are subject to federal, state, and local environmental laws includingcontained in statutes and regulations relating to the protection of the safety and health of our personnel, the public,environment and the environment.health and safety of the public. These laws are comprehensive and include requirements relating to identification, generation,the storage, handling, transportation,and disposal recordkeeping, labeling, reporting,of waste materials, emergency planning and emergency response in connection with hazardousrequirements, limitations and toxic materials; safetystandards applicable to discharges from our facilities into the air or water that are enforced through permitting requirements, and health standards;wildlife protection laws, including those related to endangered species. These environmental regulations could also affect the availability of, the cost of, and environmental protection requirements, including standardsthe demand for electricity and limitations relatingnatural gas sold to Ameren Missouri’s and Ameren Illinois’ customers as well as the demand for off-system sales. Federal, state, and local authorities continually revise these regulations, which adds uncertainty to our planning process and to the dischargeultimate implementation of air and water pollutants, water intake, and the management of waste and byproduct materials.
these or other new or revised regulations. Failure to comply with these laws could have a material adverse effectseffect on us. We could be subject to criminal or civil penalties by regulatory agencies, or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing laws that currently apply to our operations.
The EPA has promulgated environmental regulations that have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants.As of December 31, 2018, Ameren Missouri’s fossil fuel-fired energy centers represented 16% and 32% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx,mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Water intake and discharges from power plants are regulated under the Clean Water Act. Such regulation could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, either of which could result in significant capital expenditures. The management and disposal of coal ash is regulated under the CCR rule, which will require the closure of surface impoundments and the installations of dry ash handling systems at several of Ameren Missouri’s energy centers. The individual or combined effects of existing 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. These environmental regulations could also affect the availability of, the cost of, and the demand for power and natural gas that is acquired for Ameren Missouri’s natural gas customers and Ameren Illinois’ electric and natural gas customers. Federal, state, and local authorities continually revise these regulations, which adds uncertainty to our planning process and to the ultimate implementation of these or other new or revised regulations.
For additional 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 the EPA’s allegations of violations oflitigation 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,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. During 2018,The AMMO balancing authority area includes the load and energy centers of Ameren Missouri, and had a peak demand was 7,482 megawattsof 7,108 MWs in AMMO2020. The AMIL balancing authority area includes the load of Ameren Illinois, and 8,792 megawattshad a peak demand of 8,351 MWs in AMIL.2020. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
Ameren Missouri, Ameren Illinois, and ATXI are transmission-owning members of the MISO. Ameren Missouri is authorized by the MoPSC to participate in the MISO through May 2020.2024. Ameren Missouri is periodically required to filemake a periodic cost-benefit studyfiling with the MoPSC in 2020 evaluating Ameren Missouri’sregarding its continued participation in the MISO. The next filing is due in 2023.
SUPPLY OF ELECTRIC POWER
Ameren Missouri
Ameren Missouri’s electric supply is primarily generated from its energy centers. Factors that could cause Ameren Missouri to purchase power include, among other things, energy center outages, the fulfillment of renewable energy requirements, the failure of suppliers to meet their power supply obligations, extreme weather conditions, the availability of power at a cost lower than its generation cost, and the absencelack of sufficient owned generation.
Ameren Missouri files a long-term nonbinding 20-year integrated resource plan with the MoPSC every three years. The most recent integrated resource plan, filed in September 2017,2020, includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability.reliability and customer affordability. The plan, which is subject to review by the MoPSC for compliance with Missouri law, targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power.power, and supports increased investment in new energy technologies. It also includes expanding renewable sources by adding 3,100 MWs of renewable generation by adding at least 700 megawattsthe end of wind2030 and a total of 5,400 MWs of renewable generation by 2020 in2040, inclusive of the High Prairie and Atchison renewable energy centers, the expectation that Ameren Missouri will seek NRC approval for an extension of the operating license for the Callaway Energy Center, expanding customer energy-efficiency programs, adding cost-effective demand response programs, advancing the retirement dates of the Sioux and neighboring states, adding 100 megawatts of solar generation by 2027,Rush Island coal-fired energy centers to 2028 and 2039, respectively, and retiring the remaining coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs,including the Meramec Energy Center by the end of 2022. The addition of a renewable generation facility is subject to obtaining necessary project approvals, including FERC approval and adding cost-effective demand response programs.the issuance of a certificate of convenience and necessity by the MoPSC, as applicable. Advancing the retirement dates of the Sioux and Rush Island energy centers is subject to the approval of a change in the assets’ depreciable lives by the MoPSC in a future regulatory rate review. 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. Ameren Missouri expects to file its next integrated resource plan in September 2023.
Ameren Missouri continues to evaluate its longer-term needs for new generating capacity. The need for investment in new sources of energy centers is dependent on several key factors, including continuation of and customer participation in energy-efficiency programs, the amount of distributed generation from customers, load growth, technological advancements, costs of generation alternatives, environmental regulation of coal-fired power plants, and state renewable energy requirements, which could lead to the retirement of current baseload assets before the end of their current useful lives or alterations in the way those assets operate.operate, which could result in increased capital expenditures and/or increased operations and maintenance expenses. Because of the significant time required to plan, acquire permits for,
and build a baseload energy center, Ameren Missouri continues to study alternatives and to take steps to preserve options to meet future demand. Steps include evaluating the potential for further diversification of Ameren Missouri’s generation portfolio through renewable energy generation, including wind and solar generation, extending the operating license for the Callaway Energy Center, additional customer energy-efficiency and demand response programs, distributed energy resources, and energy storage.
Missouri law requires Ameren Missouri to offer rebates and net metering to certain customers that install solar generation at their premises. The cost of the rebates are deferred as a regulatory asset under the RESRAM, and earn carrying costs at short-term interest rates. Customers that elect to enroll in net metering are allowed to net their generation against their usage within each billing month.
Ameren Illinois
In Illinois, while electric transmission and distribution service rates are regulated, power supply prices are not. Although electric customers are allowed to purchase power from an alternative retail electric supplier, Ameren Illinois is required to be the provider of last resort for its electric distribution customers. In 2018, 2017,2020, 2019, and 2016,2018, Ameren Illinois procured power on behalf of its customers for 23% in each year, 22%, 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 power and related procurement costs incurred by Ameren Illinois are passed directly to its electric distribution customers through a cost recovery mechanism. The 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 transmission and distribution service rates to electric distribution customers who purchase electricity from alternative retail electric suppliers, which does affect Ameren Illinois Electric Distribution’s earnings.
Illinois law requires Ameren Illinois to offer rebates for certain net metering customers. It is anticipated that the first rebates will be issued in 2019. The cost of the rebates will beare deferred as a regulatory asset, which will earn a return based onat the utility’s weighted-average cost of capital.applicable WACC. Customers that receive these rebates will beare allowed to net their supply service charges, but not their distribution service charges. Beginning in 2017, the FEJA decoupled theAmeren Illinois’ electric distribution revenues established in a rate proceedingare decoupled from the actual sales volumes, which ensures that Ameren Illinois’the electric distribution earnings willrevenues authorized in a regulatory rate review are not be affected by any changes in sales volumes.
POWER GENERATION
Ameren Missouri owns energy centers that rely on a diverse fuel portfolio, including coal, nuclear, and natural gas, as well as renewable sources of generation, which include hydroelectric, wind, methane gas, and solar. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978. The Callaway nuclear energy center began operation in 1984 and is licensed to operate until 2044. As of December 31, 2018,2020, Ameren Missouri’s fossil fuel-firedcoal-fired energy centers represented 16%11% and 32%23% of Ameren’s and Ameren Missouri’s rate base, respectively. See Item 2 – Properties under Part I of this report for information regarding Ameren Missouri’s electric generation energy centers.
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. As of December 31, 2018,2020, Ameren Missouri had price-hedged 98%100% of its expected coal supply and 100% of its coal transportation requirements for generation in 2019.2021. Ameren Missouri has additional coal supply under contract through 2022.2025. The Powder River Basin coal transport agreements that Ameren Missouri has with Union Pacific Railroad and Burlington Northern Santa Fe Railway are currently set to expire at the end of 2024. Ameren Missouri burned approximately 18.015.4 million tons of coal in 2018.2020.
About 97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming.Wyoming, which has a limited number of suppliers. The remaining coal is typically purchased from the Illinois Basin. InventoriesTargeted coal inventory levels may be adjusted because of generation levels or uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion and maintenance, derailments, weather, and weather.supplier financial hardship. Coal suppliers in the Power River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations, as well as concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2018,2020, coal inventories for Ameren Missouri were near targeted levels. Disruptions in coal deliveries could cause Ameren
Missouri to pursue a strategy that could include reducing wholesaleoff-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.Energy Center.
The Callaway energy center requiresEnergy Center has historically required refueling at 18-month intervals. TheDuring its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was completedconducted. Work has begun to replace certain key components of the generator in December 2017. The next refueling is scheduledorder to return the energy center to service. As of the date of this filing, due to the long lead time for the springmanufacture, repair, and installation of 2019. As of December 31, 2018, Ameren Missouri had inventories for all of Callaway’s spring 2019
refueling requirements.these components, the energy center is expected to return to service in late June or early July 2021. Ameren Missouri has inventories, supply contracts, and supplyfuel fabrication service contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at least through the 20232025 refueling. Ameren Missouri has fuel fabrication service contracts through the 2023 refueling.
RENEWABLE ENERGY CREDITS AND ZERO EMISSION CREDITSSTANDARDS
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 2018.2020.
Ameren Missouri
In Missouri, utilities were required to purchase or generate electricity equal to at least 10% of native load sales from renewable energy sources in 2018. That percentage will increase2020. The requirement increased to at least 15% byin 2021, subject to an average 1% annual increase on customer rates over any 10-year period. At least 2% of the annual renewable energy requirement must be derived from solar energy. Ameren Missouri expects to satisfy the nonsolar requirement in 20192021 with its High Prairie Renewable, Atchison Renewable, Keokuk, and Maryland Heights energy centers, a 102-megawatt102-MW power purchase agreement with a wind farm operator, and an estimated purchase of approximately $2 million ofimmaterial renewable energy creditscredit purchases in the market. In December 2020, Ameren Missouri acquired and placed in service the High Prairie Renewable Energy Center, a 400-MW wind generation facility. In January 2021, Ameren Missouri acquired an up-to 300-MW wind generation project and, as of the date of this filing, placed 120 MWs in service as the Atchison Renewable Energy Center. Ameren Missouri expects approximately 150 MWs to be in service by the end of the first quarter of 2021, and the remaining portion to be in service later in 2021. For additional information see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. The Keokuk energy centerEnergy Center generates electricity using a hydroelectric dam located on the Mississippi River. The Maryland Heights energy centerEnergy 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 solar energy at its O’Fallon, Lambert, and BJC energy centercenters and its headquarters building.
Ameren Illinois
In 2018,accordance with Illinois law, Ameren Missouri entered into build-transfer agreementsIllinois is required to purchase up to 557 megawatts of wind generation. For additional information on these agreements, see Note 2 – Rate and Regulatory Matters under Part II, Item 8 of this report.
Effective June 2017, the FEJA requires the IPA to procure renewable energy credits forcollect funds from all electric distribution customers to fund IPA procurement events for renewable energy credits. The amount collected from customers by Ameren Illinois is capped at $1.81 per MWh. The IPA establishes its long-term renewable resources procurement plans in Illinois, including those customers supplied by alternative retail electric suppliers.a filing made every two years. The IPA’s initial long-term renewable resources procurement plan was approved by the ICC in 2018. The IPA’s plan set forth guidelines by which the IPA should procure 15-year contracts for four million wind renewable energy credits per year and four million solar renewable energy credits per year, allocated among Ameren Illinois, Commonwealth Edison Company, and MidAmerican Energy Company based on load.credits. As a result, of the allocation, Ameren Illinois is required to purchase 1.2 million wind renewable energy credits per year and 1.2 million solar renewable energy credits per year.year, through IPA procurement events, which represented approximately 7% of Ameren Illinois’ electric distribution sales in 2020. The IPA has completed several procurement events, resulting in contractual commitments for Ameren Illinois of 0.9 million wind renewable energy credits per year and 0.91.2 million solar renewable energy credits per year for Ameren Illinois. The remaining 0.3 million wind renewable and 0.3 million solar energy credits per year foryear. Ameren Illinois has also entered into renewable energy credit contracts with 20-year terms ending 2032 and will be obtainedexecute additional contracts in 2021, through IPA procurement events, in 2019. Ameren Illinois will execute additional renewable energy credit contracts after these procurements in 2019. The IPA is expectedorder to filefulfill its remaining obligations. In February 2020, the ICC approved the IPA’s second long-term renewable resources procurement plan. Under the second plan, in 2019, which, once approved, will establish the 2020 and 2021based on forecasted customer collections to fund renewable energy credit procurement targets.contracts, the IPA does not anticipate procuring additional contracts. However, if customer funds collected exceed the cost of procured contracts, the IPA may procure additional contracts. Funds collected but not used to procure renewable energy credits will be refunded to customers pursuant to a reconciliation proceeding that would be initiated after August 2021.
The FEJAIllinois law also required Ameren Illinois to enter into contracts for zero emission credits in an amount equal to approximately 16% of the actual amount of electricity delivered to retail customers during calendar year 2014. This one-time2014, pursuant to Illinois’ zero emission standard. As a result of a 2018 IPA procurement event, which was approved by the ICC, Ameren Illinois entered into agreements to acquire zero emission credits through 2026. Annual zero emission credit procurementcommitment amounts will be published by the IPA approval byeach May prior to the ICC, and executionstart of zero emission credit contracts were all completed in 2018. Contracts are for 10 years with quantities allocated among Ameren Illinois, Commonwealth Edison Company, and MidAmerican Energy Company.the subsequent
planning year. Both renewable energy credits and zero emission credits have cost recovery tariff mechanisms, which fully recoverallow Ameren Illinois to collect from, or refund the varianceto, customers differences between actual costs incurred from the resulting contracts and the amounts collected from customers.
ENERGY EFFICIENCYCUSTOMER ENERGY-EFFICIENCY PROGRAMS
Ameren Missouri and Ameren Illinois have implemented energy-efficiency programs to educate and to help their customers become more efficient energy consumers.
Ameren Missouri
In Missouri, the MEEIAMissouri Energy Efficiency Investment Act established a regulatory recovery mechanismrider 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 February 2016, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2016 plan. That plan included a portfolio of customer energy-efficiency programs, along with a regulatory recovery mechanism. The MoPSC’s order included a performance incentive that provides for additional revenues if certain MEEIA 2016 customer energy-efficiency goals are achieved, including $27 million if 100% of the goals are achieved during the three-year period. Ameren Missouri must achieve at least 25% of its energy efficiency-goals to be eligible for a MEEIA 2016 performance incentive and can earn more if its energy savings exceed those goals. Through 2018, Ameren Missouri invested $136 million in MEEIA 2016 customer energy-efficiency programs and recognized $11 million in additional revenue related to performance incentives.
In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 20212022 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism.rider. Ameren Missouri intends to invest $226$290 million over the life of the plan, including $65
million per year through 2021.in 2021 and $70 million in 2022. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100% ofgoals. In August 2020, the MoPSC issued an order approving a unanimous stipulation and agreement establishing performance incentives for the 2022 program year. If the target goals are achieved during the period ended December 2021. Additionalfor 2020, 2021, and 2022, additional revenues of $10 million, $13 million, and $11 million would be recognized in 2021, 2022, and 2022, respectively. Incremental additional revenues of $3 million, $3 million, and $1 million may be earned for 2020, 2021, and 2022, respectively, and would be recognized in the respective following year if Ameren Missouri exceeds 100%its targeted goals. Ameren Missouri’s ability to achieve and/or exceed targeted goals could be affected by the COVID-19 pandemic. Through 2020, Ameren Missouri has invested $121 million in MEEIA 2019 customer energy-efficiency programs. Additionally, as part of its Smart Energy Plan, Ameren Missouri has invested $115 million in smart meters since 2019 that enable customers to improve their energy savings goals.efficiency.
Both the MEEIA 2016 andThe MEEIA 2019 plans includeplan includes the continued use of the MEEIA rider. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any difference between actual program costs, lost electric margins, and any performance incentive and the amounts collected from customers, without a traditional regulatory rate proceedingreview, until lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates, based upon both forecasted program costs and lost electric margins and collected via the MEEIA rider, are reconciled annually to actual results.
Ameren Illinois
State law requires Ameren Illinois to offer customer energy-efficiency programs.programs, and imposes electric energy-efficiency savings goals and a maximum amount of investment in electric energy-efficiency programs through 2030, which is approximately $100 million annually. In September 2017, the ICC issued an order approving Ameren Illinois’ electric and natural gas energy-efficiency plans, as well as regulatory recovery mechanisms. The order authorized electric and natural gas energy-efficiency program expenditures of $394 million and $62 million, respectively, for the 2018 through 2021 period. Additionally, as part of its IEIMA capital project investments, Ameren Illinois has invested approximately $380$300 million in smart-grid infrastructuresmart meters since 2012 including smart meters that enable customers to improve their energy efficiency, and expects to spend another $60 million by 2021.efficiency.
Historically, Ameren Illinois recovered the cost of its energy-efficiency programs as they were incurred. The FEJAlaw allows Ameren Illinois to earn a return on its electric energy-efficiency program investments made since June 2017. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the company’s weighted-average cost of capital,applicable WACC, with the equity returnROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ returnallowed 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. Ameren Illinois plans to invest up to approximately $100 million per year in electric energy-efficiency programs through 2023,2025, and will earn a return on those investments. While the ICC has approved a plan consistent with targets established bythis spending level through 2021, the FEJA. The ICC can lowerhas the ability to reduce the amount of electric energy-efficiency savingsavings goals in future plan program years if sufficientthere are insufficient cost-effective measures are not available. programs available, which could reduce the investments in electric energy-efficiency programs.The electric energy-efficiency program investments and the return on those investments will be recoveredare collected from customers through a rider; they willrider and are not be included in the IEIMAelectric distribution service performance-based formula rate process.ratemaking framework. Ameren Illinois’ natural gas energy-efficiency program costs are recovered as they are incurred through a regulatory recovery mechanism.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their customers. Ameren Missouri and Ameren Illinois each develop and manage a portfolio of natural gas supply resources. These resources include firm natural gas supply
agreements with producers, firm interstate and intrastate transportation capacity, firm no-notice storage capacity leased from interstate pipelines, and on-system storage facilities to maintain natural gas deliveries to customers throughout the year and especially during peak demand periods. Ameren Missouri and Ameren Illinois primarily use Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, Mississippi River Transmission Corporation, Northern Border Pipeline Company, and Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to transactions requiring physical delivery, certain financial instruments, including those entered into in the NYMEXNew York Mercantile Exchange futures market and in the over-the-counter financial markets, are used to hedge the price paid for natural gas. Natural gas supply costs are passed on to customers of Ameren Missouri and Ameren Illinois under PGA clauses, subject to prudence reviews by the MoPSC and the ICC. As of December 31, 2018,2020, Ameren Missouri and Ameren Illinois had price-hedged 62%68% and 76%73%, respectively, of their expected 20192021 natural gas supply requirements.
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, of this report 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, and 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 regulated infrastructure, continuously improve performance, and advocate for responsible policies to deliver superior customer and shareholder value is driven by the capabilities and engagement of our workforce. Ameren’s workforce strategy is designed to promote a diverse workforce that is prepared to deliver on Ameren’s mission (To Power the Quality of Life) and vision (Leading the Way to a Sustainable Energy Future), both today and in the future. Our workforce strategy is anchored in four key pillars: Culture, Leadership, Talent, and Rewards, which are discussed further below. Foundational to our workforce strategy are our core values of:
| | | | | |
•Safety and security •Commitment to excellence •Respect •Accountability | •Diversity, equity, and inclusion •Integrity •Teamwork •Stewardship |
Ameren’s chief executive officer and chief human resources officer, with the support of other leaders of the Ameren Companies, are responsible for developing and executing our workforce strategy. In addition to reviewing and determining the Ameren Companies’ compensation practices and policies for the chief executive officer and other executive officers, the Human Resources Committee of Ameren’s board of directors is responsible for oversight of Ameren’s human capital management practices and policies, including those related to diversity, equity, and inclusion. The Human Resources Committee and Ameren’s board of directors are updated regularly on human capital matters.
Culture
We strive to cultivate a values-based “All-In” culture that enables the sustainable execution of our core strategy and reflects the following characteristics:
| | | | | |
•We Care about our customers, our communities, and each other •We Serve with Passion | •We Deliver for our customers and stakeholders •We WinTogether as a result of our teamwork and collaboration |
We design our human capital management practices and policies to reinforce our core values, share our culture, and drive employee engagement. In doing so, we strive to align our employees to our mission and vision, improve safety, enhance innovation, increase productivity, attract and retain top talent, and recognize employee contributions, among other things. We assess employee engagement through a variety of channels. As a part of our assessment, we conduct confidential employee engagement surveys at least annually to identify areas of strength and opportunities for improvement in our employees’ experience, and take actions aimed at increasing employee engagement.
As a part of our All-In culture, every employee is expected to challenge any unsafe act, complete each workday safely, and provide feedback on safety and security matters. In addition to comprehensive safety and security standards, and mandatory health, safety, and security training programs for applicable employees, we promote programs designed to encourage employees to provide feedback on practices or actions that could harm employees, customers, or the Ameren Companies, including perceived issues related to safety, security (both physical and cyber), ethics and compliance violations, or acts of discrimination. For additional information about the actions taken designed to protect the safety of our employees and customers during the COVID-19 pandemic, see The COVID-19 Pandemic section below.
We seek to foster diversity, equity, and inclusion, which was elevated to a core value in 2020, across our organization. Ameren has established programs to recruit early and mid-career talent to further enhance the diversity of our workforce pipelines. These programs include an intern/coop program that serves as a pipeline for STEM-related careers, a career reentry program for experienced professionals transitioning from voluntary career breaks, and a program for individuals transitioning from military service. Additionally, each year management and the Human Resources Committee of Ameren’s board of directors review the diversity of our workforce, leadership team, and leadership development pipeline, as well as the actions taken to further enhance the diversity of our leadership team. In addition, the Ameren Companies contribute to community-based organizations, hold diversity, equity, and inclusion leadership summits for employees and community leaders, and offer various training programs. Beginning in 2021, we implemented a program to provide paid-time off for employees who engage in volunteer or learning opportunities with organizations that support diversity, equity, and inclusion. We also have employee resource groups, which bring together groups of employees who share common interests or backgrounds. Within these groups, employees collaborate to address concerns and provide training and development opportunities related to challenges or barriers, and offer support for each other, among other things.
Leadership
Ameren’s leaders play a critical role in setting and executing Ameren’s strategic initiatives, modeling our values and culture, and engaging and enabling the workforce. As such, we seek to develop a strong, diverse leadership team. Management engages in an extensive succession planning process annually, which includes the involvement by Ameren’s board of directors. We develop our leaders both individually, through job rotations, work experiences, and leadership development programs, and as a team. 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 above. 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.
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 2020. 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 as of December 31, 2020, and the attrition rate in 2020:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Employee
Count | | Average Tenure
(in years) | | Attrition
Rate | |
| Ameren | | 9,183 | | 14 | | 7% | |
| Ameren Missouri | | 3,997 | | 15 | | 7% | |
| Ameren Illinois | | 3,304 | | 14 | | 7% | |
| Ameren Services | | 1,882 | | 11 | | 6% | |
Ameren’s workforce is diverse in many ways. At the officer level, which represents 53 individuals, 23% are female and 21% are racially and/or ethnically diverse. The following table presents our total employee population that is represented by a collective bargaining unit, is a female, or is racially and/or ethnically diverse at December 31, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Collective Bargaining Unit | | Female | | Racially and/or Ethnically Diverse | | |
| Ameren | | 48% | | 25% | | 15% | | |
| Ameren Missouri | | 59% | | 17% | | 14% | | |
| Ameren Illinois | | 55% | | 24% | | 13% | | |
| Ameren Services | | 13% | | 40% | | 22% | | |
The following table presents Ameren’s employees by generation at December 31, 2020:
| | | | | | | | | | | | | | |
| Generation Description | Ameren | Ameren Missouri | Ameren Illinois | Ameren Services |
| Baby Boomer (birth years between 1946 and 1964) | 24% | 24% | 23% | 24% |
| Generation X (birth years between 1965 and 1980) | 40% | 41% | 39% | 41% |
| Millennials (birth years between 1981 and 1996) | 34% | 33% | 37% | 33% |
| Generation Z/Post Millennial (birth years after 1997) | 2% | 2% | 1% | 2% |
| | | | |
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 2021 and 2022, which cover 3% and 97% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2022 and 2023, which cover 93% and 7% 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 supporting their overall well-being. In addition to base salary, medical benefits, and retirement benefits, including 401(k) savings and pension, our total rewards package includes short-term incentives and long-term stock-based compensation for certain employees. Further, we offer our employees various programs that encourage overall well-being, including wellness and employee assistance programs. We strive to provide a competitive and sustainable rewards package that supports our ability to attract, engage, and retain a talented and diverse workforce, while at the same time reinforcing and rewarding strong performance.
THE COVID-19 PANDEMIC
The COVID-19 pandemic continues to be a constantly evolving situation. In 2020, we experienced a net decrease in our sales volumes, an increase in our accounts receivable balances that were past due or that were a part of a deferred payment arrangement, and a decline in our cash collections from customers. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. Shelter-in-place orders began taking effect in our service territories in mid-March 2020. These orders generally required individuals to remain at home and precluded or limited the operation of businesses that were deemed nonessential. While our business operations were deemed essential and were not directly impacted by the shelter-in-place orders, approximately 65% of our workforce transitioned to remote working arrangements in mid-March 2020. In order to work more effectively in certain areas, a portion of our workforce returned to our work locations in early June 2020 under a phased approach, and, as of the date of this filing, approximately 50% of our workforce continues to work remotely. In mid-May 2020, shelter-in-place orders effective in our service territories began to be relaxed, with fewer restrictions on social activities and nonessential businesses beginning to reopen. However, certain restrictions remain in place that limit individual activities and the operation of nonessential businesses. Additional restrictions may be imposed in the future.
During the COVID-19 pandemic, Ameren has taken significant actions designed to protect the safety of our employees and customers, including restricting travel for employees, implementing work-from-home policies, offering voluntary leave of absence arrangements and flexible reduced work schedules, enhancing paid time off programs for impacted employees, securing and supplying personal protective equipment, and implementing work practices to protect the safety of our employees and customers. In addition to our existing employee assistance program, we provided additional resources on physical, emotional, and financial well-being throughout the pandemic.
For further discussion of the impact to our businesses related to the pandemic and regulatory mechanisms that reduce these impacts, as well as Ameren Missouri’s requests for accounting authority orders related to COVID-19 pandemic costs, see Overview, Results of Operations, and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
INDUSTRY ISSUES
We are facing issues common to the electric and natural gas utility industry. These issues include:
political, regulatory, and customer resistance to higher rates;
•the potential for changes in laws, regulations, enforcement efforts, and policies at the state and federal levels;
•corporate tax law changes, as well as additional interpretations, regulations, amendments, or technical corrections that affect the amount and timing of income tax payments, reduce or limit the ability to claim certain deductions and use carryforward tax benefits and/or credits, or result in rate base reductions;
•cybersecurity risks, cyber attacks, including ransomware and other ransom-based attacks, hacking, social engineering, and other forms of malicious cybersecurity and/or privacy events, which could result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the theft or inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information;
•political, regulatory, and customer resistance to higher rates;
•the potential for more intense competition in generation, supply, and distribution, including new technologies and their declining costs;
•the impact and effectiveness of vegetation management programs;
•the 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 whohow those programs should pay for those programs;be paid for;
•pressure and uncertainty on customer growth and usagesales volumes in light of the COVID-19 pandemic and other economic conditions, distributed generation, energy storage, technological advances, and energy-efficiency or conservation initiatives;
•the potential for orders to suspend disconnections and/or late fees for customer nonpayment resulting from the COVID-19 pandemic and the related potential impact on liquidity;
•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 return on common equityROE 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 resulting from the COVID-19 pandemic;
•the availability of a skilled work force, including retaining the specialized skills of those who are nearing retirement;
•the potential for reduced efficiency and productivity due to increased use of remote working arrangements;
•regulatory lag;
•the influence of macroeconomic factors on yields of United States Treasury securities and on the allowed rates of return on equityROE provided by regulators;
•higher levels of infrastructure and technology investments and adjustments to customer rates associated with the TCJArefund 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;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, CCR management requirements, and potential CO2 limitations, which may reduce the frequency at which electric generating units are dispatched based upon their CO2 emissions;
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•complex new and proposed environmental laws including statutes, regulations, and requirements, such as air and water quality standards, mercury emissions standards, CCR management requirements, and potential CO2 limitations, which may reduce the frequency at which electric generating units are dispatched based upon their CO2 emissions;
•public concerns about the potential environmental impacts from the combustion of fossil fuels and somethe use of natural gas;
•certain investors’ concerns about investing in energyutility companies that have fossil fuel-firedcoal-fired generation assets;assets and increasing scrutiny of environmental, social, and governance 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 recent high profile inappropriate lobbying and similar activities by certain utility companies; and
•consolidation of electric and natural gas utility companies.
We are monitoring all these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, 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.
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, | 2020 | | 2019 | | 2018 | |
| Electric Sales – kilowatthours (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 13,267 | | | 13,532 | | | 14,320 | | |
| Commercial | 13,117 | | | 14,269 | | | 14,791 | | |
| Industrial | 4,158 | | | 4,242 | | | 4,499 | | |
| Street lighting and public authority | 88 | | | 99 | | | 108 | | |
| Ameren Missouri retail load subtotal | 30,630 | | | 32,142 | | | 33,718 | | |
| Off-system | 7,578 | | | 5,477 | | | 10,036 | | |
| Ameren Missouri total | 38,208 | | | 37,619 | | | 43,754 | | |
Ameren Illinois Electric Distribution(a): | | | | | | |
| Residential | 11,491 | | | 11,675 | | | 12,099 | | |
| Commercial | 11,414 | | | 12,341 | | | 12,717 | | |
| Industrial | 10,674 | | | 11,587 | | | 11,673 | | |
| Street lighting and public authority | 442 | | | 491 | | | 513 | | |
| Ameren Illinois Electric Distribution total | 34,021 | | | 36,094 | | | 37,002 | | |
| Eliminate affiliate sales | (322) | | | (84) | | | (288) | | |
| Ameren total | 71,907 | | | 73,629 | | | 80,468 | | |
| Electric Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 1,373 | | | $ | 1,403 | | | $ | 1,560 | | |
| Commercial | 1,025 | | | 1,157 | | | 1,271 | | |
| Industrial | 261 | | | 278 | | | 312 | | |
| Other, including street lighting and public authority | 155 | | | 127 | | | 30 | | (b) |
| Ameren Missouri retail load subtotal | $ | 2,814 | | | $ | 2,965 | | | $ | 3,173 | | |
| Off-system | 170 | | | 144 | | | 278 | | |
| Ameren Missouri total | $ | 2,984 | | | $ | 3,109 | | | $ | 3,451 | | |
| Ameren Illinois Electric Distribution: | | | | | | |
| Residential | $ | 867 | | | $ | 848 | | | $ | 867 | | |
| Commercial | 486 | | | 497 | | | 511 | | |
| Industrial | 124 | | | 127 | | | 130 | | |
| Other, including street lighting and public authority | 21 | | | 32 | | | 39 | | |
| Ameren Illinois Electric Distribution total | $ | 1,498 | | | $ | 1,504 | | | $ | 1,547 | | |
| Ameren Transmission: | | | | | | |
Ameren Illinois Transmission(c) | $ | 329 | | | $ | 288 | | | $ | 267 | | |
| ATXI | 194 | | | 176 | | | 166 | | |
| Ameren Transmission total | $ | 523 | | | $ | 464 | | | $ | 433 | | |
| Other and intersegment eliminations | (94) | | | (96) | | | (92) | | |
| Ameren total | $ | 4,911 | | | $ | 4,981 | | | $ | 5,339 | | |
(a)Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2020, 2019, and 2018, Ameren Illinois procured power on behalf of its customers for 23%, 22%, and 23%, respectively, of its total kilowatthour sales.
(b)Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information.
(c)Includes $52 million, $62 million, and $53 million in 2020, 2019, and 2018, 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, | 2018 | | 2017 | | 2016 | |
| Electric Sales – kilowatthours (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 14,320 |
| | 12,653 |
| | 13,245 |
| |
| Commercial | 14,791 |
| | 14,384 |
| | 14,712 |
| |
| Industrial | 4,499 |
| | 4,469 |
| | 4,790 |
| |
| Street lighting and public authority | 108 |
| | 117 |
| | 125 |
| |
| Ameren Missouri retail load subtotal | 33,718 |
| | 31,623 |
| | 32,872 |
| |
| Off-system | 10,036 |
| | 10,640 |
| | 7,125 |
| |
| Ameren Missouri total | 43,754 |
| | 42,263 |
| | 39,997 |
| |
Ameren Illinois Electric Distribution(a): | | | | | | |
| Residential | 12,099 |
| | 10,985 |
| | 11,512 |
| |
| Commercial | 12,717 |
| | 12,382 |
| | 12,583 |
| |
| Industrial | 11,673 |
| | 11,436 |
| | 11,738 |
| |
| Street lighting and public authority | 513 |
| | 515 |
| | 521 |
| |
| Ameren Illinois Electric Distribution total | 37,002 |
| | 35,318 |
| | 36,354 |
| |
| Eliminate affiliate sales | (288 | ) | | (440 | ) | | (520 | ) | |
| Ameren total | 80,468 |
| | 77,141 |
| | 75,831 |
| |
| Electric Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 1,560 |
| | $ | 1,417 |
| | $ | 1,422 |
| |
| Commercial | 1,271 |
| | 1,208 |
| | 1,224 |
| |
| Industrial | 312 |
| | 305 |
| | 315 |
| |
| Other, including street lighting and public authority | 30 |
| (b) | 111 |
| | 102 |
| |
| Ameren Missouri retail load subtotal | $ | 3,173 |
| | $ | 3,041 |
| | $ | 3,063 |
| |
| Off-system | 278 |
| | 370 |
| | 333 |
| |
| Ameren Missouri total | $ | 3,451 |
| | $ | 3,411 |
| | $ | 3,396 |
| |
| Ameren Illinois Electric Distribution: | | | | | | |
| Residential | $ | 867 |
| | $ | 870 |
| | $ | 895 |
| |
| Commercial | 511 |
| | 527 |
| | 517 |
| |
| Industrial | 130 |
| | 113 |
| | 96 |
| |
| Other, including street lighting and public authority | 39 |
| | 58 |
| | 40 |
| |
| Ameren Illinois Electric Distribution total | $ | 1,547 |
| | $ | 1,568 |
| | $ | 1,548 |
| |
| Ameren Transmission: | | | | | | |
Ameren Illinois Transmission(c) | $ | 267 |
| | $ | 258 |
| | $ | 232 |
| |
| ATXI | 166 |
| | 168 |
| | 123 |
| |
| Ameren Transmission total | $ | 433 |
| | $ | 426 |
| | $ | 355 |
| |
| Other and intersegment eliminations | (92 | ) | | (98 | ) | | (103 | ) | |
| Ameren total | $ | 5,339 |
| | $ | 5,307 |
| | $ | 5,196 |
| |
| |
(a) | Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2018, 2017, and 2016, Ameren Illinois procured power on behalf of its customers for 23% of its total kilowatthour sales. |
| |
(b) | Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information. |
| |
(c) | Includes $53 million, $42 million, and $45 million in 2018, 2017, and 2016, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution. |
| | Electric Operating Statistics – Year Ended December 31, | 2018 | | 2017 | | 2016 | | Electric Operating Statistics – Year Ended December 31, | 2020 | | 2019 | | 2018 | |
Ameren Missouri fuel costs (cents per kilowatthour generated)(a) |
| 1.59 | ¢ | |
| 1.75 | ¢ | |
| 1.79 | ¢ | | Ameren Missouri fuel costs (cents per kilowatthour generated)(a) | 1.38 | ¢ | | 1.38 | ¢ | | 1.59 | ¢ | |
| Source of Ameren Missouri energy supply: | | | | | | | Source of Ameren Missouri energy supply: | |
| Coal | 67.8 | % | | 70.9 | % | | 66.2 | % | | Coal | 67.3 | % | | 63.4 | % | | 67.8 | % | |
| Nuclear | 23.7 |
| | 19.0 |
| | 22.8 |
| | Nuclear | 19.4 | | | 23.3 | | | 23.7 | | |
| Hydroelectric | 2.5 |
| | 3.4 |
| | 3.3 |
| | Hydroelectric | 4.5 | | | 5.0 | | | 2.5 | | |
| Natural gas | 1.0 |
| | 0.7 |
| | 0.7 |
| | Natural gas | 0.5 | | | 0.5 | | | 1.0 | | |
| Methane gas and solar | 0.1 |
| | 0.1 |
| | 0.1 |
| | Methane gas and solar | 0.5 | | | 0.2 | | | 0.1 | | |
| Purchased – Wind | 0.6 |
| | 0.7 |
| | 0.8 |
| | |
| Purchased – Other | 4.3 |
| | 5.2 |
| | 6.1 |
| | |
| Purchased – wind | | Purchased – wind | 0.6 | | | 0.7 | | | 0.6 | | |
| Purchased power | | Purchased power | 7.2 | | | 6.9 | | | 4.3 | | |
| Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % | | Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % | |
(a) Ameren Missouri fuel costs exclude ($49) million, $5 million and $44 million $(35) million,in 2020, 2019, and $5 million,2018, respectively, for changes in FAC recoveries.
| | | | | | | | | | | | | | | | | | | | |
Natural Gas Operating Statistics – Year Ended December 31, | 2020 | | 2019 | | 2018 | |
| Natural Gas Sales – dekatherms (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 7 | | | 7 | | | 7 | | |
| Commercial | 3 | | | 4 | | | 4 | | |
| Industrial | 1 | | | 1 | | | 1 | | |
| Transport | 9 | | | 9 | | | 9 | | |
| Ameren Missouri total | 20 | | | 21 | | | 21 | | |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | 55 | | | 61 | | | 60 | | |
| Commercial | 15 | | | 19 | | | 18 | | |
| Industrial | 7 | | | 4 | | | 4 | | |
| Transport | 96 | | | 101 | | | 100 | | |
| Ameren Illinois Natural Gas total | 173 | | | 185 | | | 182 | | |
| Ameren total | 193 | | | 206 | | | 203 | | |
| Natural Gas Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 76 | | | $ | 81 | | | $ | 90 | | |
| Commercial | 29 | | | 34 | | | 37 | | |
| Industrial | 4 | | | 4 | | | 4 | | |
| Transport and other | 16 | | | 15 | | | 7 | | |
| Ameren Missouri total | $ | 125 | | | $ | 134 | | | $ | 138 | | |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | $ | 541 | | | $ | 570 | | | $ | 581 | | |
| Commercial | 136 | | | 154 | | | 159 | | |
| Industrial | 14 | | | 13 | | | 17 | | |
| Transport and other | 69 | | | 60 | | | 58 | | |
| Ameren Illinois Natural Gas total | $ | 760 | | | $ | 797 | | | $ | 815 | | |
| Other and intercompany eliminations | (2) | | | (2) | | | (1) | | |
| Ameren total | $ | 883 | | | $ | 929 | | | $ | 952 | | |
|
Rate Base Statistics – At December 31, | 2020 | | 2019 | | 2018 | |
| Rate Base (in billions): | | | | | | |
| Electric transmission and distribution | $ | 12.1 | | | $ | 10.7 | | | $ | 9.4 | | |
| Natural gas transmission and distribution | 2.4 | | | 2.1 | | | 1.9 | | |
| Coal generation: | | | | | | |
| Labadie Energy Center | 0.9 | | | 0.9 | | | 0.8 | | |
| Sioux Energy Center | 0.7 | | | 0.6 | | | 0.6 | | |
| Rush Island Energy Center | 0.4 | | | 0.5 | | | 0.4 | | |
| Meramec Energy Center | 0.1 | | | 0.1 | | | 0.2 | | |
| Coal generation total | 2.1 | | | 2.1 | | | 2.0 | | |
| Nuclear generation | 1.5 | | | 1.4 | | | 1.3 | | |
| Renewable generation | 1.0 | | | 0.5 | | | 0.5 | | |
| Natural gas generation | 0.3 | | | 0.4 | | | 0.4 | | |
| Rate base total | $ | 19.4 | | | $ | 17.2 | | | $ | 15.5 | | |
|
| | | | | | | | | | | | |
Natural Gas Operating Statistics – Year Ended December 31, | 2018 | | 2017 | | 2016 | |
| Natural Gas Sales – dekatherms (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 7 |
| | 6 |
| | 6 |
| |
| Commercial | 4 |
| | 3 |
| | 3 |
| |
| Industrial | 1 |
| | 1 |
| | 1 |
| |
| Transport | 9 |
| | 8 |
| | 8 |
| |
| Ameren Missouri total | 21 |
| | 18 |
| | 18 |
| |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | 60 |
| | 50 |
| | 52 |
| |
| Commercial | 18 |
| | 15 |
| | 17 |
| |
| Industrial | 4 |
| | 3 |
| | 3 |
| |
| Transport | 100 |
| | 98 |
| | 94 |
| |
| Ameren Illinois Natural Gas total | 182 |
| | 166 |
| | 166 |
| |
| Ameren total | 203 |
| | 184 |
| | 184 |
| |
| Natural Gas Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 90 |
| | $ | 77 |
| | $ | 77 |
| |
| Commercial | 37 |
| | 31 |
| | 30 |
| |
| Industrial | 4 |
| | 4 |
| | 4 |
| |
| Transport and other | 7 |
| | 14 |
| | 17 |
| |
| Ameren Missouri total | $ | 138 |
| | $ | 126 |
| | $ | 128 |
| |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | $ | 581 |
| | $ | 531 |
| | $ | 530 |
| |
| Commercial | 159 |
| | 146 |
| | 153 |
| |
| Industrial | 17 |
| | 12 |
| | 10 |
| |
| Transport and other | 58 |
| | 54 |
| | 61 |
| |
| Ameren Illinois Natural Gas total | $ | 815 |
| | $ | 743 |
| | $ | 754 |
| |
| Other and intercompany eliminations | (1 | ) | | (2 | ) | | (2 | ) | |
| Ameren total | $ | 952 |
| | $ | 867 |
| | $ | 880 |
| |
| | | | | | | |
Rate Base Statistics – At December 31, | 2018 | | 2017 | | 2016 | |
| Rate Base (in billions): | | | | | | |
| Electric and natural gas transmission and distribution | $ | 11.3 |
| | $ | 10.1 |
| | $ | 9.4 |
| |
| Coal generation | 2.0 |
| | 2.0 |
| | 2.0 |
| |
| Nuclear and renewables generation | 1.8 |
| | 1.9 |
| | 1.8 |
| |
| Natural gas generation | 0.4 |
| | 0.4 |
| | 0.4 |
| |
| Rate base total | $ | 15.5 |
| | $ | 14.4 |
| | $ | 13.6 |
| |
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren’s website (www.ameren.com)(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 along with eXtensible Business Reporting Language (XBRL) 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’ auditAudit and risk committee, human resources committee, nominatingRisk Committee, Human Resources Committee, Nominating and corporate governance committee, finance committee,Corporate Governance Committee, Finance Committee, and nuclearNuclear, Operations and operations committee;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; a code of business conduct applicable to all directors, officers and employees; 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, which could adversely affect our results of operations, financial position, and liquidity.businesses.
We are subject to federal, state, and local regulation. OurThe 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;utilities, including an allowed ROE; the operation of nuclear power plants; the construction and operation of generation, transmission, and distribution facilities; the acquisition, disposal, depreciation and amortization of assets and facilities; the electric transmission system reliability; and wholesale and retail competition. In the planning and management of our operations, we must address the effects of existing and proposed laws and regulations and potential changes in our regulatory frameworks, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities. Significant changes in the nature of the regulation of our businesses, including expiration 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. AnyCertain events thatcould prevent us from recovering our costs in a timely manner or from earning adequate returns on our investments could adversely affect our results of operations, financial position, and liquidity.investments.
The rates that we are allowed to charge for our utility services significantly influence our results of operations, financial position, and liquidity. The electric and natural gas utility industry is highly regulated. The utility rates charged to customers are determined by governmental entities, including the MoPSC, the ICC, and the FERC. Decisions by these entities are influenced by many factors, including the cost of providing service, the prudency of expenditures, the quality of service, regulatory staff knowledge and experience, customer intervention, and economic conditions, as well as social and political views. Decisions made by these governmental entities regarding customer rates are largely outside of our control. We are exposed to regulatory lag and cost disallowances to varying degrees by jurisdiction, which, if unmitigated, could adversely affect our results of operations, financial position, and liquidity. Rate orders are also subject to appeal, which creates additional uncertainty as to the rates that we will ultimately be allowed to charge for our services. From time to time, our regulators may approve trackers, riders, or other recovery mechanisms that allow electric or natural gas rates to be adjusted without a traditional regulatory rate proceeding.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 rates established in those proceedings are primarily based on
historical costs and revenues. Ameren Illinois’ natural gas rates established in those proceedings are based on estimated future costs and revenues. Thus, the rates that we are allowed to charge for utility services may not match our actual costs at any given time.
Rates include an allowed rate of return on investments established by the regulator, including a return at the applicable WACC on invested capital, both debt and equity,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 invested capital,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.
As a result of its participation in performance-based formula ratemaking, Ameren Illinois’ return on equityROE for its electric distribution service and its electric energy-efficiency investments is directly correlated to yields on United States Treasury bonds. Additionally, Ameren Illinois is required to achieve certain performance standards. FailureWith respect to meet these requirements could adversely affect Ameren’s andits natural gas delivery service business, unless extended, Ameren Illinois’ results of operations, financial position, and liquidity.QIP will sunset after December 2023.
Ameren Illinois participateselects to participate in a performance-based formula ratemaking framework established pursuant to the IEIMA for its electric distribution service. Ameren Illinois is allowed to recover itsIllinois’ electric distribution revenue requirement forrevenues are decoupled from sales volumes, which ensures that the electric distribution revenues authorized in a given year, independent of actualregulatory rate review are not affected by changes in sales volumes. Ameren Illinois also has an electric energy-efficiency program rider, which includes a return at the applicable WACC on its program investments that is subject to performance-based formula ratemaking. The ICC annually reviews Ameren Illinois’ rate filings for reasonableness and prudency. If the ICC were to conclude that Ameren Illinois’ costs were not prudently incurred, the ICC would disallow recovery of such costs. The electric distribution service performance-based formula ratemaking framework expires at the end of 2022, if not extended by the legislature, while the decoupling provisions extend beyond the end of formula ratemaking by law.law. If the performance-based formula ratemaking framework is not extended or if Ameren Illinois elects not to participate, Ameren Illinois would then be required to establish future rates through a traditional regulatory rate proceedingreview with the ICC, which might result in rates that do not produce a full or timely recovery of costs or provide for an adequate return on investments and would expose Ameren Illinois’ electric distribution business to the risks described in the immediately preceding risk factor.
The return on equity componentallowed ROE under both formula ratemaking recovery mechanisms is equal tobased on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equityROE for its electric distribution business is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. With respect to electric distribution service, a 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8$10 million change in Ameren’s and Ameren Illinois’ annual net income, based on its 20192021 projected rate base.
Ameren Illinois is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed return on equityROE calculated under the ratemaking formulas. The performance standards applicable to electric distribution service include improvements in service reliability to reduce both the frequency and duration of outages, a reduction in the number of estimated bills, a reduction of consumption from inactive meters, and a reduction in bad debt expense. The electric distribution service regulatory framework provides for return on equityROE penalties up to 38 basis points annually in each year from 2019 through2021 and 2022 if these performance standards are not met. Beginning in 2018, the rider for electricThe allowed ROE on energy-efficiency investments provides for increasescan be increased or decreases ofdecreased up to 200 basis points, todepending on the return on equity.achievement of annual energy savings goals. Any adjustments to the return on equityallowed ROE for energy-efficiency investments will depend on annual performance offor a historical period relative to energy savings goals. In 2020, 2019, and 2018, there were no performance-related basis point adjustments.adjustments that materially affected financial results.
Ameren Illinois plans to invest up to approximately $100 million per year in electric energy-efficiency programs through 2023,2025, and will earn a return on those investments.While the ICC has approved a plan consistent with targets established bythis spending level through 2021, the FEJA.The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs.
The QIP provides Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that are placed in service between regulatory rate reviews. Infrastructure investments under the QIP earn a return at the applicable WACC. Ameren Illinois’ QIP is subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. If the rate impact limitation was met in a particular year, the amount of rate base causing the QIP rate to exceed the limitation would be exposed to regulatory lag until a year when that amount could be recovered under QIP or ifis added to rate base as a part of a regulatory rate review. Upon issuance of a natural gas delivery service rate order, QIP rate base is transferred to base rates and the savings goals would require investment levelsQIP is reset to zero. Without legislative action, the QIP will sunset after December 2023. If the QIP is not extended or there is no other regulatory change, Ameren Illinois will be subject to regulatory lag on its natural gas infrastructure investments that exceed amounts allowed by legislation.are placed in service between regulatory rate reviews, which could adversely affect Ameren Illinois’ results of operations, financial position, and liquidity.
As a result of the election to use the PISA, Ameren Missouri’s electric rates are subject to a rate cap. Failure to align capital investments and expenses under the rate cap will adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
As a result of Ameren Missouri’s decisionelection to participate inuse the PISA, its rate increases are limited to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in the July 2018 MoPSC order. Additionally, Ameren Missouri’s electric base rates, as determined inBoth the July 2018 MoPSC order, are frozen until April 1, 2020. Customer rates under the MEEIA, the FAC,rate cap and the RESRAM riders have not been frozen. PISA election are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.
If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the2.85%rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review willwould be subject to the rate cap. Any deferred overages approved for recovery willwould be recovered in a manner consistent with costs recovered under the PISA. Increased capital investments and operating costs could cause customer rates to exceed the rate cap. In addition, a decrease in off-system sales, which are included in net energy costs, could also contribute to customer rates exceeding the rate cap. Off-system sales are affected by planned and unplanned outages at Ameren Missouri’s energy centers, and by curtailment of generation resulting from unfavorable economic conditions, among other things. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the
amount of deferred overage that would cause customer rates to exceed the2.85%rate cap. A penalty incurred as the result of exceeding the rate cap could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Both the rate cap and PISA election are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.
Ameren and Ameren Illinois may not realize the expected return on their electric transmission investments, which could adversely affect their results of operations, financial position, and liquidity.
Ameren, through ATXI and Ameren Illinois, is investing significant capital resources in electric transmission. These investments are based on the FERC’s regulatory framework and a rate of return on common equity that is currently higher than that allowed by our state commissions. However, the FERC regulatory framework and rate of return are subject to change, including change as a result of existing and future third-party complaints and challenges at the FERC and the new methodology for determining the base return on common equity proposed by the FERC in November 2018. Accordingly, the regulatory framework may be less favorable or the rate of return may be lower in the future, compared with the current regulatory environment and rate of return, all of which may adversely affect Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity. A pending complaint case filed with the FERC in February 2015 could reduce the allowed return on common equity and could require customer refunds. A 50 basis point reduction in the FERC-allowed return on common equity would reduce Ameren’s and Ameren Illinois’ earnings by an estimated $9 million and $5 million, respectively, based on each company’s 2019 projected rate base.
We are subject to various environmental laws. Significant capital expenditures are required to achieve and to maintain compliance with these environmental laws. Failure to comply with these laws could result in the closing of facilities, alterations to the manner in which these facilities operate, increased operating costs, delays and increased costs of building new facilities, or exposure to fines and liabilities.
We are subject to variousOur electric generation, transmission, and distribution operations and natural gas transmission, distribution, and storage operations must comply with a variety of environmental laws that are enforced through statutory and regulatory requirements including statutes and regulations, enforcedpermitting programs implemented by federal, state, and local authorities. The development and operationDepending upon the business activity of electric generation, transmission, and distributionspecific facilities, and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect to environmental laws. Thesesuch laws address emissions,emissions; discharges to water water intake, impacts to air, land,bodies; the storage, handling and water, and chemicaldisposal of hazardous substances and waste handling.materials; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. Ameren is alsoFurther, we are subject to risks from changing or conflicting interpretations of existing laws, modification to existing laws, and new laws.
We are also subject to liability under environmental laws that address the remediation of environmental contamination on property currently or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such properties include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws against us. They could allege injury from exposure to hazardous materials, allege a failure to comply with environmental laws, seek to compel remediation of environmental contamination, or seek to recover damages resulting from that contamination.
The EPA has promulgated environmentalEnvironmental regulations that have a significant impact on the electric utility industry. Over time,industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, 2018,2020, Ameren Missouri’s fossil fuel-firedcoal-fired energy centers represented 16%11% and 32%23% of Ameren’s and Ameren Missouri’s rate base, respectively. RegulationsClean Air Act regulations that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx,mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Clean Water Act regulations govern both water intake and discharges from power plants are regulated underand require evaluation of the Clean Water Act. Such regulationecological and biological impact of our operations and could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, eithercenters. Depending upon the scope of whichmodifications ultimately required by state regulators, these capital expenditures could result in significant capital expenditures.be significant. The management and disposal of coal ash is regulated as a solid waste under the Resource Conservation and Recovery Act and the CCR rule, which will require the closure of our surface impoundments and the installations of dry ash handling systems at several of Ameren Missouri’s coal-fired energy centers. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers.
In January 2011, the 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. The complaint, as amended in October 2013, allegedMissouri alleging that in performing projects at its coal-fired Rush Island coal-fired energy centerEnergy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In the first phase, in January 2017, the district court issued a liability ruling and, in September 2019, entered a final order that required Ameren Missouri to install a flue gas desulfurization system at the projects violated provisionsRush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. There were no fines in the order. In October 2019, Ameren Missouri appealed the district court’s ruling to the United States Court of Appeals for the Eighth Circuit. The district court has stayed implementation of the Clean Air Act and Missouri law. Inmajority of the second phase,requirements of its order while the district court will determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. Hearings on remedy-related issues are scheduled for April 2019.case is under appeal. The ultimate resolution of this matter could have a material
adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Among other things and subject to economic and regulatory considerations, resolution
of this matter could result in increased capital expenditures for the installation of air pollution control equipment, as well as increased operations and maintenance expenses.Based upon engineering studies from October 2019, capital expenditures to comply with the district court’s order for installation of a flue gas desulfurization system at the Rush Island Energy Center are estimated at approximately $1 billion. Further, the flue gas desulfurization system would result in additional operation and maintenance expenses of $30 million to $50 million annually for the life of the energy center. Engineering studies required to develop estimated capital expenditures and estimated additional operation and maintenance expenses for the Labadie Energy Center to comply with the district court’s order will not be undertaken while the case is under appeal.
In 2015, the EPA issuedThe EPA’s Affordable Clean Energy Rule repealed the Clean Power Plan which would have established CO2 emissions standards applicable to existing power plants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In August 2018, the EPA proposed to repeal and replace the Clean Power Planreplaced it with a proposed new rule known as the Affordable Clean Energy Rule, which establishesthat had established emission guidelines for states to follow in developing plans to limit CO2 emissions from power plants. The EPA proposes to useand identified certain efficiency measures as the best system of emission reduction for coal-fired power plants. Weelectric generating units. In January 2021, the United States Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy Rule, and ruled that the EPA had the discretion to consider emission reduction measures that include efficiency measures and generation shifting to lower carbon emissions. Additional litigation including reconsideration by the entire United States Court of Appeals for the District of Columbia Circuit or an appeal to the United States Supreme Court is possible. Regardless of the outcome of such potential legal challenges, the EPA is likely to develop new regulations to address carbon emissions from coal and natural gas electric generating units, which could take years to finalize. At this time, Ameren Missouri cannot predict the outcome of the EPA’s future rulemaking or the outcome of any legal challenges relating toor future rulemakings. As such, future rulemakings, any of which could have an adverse effectthe impact on ourthe results of operations, financial position, and liquidity.liquidity of Ameren and Ameren Missouri is uncertain.
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, increased financing requirements, penalties or fines, or reduced operations of some of Ameren Missouri’s coal-fired energy centers, which, in turn, could lead to increased liquidity 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 rates, 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.
Customers’, legislators’, and regulators’ opinions of us are affected by many factors, including system reliability, implementation of our investment plans, protection of customer information, rates, and media coverage. To the extent that customers, legislators, or regulators have or develop a negative opinion of us, our results of operations, financial position, and liquidity could be adversely affected.
Service interruptions can occur due to failures of equipment as a result of severe or destructive weather or other causes. The ability of Ameren Missouri and Ameren Illinois to respond promptly to such failures can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, our ability to safeguard sensitive customer information and protect our systems from cyber attacks, and other actions can affect customer satisfaction. The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction. Customers’, legislators’, and regulators’ opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation.
If customers, legislators, or regulators have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the returns on common equity we are allowed to earn. Additionally, negative opinions about us could make it more difficult for our utilities 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 federal regulatory compliance and proceedings, which exposes us tocould result in increasing costs and the potential for regulatory penalties and other sanctions.
TheWe are subject to FERC can impose civil penalties of approximately $1.3 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards.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 mandatory 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 $1.3 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 itstheir respective formula ratemaking process, and it can require refunds to customers for previously billed amounts, with interest.
OPERATIONAL RISKS
Our results of operations, financial position, and liquidity have been and are expected to continue to be adversely affected by the international public health emergency associated with the COVID-19 pandemic.
The COVID-19 pandemic continues to be a constantly evolving situation. In 2020, we experienced a net decrease in our sales volumes, an increase in our accounts receivable balances that were past due or that were a part of a deferred payment arrangement, and a decline in our cash collections from customers. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. As a result of the COVID-19 pandemic, measures have been taken by local, state, and federal governments, such as travel bans, quarantines, and shelter-in place orders. Shelter-in-place orders began taking
effect in our service territories in mid-March 2020. These orders generally required individuals to remain at home and precluded or limited the operation of businesses that were deemed nonessential. In mid-May 2020, shelter-in-place orders effective in our service territories began to be relaxed, with individuals allowed to leave their homes and nonessential businesses allowed to begin reopening. However, certain restrictions remain in place that limit individual activities and the operation of nonessential businesses. Additional restrictions may be imposed in the future. Ameren’s business operations are deemed essential and are not directly impacted by the shelter-in-place orders. As a result of the COVID-19 pandemic, economic activity has been disrupted in the service territories of Ameren Missouri and Ameren Illinois. It has also caused disruptions in the capital markets, which could adversely affect our ability to access these markets on reasonable terms and when needed. These disruptions could continue for a prolonged period of time or become more severe.
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. Disruptions to the capital markets as a result of the COVID-19 pandemic could negatively affect our ability to maintain and to expand our businesses. In addition, our credit ratings may be impacted by the economic conditions of the COVID-19 pandemic. The COVID-19 pandemic could lead to events beyond our control, such as further depressed economic conditions or extreme volatility in the debt, equity, or credit markets, and 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 or issue commercial paper.
As a result of the COVID-19 pandemic, we experienced and expect to continue to experience changes to our sales volumes. In 2020, compared to 2019, Ameren Missouri experienced a reduction in commercial and industrial electric sales volumes, partially offset by increased electric sales volumes to higher margin residential customers, excluding the estimated effects of weather and customer energy-efficiency programs. The COVID-19 pandemic will continue to affect Ameren Missouri’s total electric sales volumes and sales volumes by customer class beyond 2020. Assuming a ratable change in Ameren Missouri’s electric sales volumes by month, a 1% change for the calendar year 2021 to residential, commercial, and industrial customers would affect earnings per diluted share by approximately 3 cents, 2 cents, and a half-cent, respectively. The actual change in earnings per diluted share will be affected by the timing of sales volume changes due to seasonal customer rates. Pursuant to the PISA, Ameren Missouri’s electric rates are limited to a 2.85% compound annual growth rate cap. Continued long-term declines in sales volumes, along with increased capital investments and operating costs, could result in Ameren Missouri’s inability to recover amounts exceeding the rate cap. Ameren Illinois also experienced decreases in electric and natural gas sales volumes in 2020. While the revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission businesses are decoupled from changes in sales volumes, changes in sales volumes at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers may affect net income.
Our customers’ payment for our services has been adversely affected by the COVID-19 pandemic, resulting in a decrease to our cash flow from operations. Ameren Missouri suspended disconnections for customer nonpayment and late fees in mid-March 2020, and resumed those activities for commercial and industrial customers in mid-July 2020 and residential customers in early August 2020. Ameren Illinois resumed disconnection activities for commercial and industrial customers for nonpayment in early August 2020 and residential customers in mid-September 2020, with the exception of residential customers classified as low income, expressing a financial hardship, or relying on medical equipment. Disconnections for nonpayment for these and all other residential customers are expected to begin in April 2021, which is after the annual winter moratorium period on disconnections that ends March 31, 2021. Ameren Illinois began the winter moratorium on November 18, 2020, which has historically started at the beginning of December. Ameren Illinois also resumed charging late fees to all customers in late July 2020, following the suspension of both disconnections and late fees for all customers in mid-March 2020. Future regulatory or legislative action could require suspension of customer disconnections and/or late fees, among other things, for an extended period of time. As of December 31, 2020, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 29%, 22%, and 35%, or $133 million, $40 million, and $93 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. As of December 31, 2019, these percentages were 18%, 18%, and 20%, or $75 million, $30 million, and $45 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Pursuant to a June 2020 ICC order, Ameren Illinois’ electric bad debt rider provided for the recovery of bad debt expense in 2020, which reverted to the recovery of bad debt write-offs, net of any subsequent recoveries, in 2021. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri does not expect a material impact to earnings from increases in bad debt expense. While Ameren Missouri is seeking recovery of certain COVID-19 pandemic related costs incurred, net of savings, and forgone customer late revenues, it could be unsuccessful in obtaining regulatory approval to recover them, which may adversely affect Ameren and Ameren Missouri’s results of operations.
In addition, suppliers and contractors may not perform as provided under their contracts. This could cause delays in construction projects, or the performance of necessary maintenance to our electric and natural gas infrastructure, which could lead to failures of equipment that can result in unanticipated liabilities or unplanned outages. Delays in our construction projects could also result in reduced planned capital expenditures and decreased rate base growth.
Also, our businesses depend on skilled professional and technical employees. Our operations could be adversely affected if a large portion of our employees contracted COVID-19 or became quarantined at the same time. This could lead to facility shutdowns and disruptions in the delivery of electricity and natural gas to our customers. In addition, remote working arrangements increase our data security risks, including loss of data related to sensitive customer, employee, financial, and operating system information, through insider or outsider actions.
Ameren cannot predict the extent or duration of the COVID-19 pandemic or its effects on the global, national, or local economy, the capital markets, or its customers, suppliers, business continuity plans, results of operations, financial position, liquidity, planned rate base growth, or sales volumes.
The construction and acquisition of, and capital improvements to, electric and natural gas utility infrastructure, along with Ameren Missouri’s ability to implement its Smart Energy Plan, which is aligned with its 2020 IRP, involve substantial risks. These risks include escalating costs, unsatisfactory performance by the projects when completed, the inability to complete projects as scheduled, cost disallowances by regulators, and the inability to earn an adequate return on invested capital, any of which could result in higher costs and facility closures.
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 $13.9$17.8 billion (Ameren Missouri – up to $7.1$9.3 billion; Ameren Illinois – up to $6.6$8.2 billion; ATXI – up to $0.2 billion) of capital expenditures from 20192021 through 2023. These2025. For additional information on these estimates, include allowance for equity funds used during construction, but do not include any additional wind generation investments by Ameren Missouri beyond the two facilities that Ameren Missouri has agreed to acquire after construction.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 acquire windimplement Ameren Missouri’s Smart Energy Plan, which may include acquisition of generation facilities after they are constructed, is contingent upon many variablesfactors and subject to substantial risks. These variablesfactors include, but are not limited to, the following: project management expertise,expertise; escalating costs and/or shortages for labor, materials, and materials,equipment, including changes to tariffs on materials, reliance on third parties,materials; the ability of suppliers, contractors, and developers to meet contractual commitments timely; changes in the scope and timing of projects; the ability to obtain required regulatory, project, approvals, and permit approvals; the ability to obtain necessary rights-of-way, easements, and transmission connections. Delaysconnections at an acceptable cost in obtaining permits or regulatory approvals, shortages in materials and qualified labor, suppliers and contractors who do not perform as required under their contracts, changes ina timely fashion; unsatisfactory performance by the scope and timing of projects when completed; the inability to earn an adequate return on invested capital; the ability to raise capital on reasonable terms, orterms; and other events beyond our control, could affectincluding construction delays due to weather. With respect to the schedule,transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2020 IRP, factors also include MoPSC approval for the retirement of energy centers and new or continued customer energy-efficiency programs; the cost of wind, solar, and performanceother renewable generation and storage technologies; the ability to qualify for, and use, federal production or investment tax credits; changes in environmental laws or requirements, including those related to carbon emissions; and energy prices and demand.
Any of these projects. There is a risk that an energy center might not be permittedrisks could result in higher costs, the inability to continue to operate if pollution control equipment is not installed by prescribed deadlinescomplete anticipated projects, or does not perform as expected. Should any such pollution control equipment not be installed on time or not perform as expected, Ameren Missouri could be subject to additional costsfacility closures, and to the loss of its investment in the project or facility. All of these project and construction risks could adversely affect our results of operations, financial position, and liquidity.
Our electric generation, transmission, and distribution facilities are subject to operational risks that could adversely affect our results of operations, financial position, and liquidity.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;outages, such as the unplanned outage resulting from non-nuclear operating issues related to the Callaway Energy Center’s generator;
•aging infrastructure that may require significant expenditures to operate and maintain;
disruptions in the delivery of fuel, failure of our fuel suppliers•an energy center that might not be permitted to provide adequate quantitiescontinue to operate if pollution control equipment is not installed by prescribed deadlines or quality of fuel, or lack of adequate inventories of fuel, including ultra-low-sulfur coal used by Ameren Missouri to comply with environmental regulations;does not perform as expected;
•lack of adequate water required for cooling plant operations;
•labor disputes;
•disruptions in the delivery of electricity to our customers;
•suppliers and contractors who do not perform as required under their contracts;
•failure of other operators’ facilities and the effect of that failure on our electric system and customers;
•inability to comply with regulatory or permit requirements, including those relating to environmental laws;
•handling, storage, and disposition of CCR;
•unusual or adverse weather conditions or other natural disasters, including severe storms, droughts, floods, tornadoes, earthquakes, sustained high or low temperatures, icing, solar flares, and electromagnetic pulses;pulses, such as the extremely low temperatures experienced in mid-February 2021;
•the level of wind and solar resources;
•inability to operate wind generation facilities at full capacity resulting from requirements to protect natural resources, including wildlife;
•the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, civil unrest, pandemic health events, including the COVID-19 pandemic, or other similar events;
•accidents that might result in injury or loss of life, extensive property damage, or environmental damage;
•ineffective vegetation management programs;
•cybersecurity risks, including loss of operational control of Ameren Missouri’s energy centers and our transmission and distribution systems and loss of data, including sensitive customer, employee, financial, and operating system information, through insider or outsider actions;
•limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities;
•inability to implement or maintain information systems;
•failure to keep pace with and the ability to adapt to rapid technological change; and
•other unanticipated operations and maintenance expenses and liabilities.
The foregoing risks could affect the controls and operations of our facilities or impede our ability to meet regulatory requirements, which could increase operating costs, increase our capital requirements and costs, reduce our revenues, or have an adverse effect on our liquidity.
Ameren Missouri’s ability to obtain an adequate supply of coal could limit operation of its coal-fired energy centers.
Ameren Missouri owns and operates coal-fired energy centers. About 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 and maintenance, derailments, weather, and supplier financial hardship. Coal suppliers in the Power River Basin are experiencing financial hardship because of a decrease in demand resulting from increased natural gas and renewable energy generation, and the impact of environmental regulations, as well as concerns related to coal-fired generation. These financial hardships have resulted in bankruptcy filings by certain coal suppliers in recent years. As of December 31, 2020, coal inventories for Ameren Missouri were near targeted levels. However, disruptions in the delivery of coal, failure of our coal suppliers to provide adequate quantities or quality of coal, or lack of adequate inventories of coal, including low-sulfur coal used to comply with environmental regulations, could have adverse effects on Ameren Missouri’s electric generation operations. If Ameren Missouri is unable to obtain an adequate supply of coal under existing agreements, it may be required to purchase coal at higher prices or be forced to reduce generation at its coal-fired energy centers, which could adversely affect Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
Ameren Missouri’s ownership and operation of a nuclear energy center creates business, financial, and waste disposal risks.
Ameren Missouri’s ownership of the Callaway energy centerEnergy 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;Energy Center;
•limitations on the amounts and types of insurance available to cover losses that might arise in connection with the Callaway energy centerEnergy Center or other United States nuclear facilities;
•uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway energy centerEnergy Center or any other United States nuclear facilities;
•public and governmental concerns about the safety and adequacy of security at nuclear facilities;
•limited availability of fuel supply and our reliance on licensed fuel assemblies from the one NRC-licensed supplier of Callaway energy center’sEnergy 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 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.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. NRC standards relating to seismic risk require Ameren Missouri to further evaluate the impact of an earthquake on its Callaway energy centerEnergy Center due to its proximity to a fault line, which could require the installation of additional capital equipment.
Our natural gas distribution and storage activities involve numerous risks that may result in accidents and increased operating costs.
Inherent in our natural gas distribution and storage activities are a variety of hazards and operating risks, such as leaks, explosions, mechanical problems and cybersecurity risks, which could cause substantial financial losses.losses, including fines and penalties. In addition, these hazards could result in serious injury, loss of human life, significant damage to property, environmental impacts, and impairment of our operations, which in turn could lead us to incur substantial losses. The location of distribution mains and storage facilities near populated areas, including residential areas, business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. A major domestic incident involving natural gas distribution, and storage systems could lead toresult in additional capital expenditures and/or increased operations and maintenance expenses for us and increased regulation and fines and penalties onof 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 that could adversely affect our results of operations, financial position, and liquidity. Additionally,replacement. Ameren Missouri’s results of operations, financial position, and liquidityMissouri could be adversely affected if an energy center’s costs orit is unable to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center’s retirement are not fully recovered.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 centerEnergy Center began operating in 1984. The age of these energy centers increases the risks of unplanned outages, reduced generation output, and higher maintenance expense. If, at the end of its life, an energy center’s cost has not been fully recovered,Further, Ameren Missouri maywould be adversely affected if the MoPSC does not allow such cost to be recovered in rates. Ameren Missouri may also be adversely affected ifrecovery of the MoPSC does
not allow full or timely recovery ofremaining investment and decommissioning costs associated with the retirement of an energy center.center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. As indicated it its 2020 IRP, Ameren Missouri intends to advance the retirement dates of the Sioux and Rush Island coal-fired energy centers to 2028 and 2039, respectively, which are subject to the approval of a change in the assets’ depreciable lives by the MoPSC in a future regulatory rate review. 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 if the system is properly maintained, its reliability may ultimately deteriorate and negatively affect our ability to serve our customers, which could result in increased costs associated with regulatory oversight. The frequency and duration of customer outages are among the IEIMA performance standards. Any failure to achieve these standards will result in a reduction in Ameren Illinois’ allowed return on equityROE on electric distribution assets. The higher maintenance costs associated with aging infrastructure and capital expenditures for new or replacement infrastructure could cause additional rate volatility for our customers, resistance by our regulators to allow customer rate increases, and/or regulatory lag in some of our jurisdictions, any of which could adversely affect our results of operations, financial position, and liquidity.
Energy conservation, energy efficiency, distributed generation, energy storage, technological advances, and other factors could reduce energy demand from Ameren Missouri’sour customers.
Without a regulatory mechanism to ensure recovery, declines in energy usage could result in an under-recovery of Ameren Missouri’sour revenue requirement or an increase in our customer rates, as the revenue requirement would be spread over less sales volumes, which could adversely affect Ameren and Ameren Missouri’sour results of operations, financial position, and liquidity. Such declines could occur due to a number of factors:factors, including:
Conservation and energy-efficiency programs. Missouri allows for conservation and•customer energy-efficiency programs that are designed to reduce energy demand.
demand;Distributed generation and other energy-efficiency efforts. Ameren Missouri is exposed to declining usage from •energy-efficiency efforts by customers not related to itsour energy-efficiency programs, as well as fromprograms;
•increased customer use of distributed generation sources, such as solar panels and other technologies. Ameren Missouri generates power at utility-scale energy centers to achieve economies of scale and to produce power at a competitive cost. Some distributed generation technologies, which have become more cost-competitive, with decreasing costs expected in the future. The costsfuture, as well as the use of these distributed generation technologies may decline over time to a level that is competitive with that of Ameren Missouri’s energy centers. Additionally, technological advances in energy storage may be coupled with distributed generation totechnologies; and
•macroeconomic factors resulting in low economic growth or contraction within our service territories, which could reduce the demand for our electric utility services. Increased adoptionenergy demand.
Decreased use of these technologies by customers could decrease our revenues if customers cease to use our generation, transmission, and distribution services at current levels. Ameren Missouri might incurresult in stranded costs, which ultimately might not be recovered through rates.
rates, and therefore, could lead to an impairment of assets.Macroeconomic factors. Macroeconomic factors resulting in low economic growth or contraction within Ameren Missouri’s service territories could reduce energy demand.26
We are subject to employee work force factors that could adversely affect our operations.
Our operations are subject to acts of terrorism, cyber attacks, and other intentionally disruptive acts.
Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and information systems may be affected by terrorist activities and other intentionally disruptive acts, including cyber attacks, which could disrupt our ability to produce or distribute our energy products. Within our industry, there have been attacks on energy infrastructure, such as substations and related assets, in the past, and there may be 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 cyber attacks across all industries worldwide. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm resulting from theft or the inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected system. Therefore, a disruption caused by a cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. Insurance might not be adequate to cover losses that arise in connection with these events. In addition, new
regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
FINANCIAL, ECONOMIC, AND MARKET RISKS
Our businesses are dependent on our ability to access the capital markets successfully. We might not have access to sufficient capital in the amounts and at the times needed.
We rely on the issuance of short-term and long-term debt 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 at reasonable terms, or at all, could negatively affect our ability to maintain and to expand our businesses. Events beyond our control, such as depressed economic conditions or extreme volatility in the debt, equity, or credit markets, might create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity, or credit markets, including our ability to draw on bank credit facilities. The unfavorable near-term impacts of the TCJA on our operating cash flows may adversely affect our credit ratings. 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.
Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.
Ameren is a holding company; therefore, its primary assets are its investments in the common stock of its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. As a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s ability to service its debt obligations is dependent upon the earnings of its operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under affiliate indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations, and other items affecting retained earnings, and available cash. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of affiliate borrowing arrangements and cash payments under the tax allocation agreement) to Ameren. Certain financing agreements, corporate organizational documents, and certain statutory and regulatory requirements may impose restrictions on the ability of Ameren Missouri, Ameren Illinois, and ATXI to transfer funds to Ameren in the form of cash dividends, loans, or advances.
Increasing costsCosts associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits could adversely affect our financial position and liquidity.increase.
Ameren offers defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren offershas defined benefit pension plans covering substantially all of its non-union employees and has postretirement benefit plans covering non-union employees hired before October 2015.2015 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 unfunded obligation under its pension and postretirement benefit plans was $481were overfunded by $249 million as of December 31, 2018.2020. 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 Ameren’s assumptions at December 31, 2018,2020, its investment performance in 2018,2020, and its pension funding policy, Ameren expects to make annualaggregate contributions of approximately $20$60 million to $70 million in each ofover the next five years, with aggregate estimated contributions of $200 million.years. Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements are estimated to be 30% and 60%, respectively. These estimates may change with 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. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits could increase our financing needs and otherwise adversely affect our financial position and liquidity.
GENERAL RISKS
Customers’, investors’, legislators’, and regulators’ opinions of us are affected by many factors, including system reliability, implementation of our strategic plan, protection of customer information, rates, media coverage, and environmental, social, and governance practices, as well as actions by other utility companies. Negative opinions developed by customers, investors, legislators, or regulators could harm our reputation.
Service interruptions and facility shutdowns can occur due to failures of equipment as a result of severe or destructive weather or other causes. The ability of Ameren Missouri and Ameren Illinois to respond promptly to such failures can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, our ability to safeguard sensitive customer information and protect our systems from cyber attacks, and other actions can affect customer satisfaction. The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction.
Our ability to successfully execute our strategic plan, including the transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2020 IRP, may affect customers’, investors’, legislators’, and regulators’ opinions and actions. Additionally, negative perceptions or publicity resulting from increasing scrutiny of environmental, social, and governance practices could negatively impact our reputation, investment in our common stock, or our access to capital markets. Customers’, investors’, legislators’, and regulators’ opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation.
If customers, investors, legislators, or regulators have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the ROEs we are allowed to earn, as well as the access to, and the cost of, capital. Additionally, negative opinions about us or other utility companies could make it more difficult for our businesses to achieve
favorable legislative or regulatory outcomes. Negative opinions could also result in sales volume reductions or increased use of distributed generation by our customers. Any of these consequences could adversely affect our results of operations, financial position, and liquidity.
We are subject to employee work force factors that could adversely affect our operations.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. Certain specialized knowledge that focuses on skilled-craft and STEM-related disciplines is required to construct and operate generation, transmission, and distribution assets. Further, a significant portion of our work force is nearing retirement. We are also party to collective bargaining agreements that collectively represent about 48% of Ameren’s total employees. Certain events, such as an aging workforce without adequately trained replacement employees, the mismatch of skill sets to future needs, or any work stoppage experienced in connection with negotiations of collective bargaining agreements, could adversely affect our operations.
Our operations are subject to acts of terrorism, cyber attacks, and other intentionally disruptive acts.
Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and information systems may be affected by terrorist activities and other intentionally disruptive acts, including cyber attacks, which could disrupt our ability to produce or distribute our energy products. There have been attacks on energy infrastructure, such as substations and related assets, in the past, and there may be more attacks in the future as technology becomes more prevalent in energy infrastructure. 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 cyber attacks across all industries worldwide. Cyber attacks could include viruses, malicious or destructive code, phishing attacks, denial of service attacks, ransomware and other ransom-based attacks, improper access by third parties, attacks on email systems, and ransom demands to not expose sensitive data, operational control, or security vulnerabilities specific to our systems, among various other security breaches. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm resulting from theft or the inappropriate release or destruction of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected system. Therefore, a disruption caused by a cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. Insurance might not be adequate to cover losses that arise in connection with these events. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
Our businesses are dependent on our ability to access the capital markets successfully. We might not have access to sufficient capital in the amounts and at the times needed, as well as on reasonable terms.
We rely on the issuance of short-term and long-term debt and equity as significant sources of liquidity and funding for capital requirements not satisfied by our operating cash flow, as well as to refinance existing long-term debt. The inability to raise debt or equity capital on reasonable terms, or at all, could negatively affect our ability to maintain or to expand our businesses. Events beyond our control, such as depressed economic conditions, the COVID-19 pandemic, or extreme volatility in the debt, equity, or credit markets, might create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity, or credit markets, including our ability to draw on bank credit facilities. Any adverse change in our credit ratings could reduce access to capital and trigger collateral postings and prepayments. Such changes could also increase the cost of borrowing and the costs of fuel, power, and natural gas supply, among other things, which could adversely affect our results of operations, financial position, and liquidity.
| |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.PROPERTIES
For information on our principal properties, see the energy center table 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, replacements, or transfers. See also Note 5 – Long-term Debt and Equity Financings and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows the anticipated capability of Ameren Missouri’s energy centers at the time of Ameren Missouri’s expected 20192021 peak summer electrical demand:
demand for all energy centers owned as of December 31, 2020: |
| | | | | | | | | | |
| Primary Fuel Source | Energy Center | Location | Net Kilowatt Capability(a) |
| Coal | Labadie(b) | Franklin County, Missouri | 2,372,000 |
|
| Rush Island(c) | Jefferson County, Missouri | 1,178,000 |
|
| Sioux(c) | St. Charles County, Missouri | 972,000 |
|
| Meramec(b)(c) | St. Louis County, Missouri | 591,000540,000 |
|
| Total coal | | | 5,113,0005,062,000 |
|
| Nuclear | Callaway(d) | Callaway County, Missouri | 1,194,000 |
|
| Hydroelectric | Osage(d) | Lakeside, Missouri | 235,000 |
|
| Keokuk | Keokuk, Iowa | 144,000148,000 |
|
| Total hydroelectric | | | 379,000383,000 |
|
| Pumped-storage | Taum Sauk(d) | Reynolds County, Missouri | 440,000 |
|
Wind(e) | High Prairie | Adair and Schuyler Counties, Missouri | 400,000 | |
Natural gas (CTs) | Audrain(c)(f) | Audrain County, Missouri | 608,000616,000 |
|
| Venice(d) | Venice, Illinois | 492,000495,000 |
|
| Goose Creek | Piatt County, Illinois | 438,000444,000 |
|
| Pinckneyville | Pinckneyville, Illinois | 316,000 |
|
| Raccoon Creek | Clay County, Illinois | 304,000308,000 |
|
| Meramec(b)(d)(e)(c)(g) | St. Louis County, Missouri | 282,000226,000 |
|
| Kinmundy(d) | Kinmundy, Illinois | 210,000 |
|
| Peno Creek(c)(d)(f) | Bowling Green, Missouri | 192,000 |
|
| | | |
| Total natural gas | | | 2,842,0002,807,000 |
|
| Oil (CTs) | Fairgrounds(c) | Jefferson City, Missouri | 55,000 |
|
| MeramecMexico(c) | Mexico, Missouri | 55,000 | |
| Moberly(c) | Moberly, Missouri | 55,000 | |
| Moreau(c) | Jefferson City, Missouri | 55,000 | |
| Total oil | | | 220,000 | |
| Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 8,000 | |
| Solar | O’Fallon | O’Fallon, Missouri | 4,500 | |
| Lambert | St. Louis County, Missouri | 55,0001,000 |
|
| MexicoBJC | Mexico,St. Louis, Missouri | 54,0001,500 |
|
| Total solar | Moberly | Moberly, Missouri | 54,0007,000 |
|
| Moreau | Jefferson City, Missouri | 54,000 |
|
Total oil | | | 272,000 |
|
Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 8,000 |
|
Solar | O’Fallon | O’Fallon, Missouri | 3,000 |
|
| Total Ameren and Ameren Missouri | | | 10,251,00010,521,000 |
|
| |
(a) | Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid. |
| |
(b) | All coal-fueled kilowatts and 236,000 natural-gas-fueled kilowatts at the Meramec energy center are scheduled for retirement in 2022. |
| |
(c) | There are economic development arrangements applicable to these CTs. |
| |
(d) | These CTs have the capability to operate on either oil or natural gas (dual fuel). |
| |
(e) | Two of its three units are steam-powered. |
(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 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, Sioux, and Meramec energy centers are scheduled to retire by 2039, 2028, and 2022, respectively. The retirement dates of the Rush Island and Sioux energy centers are proposed to be advanced from their previous retirement dates of 2045 and 2033, respectively, as part of the 2020 IRP. The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to be retired by 2026 as part of the 2020 IRP. Advancing the retirement date of an energy center is subject to the approval of a change in the assets’ depreciable lives by the MoPSC in a future regulatory rate review.
(d)The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively.
(e)Ameren Missouri acquired the Atchison Renewable Energy Center in January 2021. As of the date of this filing, 120,000 kilowatts were in service. Ameren Missouri expects approximately 150,000 kilowatts of the up-to 300,000-kilowatt project to be in service by the end of the first quarter of 2021, and the remaining portion to be in service later in 2021.
(f)There are economic development arrangements applicable to these CTs, as discussed below.
(g)Its two operating units are steam-powered.
The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2018:2020:
| | | | | | | | | | | |
| Ameren
Missouri | | Ameren
Illinois |
Circuit miles of electric transmission lines(a) | 3,150 | | | 4,662 | |
| Circuit miles of electric distribution lines | 34,122 | | | 46,911 | |
| Percentage of circuit miles of electric distribution lines underground | 24 | % | | 16 | % |
| Miles of natural gas transmission and distribution mains | 3,466 | | | 18,565 | |
| Underground natural gas storage fields | — | | | 12 | |
| Total working capacity of underground natural gas storage fields in billion cubic feet | — | | | 24 | |
|
| | | | | |
| | Ameren Missouri | | Ameren Illinois |
Circuit miles of electric transmission lines(a) | 2,971 |
| | 4,639 |
|
| Circuit miles of electric distribution lines | 33,517 |
| | 45,878 |
|
| Percentage of circuit miles of electric distribution lines underground | 24 | % | | 16 | % |
| Miles of natural gas transmission and distribution mains | 3,422 |
| | 18,417 |
|
| Underground natural gas storage fields | — |
| | 12 |
|
| Total working capacity of underground natural gas storage fields in billion cubic feet | — |
| | 24 |
|
| |
(a) | ATXI owns 408 miles of transmission lines not reflected in this table. |
Our other properties include office buildings, warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all principal energy centers and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bonds and to certain permitted liens and judgment liens). The exceptions are as follows:
A portion of Ameren Missouri’s Osage energy center reservoir, certain facilities at Ameren Missouri’s Sioux energy center, most of Ameren Missouri’s Peno Creek and Audrain CT energy centers, Ameren Missouri’s Maryland Heights energy center, certain substations, and most transmission and distribution lines and natural gas mains are•Certain property is situated on lands occupied under leases, easements, franchises, licenses, or permits. That property includes a portion of Ameren Missouri’s Osage Energy Center reservoir; certain facilities at Ameren Missouri’s Sioux Energy Center; most of Ameren Missouri’s High Prairie Renewable, Atchison Renewable, Peno Creek CT and Audrain CT energy centers; Ameren Missouri’s Maryland Heights, Lambert, and BJC energy centers; certain substations; and most transmission and distribution lines and natural gas mains. The United States or the state of Missouri may own or may have paramount rights with respect to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which certain of Ameren Missouri’s energy centers and other properties are located.
•The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of Ameren Missouri’s Keokuk energy centerEnergy Center is located.
Substantially all of the properties and plant of Ameren Missouri and Ameren Illinois are subject to the liens of the indentures securing their mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek CT energy centerEnergy Center to the city of Bowling Green, Missouri through December 2022. Ameren Missouri has rights and obligations as the operator of the energy center under a long-term agreement with the city of Bowling Green. Under the terms of this agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the agreement, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri first mortgage bond indenture.
Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as the operator of the energy center under a long-term agreement with Audrain County. Under the terms of this agreement, Ameren Missouri is responsible for all operation and maintenance for the energy center. The agreement will expire in December 2023. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the agreement, at which time the property, plant, and equipment will become subject to the lien of the Ameren Missouri first mortgage bond indenture.
In 2018, Ameren Missouri entered into build-transfer agreements to purchase up to 557 megawatts of wind generation. For additional information on these agreements, see Note 2 – Rate and Regulatory Matters under Part II, Item 8 of this report.
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. MaterialFor additional information on material legal and administrative proceedings, which are discussed in 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 and are incorporated herein by reference, include the following: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. the February 2015 complaint case filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff;
the November 2018 FERC order requesting briefs regarding a new methodology for determining the base return on common equity under the MISO tariff and how to apply the new methodology to the February 2015 complaint case and the September 2016 order related to the November 2015 complaint case;
the January 2019 appeal filed by the MoOPC challenging the MoPSC’s December 2018 order in the RESRAM case;
litigation against Ameren Missouri with respect to the EPA Clean Air Act; and
remediation matters associated with former MGP and waste disposal sites of the Ameren Companies.
| |
ITEM 4. | MINE SAFETY DISCLOSURES |
ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):OFFICERS:
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2018,2020, all their positions and offices held with the Ameren Companies as of February 14, 2019,22, 2021, their tenures as officers, and their business backgrounds for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.
AMEREN CORPORATION:
|
| | | | | | | | | | |
| Name | Age | | Positions and Offices Held |
| | | |
| Warner L. Baxter | 5759 |
| | Chairman, President and Chief Executive Officer, and Director |
| Baxter joined Ameren Missouri in 1995. He was elected to the positions of executive vice president and chief financial officer of Ameren, Ameren Missouri, Ameren Illinois, and Ameren Services in 2003. He was elected chairman, president, chief executive officer, and chief financial officer of Ameren Services in 2007. In 2009, he was elected chairman, president, and chief executive officer of Ameren Missouri. In 2014, he was elected chairman, president, and chief executive officer of Ameren, and relinquished his positions at Ameren Missouri. |
| | | |
Martin J. Lyons, Jr.Michael L. Moehn | 5251 |
| | Executive Vice President and Chief Financial Officer |
LyonsMoehn joined Ameren Services in 2001.2000. In 2004, he was elected vice president, corporate planning, of Ameren Services. In 2008, he was elected senior vice president, corporate planning and chief accounting officerbusiness risk management, of the Ameren Companies.Services. In 2009,2012, he was also elected chief financial officersenior vice president, customer operations, of the Ameren Companies.Missouri, and relinquished his position at Ameren Services. In 2013,2014, he was elected chairman and president of Ameren Missouri. In December 2019, he was elected executive vice president and chief financial officer of the Ameren Companies and relinquished his duties as chief accounting officer. In 2016, he was elected chairman and president of Ameren Services.Services and relinquished his positions at Ameren Missouri. |
| | | |
Gregory L. NelsonChonda J. Nwamu | 6149 |
| | Senior Vice President, General Counsel, and Secretary |
NelsonNwamu joined Ameren MissouriServices in 1995. He was electedSeptember 2016 as vice president and tax counsel of Ameren Services in 1999 anddeputy general counsel. In January 2019, she was elected senior vice president of Ameren Missouri and Ameren Illinois in 2003. In 2010, he was elected vice president, tax and deputy general counsel of Ameren Services. He remained vice president of Ameren Missouri and Ameren Illinois. In 2011, heAugust 2019, she was elected senior vice president, general counsel and secretary of the Ameren Companies. Nelson has notifiedPrior to joining Ameren of his intentionServices, she served as regulatory counsel at Pacific Gas and Electric Company, a public utility, from 2000 to retire, effective August 1, 2019. Chonda J. Nwamu, senior vice presidentMay 2014 and deputy general counsel, will succeed Nelson as senior vice president, generalmanaging counsel and secretary, effective upon his retirement.senior director from June 2014 to June 2016. |
| | | |
| Bruce A. Steinke | 5759 |
| | Senior Vice President, Finance, and Chief Accounting Officer |
| Steinke joined Ameren Services in 2002. In 2008, he was elected vice president and controller of Ameren, Ameren Illinois, and Ameren Services. In 2009, he relinquished his positions at Ameren Illinois. In 2013, he was elected senior vice president, finance, and chief accounting officer of the Ameren Companies. |
SUBSIDIARIES:
|
| | | | | | | | | | |
| Name | Age | | Positions and Offices Held |
| | | |
| Bhavani Amirthalingam | 4345 |
| | Senior Vice President and Chief Digital Information Officer (Ameren Services) |
| Amirthalingam joined Ameren Services in March 2018 as senior vice president and chief digital information officer. She served as the chief information officer and vice president North America for Schneider Electric SE, an energy management and automation solutions company, from January 2015 to March 2018 and in various roles at World Wide Technology Inc., a technology solution provider, from November 1999 to January 2015, most recently serving as vice president of customer solutions and innovation from September 2013 to January 2015. |
| | | |
| Mark C. Birk | 5456 |
| | Senior Vice President, Customer and Power Operations (Ameren Missouri) |
Birk joined Ameren Missouri in 1986. In 2005,2004, he was elected vice president, power operations, of Ameren Missouri. In 2012, he was elected senior vice president, corporate planning, of Ameren Services. In 2014, he was also elected senior vice president, oversight, of Ameren Services, and in 2015, he was elected senior vice president, corporate safety, planning and operations oversight. In January 2017, he was elected senior vice president, customer operations, at Ameren Missouri and relinquished his positions at Ameren Services. In October 2017, he was elected senior vice president, customer and power operations, at Ameren Missouri. |
| | | |
| Fadi M. Diya | 5658 |
| | Senior Vice President and Chief Nuclear Officer (Ameren Missouri) |
| Diya joined Ameren Missouri in 2005. In 2008, he was elected vice president, nuclear operations, of Ameren Missouri. In 2014, he was elected senior vice president and chief nuclear officer of Ameren Missouri. |
| | | |
| Mary P. Heger | 6264 |
| | Senior Vice President, Customer Experience (Ameren Illinois) |
Heger joined Ameren Missouri in 1976. In 2009, she was elected vice president, information technology, of Ameren Services, and in 2012,2013, she was also elected chief information officer of Ameren Services. In September 2015, she was elected senior vice president and chief information officer of Ameren Services. In February 2019, she was elected senior vice president, customer experience, at Ameren Illinois.Illinois and relinquished her position at Ameren Services. |
| | | |
| Mark C. Lindgren | 5153 |
| | Senior Vice President, Corporate Communications, and Chief Human Resources Officer (Ameren Services) |
| Lindgren joined Ameren Services in 1998. In 2009, he was elected vice president, human resources, of Ameren Services, and in 2012, he was also elected chief human resources officer of Ameren Services. In September 2015, he was elected senior vice president, corporate communications, and chief human resources officer of Ameren Services. |
| | | |
| Richard J. Mark | 6365 |
| | Chairman and President (Ameren Illinois) |
| Mark joined Ameren Services in 2002 as vice president, customer service. In 2003, he was elected vice president, governmental policy and consumer affairs, of Ameren Services. In 2005, he was elected senior vice president, customer operations, of Ameren Missouri. In 2007, he relinquished his position at Ameren Services. In 2012, he relinquished his position at Ameren Missouri and was elected chairman and president of Ameren Illinois. |
| | | |
Michael L. MoehnMartin J. Lyons, Jr. | 4954 |
| | Chairman and President (Ameren Missouri) |
MoehnLyons joined Ameren Services in 2000. In 2004, he was elected vice president, corporate planning, of Ameren Services.2001. In 2008, he was elected senior vice president corporate planning and business risk management,chief accounting officer of the Ameren Services.Companies. In 2012,2009, he was also elected chief financial officer of the Ameren Companies. In 2013, he was elected seniorexecutive vice president customer operations,and chief financial officer of the Ameren Missouri,Companies, and relinquished his position at Ameren Services.duties as chief accounting officer. In 2014,March 2016, he was elected chairman and president of Ameren Missouri. |
| | | |
Chonda J. Nwamu | 47 |
| | Senior Vice PresidentServices. In December 2019, he was elected chairman and Deputy General Counsel (Ameren Services) |
Nwamu joinedpresident of Ameren Services in September 2016Missouri and relinquished his position as executive vice president and deputy general counsel. In January 2019, she was elected senior vice presidentchief financial officer of the Ameren Companies and deputy general counsel ofhis positions at Ameren Services. Prior to joining Ameren Services, she served as regulatory counsel at Pacific Gas and Electric Company, a public utility, from 2000 to May 2014 and as managing counsel and senior director from June 2014 to June 2016. She will succeed Gregory L. Nelson as senior vice president, general counsel, and secretary effective upon his retirement. |
| | | |
| Shawn E. Schukar | 5759 |
| | Chairman and President (ATXI) |
| Schukar joined a predecessor company of Ameren Illinois in 1984. In 2005, he was elected vice president, commercial RTO operations, of Ameren Services. In 2013, he was elected senior vice president, transmission operations, construction and project management, of ATXI. In May 2017, he was elected chairman and president of ATXI. |
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the executive officers or between any executive officers and any directors of the Ameren Companies. Except as noted, the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
PART II
| |
ITEM 5. | MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES |
ITEM 5.MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 45,57542,072 on January 31, 2019.29, 2021. 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, 2018,2020, to December 31, 2018.2020.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder returnTSR during the five years ended December 31, 2018.2020. The graph also shows the cumulative total returns of the S&P 500 Index, S&P 500 Utility Index, and the Edison Electric InstitutePhiladelphia Utility Index. The S&P 500 Utility Index (EEI Index), which comprises most investor-owned electric utilities inand the United States.Philadelphia Utility Index are market capitalization-weighted indices of U.S. public utility companies. The comparison assumes that $100 was invested on December 31, 2013,2015, 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
| | | December 31, | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | December 31, | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 |
| Ameren (AEE) | $ | 100.00 |
| | $ | 132.73 |
| | $ | 129.58 |
| | $ | 162.84 |
| | $ | 188.82 |
| | $ | 215.22 |
| Ameren (AEE) | $ | 100.00 | | | $ | 125.66 | | | $ | 145.72 | | | $ | 166.09 | | | $ | 200.67 | | | $ | 209.23 | |
| S&P 500 Index | 100.00 |
| | 113.69 |
| | 115.26 |
| | 129.04 |
| | 157.21 |
| | 150.33 |
| S&P 500 Index | 100.00 | | | 111.96 | | | 136.40 | | | 130.43 | | | 171.50 | | | 203.05 | |
| EEI Index | 100.00 |
| | 128.91 |
| | 123.88 |
| | 145.49 |
| | 162.54 |
| | 168.50 |
| |
| S&P 500 Utility Index | | S&P 500 Utility Index | 100.00 | | | 116.29 | | | 130.37 | | | 135.73 | | | 171.50 | | | 172.32 | |
| Philadelphia Utility Index | | Philadelphia Utility Index | 100.00 | | | 117.40 | | | 132.45 | | | 137.11 | | | 173.88 | | | 178.61 | |
Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.
| |
ITEM 6. | SELECTED FINANCIAL DATA |
ITEM 6.SELECTED FINANCIAL DATA
Ameren has early adopted the SEC’s Disclosure Modernization Final Rule, effective February 10, 2021, for Item 301 of Regulation S-K. As such, Item 6 – Selected Financial Data has not been provided.
|
| | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | |
| Ameren: | | | | | | | | | | |
Operating revenues(a) | $ | 6,291 |
| | $ | 6,174 |
| | $ | 6,076 |
| | $ | 6,098 |
| | $ | 6,053 |
| |
Operating income(a)(b) | 1,357 |
| | 1,410 |
| | 1,322 |
| | 1,235 |
| (c) | 1,226 |
| |
| Income from continuing operations | 821 |
| | 529 |
| (d) | 659 |
| | 585 |
| | 593 |
| |
| Income (loss) from discontinued operations, net of taxes | — |
| | — |
| | — |
| | 51 |
| | (1 | ) | |
| Net income attributable to Ameren common shareholders | 815 |
| | 523 |
| | 653 |
| | 630 |
| | 586 |
| |
| Common stock dividends | 451 |
| | 431 |
| | 416 |
| | 402 |
| | 390 |
| |
| Continuing operations earnings per share – basic | 3.34 |
| | 2.16 |
| | 2.69 |
| | 2.39 |
| | 2.42 |
| |
| Continuing operations earnings per share – diluted | 3.32 |
| | 2.14 |
| | 2.68 |
| | 2.38 |
| | 2.40 |
| |
| Common stock dividends per share | 1.8475 |
| | 1.7775 |
| | 1.715 |
| | 1.655 |
| | 1.61 |
| |
| As of December 31: | | | | | | | | | | |
| Total assets | $ | 27,215 |
| | $ | 25,945 |
| | $ | 24,699 |
| | $ | 23,640 |
| | $ | 22,289 |
| |
| Long-term debt, excluding current maturities | 7,859 |
| | 7,094 |
| | 6,595 |
| | 6,880 |
| | 6,085 |
| |
| Total Ameren Corporation shareholders’ equity | 7,631 |
| | 7,184 |
| | 7,103 |
| | 6,946 |
| | 6,713 |
| |
| Ameren Missouri: | | | | | | | | | | |
Operating revenues(a) | $ | 3,589 |
| | $ | 3,537 |
| | $ | 3,524 |
| | $ | 3,609 |
| | $ | 3,553 |
| |
Operating income(a)(b) | 749 |
| | 722 |
| | 725 |
| | 742 |
| (c) | 784 |
| |
| Net income available to common shareholder | 478 |
| | 323 |
| (d) | 357 |
| | 352 |
| | 390 |
| |
| Dividends to parent | 375 |
| | 362 |
| | 355 |
| | 575 |
| | 340 |
| |
| As of December 31: | | | | | | | | | | |
| Total assets | $ | 14,291 |
| | $ | 14,043 |
| | $ | 14,035 |
| | $ | 13,851 |
| | $ | 13,474 |
| |
| Long-term debt, excluding current maturities | 3,418 |
| | 3,577 |
| | 3,563 |
| | 3,844 |
| | 3,861 |
| |
| Total shareholders’ equity | 4,229 |
| | 4,081 |
| | 4,090 |
| | 4,082 |
| | 4,052 |
| |
| Ameren Illinois: | | | | | | | | | | |
Operating revenues(a) | $ | 2,576 |
| | $ | 2,527 |
| | $ | 2,489 |
| | $ | 2,466 |
| | $ | 2,498 |
| |
Operating income(a)(b) | 512 |
| | 569 |
| | 519 |
| | 446 |
| | 425 |
| |
| Net income available to common shareholder | 304 |
| | 268 |
| | 252 |
| | 214 |
| | 201 |
| |
| Dividends to parent | — |
| | — |
| | 110 |
| | — |
| | — |
| |
| As of December 31: | | | | | | | | | | |
| Total assets | $ | 11,319 |
| | $ | 10,345 |
| | $ | 9,474 |
| | $ | 8,903 |
| | $ | 8,204 |
| |
| Long-term debt, excluding current maturities | 3,296 |
| | 2,373 |
| | 2,338 |
| | 2,342 |
| | 2,224 |
| |
| Total shareholders’ equity | 3,774 |
| | 3,310 |
| | 3,034 |
| | 2,897 |
| | 2,661 |
| |
| |
(a) | Amounts for 2017 and 2016 have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. The 2015 and 2014 balances are not revised for this guidance and are not comparative. |
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(b) | Amounts have been revised to reflect the adoption of accounting guidance on the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information. |
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(c) | Includes a $69 million provision recorded for all of the previously capitalized construction and operating license costs relating to the cancelled second nuclear unit at Ameren Missouri’s Callaway energy center. |
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(d) | Includes an increase to income tax expense of $154 million and $32 million as a result of the TCJA at Ameren and Ameren Missouri, respectively. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information. |
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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 which includes– 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.ATXI is constructing MISO-approved electric transmission projects, includingbusiness in the Illinois Rivers and Mark Twain projects, and operates the Spoon River project, which was placed in service in February 2018. Ameren also evaluates competitive electric transmission investment opportunities as they arise.
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 1516 – Segment Information under Part II, Item 8, of this report for further discussion of Ameren’s Ameren Missouri’s, and Ameren Illinois’ Segments.segments.
Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated.eliminated, except as disclosed inNote 13 – Related-party Transactions under Part II, Item 8, of this report. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular and graphical dollar amounts are in millions, unless otherwise indicated.
The following discussion should be read in conjunction with the financial statements contained in this Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Discussion regarding our financial condition and results of operations for the year ended December 31, 2018, including comparisons with the year ended December 31, 2019, is included in Item 7 of our Form 10-K for the year ended December 31, 2019, filed with the SEC on February 28, 2020.
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 share. All references
OVERVIEW
Our core strategy is driven by the following three pillars:
| | | | | | | | | | | | | | | | | |
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| Investing in and operating our utilities in a manner consistent with existing regulatory frameworks | | Enhancing regulatory frameworks and advocating for responsible energy and economic policies | | Creating and capitalizing on opportunities for investment for the benefit of our customers and shareholders |
| We seek to earn competitive returns on investments in our businesses. Accordingly, we remain focused on disciplined cost management and strategic capital allocation. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators, to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned ROEs and allocating capital resources to business opportunities that we expect will provide the most benefit to our customers and offer the most attractive risk-adjusted return potential. | | We seek to partner with our stakeholders, including our customers, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers and shareholders. We believe constructive regulatory frameworks for investment exist at all of our business segments. Accordingly, we expect to earn competitive returns on investments in our businesses and realize timely recovery of our costs in the coming years with the benefits accruing to both customers and shareholders. | | We seek to make prudent investments that benefit our customers. The goal of these investments is to maintain and enhance the reliability of our services, develop cleaner sources of energy, create economic development opportunities in our region, and provide customers with more options and greater control over their energy usage, among other things. By prudently investing in our businesses, we believe that we deliver superior value to both customers and shareholders. |
| | Customer Rates, (¢/KWH)(e) |
| | |
Rate Base ($ in billions)(a) | | Constructive Regulatory Frameworks(c) | | TSR 2015-2020(f) |
| | Segment | Regulatory Framework | | |
| Ameren
Transmission | Formula ratemaking
Allowed ROE is 10.52% | |
| Ameren Illinois
Natural Gas | Future test year ratemaking and QIP, PGA, VBA
Allowed ROE is 9.67% | |
| Ameren Illinois
Electric Distribution | Formula ratemaking
Allowed ROE is 30-year U.S. Treasury + 5.8% | |
| Ameren
Missouri | Historical test year ratemaking and PISA, RESRAM, FAC, MEEIA Allowed ROE is 9.4% - 9.8%(d) | |
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(a) Reflects year-end rate base except for Ameren Transmission, which is average rate base.
(b) Compound annual growth rate.
(c) As of January 2021.
(d) Allowed ROE applicable to electric service.
(e) Average residential electric prices. Source: Edison Electric Institute, “Typical Bills and Average Rates Report” for the 12 months ended June 30, 2020.
(f) Ameren management cautions that the stock price performance shown above should not be considered indicative of future stock price performance.
Key announcements, updates, and regulatory outcomes
The COVID-19 pandemic continues to be a constantly evolving situation. In 2020, we experienced a net decrease in our sales volumes, an increase in our accounts receivable balances that were past due or that were a part of a deferred payment arrangement, and a decline in our cash collections from customers. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. Shelter-in-place orders began taking effect in our service territories in mid-March 2020. These orders generally required individuals to remain at home and precluded or limited the operation of businesses that were deemed nonessential. In early 2020, Ameren began implementing its business continuity plans, and continues to take measures to mitigate the risk of COVID-19 transmission. Actions included restricting travel for employees, implementing work-from-home policies, securing and supplying personal protective equipment, and implementing work practices to protect the safety of our employees and customers. While our business operations were deemed essential and were not directly impacted by the shelter-in-place orders, approximately 65% of our workforce transitioned to remote working arrangements in mid-March 2020. In order to work more effectively in certain areas, a portion of our workforce returned to our work locations in early June 2020 under a phased approach, and, as of the date of this filing, approximately 50% of our workforce continues to work remotely. In mid-May 2020, shelter-in-place orders effective in our service territories began to be relaxed, with fewer restrictions on social activities and nonessential businesses beginning to reopen. However, certain
restrictions remain in place that limit individual activities and the operation of nonessential businesses. Additional restrictions may be imposed in the future. We continue to assess the impacts the pandemic is having on our businesses, including impacts on electric and natural gas sales volumes, liquidity, and bad debt expense, among other things. For further discussion of these and other matters, see Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Mattersunder Part II, Item 8, of this report, and Results of Operations, Liquidity and Capital Resources, and Outlook sections below. In addition, for information regarding Ameren Missouri’s and Ameren Illinois’ suspensions and reinstatement of customer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
In February 2020, the MoPSC issued an order approving a stipulation and agreement allowing Ameren Missouri to earnings per sharedefer and amortize maintenance expenses related to scheduled refueling and maintenance outages at its Callaway Energy Center. Maintenance expenses associated with the fall 2020 refueling and maintenance outage were deferred as a regulatory asset. Amortization of those expenses began in January 2021, and will be amortized until the completion of the next refueling and maintenance outage. During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was conducted. Work has begun to replace certain key components of the generator in order to return the energy center to service. Ameren Missouri expects generator repairs of $65 million, which are based on average diluted common shares outstandingexpected to be largely capital expenditures. Due to the long lead time for the relevant period.
OVERVIEW
Ameren’s strategic plan includes investing in,manufacture, repair, and operating its utilities in, a manner consistent with existing regulatory frameworks, enhancing those frameworks, and advocating for responsibleinstallation of the components, the energy and economic policies, as well as creating and capitalizing on opportunities for investment for the benefit of its customers and shareholders. Ameren remains focused on disciplined cost management and strategic capital allocation. As discussed below, Ameren successfully executed on its strategic plan in 2018, with constructive outcomes received in various regulatory proceedings. With the enactment of legislation in Missouri, we believe constructive regulatory frameworks for investment exist at all of Ameren's utility businesses. In February 2019, Ameren Missouri announced its Smart Energy Plan to upgrade the electric grid and accommodate more renewable energy. In addition, Ameren Missouri advanced its transition of generation to a cleaner, more diverse portfolio by entering into two build-transfer agreements for the acquisition of up to 557 megawatts of wind generation in Missouri.
In 2018, Ameren’s utility businesses each received orders to reduce customer rates to reflect the benefits of a lower federal tax rate and, over time, to reflect the return of excess deferred taxes of over $2 billion. The return of excess deferred taxes to customers reduces operating cash flows butcenter is expected to increasereturn to service in late June or early July 2021. See Note 9 – Callaway Energy Center under Part II, Item 8, of this report for additional information.
In March 2020, the rate base on which customer rates are established.
In June 2018, legislation was enactedMoPSC issued an order in Missouri that enhanced Ameren Missouri’s July 2019 electric service regulatory framework. Pursuant rate review, approving nonunanimous stipulation and agreements. The order resulted in a decrease of $32 million to its PISA election,Ameren Missouri’s annual revenue requirement for electric retail service, which reflected infrastructure investments as of December 31, 2019. The order also provided for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, and certain excess deferred income taxes that the MoPSC previously authorized in earlier electric rate orders. In addition, the order required Ameren Missouri is permitted to defer and recover 85%donate $8 million to low-income assistance programs, which was reflected in results of operations in the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, and all approved PISA deferrals will be added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. PISA mitigates the impacts of regulatory lag between regulatory rate reviews. The remaining 15% of certain property, plant, and equipment placed in service and not eligible for recovery under PISA, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions of the new law apply to Ameren Missouri, including limitations on electric customer rate increases and an electric base rate freeze until April 2020. Both the rate increase limitation and PISA are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. This Missouri law maintains strong MoPSC oversight and consumer protections while supporting Ameren Missouri’s ability to strengthen and modernize Missouri’s electric grid.
In the secondfirst quarter of 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Terra-Gen, LLC to acquire, after construction, a 400-megawatt wind generation facility, which is expected to be located in northeastern Missouri. 2020.The new rates became effective on April 1, 2020.
In October 2018,August 2020, the MoPSC issued an order approving a unanimous stipulation and agreement regarding a requested certificatewith respect to the 2022 program year of convenienceAmeren Missouri’s six-year MEEIA 2019 program and necessityrelated performance incentives. The order also approved Ameren Missouri’s energy savings results for the facility. In December 2018,first year of the MEEIA 2019 program. As a result of this order and in accordance with revenue recognition guidance, Ameren Missouri received FERC approval to acquire the facility after construction. A transmission interconnection agreement with the MISO for this facility is expectedrecognized revenues of $6 million in the fallthird quarter of 2019. Also, in October 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of EDF Renewables, Inc. to acquire, after construction, a wind generation facility of up to 157 megawatts. 2020.
In February 2019,September 2020, Ameren Missouri filed its 2020 IRP with the MoPSC a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. The up to 157-megawatt facility is expected to be located in northwestern Missouri. A transmission interconnection agreementMoPSC. In connection with the MISO for this facility2020 IRP filing, Ameren established a goal of achieving net-zero carbon emissions by 2050. Ameren is expected in early 2020. Both facilities are expected to be completedalso targeting a 50% CO2 emission reduction by 2030 and an 85% reduction by 2040 from the end of 2020 and would help Ameren Missouri comply with the Missouri renewable energy standard. Each acquisition2005 level. The plan, which is subject to certain conditions, including entering into a MISO transmission interconnection agreement at an acceptable cost for each facility and obtaining FERC approval and the issuance of a certificate of convenience and necessityreview by the MoPSC for the up to 157-megawatt facility, as well as other customary contract termscompliance with Missouri law, targets cleaner and conditions. These agreements collectively represent approximately $1 billionmore diverse sources of energy generation, including solar, wind, hydro, and nuclear power, and supports increased investment in capital expenditures expected in 2020, which is included in Ameren Missouri’s Smart Energy Plan. As outlined in its 2017 IRP, Ameren Missouri is pursuing at least 700 megawattsnew energy technologies. It also includes expanding renewable sources by adding 3,100 MWs of windrenewable generation by the end of 2020. 2030 and a total of 5,400 MWs of renewable generation by 2040. These amounts include the 700 MWs of wind generation projects discussed below, which will support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources beginning in 2021. The plan also includes advancing the retirement dates of the Sioux and Rush Island coal-fired energy centers to 2028 and 2039, respectively, which are subject to the approval of a change in the assets’ depreciable lives by the MoPSC in a future regulatory rate review, the continued implementation of customer energy-efficiency programs, and the expectation that Ameren Missouri will seek NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date. Additionally, the plan includes retiring the Meramec and Labadie coal-fired energy centers at the end of their useful lives (by 2022 and 2042, respectively).
In October and December 2018,2020, Ameren Missouri filed requests with the MoPSC for accounting authority orders related to its electric and natural gas services. If issued as requested, the orders approving a RESRAM that allowswould allow Ameren Missouri to adjustaccumulate certain costs incurred related to the COVID-19 pandemic, including bad debt write-offs, net of cost savings, as well as forgone customer rates on an annual basis withoutlate fee and reconnection fee revenues, for a traditionalspecified time period, for potential recovery in future electric and natural gas service regulatory rate review.reviews. Costs incurred, net of savings, and forgone customer late fee and reconnection fee revenues related to the COVID-19 pandemic from March 2020 through December 2020 were immaterial. The RESRAMMoPSC is designedunder no deadline to mitigateissue orders, and Ameren Missouri cannot predict the impactsultimate outcome of these regulatory lagproceedings.
In December 2020, Ameren Missouri acquired a 400-MW wind generation project located in northeastern Missouri for approximately $615 million, and placed the costassets in service as the High Prairie Renewable Energy Center. In January 2021, Ameren Missouri acquired an up-to 300-MW wind generation project located in northwestern Missouri. At the date of compliancethis filing, Ameren Missouri placed 120 MWs in service as the Atchison Renewable Energy Center, with renewable energy standards, including recoverya purchase price of investmentsapproximately $200 million. There have been changes to the schedule
for this project, particularly as a result of component delivery delays. Ameren Missouri expects approximately 150 MWs of the up-to 300-MW project to be in windservice by the end of the first quarter of 2021, and other renewable generation, by providing more timely recovery of costs and a return on investments not already provided forthe remaining portion to be in customer rates or recovered under PISA.service later in 2021.
In February 2019,2021, Ameren Missouri announcedfiled 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 2019,2021. The plan is designed to upgrade Ameren Missouri'sMissouri’s electric infrastructure. The planinfrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $6.3$8.4 billion over the five-year period from 20192021 through 2023,2025, with costsexpenditures largely recoverable under the PISA and for the portion of wind and other renewable generation investments that are not recoverable under PISA, recoverable under the RESRAM. The planned investments in 2024 and 2025 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028.
In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65 million per year through 2021. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100% of the goals are achieved during the period ended December 2021. Additional revenues may be earned if Ameren Missouri exceeds 100% of its energy savings goals.
In April 2018, Ameren Illinois filed its annual electric distribution service formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In November 2018,2020, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $72$49 million increasedecrease in Ameren Illinois’ electric distribution service rates beginning in January 2019.2021. This order reflected a decrease to the annual formula rate based on 2019 actual costs, a decrease to include the 2019 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2018 revenue requirement reconciliation adjustment, which was fully collected from customers in 2020, consistent with the ICC’s December 2019 annual update filing order. It also reflected an increase based on expected net plant additions for 2020.
In November 2018,January 2021, the ICC issued an order approving a stipulation and agreement thatin Ameren Illinois’ February 2020 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas rate increasedelivery service of $32$76 million, based on a 9.87% return on common equity,9.67% allowed ROE, a capital structure composed of 50%52% common equity, and a rate base of $1.6$2.1 billion. This increase reflects the reduction in the federal statutory corporate income tax rate enacted under the TCJA, as well as the increase in the Illinois corporate income tax rate thatThe new rates became effective in July 2017, which collectively decreased annual rates by approximately $17 million. The new customer rates were effective in November 2018.January 2021. As a result of this order, the rate base under the QIP rider was reset to zero. Ameren Illinois used a 20192021 future test year in this proceeding.
ATXI’s Spoon River project, located in northwest Illinois, was placed in service in February 2018. Construction of the Illinois Rivers project is substantially complete, with the last section awaiting the outcome of certain legal proceedings, which will delay the expected completion date to 2020. This delay is not expected to materially affect 2019 rate base or earnings. Construction activities for ATXI’s Mark Twain project began in the second quarter of 2018, and the project is expected to be completed by the end of 2019.
In October 2018,2020, Ameren’s board of directors increased the quarterly common stock dividend to 47.551.5 cents per share. In February 2021, the board increased the quarterly common stock dividend to 55 cents per share, resulting in an annualized equivalent dividend rate of $1.90$2.20 per share.
Earnings
Net income attributable to Ameren common shareholders was $815$871 million, or $3.32$3.50 per diluted share, for 2018,2020, and $523$828 million, or $2.14$3.35 per diluted share, for 2017.2019. Net income was favorably affected in 20182020, compared with 20172019, by the absenceresults of a noncash charge toAmeren Missouri’s March 2020 electric rate order; infrastructure investments that drove higher earnings for the revaluation of deferred taxes, primarily at Ameren (parent) as a result of federal and Illinois tax law changes, and by increased demand at Ameren Missouri, primarily due to warmer summer and colder winter temperatures in 2018. Earnings were also
favorably affected in 2018 compared with 2017 by an increase in base rates and a reduction in operating expenses for net energy costs and other expenses subject to regulatory tracking mechanisms at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order, by the absence of a Callaway energy center scheduled refueling and maintenance outage at Ameren Missouri, and by increased investments in infrastructure at theTransmission, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas; and increased Ameren Transmission segments. Net income was unfavorably affectedearnings resulting from the May 2020 FERC order addressing the allowed base ROE. Earnings in 2018,2020, compared with 20172019, were also favorably affected by increasedlower other operationoperations and maintenance expenses not subject to riders or regulatory tracking mechanisms,trackers, primarily due to higher-than-normal energy centerthe absence in 2020 of expenses related to the Callaway Energy Center’s 2019 scheduled outagerefueling and maintenance outage; and by lower electric distributionsystem infrastructure maintenance expenses as a result of decreased system load, disciplined cost management, and the deferral of projects to future periods. Net income was unfavorably affected in 2020, compared with 2019, by decreased electric retail sales at Ameren Missouri largely due to the COVID-19 pandemic, and due to milder summer and warmer winter temperatures in 2020; higher net financing costs at Ameren Missouri and by increased depreciation and amortization expensesAmeren (parent); lower revenues due to reduced MEEIA performance incentives at Ameren Missouri.Missouri; and a lower recognized ROE at Ameren Illinois Electric Distribution.
Liquidity
At December 31, 2018,2020, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.5$1.9 billion. In December 2018, the Credit Agreements were extended and now mature in December 2022.
In 2018, Ameren continued to make significant investment in its utility businesses by makingremains focused on strategic capital allocation. The following chart presents 2020 capital expenditures by segment and the midpoint of $0.9 billion, $0.6 billion, $0.5 billion, and $0.3 billion projected cumulative capital expenditures for 2021 through 2025 by segment:
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2020 Capital Expenditures by Segment (Total Ameren – $3.2 billion) (in billions) | | Midpoint of 2021 – 2025 Projected Capital Expenditures by Segment (Total Ameren – $17.1 billion) (in billions) |
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri(a) | | | Ameren Illinois Natural Gas | |
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| | Ameren Illinois Electric Distribution | | | Ameren Transmission | |
(a)Ameren Missouri Ameren Transmission, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. capital expenditures include $564 million for the acquisition of the High Prairie Renewable Energy Center for the year ended December 31, 2020.
For 20192021 through 2023,2025, Ameren’s cumulative capital expenditures are projected to range from $12.8$16.4 billion to $13.9$17.8 billion. The following table presents the range of projected spending by segment includes up to $7.1 billion, $2.7 billion, $2.5 billion, and $1.6 billion for Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively, including approximately $1 billion to acquire twosegment:
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| | Range (in billions) |
Ameren Missouri(a) | | $ | 8.7 | | – | $ | 9.3 | |
| Ameren Illinois Electric Distribution | | 2.6 | | – | 2.8 | |
| Ameren Illinois Natural Gas | | 1.7 | | – | 1.8 | |
| Ameren Transmission | | 3.5 | | – | 3.8 | |
Ameren(a) | | $ | 16.4 | | – | $ | 17.8 | |
(a)Amounts include 300 MWs of wind generation facilitiesat the Atchison Renewable Energy Center, but exclude incremental renewable generation investment opportunities of 1,200 MWs by 2025, which are included in Ameren Missouri’s 2020 at Ameren Missouri.IRP.
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Economic conditions, including those resulting from the COVID-19 pandemic discussed below, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by nuclear refueling and other energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing, and our pension and postretirement benefits costs. Almost all of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the pricesrates 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, withinwith the frameworks established by our regulators. Our 2018 revenues includeSee 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.
We continue to assess the impacts of the COVID-19 pandemic on our businesses, including impacts on electric and natural gas sales volumes, supply chain operations, and bad debt expense. Ameren Missouri and Ameren Illinois suspended customer disconnections and late
fee charges for nonpayment in mid-March 2020 and began resuming these activities, with certain exceptions, in the third quarter of 2020. For additional information on Ameren Missouri’s and Ameren Illinois’ reinstatement of customer disconnection and late fee charges for non-payment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. With respect to uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Pursuant to a reductionJune 2020 ICC order, Ameren Illinois’ electric bad debt rider provided for the recovery of bad debt expense in 2020, which reverted to the recovery of bad debt write-offs, net of any subsequent recoveries, in 2021. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri does not expect a material impact to earnings from 2017increases in bad debt expense. In October 2020, Ameren Missouri filed requests with the MoPSC for accounting authority orders related to certain impacts resulting from the COVID-19 pandemic. If issued as requested, the orders would allow Ameren Missouri to accumulate certain costs incurred related to the COVID-19 pandemic, including bad debt write-offs, net of cost savings, as well as forgone customer late fee and reconnection fee revenues, for a specified time period, for potential recovery in future electric and natural gas service regulatory rate reviews.As of December 31, 2020, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 29%, 22%, and 35%, or $133 million, $40 million, and $93 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. As of December 31, 2019, these percentages were 18%, 18%, and 20%, or $75 million, $30 million, and $45 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. Ameren Missouri’s electric sales volumes have been, and continue to be, affected by the pass-throughCOVID-19 pandemic. In 2020, compared to customers of reduced income taxes resulting from TCJA, which is substantially offset by2019, Ameren Missouri experienced a reduction in income tax expense.commercial and industrial electric sales volumes, partially offset by increased electric sales volumes to higher margin residential customers, excluding the estimated effects of weather and customer energy-efficiency programs. For 2021, Ameren Missouri expects gradual improvement in economic activities to result in increased electric sales volumes, excluding the estimated effects of weather and customer energy-efficiency programs. The table below provides the increases and (decreases) in Ameren Missouri electric sales volumes by customer class for 2020, compared to 2019, and the estimated increases and (decreases) for 2021, compared to 2020, excluding the estimated effects of weather and customer energy-efficiency programs:
| | | | | | | | | | | | | | | | | | |
| | | | | | 2020 versus 2019 | | Estimated 2021 versus 2020 |
| Ameren Missouri Customer Class | | | | | | | | |
| Residential | | | | | | | | 3.0 | % | | 1 | % |
| Commercial | | | | | | | | (7.0) | % | | 2 | % |
| Industrial | | | | | | | | (2.1) | % | | 3 | % |
| Total | | | | | | | | (2.2) | % | | 2 | % |
| | | | | | | | | | |
Assuming a ratable change in Ameren Missouri’s electric sales volumes by month, a 1% change for the calendar year 2021 to residential, commercial, and industrial customers would affect earnings per diluted share by approximately 3 cents, 2 cents, and a half-cent, respectively. The actual change in earnings per diluted share will be affected by the timing of sales volume changes due to seasonal customer rates.
Ameren Missouri principally uses coal and nuclear fuelenriched 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, and many other factors. As described below, weWe 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.
Ameren Missouri’s electric service and natural gas distribution service rates are established in a traditional regulatory rate review based on a historical test year and an allowed return on equity. To mitigate the effects of regulatory lag, Ameren Missouri has recovery mechanisms in place for certain costs that allow customer rates to be adjusted without a traditional regulatory rate review. Ameren Missouri’s FAC cost recovery mechanism 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, with the remaining 5% of changes retained by Ameren Missouri. Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the related lost electric margins, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional regulatory rate review. Ameren Missouri also has a cost recovery mechanism for natural gas purchased on behalf of its customers. 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. Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a tracker on certain excess deferred taxes, a renewable energy standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability. The difference will be reflected in base rates in a subsequent MoPSC rate order. Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of renewable generation plant placed in service not recovered under PISA. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Missouri’s PISA election and the RESRAM.
Ameren Illinois’ electric distribution service rates are reconciled annually to its actual revenue requirement and allowed return on equity, under a formula ratemaking process effective through 2022. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years. In addition, Ameren Illinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for both its electric distribution service and its electric energy-efficiency investments, the revenue requirements are based on recoverable costs, year-end rate base, a capital structure of 50% common equity, and a return on equity. The return on equity component is equal to the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity for its electric distribution business is directly correlated to the yields on such bonds.
Ameren Illinois’ natural gas distribution service rates are established in a traditional regulatory rate review based on a future test year and allowed return on equity. Ameren Illinois employs a VBA to ensure recoverability of the natural gas distribution service revenue requirement for residential and small nonresidential customers that is dependent on sales volumes. 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 normalized sales volumes approved by the ICC in a previous regulatory rate review. In addition, the QIP rider provides Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews.
Ameren Illinois also has recovery mechanisms in place for certain costs that allow customer rates to be adjusted without a traditional regulatory rate review. Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers, renewable energy credit compliance, and zero emission credits. Ameren Illinois’ natural gas business has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through costs do not affect Ameren Illinois’ electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expenses and costs of certain asbestos-related claims not recovered in base rates.
FERC’s electric transmission 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 return on equity. Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These rates are updated each January with forecasted information. 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. The regulatory balance is collected from, or refunded to, customers within two years. The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
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'sMissouri’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, 2018, 2017,2020 and 2016:2019: |
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Net income attributable to Ameren common shareholders | $ | 815 |
| | $ | 523 |
| | $ | 653 |
|
| Earnings per common share – diluted | 3.32 |
| | 2.14 |
| | 2.68 |
|
2018 versus 2017 | | | | | | | | | | | |
| 2020 | | 2019 |
| Net income attributable to Ameren common shareholders | $ | 871 | | | $ | 828 | |
| Earnings per common share – diluted | 3.50 | | | 3.35 | |
| | | |
| | | |
| | | |
Net income attributable to Ameren common shareholders in 20182020 increased $292$43 million, or $1.18$0.15 per diluted share, from 2017.2019. The increase was due to net income increases of $155$31 million, $24$15 million, and $10 million, and $5 million at Ameren Missouri, Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Illinois Electric Distribution,Missouri, respectively. Additionally,The increases in net income were partially offset by an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent), decreased $98 of $10 million and a decrease in net income at Ameren Illinois Electric Distribution of $3 million.
Earnings per share in 2020, compared with 2017, 2018 earnings per share2019, were favorably affected by:
the absence•lower base level of a noncash charge to earnings, primarily at Ameren (parent), for the revaluation of deferred taxes recorded in 2017, as a
result of a decrease in the federal statutory corporate income tax rate under the TCJA and an increase in the Illinois corporate income tax rate,expenses, partially offset by a noncash charge for updates to the revaluation of deferred taxes recorded in 2018 (64 cents per share);
increased demand in 2018 at Ameren Missouri, primarily due to warmer summer and colder winter temperatures in 2018 (estimated at 42 cents per share);
increasedlower base rates, net of recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs and reduced operating expenses for net energy costs and other expenses subject to regulatory tracking mechanismsrecoverable depreciation under the PISA, at Ameren Missouri pursuant to the MoPSC’s March 20172020 MoPSC electric rate order (9as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report (23 cents per share);
•increased rate base investments, which increased earnings at Ameren Transmission and Ameren Illinois Electric Distribution, including energy-efficiency investments at Ameren Illinois (14 cents per share);
•decreased Callaway Energy Center scheduled refueling and maintenance expenses, due to the absencetreatment of a Callaway energy centerthe 2019 scheduled refueling and maintenance outage in 2018,costs at the Callaway Energy Center, which last occurred inwere expensed as incurred, as compared with the fourth quarterdeferral of 2017, partially offset by preparation costs incurred in 2018expenses for the 2019fall 2020 scheduled refueling and maintenance outage (9pursuant to the February 2020 MoPSC order, which decreased other operations and maintenance expenses (10 cents per share);
•decreased system load, disciplined cost management, the deferral of projects to future periods, and decreased other costs not recoverable under riders or trackers, excluding decreased costs associated with the Callaway Energy Center’s scheduled refueling and maintenance outage, which decreased other operations and maintenance expenses (10 cents per share);
•the result of the May 2020 FERC order addressing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which increased Ameren Transmission earnings under formula ratemaking, primarily due to additional investment (8(4 cents per share); and
•increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional investment and a higher return on equity (5 cents per share);
increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP, rider andwhich increased base rates pursuant to the ICC’s November 2018 gas rate order (5earnings at Ameren Illinois Natural Gas (4 cents per share);.
decreased property taxes at Ameren Missouri due to lower assessed property values (5 cents per share);
decreased financing costs, primarily at Ameren Missouri, due to lower interest rates and higher levels of the allowance for funds used during construction (3 cents per share); and
the recognition of a MEEIA 2016 performance incentive in 2018 at Ameren Missouri (3 cents per share).
Compared with 2017, 2018 earningsEarnings per share in 2020, compared with 2019, were unfavorably affected by:
increased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily due to higher-than-normal energy center scheduled outage and electric distribution maintenance costs•lower MEEIA performance incentives recognized at Ameren Missouri (19(9 cents per share) and due to changes in the market value of company-owned life insurance (7 cents per share);
•increased donationsnet financing costs at Ameren (parent) and Ameren Missouri, primarily due to higher long-term debt balances (9 cents per share);
•decreased electric retail sales, excluding the estimated effects of weather, at Ameren Missouri, largely due to the COVID-19 pandemic, which decreased sales volumes and demand charge revenue from commercial and industrial customers, partially offset by increased sales volumes to higher margin residential customers (8 cents per share);
•the impact of weather on electric retail sales at Ameren Missouri, primarily resulting from milder summer and warmer winter temperatures experienced in 2020 (estimated at 7 cents per share);
•a lower recognized ROE at Ameren Illinois Electric Distribution under performance-based formula ratemaking driven by lower annual average monthly yields on 30-year United States Treasury bonds (7 cents per share);
•increased charitable donations, primarily at Ameren Missouri, which included an increase of 2 cents per share pursuant to its March 2020 electric rate order (4 cents per share);
•decreased electric margins from transmission services, and customer late fees and reconnection fees at Ameren Missouri, largely due to the COVID-19 pandemic (3 cents per share);
•decreased income tax benefits at Ameren (parent) related to stock-based compensation (3 cents per share);
•increased depreciation and amortization expenses not subject torecoverable under riders or regulatory tracking mechanisms, primarilytrackers at Ameren Missouri, resulting fromprimarily due to additional electric property, plant, and equipment (7investments (2 cents per share); and
the dilutive effect of issuing•increased weighted-average basic common stockshares outstanding (2 cents per share).
The cents per share information presented is based on the weighted-average basic shares outstanding in 20172019 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 20182020 statutory tax rate of 27%26%.
2017 versus 2016
Net income attributable to Ameren common shareholders in 2017 decreased $130 million, or $0.54 per diluted share, from 2016. The decrease was due to an increase in net loss of $125 million for activity not reported as part of a segment, primarily at Ameren (parent), and a net income decrease of $34 million at Ameren Missouri, both of which were primarily due to the enactment of the TCJA. The decrease was partially offset by a $23 million and a $5 million increase in net income from Ameren Transmission and Ameren Illinois Electric Distribution, respectively.
Compared with 2016, 2017 earnings per share were unfavorably affected by:
an increase in income tax expense, primarily at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decrease in the federal statutory corporate income tax rate due to enactment of the TCJA (63 cents per share) and an increase in the Illinois corporate income tax rate (6 cents per share);
decreased demand primarily at Ameren Missouri due to milder winter and summer temperatures in 2017 (estimated at 15 cents per share);
the absence in 2017 of a MEEIA 2013 performance incentive at Ameren Missouri recognized in 2016 (7 cents per share);
increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri resulting from additional electric property, plant, and equipment (6 cents per share); and
increased transmission services charges at Ameren Missouri resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities (2 cents per share).
Compared with 2016, 2017 earnings per share were favorably affected by:
an increase in base rates, net of increased revenues in 2016 from the suspension of operations at the New Madrid Smelter, and reduced operating expenses for net energy costs and other expenses subject to regulatory tracking mechanisms at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order (32 cents per share);
increased Ameren Transmission earnings under formula ratemaking, primarily due to additional investment, partially offset by a lower recognized return on equity (9 cents per share);
increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional investment and a higher recognized return on equity (4 cents per share); and
decreased income tax expense, excluding the effect of corporate income tax rate changes discussed above, primarily at Ameren (parent) resulting from changes in the valuation allowance for charitable contributions, tax benefits related to company-owned life insurance, and tax credits in 2017, partially offset by a lower income tax benefit in 2017 related to stock-based compensation compared with 2016 (1 cent per share).
The cents per share information presented is based on the weighted-average basic shares outstanding in 2016 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 2017 statutory tax rate of 39%.
For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income, Net, Interest Charges, and Income Taxes, see the major headings below.
Below is Ameren’s table of income statement components by segment for the years ended December 31, 2018, 2017,2020 and 2016:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | Ameren Missouri | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren Transmission | | Other /
Intersegment
Eliminations | | Ameren |
| Electric margins | $ | 2,323 | | | $ | 1,091 | | | $ | — | | | $ | 523 | | | $ | (29) | | | $ | 3,908 | |
| Natural gas margins | 82 | | | — | | | 531 | | | — | | | (2) | | | 611 | |
| | | | | | | | | | | |
| Other operations and maintenance expenses | (886) | | | (506) | | | (221) | | | (57) | | | 9 | | | (1,661) | |
| | | | | | | | | | | |
| Depreciation and amortization | (604) | | | (288) | | | (81) | | | (98) | | | (4) | | | (1,075) | |
| Taxes other than income taxes | (328) | | | (72) | | | (65) | | | (8) | | | (10) | | | (483) | |
| Other income, net | 76 | | | 33 | | | 13 | | | 13 | | | 16 | | | 151 | |
| Interest charges | (190) | | | (72) | | | (41) | | | (78) | | | (38) | | | (419) | |
| Income (taxes) benefit | (34) | | | (42) | | | (36) | | | (78) | | | 35 | | | (155) | |
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| | | | | | | | | | | |
| Net income (loss) | 439 | | | 144 | | | 100 | | | 217 | | | (23) | | | 877 | |
| Noncontrolling interests – preferred stock dividends | (3) | | | (1) | | | (1) | | | (1) | | | — | | | (6) | |
| Net income (loss) attributable to Ameren common shareholders | $ | 436 | | | $ | 143 | | | $ | 99 | | | $ | 216 | | | $ | (23) | | | $ | 871 | |
| 2019 | | | | | | | | | | | |
| Electric margins | $ | 2,381 | | | $ | 1,074 | | | $ | — | | | $ | 464 | | | $ | (29) | | | $ | 3,890 | |
| Natural gas margins | 81 | | | — | | | 519 | | | — | | | (2) | | | 598 | |
| | | | | | | | | | | |
| Other operations and maintenance expenses | (960) | | | (498) | | | (233) | | | (60) | | | 6 | | | (1,745) | |
| | | | | | | | | | | |
| Depreciation and amortization | (556) | | | (273) | | | (78) | | | (84) | | | (4) | | | (995) | |
| Taxes other than income taxes | (329) | | | (73) | | | (67) | | | (4) | | | (8) | | | (481) | |
| Other income, net | 58 | | | 33 | | | 12 | | | 8 | | | 19 | | | 130 | |
| Interest charges | (178) | | | (71) | | | (38) | | | (74) | | | (20) | | | (381) | |
| Income (taxes) benefit | (68) | | | (45) | | | (30) | | | (64) | | | 25 | | | (182) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Net income (loss) | 429 | | | 147 | | | 85 | | | 186 | | | (13) | | | 834 | |
| Noncontrolling interests – preferred stock dividends | (3) | | | (1) | | | (1) | | | (1) | | | — | | | (6) | |
| | | | | | | | | | | |
| Net income (loss) attributable to Ameren common shareholders | $ | 426 | | | $ | 146 | | | $ | 84 | | | $ | 185 | | | $ | (13) | | | $ | 828 | |
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| 2018 | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other / Intersegment Eliminations | | Ameren |
| Electric margins | $ | 2,518 |
| | $ | 1,065 |
| | $ | — |
| | $ | 433 |
| | $ | (27 | ) | | $ | 3,989 |
|
| Natural gas margins | 82 |
| | — |
| | 497 |
| | — |
| | (1 | ) | | 578 |
|
| Other operations and maintenance | (972 | ) | | (506 | ) | | (241 | ) | | (63 | ) | | 10 |
| | (1,772 | ) |
| Depreciation and amortization | (550 | ) | | (259 | ) | | (65 | ) | | (77 | ) | | (4 | ) | | (955 | ) |
| Taxes other than income taxes | (329 | ) | | (75 | ) | | (66 | ) | | (4 | ) | | (9 | ) | | (483 | ) |
| Other income, net | 56 |
| | 26 |
| | 9 |
| | 7 |
| | 4 |
| | 102 |
|
| Interest charges | (200 | ) | | (73 | ) | | (38 | ) | | (75 | ) | | (15 | ) | | (401 | ) |
| Income taxes | (124 | ) | | (41 | ) | | (25 | ) | | (56 | ) | | 9 |
| | (237 | ) |
| Net income (loss) | 481 |
| | 137 |
| | 71 |
| | 165 |
| | (33 | ) |
| 821 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | $ | 478 |
| | $ | 136 |
| | $ | 70 |
| | $ | 164 |
| | $ | (33 | ) | | $ | 815 |
|
| 2017 | | | | | | | | | | | |
| Electric margins | $ | 2,429 |
| | $ | 1,109 |
| | $ | — |
| | $ | 426 |
| | $ | (32 | ) | | $ | 3,932 |
|
| Natural gas margins | 79 |
| | — |
| | 479 |
| | — |
| | (2 | ) | | 556 |
|
| Other operations and maintenance | (925 | ) | | (519 | ) | | (227 | ) | | (64 | ) | | 30 |
| | (1,705 | ) |
| Depreciation and amortization | (533 | ) | | (239 | ) | | (59 | ) | | (60 | ) | | (5 | ) | | (896 | ) |
| Taxes other than income taxes | (328 | ) | | (74 | ) | | (60 | ) | | (6 | ) | | (9 | ) | | (477 | ) |
| Other income, net | 65 |
| | 11 |
| | — |
| | 2 |
| | 8 |
| | 86 |
|
| Interest charges | (207 | ) | | (73 | ) | | (36 | ) | | (67 | ) | | (8 | ) | | (391 | ) |
| Income taxes | (254 | ) | | (83 | ) | | (36 | ) | | (90 | ) | | (113 | ) | | (576 | ) |
| Net income (loss) | 326 |
|
| 132 |
| | 61 |
| | 141 |
| | (131 | ) | | 529 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | $ | 323 |
| | $ | 131 |
| | $ | 60 |
| | $ | 140 |
| | $ | (131 | ) |
| $ | 523 |
|
| 2016 | | | | | | | | | | | |
| Electric margins | $ | 2,397 |
| | $ | 1,104 |
| | $ | — |
| | $ | 355 |
| | $ | (28 | ) | | $ | 3,828 |
|
| Natural gas margins | 79 |
| | — |
| | 462 |
| | — |
| | (2 | ) | | 539 |
|
| Other operations and maintenance | (912 | ) | | (551 | ) | | (223 | ) | | (63 | ) | | 16 |
| | (1,733 | ) |
| Depreciation and amortization | (514 | ) | | (226 | ) | | (55 | ) | | (43 | ) | | (7 | ) | | (845 | ) |
| Taxes other than income taxes | (325 | ) | | (72 | ) | | (58 | ) | | (4 | ) | | (8 | ) | | (467 | ) |
| Other income, net | 62 |
| | 22 |
| | 7 |
| | 5 |
| | 5 |
| | 101 |
|
| Interest charges | (211 | ) | | (72 | ) | | (34 | ) | | (58 | ) | | (7 | ) | | (382 | ) |
| Income taxes | (216 | ) | | (78 | ) | | (39 | ) | | (74 | ) | | 25 |
| | (382 | ) |
| Net income (loss) | 360 |
| | 127 |
| | 60 |
| | 118 |
| | (6 | ) | | 659 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren common shareholders | $ | 357 |
| | $ | 126 |
| | $ | 59 |
| | $ | 117 |
| | $ | (6 | ) |
| $ | 653 |
|
Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2018, 2017,2020 and 2016:2019: | | | 2018 | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois | |
| 2020 | | 2020 | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | | Ameren Illinois |
| Electric margins | $ | 1,065 |
| | $ | — |
| | $ | 267 |
| | $ | 1,332 |
| Electric margins | $ | 1,091 | | | $ | — | | | $ | 329 | | | | $ | 1,420 | |
| Natural gas margins | — |
| | 497 |
| | — | | 497 |
| Natural gas margins | — | | | 531 | | | — | | | | 531 | |
| Other operations and maintenance | (506 | ) | | (241 | ) | | (52 | ) | | (799 | ) | |
| | Other operations and maintenance expenses | | Other operations and maintenance expenses | (506) | | | (221) | | | (48) | | | | (775) | |
| Depreciation and amortization | (259 | ) | | (65 | ) | | (50 | ) | | (374 | ) | Depreciation and amortization | (288) | | | (81) | | | (65) | | | | (434) | |
| Taxes other than income taxes | (75 | ) | | (66 | ) | | (3 | ) | | (144 | ) | Taxes other than income taxes | (72) | | | (65) | | | (3) | | | | (140) | |
| Other income, net | 26 |
| | 9 |
| | 7 |
| | 42 |
| Other income, net | 33 | | | 13 | | | 13 | | | | 59 | |
| Interest charges | (73 | ) | | (38 | ) | | (38 | ) | | (149 | ) | Interest charges | (72) | | | (41) | | | (42) | | | | (155) | |
| Income taxes | (41 | ) | | (25 | ) | | (32 | ) | | (98 | ) | Income taxes | (42) | | | (36) | | | (46) | | | | (124) | |
| | Net income | 137 |
| | 71 |
| | 99 |
| | 307 |
| Net income | 144 | | | 100 | | | 138 | | | | 382 | |
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | Preferred stock dividends | (1) | | | (1) | | | (1) | | | | (3) | |
| Net income attributable to common shareholder | $ | 136 |
| | $ | 70 |
| | $ | 98 |
| | $ | 304 |
| Net income attributable to common shareholder | $ | 143 | | | $ | 99 | | | $ | 137 | | | | $ | 379 | |
| 2017 | | | | | | | | |
| 2019 | | 2019 | | | |
| Electric margins | $ | 1,109 |
| | $ | — |
| | $ | 258 |
| | $ | 1,367 |
| Electric margins | $ | 1,074 | | | $ | — | | | $ | 288 | | | | $ | 1,362 | |
| Natural gas margins | — | | 479 |
| | — | | 479 |
| Natural gas margins | — | | | 519 | | | — | | | | 519 | |
| Other operations and maintenance | (519 | ) | | (227 | ) | | (53 | ) | | (799 | ) | |
| | Other operations and maintenance expenses | | Other operations and maintenance expenses | (498) | | | (233) | | | (51) | | | | (782) | |
| Depreciation and amortization | (239 | ) | | (59 | ) | | (43 | ) | | (341 | ) | Depreciation and amortization | (273) | | | (78) | | | (55) | | | | (406) | |
| Taxes other than income taxes | (74 | ) | | (60 | ) | | (3 | ) | | (137 | ) | Taxes other than income taxes | (73) | | | (67) | | | (3) | | | | (143) | |
| Other income, net | 11 |
| | — |
| | 1 |
| | 12 |
| Other income, net | 33 | | | 12 | | | 8 | | | | 53 | |
| Interest charges | (73 | ) | | (36 | ) | | (35 | ) | | (144 | ) | Interest charges | (71) | | | (38) | | | (38) | | | | (147) | |
| Income taxes | (83 | ) | | (36 | ) | | (47 | ) | | (166 | ) | Income taxes | (45) | | | (30) | | | (35) | | | | (110) | |
| | Net income | 132 |
| | 61 |
| | 78 |
| | 271 |
| Net income | 147 | | | 85 | | | 114 | | | | 346 | |
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | Preferred stock dividends | (1) | | | (1) | | | (1) | | | | (3) | |
| | Net income attributable to common shareholder | $ | 131 |
| | $ | 60 |
| | $ | 77 |
| | $ | 268 |
| Net income attributable to common shareholder | $ | 146 | | | $ | 84 | | | $ | 113 | | | | $ | 343 | |
| 2016 | | | | | | | | |
| Electric margins | $ | 1,104 |
| | $ | — |
| | $ | 232 |
| | $ | 1,336 |
| |
| Natural gas margins | — |
| | 462 |
| | — |
| | 462 |
| |
| Other operations and maintenance | (551 | ) | | (223 | ) | | (54 | ) | | (828 | ) | |
| Depreciation and amortization | (226 | ) | | (55 | ) | | (38 | ) | | (319 | ) | |
| Taxes other than income taxes | (72 | ) | | (58 | ) | | (2 | ) | | (132 | ) | |
| Other income, net | 22 |
| | 7 |
| | 5 |
| | 34 |
| |
| Interest charges | (72 | ) | | (34 | ) | | (34 | ) | | (140 | ) | |
| Income taxes | (78 | ) | | (39 | ) | | (41 | ) | | (158 | ) | |
| Net income | 127 |
| | 60 |
| | 68 |
| | 255 |
| |
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) | |
| Net income attributable to common shareholder | $ | 126 |
| | $ | 59 |
| | $ | 67 |
| | $ | 252 |
| |
|
Margins
The following table presents the favorable (unfavorable) variations by segment forElectric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas margins in 2018 compared with 2017, as well as 2017 compared with 2016.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.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins |
| 2018 versus 2017 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 157 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 157 |
|
Base rates, including effects of TCJA (estimate)(c) | (113 | ) | | (23 | ) | | — |
| | 7 |
| | — |
| | (129 | ) |
| Recovery of power restoration efforts provided to other utilities | 5 |
| | 8 |
| | — |
| | — |
| | — |
| | 13 |
|
| Sales volume (excluding the estimated effects of weather and MEEIA) | 21 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
|
| Off-system sales and capacity revenues | (110 | ) | | — |
| | — |
| | — |
| | — |
| | (110 | ) |
| MEEIA 2016 performance incentive | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Energy-efficiency program investments | — |
| | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
| Other | 6 |
| | 2 |
| | — |
| | — |
| | 6 |
| | 14 |
|
Cost recovery mechanisms – offset in fuel and purchased power(d) | 33 |
| | 19 |
| | — |
| | — |
| | — |
| | 52 |
|
Other cost recovery mechanisms(e) | 30 |
| | (40 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| Total electric revenue change | $ | 40 |
| | $ | (21 | ) | | $ | — |
| | $ | 7 |
| | $ | 6 |
| | $ | 32 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | 109 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 109 |
|
Effect of weather (estimate)(b) | (34 | ) | | — |
| | — |
| | — |
| | — |
| | (34 | ) |
| Effect of lower net energy costs included in base rates | 9 |
| | — |
| | — |
| | — |
| | — |
| | 9 |
|
| Other | (2 | ) | | (4 | ) | | — |
| | — |
| | (1 | ) | | (7 | ) |
Cost recovery mechanisms – offset in electric revenue(d) | (33 | ) | | (19 | ) | | — |
| | — |
| | — |
| | (52 | ) |
| Total fuel and purchased power change | $ | 49 |
| | $ | (23 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | 25 |
|
| Net change in electric margins | $ | 89 |
| | $ | (44 | ) | | $ | — |
| | $ | 7 |
| | $ | 5 |
| | $ | 57 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| Base rates, including effects of TCJA (estimate) | — |
| | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| QIP rider | — |
| | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
| Other | — |
| | — |
| | 2 |
| | — |
| | 1 |
| | 3 |
|
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | (7 | ) | | — |
| | 54 |
| | — |
| | — |
| | 47 |
|
Other cost recovery mechanisms(e) | — |
| | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
| Total natural gas revenue change | $ | 12 |
| | $ | — |
| | $ | 72 |
| | $ | — |
| | $ | 1 |
| | $ | 85 |
|
| Natural gas purchased for resale change: | | | | | | | | | | | �� |
Effect of weather (estimate)(b) | $ | (16 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (16 | ) |
Cost recovery mechanisms – offset in natural gas revenue(d) | 7 |
| | — |
| | (54 | ) | | — |
| | — |
| | (47 | ) |
| Total natural gas purchased for resale change | $ | (9 | ) | | $ | — |
| | $ | (54 | ) | | $ | — |
| | $ | — |
| | $ | (63 | ) |
| Net change in natural gas margins | $ | 3 |
| | $ | — |
| | $ | 18 |
| | $ | — |
| | $ | 1 |
| | $ | 22 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2017 versus 2016 | Ameren
Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (65 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (70 | ) |
Base rates (estimate)(c) | 61 |
| | 42 |
| | — |
| | 71 |
| | — |
| | 174 |
|
| Recovery of power restoration efforts provided to other utilities | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | 8 |
|
| Sales volume (excluding the estimated effects of weather and MEEIA) | (6 | ) | | — |
| | — |
| | — |
| | — |
| | (6 | ) |
| Off-system sales and capacity revenues | 22 |
| | — |
| | — |
| | — |
| | — |
| | 22 |
|
| MEEIA 2013 performance incentive | (28 | ) | | — |
| | — |
| | — |
| | — |
| | (28 | ) |
| Transmission services revenues | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 5 |
| | 5 |
|
Cost recovery mechanisms – offset in fuel and purchased power(d) | (11 | ) | | 18 |
| | — |
| | — |
| | — |
| | 7 |
|
Other cost recovery mechanisms(e) | 24 |
| | (36 | ) | | — |
| | — |
| | — |
| | (12 | ) |
| Total electric revenue change | $ | 15 |
| | $ | 20 |
| | $ | — |
| | $ | 71 |
| | $ | 5 |
| | $ | 111 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | (22 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (22 | ) |
Effect of weather (estimate)(b) | 13 |
| | (1 | ) | | — |
| | — |
| | — |
| | 12 |
|
| Effect of lower net energy costs included in base rates | 39 |
| | — |
| | — |
| | — |
| | — |
| | 39 |
|
| Transmission services charges | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) |
| Other | (8 | ) | | 4 |
| | — |
| | — |
| | (9 | ) | | (13 | ) |
Cost recovery mechanisms – offset in electric revenue(d) | 11 |
| | (18 | ) | | — |
| | — |
| | — |
| | (7 | ) |
| Total fuel and purchased power change | $ | 17 |
| | $ | (15 | ) | | $ | — |
| | $ | — |
| | $ | (9 | ) | | $ | (7 | ) |
| Net change in electric margins | $ | 32 |
| | $ | 5 |
| | $ | — |
| | $ | 71 |
| | $ | (4 | ) | | $ | 104 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
| QIP rider | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Other | — |
| | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | 2 |
| | — |
| | (28 | ) | | — |
| | — |
| | (26 | ) |
Other cost recovery mechanisms(e) | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Total natural gas revenue change | $ | (2 | ) | | $ | — |
| | $ | (11 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Cost recovery mechanisms – offset in natural gas revenue(d) | (2 | ) | | — |
| | 28 |
| | — |
| | — |
| | 26 |
|
| Total natural gas purchased for resale change | $ | 2 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 30 |
|
| Net change in natural gas margins | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
| | | | | | | | | | | | | | |
(a) | Includes an increase in transmission marginsTotal by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $9 million and $26 million in 2018 and 2017, respectively, at Ameren Illinois.$18 Million) | |
(a)Includes other/intersegment eliminations of $(29) million and $(29) million in 2020and 2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(b) | Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. | Ameren Missouri | | | Ameren Illinois Electric Distribution | | Ameren Transmission | | | Other/Intersegment Eliminations | |
Natural Gas Margins
| | | | | | | | | | | | | | |
(c) | ForTotal by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall 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.Increase of $13 Million) | |
(a)Includes other/intersegment eliminations of $(2) million and $(2) million in 2020and 2019, respectively.
| | | | | | | | | | | | | | | | | | | | |
(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. |
| Ameren Missouri | | |
(e)Ameren Illinois Natural Gas | Offsetting increases or decreases to expenses are reflected in “Operating Expenses – Other operations and maintenance” or in “Operating Expenses – Taxes other than income taxes” on the statement of income. These items have no overall impact on earnings. |
The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2020, compared with 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins | | | | | |
| 2020 versus 2019 | Ameren
Missouri | | Ameren Illinois
Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (30) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (30) | | | | | | |
Base rates (estimate)(c) | (58) | | | (3) | | | — | | | 59 | | | — | | | (2) | | | | | | |
| Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | (36) | | | — | | | — | | | — | | | — | | | (36) | | | | | | |
| Customer demand charges | (7) | | | — | | | — | | | — | | | — | | | (7) | | | | | | |
| MEEIA performance incentives | (31) | | | — | | | — | | | — | | | — | | | (31) | | | | | | |
| Off-system sales | 47 | | | — | | | — | | | — | | | — | | | 47 | | | | | | |
| Customer late fees and reconnection fees | (4) | | | — | | | — | | | — | | | — | | | (4) | | | | | | |
| Energy-efficiency program investments | — | | | 12 | | | — | | | — | | | — | | | 12 | | | | | | |
| Transmission service revenues | (3) | | | — | | | — | | | — | | | — | | | (3) | | | | | | |
| Other | (1) | | | 5 | | | — | | | — | | | 2 | | | 6 | | | | | | |
Cost recovery mechanisms – offset in fuel and purchased power(d) | (4) | | | (23) | | | — | | | — | | | — | | | (27) | | | | | | |
Other cost recovery mechanisms(e) | 2 | | | 3 | | | — | | | — | | | — | | | 5 | | | | | | |
| Total electric revenue change | $ | (125) | | | $ | (6) | | | $ | — | | | $ | 59 | | | $ | 2 | | | $ | (70) | | | | | | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | (34) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (34) | | | | | | |
Effect of weather (estimate)(b) | 8 | | | — | | | — | | | — | | | — | | | 8 | | | | | | |
| Effect of lower net energy costs included in base rates | 92 | | | — | | | — | | | — | | | — | | | 92 | | | | | | |
| Transmission service charges | (3) | | | — | | | — | | | — | | | — | | | (3) | | | | | | |
| Other | — | | | — | | | — | | | — | | | (2) | | | (2) | | | | | | |
Cost recovery mechanisms – offset in electric revenue(d) | 4 | | | 23 | | | — | | | — | | | — | | | 27 | | | | | | |
| Total fuel and purchased power change | $ | 67 | | | $ | 23 | | | $ | — | | | $ | — | | | $ | (2) | | | $ | 88 | | | | | | |
| Net change in electric margins | $ | (58) | | | $ | 17 | | | $ | — | | | $ | 59 | | | $ | — | | | $ | 18 | | | | | | |
| Natural gas revenue change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (5) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (5) | | | | | | |
| | | | | | | | | | | | | | | | |
| QIP | — | | | — | | | 23 | | | — | | | — | | | 23 | | | | | | |
| Software licensing agreement | — | | | — | | | (5) | | | — | | | — | | | (5) | | | | | | |
| Other | 3 | | | — | | | (1) | | | — | | | — | | | 2 | | | | | | |
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | (6) | | | — | | | (49) | | | — | | | — | | | (55) | | | | | | |
Other cost recovery mechanisms(e) | (1) | | | — | | | (5) | | | — | | | — | | | (6) | | | | | | |
| Total natural gas revenue change | $ | (9) | | | $ | — | | | $ | (37) | | | $ | — | | | $ | — | | | $ | (46) | | | | | | |
| Natural gas purchased for resale change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4 | | | | | | |
Cost recovery mechanisms – offset in natural gas revenue(d) | 6 | | | — | | | 49 | | | — | | | — | | | 55 | | | | | | |
| Total natural gas purchased for resale change | $ | 10 | | | $ | — | | | $ | 49 | | | $ | — | | | $ | — | | | $ | 59 | | | | | | |
| Net change in natural gas margins | $ | 1 | | | $ | — | | | $ | 12 | | | $ | — | | | $ | — | | | $ | 13 | | | | | | |
(a)Includes an increase in transmission electric margins of $41 million in 2020, compared with 2019, at Ameren Illinois.
(b)Represents the estimated variation resulting primarily from changes in cooling and heating degree days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.
(c)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates. For Ameren Missouri, base rates exclude an increase of $43 million for the recovery of lost electric margins in 2020, compared with 2019, resulting from the MEEIA 2016 and 2019 customer energy-efficiency programs. This amount is included in the “sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” line item.
(d)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of income, resulting in no change to electric and natural gas margins.
(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.
Ameren
Ameren’s electric margins increased $57$18 million, or less than 1%, in 20182020, compared with 2017,2019, primarily because of increased margins at Ameren MissouriTransmission and Ameren Illinois Electric Distribution, partially offset by decreased margins at Ameren Illinois Electric Distribution.Missouri, as discussed
below. Ameren’s natural gas margins increased $22$13 million, or 4%2%, in 2018 compared with 2017,between years primarily because of increased margins at Ameren Illinois Natural Gas.Gas, as discussed below.
Ameren Transmission
Ameren Transmission’s electric margins increased $7$59 million, or 2%13%, in 20182020, compared with 2017.2019. Margins were favorably affected by increased capital investment, as evidenced by a 13% increase in the 13-month average rate base used to calculate the revenue requirement in 2018 compared with 2017. Margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, which decreased revenues $54 million in 2018 compared with 2017.
Ameren Missouri
Ameren Missouri’s electric margins increased $89 million, or 4%, in 2018 compared with 2017. Ameren Missouri’s natural gas margins increased $3 million, or 4%, in 2018 compared with 2017 primarily due to colder winter temperatures, as discussed below.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2018 compared with 2017:
Summer temperatures were warmer as cooling degree days increased 11% in 2018 compared with 2017between years, and winter temperatures were colder as heating degree days increased 34% in 2018 compared with 2017. The effect of weather increased margins by an estimated $123 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$157 million) and the effect of weather (estimate) on fuel and purchased power (-$34 million) in the table above.
Revenues from other cost recovery mechanisms due to MEEIA customer energy-efficiency program costs and gross receipts taxes, which increased margins $30 million. See Other Operations and Maintenance Expenses in this section for the related offsetting increase in MEEIA customer energy-efficiency program costs and Taxes Other Than Income Taxes in this section for the related offsetting increase in gross receipts taxes.
Excluding the estimated effects of weather and the MEEIA 2016 customer energy-efficiency programs, total retail sales volumes increased 1%, which increased revenues by an estimated $21 million, primarily due to growth. While MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins ensured that electric margins were not affected.
The MEEIA 2016 performance incentive, which increased revenues $11 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2016 performance incentive.
An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $5 million.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2018 compared with 2017:
Lower electric base rates in accordance with the TCJA provisions in Missouri Senate Bill 564, partially offset by higher electric base rates, as a result of the March 2017 electric rate order. These items collectively decreased margins by an estimated $104 million in 2018 compared with 2017. The net change in electric base rates is the sum of the change in base rates (estimate) (-$113 million) and the effect of lower net energy costs included in base rates (+$9 million) in the table above.
An increase in net energy costs as a result of increased sales volumes discussed above, partially offset by the 5% Ameren Missouri retains for the variance in net energy costs from the amount set in base rates, primarily as a result of lower fuel costs in 2018 compared with 2017, which collectively decreased margins $1 million. The change in net energy costs is the sum of the effect of revenue change in off-system sales and capacity revenues (-$110 million) and the effect of the change in energy costs (excluding the estimated effect of weather) (+$109 million) in the table above.
Ameren Illinois
Ameren Illinois’ electric margins decreased $35 million, or 3%, in 2018 compared with 2017 driven by decreased margins at Ameren Illinois Electric Distribution (-$44 million), partially offset by increased margins at Ameren Illinois Transmission (+$9 million). Ameren Illinois Natural Gas’ margins increased $18 million, or 4%, in 2018 compared with 2017.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins decreased $44 million, or 4%, in 2018 compared with 2017. The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s margins in 2018 compared with 2017:
Revenues from other cost recovery mechanisms, primarily due to a decrease in recoverable customer energy-efficiency program costs prior to the FEJA, which decreased margins $40 million. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency program costs prior to the FEJA.
Revenues decreased due to lower recoverable expenses in 2018 compared with 2017 under formula ratemaking, partially offset by an increase in rate base of 8% and a higher recognized return on common equity due to an increase in the 30-year United States Treasury bond yields of 22 basis points, which collectively decreased margins $23 million. The reduction inallowed ROE resulting from the federal statutory corporate income tax rate decreased recoverable expenses $52 million.
The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in 2018 compared with 2017:
Revenues increased $13 million due to energy-efficiency program investments pursuant to the FEJA.
An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $8 million.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $18 million, or 4%, in 2018 compared with 2017. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins:
Revenues from QIP recoveries, which increased margins $13 million due to additional investment in qualified natural gas infrastructure.
Revenues from other cost recovery mechanisms, which increased margins $9 million.
Ameren Illinois Natural Gas’ margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, partially offset by higher natural gas base rates, as a result of the November 2018 natural gas rateMay 2020 FERC order. These items collectively decreased margins by an estimated $6 million, in 2018 compared with 2017.
Ameren Illinois Transmission
Ameren Illinois Transmission’s margins increased $9 million, or 3%, in 2018 compared with 2017. Margins were favorably affected by increased capital investment, as evidenced by an 18% increase in rate base used to calculate the revenue requirement in 2018 compared with 2017. Margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, which decreased revenues $32 million, in 2018 compared with 2017.
2017 versus 2016
Ameren
Ameren’s electric margins increased $104 million, or 3%, in 2017 compared with 2016 primarily because of increased margins at Ameren Transmission and Ameren Missouri. Ameren’s natural gas margins increased $17 million, or 3%, in 2017 compared with 2016 because of increased margins at Ameren Illinois Natural Gas.
Ameren Transmission
Ameren Transmission’s margins increased $71 million, or 20%, in 2017 compared with 2016. Margins were favorably affected by increased capital investment, as evidenced by a 23% increase in rate base used to calculate the revenue requirement in 2017 compared with 2016, as well as higher recoverable costs in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the allowed return on common equity for FERC-regulated transmission rate base.May 2020 FERC order.
Ameren Missouri
Ameren Missouri’s electric margins increased $32decreased $58 million, or 1%2%, in 20172020, compared with 2016.2019. Ameren Missouri’s natural gas margins were comparable between years.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2017 compared with 2016:
Higher electric base rates, effective April 1, 2017, as a result of the March 2017 MoPSC electric rate order, which increased margins by an estimated $100 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$61 million) and the effect of lower net energy costs included in base rates (+$39 million) in the table above. Higher electric base rates incorporated the effect of the suspension of operations at the New Madrid Smelter.
Revenues from other cost recovery mechanisms, primarily due to MEEIA customer energy-efficiency program costs, which increased margins $24 million. See Other Operations and Maintenance Expenses in this section for the related offsetting increase in MEEIA customer energy-efficiency program costs.
Increased transmission services revenues due to additional rate base investment, which increased margins $11 million.
An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $7 million.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 20172020, compared with 2016:2019:
Summer temperatures were milder in 2017 compared with 2016, as cooling degree days decreased 10%. •The aggregate effect of changes in customer usage, excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, decreased margins byelectric revenues an estimated $52$43 million. The change in marginsdecrease was primarily due to weather is the sum of the effect of weather (estimate) on electric revenuesa reduction in sales volumes (-$6544 million) and decreased revenues from customer demand charges (-$7 million), both of which were unfavorably affected by the effect of weather (estimate) on fuel and purchased power (+$13 million)COVID-19 pandemic. An increase in the table above.average retail price per kilowatthour due to changes in customer usage patterns partially offset the decreases by a favorable $8 million. While the MEEIA customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins under the MEEIA ensured that electric margins were not affected.
•The absence of revenues associated with MEEIA 2013 and 2016 performance incentives in 2020, partially offset by revenues from the MEEIA 20132019 performance incentive, which decreased margins $28revenues $31 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 performance incentive.incentives.
Increased transmission services charges resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, which•Summer temperatures were milder as cooling degree days decreased margins $16 million.
Excluding the estimated effects7%, and winter temperatures were warmer as heating degree days decreased 9%. The aggregate effect of weather and the MEEIA 2016 customer energy-efficiency programs, total retail sales volumes decreased less than 1%, which decreased revenues by an estimated $6 million. Lower sales volumes were due, in part, to the absence of the leap year benefit experienced in 2016, partially offset by growth. While MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins ensured that electric margins were not affected.
Ameren Illinois
Ameren Illinois’ electric margins increased $31 million, or 2%, in 2017 compared with 2016 driven by increases in Ameren Illinois Electric Distribution (+$5 million) and Ameren Illinois Transmission (+$26 million) margins. Ameren Illinois Natural Gas’ margins increased $17 million, or 4%, in 2017 compared with 2016 primarily due to increased QIP rider recoveries, which increased margins $12 million.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $5 million, or less than 1%, in 2017 compared with 2016. Ameren Illinois Electric Distribution’s margins were favorably affected by an increase in rate base of 6% in 2017 compared with 2016 and a higher return on common equity due to an increase in the 30-year United States Treasury bond yields of 29 basis points in 2017 compared with 2016, as well as higher recoverable expenses under formula ratemaking pursuant to the IEIMA, which collectively increased margins $42 million.
The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s margins in 2017 compared with 2016:
Revenues from other cost recovery mechanisms, primarily due to a decrease in recoverable customer energy-efficiency program costs prior to the FEJA, which decreased margins $36 million. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency program costs prior to the FEJA.
The absence of the impact of warmer-than-normal summer temperatures experienced in 2016, which decreased margins by an estimated $6$22 million. Ameren Illinois Electric Distribution revenues were decoupled from sales volumes beginning in 2017. The change in margins due to weather is the sum of the effect“Effect of weather (estimate)” on electric revenues (-$530 million) and the effect“Effect of weather (estimate)” on fuel and purchased power (-(+$18 million) in the table above.
•Additional investments made by other transmission entities contributed to increased transmission service charges of $3 million and lower system load contributed to decreased transmission service revenues of $3 million.
•In response to the COVID-19 pandemic, suspensions of customer late fees and reconnection fees resulted in a $4 million decrease in revenue. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information on the suspension of customer late fees and disconnections.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2020, compared with 2019:
•The March 2020 MoPSC electric rate order, with new rates effective April 1, 2020, increased margins $34 million. The change in electric base rates is the sum of the “Change in base rates (estimate)” (-$58 million) and the “Effect of lower net energy costs included in base rates” (+$92 million) in the table above.
•Decreased sales volumes, which were affected by the COVID-19 pandemic, resulted in lower net energy costs and increased margins $13 million. The change in net energy costs is the sum of the effect of the revenue change in “Off-system sales” (+$47 million) and the “Effect of the change in energy costs” (-$34 million) in the table above.
Ameren Illinois
Ameren Illinois’ electric margins increased $58 million, or 4%, in 2020, compared with 2019, driven by increased margins at Ameren Illinois Transmission (+$41 million) and Ameren Illinois Electric Distribution (+$17 million). Ameren Illinois Natural Gas’ margins increased $12 million, or 2%, between years.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $17 million, or 2%, in 2020, compared with 2019. Revenues increased $12 million due to increased energy-efficiency program investments under performance-based formula ratemaking. Margins decreased due to a lower recognized ROE (-$17 million), as evidenced by a decrease of 102 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, partially offset by increased capital investment (+$8 million), as evidenced by a 6% increase in year-end rate base, and higher recoverable non-purchased power expenses (+$6 million). The sum of these base rate changes collectively decreased margins $3 million in 2020, compared with 2019.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $12 million, or 2%, in 2020, compared with 2019. Revenues from increased QIP recoveries due to additional investment in qualified natural gas infrastructure increased margins $23 million. The absence of revenues from a software licensing agreement with Ameren Missouri decreased margins $5 million. See the Software Licensing Agreement section within Note 13 – Related-party Transactions under Part II, Item 8, of this report for information regarding this transaction.
Ameren Illinois Transmission
Ameren Illinois Transmission’s electric margins increased $26$41 million, or 11%14%, in 20172020, compared with 2016.2019. Margins were favorably affected by increased capital investment, as evidenced by a 16%19% increase in the 13-month average rate base used to calculate the revenue requirementbetween years, and higher recoverable costs in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund periodan increase in the February 2015allowed ROE resulting from the May 2020 FERC complaint case.order. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the May 2020 FERC order.
Other Operations and Maintenance Expenses
2018 versus 2017 | | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Decrease of $84 Million) | |
(a)Includes $57 million and $60 million at Ameren Transmission in 2020 and 2019, respectively, and other/intersegment eliminations of $(9) million and $(6) million in 2020and 2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Ameren
Other operations and maintenance expenses were $67$84 million higherlower in 20182020, compared with 2017.2019. In addition to changes by segmentsegments discussed below, other operations and maintenance expenses increased $20decreased $3 million in 20182020 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of a decrease in intersegment eliminations.decreased costs for support services.
Ameren Transmission
Other operations and maintenance expenses were comparable between 2018 and 2017.$3 million lower in 2020, compared with 2019, primarily due to a decrease in transmission expenditures at Ameren Illinois Transmission resulting from disciplined cost management.
Ameren Missouri
OtherThe $74 million decrease in other operations and maintenance expenses were $47 million higher in 20182020, compared with 2017. 2019, was primarily due to the following items:
•Callaway Energy Center refueling operations and maintenance costs decreased $34 million, due to the treatment of the 2019 scheduled refueling and maintenance outage costs at the Callaway Energy Center, which were expensed as incurred, as compared with the deferral of expenses for the fall 2020 scheduled refueling and maintenance outage pursuant to the February 2020 MoPSC order.
•Energy center maintenance costs, other than those associated with the Callaway refueling and maintenance outage, decreased $29 million, primarily because of lower electric system infrastructure maintenance expenses as a result of decreased system load, disciplined cost management, and the deferral of projects to future periods.
•Transmission and distribution expenditures decreased $15 million, primarily resulting from less maintenance due to recent capital improvements and disciplined cost management.
•Amortization of solar rebate costs incurred prior to the RESRAM decreased $13 million as a result of the March 2020 MoPSC electric rate order.
The following items increasedpartially offset the above decreases in other operations and maintenance expenses between years:
Nonnuclear energy center operations and maintenance•Solar rebate costs recoverable under the RESRAM increased $31$9 million, primarily because of higher-than-normal scheduled outage costs and an increasethe amortization of previously-deferred rebates included in routine maintenance work.customer rates in 2020.
MEEIA customer energy-efficiency program•Bad debt costs increased $20 million.
Distribution maintenance expenditures increased $20 million, primarily due to increased reliability work, including vegetation management work and inspections, and increased system repairs and maintenance costs.
Labor and employee benefit costs increased $14$7 million, primarily because of an unrealized MTM loss in 2018 compared with a MTM gain in 2017 resulting from changes in the market value of company-owned life insurance and an increase in power restoration assistance providedaccounts receivable balances that were past due or that were a part of a deferred payment arrangement, which increased primarily due to other utilities.the COVID-19 pandemic.
The above increases were partially offset by a $29•Technology-related expenditures increased $5 million, reduction in Callaway energy center refueling and maintenance outage costs. There was no Callaway refueling and maintenance outage in 2018; however, $6 million in preparationprimarily because of costs were incurred in 2018 forassociated with the 2019 scheduled outage.implementation of cloud computing technology.
Ameren Illinois
Other operations and maintenance expenses were comparable$7 million lower at Ameren Illinois and Ameren Illinois Transmission between 2018 and 2017.in 2020, compared with 2019, as discussed below.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $13 million lower in 2018 compared with 2017, primarily because of a $36 million decrease in customer energy-efficiency costs prior to the FEJA and a $3 million decrease in environmental remediation costs. These decreases were partially offset by a $21The $8 million increase in labor and employee benefit costs, primarily because of an unrealized MTM loss in 2018 compared with a MTM gain in 2017 resulting from changes in the market value of company-owned life insurance and an increase in power restoration assistance provided to other utilities. Additionally, amortization of regulatory assets associated with the FEJA energy-efficiency program increased $9 million.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $14 million higher in 2018 compared with 2017, primarily because of increased operations and compliance expenditures related to pipeline integrity, higher bad debt expense, and increased customer energy-efficiency program costs.
2017 versus 2016
Ameren
Other operations and maintenance expenses decreased $28 million in 2017 compared with 2016. In addition to changes by segment discussed below, other operations and maintenance expenses decreased $14in 2020, compared with 2019, was primarily due to the following items:
•Amortization of energy-efficiency program investments under performance-based formula ratemaking increased $8 million.
•Labor and benefit costs increased $8 million, in 2017 for activity not reported as part of a segment, primarily because of an increase in intersegment eliminations.higher pension costs.
Ameren Transmission
Other operations and maintenance expenses were comparable between 2017 and 2016.
Ameren Missouri
Other operations and maintenance expenses were $13 million higher in 2017 compared with 2016. The following items increasedpartially offset the above increases in other operations and maintenance expenses between years:
MEEIA customer energy-efficiency program•Meter reading costs increased $22 million.decreased $4 million, as deployment of automated smart meters was substantially completed in 2019.
Nonnuclear energy center operations and maintenance costs increased•Distribution expenditures decreased $3 million, primarily due to higher coal handling charges.because of lower storm costs.
Ameren Illinois Natural Gas
The following items decreased$12 million decrease in other operations and maintenance expenses between years:
Labor and employee benefit costs decreased $6 million,in 2020, compared with 2019, was primarily due to a $4 million reduction in the base levelcosts recovered through riders and a $4 million reduction in meter reading costs, as deployment of pension and postretirement expenses allowedautomated smart meters was substantially completed in rates as a result of the March 2017 MoPSC electric rate order along with changes in the market value of company-owned life insurance, partially offset by higher labor costs resulting from increased power restoration assistance provided to other utilities and higher wages.
Solar rebate costs decreased $8 million, primarily as a result of the March 2017 MoPSC electric rate order.
Ameren Illinois
2019. Other operations and maintenance expenses also decreased $29because of a $4 million reduction in 2017 compared with 2016, as discussed below. Otherdistribution expenditures due to disciplined cost management.
Ameren Illinois Transmission
The $3 million decrease in other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2017 and 2016.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $32 million lower in 20172020, compared with 2016,2019, was primarily because ofdue to a $47 million decrease in customer energy-efficiency program costs and a $3 million decrease in labor and employee benefit costs, partially offset by an $11 million increase in environmental remediation costs.transmission expenditures resulting from disciplined cost management.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $4 million higher in 2017 compared with 2016, primarily because
Depreciation and Amortization
2018 versus 2017 | | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $80 Million) | |
Depreciation
(a)Includes other/intersegment eliminations of $4 million and $4 million in 2020 and 2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
The $80 million, $48 million, and $28 million increase in depreciation and amortization expenses increased $59 million, $17 million, and $33 million in 20182020, compared with 20172019, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, was primarily because ofdue to additional property, plant, and equipment across their respective segments. Additionally,Ameren’s and Ameren Missouri’s depreciation and amortization expenses were higher at Ameren Missouri and Ameren Illinois Electric Distribution duereflected a deferral to increased software amortization expenses.
2017 versus 2016
Depreciationa regulatory asset of depreciation and amortization expenses increased $51 million, $19pursuant to the PISA. The PISA deferral of depreciation and amortization expenses was $27 million and $22$24 million in 2017 compared with 2016 at Ameren, Ameren Missouri,2020 and Ameren Illinois, respectively, primarily because2019, respectively.
Taxes Other Than Income Taxes
2018 versus 2017 | | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $2 Million) | |
(a)Includes $8 million and $4 million at Ameren Transmission in 2020 and 2019, respectively, and other/intersegment eliminations of $10 million and $8 million in 2020and2019, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Taxes other than income taxes increased $6were comparable at Ameren between 2020 and 2019. Excise taxes decreased $8 million in 2018 compared with 2017, primarily because of higher gross receipts taxesand $4 million at Ameren Missouri and Ameren Illinois Natural Gas, partiallyrespectively, because of reduced sales. These decreases were mostly offset by a decreaseincreases of $7 million and $4 million in property taxes at Ameren Missouri and Ameren Transmission, respectively, primarily due to lowerhigher assessed property values. See Excise Taxes in Note 115 – Summary of Significant Accounting PoliciesSupplemental Information under Part II, Item 8, of this report for additional information.
Taxes other than income taxes increased $10 million in 2017 compared with 2016, primarily because
Other Income, Net
2018 versus 2017 | | | | | | | | | | | | | | |
| Total by Segment | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $21 Million) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Other income, net, increased $16$21 million at Ameren in 20182020, compared with 2017, primarily because2019. An increase of an increase$28 million in the non-service cost components of net periodic benefit income at Ameren Transmission and each of the Ameren Illinois segments, along with anMissouri was partially offset by a $9 million increase in donations, primarily due to charitable donations made pursuant to the March 2020 MoPSC electric rate order. Additionally, other income, net, increased because of a $4 million increase in the equity portion of allowance for equity funds used during construction at Ameren Missouri, Ameren Transmission, and each of the Ameren Illinois segments, resulting from increased capital projects. These increases were partially offset by a decrease in Ameren Missouri’s non-service cost components of net periodic benefit income and increased donations at Ameren Missouri.
In addition to the changes discussed above, Other income, net, decreased in 2018 compared with 2017, due to activity not reported as part of a segment, primarily as a result of increased donations at Ameren (parent), partially offset by an increase in the non-service cost components of net periodic benefit income.
Transmission. See Note 6 – Other Income, Net under Part II, Item 8, of this report for additional information. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding Ameren Missouri’s March 2020 electric rate order. 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.
Other income, net, decreased $15
Interest Charges
| | | | | | | | | | | | | | |
| Total by Segment | | Increase (Decrease) by Segment | |
| | (Overall Ameren Increase of $38 Million) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Interest charges increased $38 million in 20172020, compared with 2016,2019, primarily because of a decrease in the non-service cost
components of net periodic benefit incomelong-term debt issuance at Ameren Transmission and each of the Ameren Illinois segments, lower interest income associated with a lower IEIMA revenue requirement reconciliation regulatory asset balance at Ameren Illinois Electric Distribution, and a decrease(parent) in allowance for equity funds used during construction, primarily at Ameren Missouri. These decreases were partially offset by an increase in Ameren Missouri’s non-service cost components of net periodic benefit income.
In addition to the changes discussed above, Other income, net,April 2020, which increased in 2017 compared with 2016, due to activity not reported as part of a segment, primarily as a result of decreased donations at Ameren (parent).
Interest Charges
2018 versus 2017
Ameren
Interest charges increased $10 million in 2018 compared with 2017. Along with the changes discussed below, interest charges increased $7by $21 million, for activity not reported as part of a segment, primarily because of a decrease in intersegment borrowings at Ameren Transmission.
Ameren Transmission
Interest charges increased $8 million, primarily because of higher average outstanding debt at Ameren Illinois Transmission and ATXI, partially offset by decreased affiliate borrowings at ATXI.
Ameren Missouri
Interest charges decreased $7 million, primarily because of a decrease in the average interest rate of long-term debt, partially offset by an increase in average outstanding debt.
Ameren Illinois
Interest charges increased $5 million across the Ameren Illinois segments, primarily because of an increase in average outstanding debt,which was partially offset by a decrease associated with the reduction in average short-term debt outstanding, as proceeds from the average interest rate of long-term debt issuance were used to repay outstanding short-term debt.
2017 versus 2016
Ameren
Interest charges also increased $9 million in 2017 compared with 2016, as discussed below.
Ameren Transmission
Interest charges increased $9 million, primarily because of an increase in average outstandingdue to long-term debt issuances at Ameren Illinois TransmissionMissouri in March 2020 and ATXI.
Ameren Missouri
Interest charges decreased $4 million, primarily because of a decrease in the average interest rate of long-term debt.
Ameren Illinois
Interest charges increased $4 million across the Ameren Illinois segments, primarily because of an increase in average outstanding debt,October 2020, partially offset by a decrease in thelower average interest raterates applicable to long-term debt, which increased interest charges by $14 million. Interest charges at Ameren Missouri reflected a deferral to a regulatory asset of long-term debt.interest charges pursuant to PISA. The PISA deferral of interest charges was $12 million and $15 million in 2020 and 2019, respectively.
Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2018, 2017, 2020and 2016:2019: | | | | | 2018 | | 2017 | | 2016 | | | 2020 | | 2019 | | |
| Ameren | Ameren | 22% | | 52% | (a) | 37% | | Ameren | 15% | | 18% | | |
| Ameren Missouri | Ameren Missouri | 20% | | 44% | (b) | 38% | | Ameren Missouri | 7% | | 14% | | |
| Ameren Illinois | Ameren Illinois | 24% | | 38% | (c) | 38% | | Ameren Illinois | 24% | | 24% | | |
| Ameren Illinois Electric Distribution | Ameren Illinois Electric Distribution | 23% | | 38% | (c) | 38% | | Ameren Illinois Electric Distribution | 22% | | 23% | | |
| Ameren Illinois Natural Gas | Ameren Illinois Natural Gas | 26% | | 38% | (c) | 39% | | Ameren Illinois Natural Gas | 26% | | 26% | | |
| Ameren Illinois Transmission | Ameren Illinois Transmission | 24% | | 37% | (c) | 38% | | Ameren Illinois Transmission | 25% | | 24% | | |
| Ameren Transmission | Ameren Transmission | 25% | | 39% | (c) | 39% | | Ameren Transmission | 26% | | 25% | | |
| |
(a) | The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate increased the effective income tax rate for 2017 by 15 percentage points. |
| |
(b) | The impact of the revaluation of deferred income taxes as a result of the TCJA increased the effective income tax rate for 2017 by 6 percentage points. |
| |
(c) | The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate had no material effect on the effective income tax rate. |
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, as well as a discussion of the effect of the TCJA and the revaluation of deferred taxes in 2017.Illinois. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding reductions in revenues related to the lower federal statutory corporate income tax rate enacted under the TCJA and the return of excess deferred income taxes to customers.
2018 versus 2017
The effective income tax rate was lower in 2018 compared with 2017, primarily because
Ameren Transmission
The effective income tax rate was lower in 2018 compared with 2017, primarily because of the decrease in the federal statutory corporate income tax rate, along with amortization of excess deferred taxes in 2018, partially offset by the increase in the Illinois corporate income tax rate applied to the full year in 2018.
Ameren Missouri
The effective income tax rate was lower in 2018 compared with 2017, primarily because of the decrease in the federal statutory corporate income tax rate in 2018, amortization of excess deferred taxes in 2018, and revaluation of deferred taxes in 2017.
Ameren Illinois
The effective tax rate was lower in 2018 compared with 2017 at Ameren Illinois and its respective segments, primarily because of the decrease in the federal statutory corporate income tax rate and amortization of excess deferred taxes in 2018, partially offset by the increase in the Illinois corporate income tax rate applied to the full year in 2018.
2017 versus 2016
Ameren
The effective income tax rate was higher in 2017 compared with 2016, primarily because of revaluation of deferred taxes due to enactment of the TCJA in 2017. In addition, income tax expense increased due to the revaluation of deferred taxes as a result of an increase in the Illinois income tax rate in 2017 and due to a decrease in the recognition of tax benefits associated with share-based compensation, resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. These items were partially offset by a reduction in the valuation allowance related to charitable contributions, due to higher-than-expected current-year taxable income.
Ameren Transmission
The effective income tax rate was comparable between years.
Ameren Missouri
The effective income tax rate was higher, primarily because of revaluation of deferred taxes due to the reduction in the federal statutory corporate income tax rate described above.
Ameren Illinois
The effective tax rate was comparable between years at Ameren Illinois and its respective segments.
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, borrowingsdrawings under the Credit Agreements,committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, other 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 the near term, our operating cash flows will decrease due to the reduction in the federal statutory income tax rate enacted under the TCJA. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2020 because of our use of net operating losses and tax credit carryforwards. Additionally, operating cash flows will be further reduced by lower customer rates, resulting from the return of excess deferred taxes. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts resulting from lower accumulated deferred income tax liabilities. We expect to make significant capital expenditures over the next five years as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy targets requirements, environmental compliance, and other improvements. As part of its plan to fund these cash flow requirements, beginning in the first quarter of 2018, Ameren beganis using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2023.2025. Ameren alsoexpects these issuances to provide equity of about $100 million annually. In addition to the issuance of common shares in connection with the 2021 settlement of the remaining portion of the forward sale agreement, Ameren plans to issue incremental common equity of about $150 million in 2021 and about $300 million each year from 2022 to fund a portion of2025. Ameren Missouri’s wind generation investments. Ameren, Ameren Missouri, and Ameren Illinois expect their respectiveexpects its equity to total capitalization levels over the period ending December 2023 to remain in-line with their respective equity to total capitalization levels as ofbe about 45% through December 31, 2018.2025, with the long-term intent to support solid investment-grade credit ratings.
The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically resultat the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2018,2020, for the Ameren Companies. The working capital deficit as of December 31, 2018, was primarily the result of current maturities of long-term debt and our decision to finance our businesses with lower-cost commercial paper issuances.Ameren Illinois. With the credit capacity available under the Credit Agreements, along withand cash and cash equivalents, Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively had net available liquidity of $1.5$1.9 billion at December 31, 2018.2020. As a result of capital market volatility, due, in part, to the COVID-19 pandemic, and to increase net available liquidity, Ameren (parent) accelerated a debt issuance to April 2020, which had been planned for later in 2020, and used a portion of the proceeds to repay $350 million of senior unsecured notes held by Ameren (parent) in October 2020. Also, in August 2019, Ameren entered into a forward sale agreement with a counterparty relating to 7.5 million shares of common stock. In December 2020, Ameren partially settled the forward sale agreement by physically delivering 5.9 million shares of common stock for cash proceeds of $425 million. In February 2021, Ameren settled the remainder of the forward sale agreement by physically delivering 1.6 million shares of common stock for cash proceeds of $113 million. The proceeds were used to fund a portion of Ameren Missouri’s wind generation investments. See Credit Facility Borrowings and Liquidity and Long-term Debt and Equity below for additional information.
The following table presents net cash provided by (used in) operating, investing, and financing activities for the years ended December 31, 2018, 2017,2020 and 2016:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Cash Provided by
Operating Activities | | Net Cash Used in
Investing Activities | | Net Cash Provided by
Financing Activities |
| 2020 | | 2019 | | | Variance | | 2020 | | 2019 | | | Variance | | 2020 | | 2019 | | | Variance |
| Ameren | $ | 1,727 | | | $ | 2,170 | | | | $ | (443) | | | $ | (3,329) | | | $ | (2,435) | | | | $ | (894) | | | $ | 1,727 | | | $ | 334 | | | | $ | 1,393 | |
| | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | 911 | | | 1,067 | | | | (156) | | | (1,904) | | | (1,095) | | | | (809) | | | 1,099 | | | 59 | | | | 1,040 | |
| Ameren Illinois | 679 | | | 962 | | | | (283) | | | (1,444) | | | (1,205) | | | | (239) | | | 787 | | | 288 | | | | 499 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Cash Provided by Operating Activities | | Net Cash Used in Investing Activities | | Net Cash Provided by (Used in) Financing Activities |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Ameren | $ | 2,170 |
| | $ | 2,118 |
| | $ | 2,117 |
| | $ | (2,336 | ) | | $ | (2,204 | ) | | $ | (2,158 | ) | | $ | 205 |
| | $ | 102 |
| | $ | (258 | ) |
| Ameren Missouri | 1,260 |
| | 1,017 |
| | 1,169 |
| | (976 | ) | | (684 | ) | | (937 | ) | | (283 | ) | | (331 | ) | | (434 | ) |
| Ameren Illinois | 659 |
| | 828 |
| | 796 |
| | (1,248 | ) | | (1,070 | ) | | (918 | ) | | 628 |
| | 255 |
| | 51 |
|
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,riders, which may be adjusted without a traditional regulatory rate proceeding.review, subject to prudence reviews. Similar regulatory mechanisms exist for certain 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 affect the amount and timing of our cash provided by operating activities. See Part 1, Item 1, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our rate-adjustment mechanisms.regulatory frameworks.
2018 versus 2017
Ameren
Ameren’sOur customers’ payment for our services has been adversely affected by the COVID-19 pandemic, resulting in a decrease to our cash flow from operating activities increased $52 million in 2018 compared with 2017. The following items contributed to the increase:
A $220 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
A $27 million decrease in payments for nuclear refueling and maintenance outages atoperations. For information regarding Ameren Missouri’s Callaway energy center. There was no refueling and maintenance outage in 2018; however, there were cash expenditures related to the 2019 scheduled outage paid in 2018.
The absenceAmeren Illinois’ suspensions and reinstatement of $21 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed incustomer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. In addition, see Results of Operations above 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.
Ameren
Ameren’s cash provided by operating activities decreased $443 million in 2020, compared with 2019. The following items partially offsetcontributed to the increase in Ameren’s cash from operating activities between years:decrease:
•A net $88$381 million decrease resulting from costs and associatedreduced customer collections, under various cost recovery mechanisms from Ameren Missouri and Ameren Illinois customers.
A $40 million decreaseprimarily resulting from income tax payments of $21 milliona decrease in 2018, compared with income tax refunds of $19 millionsales volumes and an increase in 2017,accounts receivable balances, which were primarily due to state income tax refundsthe COVID-19 pandemic, and the sale of state tax credits.
A $25 million increase in energy center maintenancea net decrease attributable to regulatory recovery mechanisms, partially offset by decreased fuel and purchased power costs at Ameren Missouri primarily due to higher-than-normal, non-nuclear scheduled outageand decreased purchased power costs and an increase in routine maintenance work.volumes, and natural gas costs, at Ameren Illinois.
•A $19$38 million increase in payments to settle ARO liabilities, primarily related to donations.Ameren Missouri’s CCR storage facilities.
•A $17$28 million increase in pension and postretirement benefit plan contributions.
•A $27 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of power and natural gas, changes in contracted commodity volumes, and decreases resulting from Ameren Illinois’ renewable energy contracts entered into pursuant to the FEJA.
•A $25 million decrease, primarily resulting from increases to materials and supplies to support operations as levels were increased in 2020 to mitigate against any potential supply disruptions associated with the COVID-19 pandemic.
•A $16 million increase in interest payments, primarily due to an increase in the average outstanding debt balance at ATXI.
Ameren Missouri
Ameren Missouri’s cash from operating activities increased $243 million in 2018 compared with 2017. The following items contributed to the increase:
A $136 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
A net $95 million increase resulting from net energy costs and associated collections from customers under the FAC.
A decrease in income tax payments of $49 million to Ameren (parent) pursuant to the tax allocation agreement, primarily due to the lower federal income tax rate and lower property-related deductions.Ameren Illinois.
•A $27 million decrease in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center. There was no refueling and maintenance outage in 2018; however, there were cash expenditures related to the 2019 scheduled outage paid in 2018.
The increase was partially offset by a $25$13 million increase in energy center maintenance costs, primarily due to higher-than-normal nonnuclear scheduled outage costs, and an increase in routine maintenance work between periods.
Ameren Illinois
Ameren Illinois’ cash from operating activities decreased $169 million in 2018 compared with 2017. The following items contributed to the decrease:
A net $183 million decrease resulting from costs and associated collections under various cost recovery mechanisms from customers.
A $50 million decrease resulting from incomeproperty tax payments of $28 million, compared with income tax refunds of $22 million in 2017, to Ameren (parent) pursuant to the tax allocation agreement resulting primarily from the lower federal income tax rate and lower property-related deductions.
The following items partially offset the decrease in Ameren Illinois’ cash from operating activities between periods:
A $75 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
The absence of $17 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
2017 versus 2016
Ameren
Ameren’s cash from operating activities were comparable between 2017 and 2016. The following items increased cash from operating activities:
A $167 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
A $14 million decrease in coal inventory because of decreased market prices and decreased purchases at Ameren Missouri as a result of inventory reductions at its energy centers.due to higher assessed property tax values.
The following items largely offset the increase in Ameren’s cash from operating activities during 2017, compared with 2016:
A net $83 million decrease resulting from costs and associated collections under various cost recovery mechanisms from Ameren Missouri and Ameren Illinois customers.
The absence of a $42 million insurance receipt received in 2016 at Ameren Missouri related to the Taum Sauk breach that occurred in December 2005.
•Refunds paid in 20172020 of $21$13 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
The following items partially offset the decrease in Ameren’s cash from operating activities between periods:
•A $14$37 million increasedecrease in payroll tax payments primarily due to the cost employer portion of natural gas held in storage at Ameren Illinois, caused primarily by reduced withdrawalsSocial Security taxes as a result of milder winter temperatures compareda payment deferral allowed under the Coronavirus Aid, Relief, and Economic Security Act. Half of this deferral will be paid at the end of 2021 and the remaining half will be paid at the end of 2022.
•A $35 million decrease in energy center maintenance costs, other than those associated with the prior year.
A $13 million increase in interest payments,Callaway refueling and maintenance outage, at Ameren Missouri, primarily due to an increaselower electric system infrastructure maintenance expenses as a result of decreased system load, disciplined cost management, and the deferral of projects to future periods.
•An $11 million decrease in the average outstanding debtcoal inventory at Ameren Illinois.Missouri primarily as a result of decreased market prices and inventory reductions at the coal-fired energy centers.
Ameren Missouri
Ameren Missouri’s cash fromprovided by operating activities decreased $152$156 million in 20172020, compared with 2016.2019. The following items contributed to the decrease:
An increase in income tax payments of $151 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to higher taxable income in 2017, because of significantly lower property-related deductions.
The absence of a $42 million insurance receipt received in 2016 related to the Taum Sauk breach that occurred in December 2005.
•A net $47$190 million decrease resulting from costsreduced customer collections, primarily resulting from a decrease in sales volumes and associated collections under various costan increase in accounts receivable balances, which were primarily due to the COVID-19 pandemic, and a net decrease attributable to regulatory recovery mechanisms, partially offset by decreased fuel and purchased power costs.
•A $38 million increase in payments to settle ARO liabilities, primarily related to CCR storage facilities.
•A $17 million decrease in net collateral activity with counterparties, primarily resulting from customers.changes in the market prices of power and natural gas and changes in contracted commodity volumes.
•A $14 million increase in pension and postretirement benefit plan contributions.
•A $13 million increase in property tax payments due to higher assessed property tax values.
•A $12 million decrease, primarily resulting from increases to materials and supplies to support operations as levels were increased in 2020 to mitigate against any potential supply disruptions associated with the COVID-19 pandemic.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities between years:periods:
•A $70$76 million increase resulting fromdecrease in income tax payments to Ameren (parent) pursuant to the tax allocation agreement, primarily due to the timing of payments and lower taxable income in 2020.
•A $35 million decrease in energy center maintenance costs, other than those associated with the Callaway refueling and maintenance outage, primarily due to lower electric system infrastructure maintenance expenses as a result of decreased system load, disciplined cost management, and natural gas margins,the deferral of projects to future periods.
•A $17 million decrease in payroll tax payments primarily due to the employer portion of Social Security taxes as discussed in Resultsa result of Operations, excluding certain noncash items, as well asa payment deferral allowed under the change in customer receivable balances.Coronavirus Aid, Relief, and Economic Security Act. Half of this deferral will be paid at the end of 2021 and the remaining half will be paid at the end of 2022.
A $14•An $11 million decrease in coal inventory primarily as a result of decreased market prices and decreased purchases as a result of inventory reductions at the coal-fired
energy centers.
Ameren Illinois
Ameren Illinois’ cash fromprovided by operating activities increased $32decreased $283 million in 20172020, compared with 2016.2019. The following items contributed to the increase:decrease:
•A $75$195 million increasedecrease resulting from electricreduced customer collections, primarily resulting from a decrease in sales volumes and an increase in accounts receivable balances, which were primarily due to the COVID-19 pandemic, and a net decrease attributable to regulatory recovery mechanisms, partially offset by decreased purchased power costs and volumes, and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.costs.
•A $30$37 million increase resulting from income tax refunds of $22 million in 2017, compared with income tax payments of $8 million in 2016,to Ameren (parent) pursuant to the tax allocation agreement, primarily due to the timing of payments in 2020.
•A $13 million decrease, primarily resulting from increases to materials and supplies to support operations as levels were increased in 2020 to mitigate against any potential supply disruptions associated with Ameren (parent), primarily related to tax losses in 2017 as a result of higher property-related deductions and use of net operating losses.the COVID-19 pandemic.
The following items partially offset the•A $10 million increase in Ameren Illinois’ cash from operating activities between periods:interest payments, primarily due to an increase in the average outstanding debt.
•A net $36$10 million decrease in net collateral activity with counterparties, primarily resulting from costschanges in the market prices of power and associated collections under various cost recovery mechanismsnatural gas, changes in contracted commodity volumes, and decreases resulting from customers.renewable energy contracts entered into pursuant to the FEJA.
•Refunds paid in 20172020 of $17$9 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
•A $14$8 million increase in pension and postretirement benefit plan contributions.
The decrease in Ameren Illinois’ cash from operating activities between periods was partially offset by a $14 million decrease in payroll tax payments primarily due to the cost employer portion of natural gas held in storage, caused primarily by reduced withdrawalsSocial Security taxes as a result of milder winter temperatures compared witha payment deferral allowed under the prior year.
A $13 million increase in interest payments, primarily due to an increase inCoronavirus Aid, Relief, and Economic Security Act. Half of this deferral will be paid at the average outstanding debt.
end of 2021 and the remaining half will be paid at the end of 2022.
Pension Plans
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 Ameren’s assumptions at December 31, 2018,2020, its investment performance in 2018,2020, and its pension funding policy, Ameren expects to make annualaggregate contributions of $20$60 million to $70 million in each ofover the next five years, with aggregate estimated contributions of $200 million.years. We estimate that Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements will be approximately 30% and 60%, respectively. These estimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In 2018,2020, Ameren contributed $60$52 million to its pension plans. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.
Cash Flows from Investing Activities
2018 versus 2017
Ameren’s cash used in investing activities increased $132$894 million during 20182020, compared with 2017,2019, primarily as a result of a $564 million increase from the acquisition of the High Prairie Renewable Energy Center and a $258 million increase in capital expenditures. Cash used in investing activities also increased capital expenditures of $154due to a $45 million partially offset by an $11increase in net investment activity in the nuclear decommissioning trust fund at Ameren Missouri and a $35 million decreaseincrease due to the timing of nuclear fuel expenditures. IncreasedIn addition to the capital expendituresexpenditure changes at Ameren Missouri and Ameren Illinois discussed below, Ameren’s capital expenditures were partially offset by a $171$43 million decrease in capital expenditures at ATXI. ATXI’s capital expenditures decreasedATXI and other electric transmission subsidiaries, primarily as a result of decreased Mark Twain transmission line expenditures, on the Illinois Rivers and Spoon River projects. The Spoon River projectas it was placed in service in February 2018.2019. In 2020, ATXI placed the ninth and final line segment of the Illinois Rivers transmission line in service.
Ameren Missouri’s cash used in investing activities increased $292$809 million during 20182020, compared with 2017,2019, primarily due to money pool activity and increased capital expenditures. During 2018, Ameren Missouri had no money pool activity, compared with $161as a result of $564 million in returnscash paid for the acquisition of the High Prairie Renewable Energy Center and a $139 million increase in net money pool advances received during 2017. Additionally, capital expendituresadvances. Cash used in investing activities also increased $141due to a $45 million between periods, primarily related to energy center projects and electric distribution system reliability projects. The increase in capital expenditures was partially offset by an $11net investment activity in the nuclear decommissioning trust fund, a $35 million decreaseincrease due to the timing of nuclear fuel expenditures.
Ameren Illinois’ cash used in investing activities increased $178 million during 2018 compared with 2017 due to an increase in capital expenditures, of $182 million, primarily related to substation upgrades, upgrades to natural gas main infrastructure, and electric transmission system reliability projects.
2017 versus 2016
Ameren’s cash used in investing activities increased $46 million during 2017 compared with 2016, primarily as a result of increased capital expenditures of $56 million. Increased capital expenditures at Ameren Missouri and Ameren Illinois, discussed below, were partially offset by a $127 million decrease in capital expenditures at ATXI. Reduced spending on ATXI’s Illinois Rivers project was partially offset by an increase in spending on its Spoon River project.
Ameren Missouri’s cash used in investing activities decreased $253 million during 2017 compared with 2016, primarily because of net money pool advances. During 2017, Ameren Missouri received $161 million in returns of net money pool advances compared with investing $125 million in net money pool advances in 2016. This decrease was partially offset by a $35$26 million increase in capital expenditures, primarily related to electric distributiondelivery infrastructure upgrades and electric transmission system reliability projects and energy center projects.
Ameren Illinois’ cash used in investing activities increased $152$239 million during 20172020, compared with 2016 because of increased2019, due to an increase in capital expenditures, primarily related to electric transmission system reliability projects and natural gas infrastructure projects.
Capital Expenditures
The following table presentscharts present our capital expenditures for the years ended December 31, 2018, 2017,2020 and 2016:2019:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Ameren Missouri | $ | 914 |
| | $ | 773 |
| | $ | 738 |
|
| Ameren Illinois Electric Distribution | 503 |
| | 476 |
| | 470 |
|
| Ameren Illinois Natural Gas | 311 |
| | 245 |
| | 181 |
|
| Ameren Illinois Transmission | 444 |
| | 355 |
| | 273 |
|
| ATXI | 118 |
| | 289 |
| | 416 |
|
Other (a) | (4 | ) | | (6 | ) | | (2 | ) |
| Ameren | $ | 2,286 |
| | $ | 2,132 |
| | $ | 2,076 |
|
| | | | | | | | |
|
2020 – Total Ameren $3,233(a) | Includes amounts for the elimination of intercompany transfers. | 2019 – Total Ameren $2,411(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 $7 million and $(29) million for the years ended December 31, 2020 and 2019, respectively, which includes amounts for the elimination of intercompany transfers.
(b)Ameren Missouri capital expenditures include $564 million for the acquisition of the High Prairie Renewable Energy Center for the year ended December 31, 2020.
Ameren’s 20182020 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI and other electric transmission subsidiaries, which spent $118$113 million primarily on the Illinois Rivers and Mark Twain projects.transmission line. Of the $301 million in capital expenditures spent by Ameren Illinois spent $444Natural Gas during 2020, $189 million on transmission projects, $188 million onrelated to natural gas projects eligible for QIP recovery, and $89recovery. In addition, Ameren Missouri expenditures included approximately $564 million on IEIMA projects. Otherfor the acquisition of the High Prairie Renewable Energy Center. In both years, other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects.
Ameren’s 20172019 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $289$156 million primarily on the Mark Twain and Illinois Rivers and Spoon River projects.transmission lines. Of the $318 million in capital expenditures spent by Ameren Illinois spent $355Natural Gas during 2019, $203 million on transmission projects, $153 million onrelated to natural gas projects eligible for QIP recovery, and $123 million on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri andrecovery. Ameren Illinois by investingexceeded the minimum capital spending levels required pursuant to IEIMA in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects.2019.
Ameren’s 2016 capital expenditures consisted
The following table presents Ameren’s estimate of capital expenditures that will be incurred from 20192021 through 2023,2025, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations: | | | | 2019 | | 2020-2023 | | Total | | 2021 | | 2022-2025 | | Total |
| Ameren Missouri | $ | 1,070 |
| | $ | 5,410 |
| – | $ | 5,980 |
| | $ | 6,480 |
| – | $ | 7,050 |
| Ameren Missouri | $ | 2,205 | | | $ | 6,450 | | – | $ | 7,130 | | | $ | 8,655 | | – | $ | 9,335 | |
| Ameren Illinois Electric Distribution | 495 |
| | 1,925 |
| – | 2,125 |
| | 2,420 |
| – | 2,620 |
| Ameren Illinois Electric Distribution | 515 | | | 2,060 | | – | 2,280 | | | 2,575 | | – | 2,795 | |
| Ameren Illinois Natural Gas | 350 |
| | 1,165 |
| – | 1,290 |
| | 1,515 |
| – | 1,640 |
| Ameren Illinois Natural Gas | 335 | | | 1,315 | | – | 1,450 | | | 1,650 | | – | 1,785 | |
| Ameren Illinois Transmission | 360 |
| | 1,765 |
| – | 1,950 |
| | 2,125 |
| – | 2,310 |
| Ameren Illinois Transmission | 615 | | | 2,715 | | – | 3,000 | | | 3,330 | | – | 3,615 | |
| ATXI | 155 |
| | 65 |
| – | 70 |
| | 220 |
| – | 225 |
| |
| ATXI and Other Electric Transmission Subsidiaries | | ATXI and Other Electric Transmission Subsidiaries | 55 | | | 130 | | – | 140 | | | 185 | | – | 195 | |
| Other | 5 |
| | 5 |
| – | 5 |
| | 10 |
| – | 10 |
| Other | 5 | | | 20 | | – | 25 | | | 25 | | – | 30 | |
| Ameren | $ | 2,435 |
| | $ | 10,335 |
| – | $ | 11,420 |
| | $ | 12,770 |
| – | $ | 13,855 |
| Ameren | $ | 3,730 | | | $ | 12,690 | | – | $ | 14,025 | | | $ | 16,420 | | – | $ | 17,755 | |
Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, as well as expenditures for compliance with environmental regulations. In addition, Ameren Missouri’s estimated capital expenditures include approximately $1 billion in$500 million related to 300 MWs of wind generation investments expectedat the Atchison Renewable Energy Center, but exclude incremental renewable generation investment opportunities of 1,200 MWs by 2025, which are included in 2020.Ameren Missouri’s 2020 IRP. As of the date of this filing, no contractual agreements have been entered into, and no regulatory approvals have been requested, related to these opportunities. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, including capital expenditures to modernize its electric and gas distribution system pursuant tosystems. These planned investments are based on the IEIMA,assumption of continued constructive regulatory frameworks, including an assumption that Ameren Missouri requests and capital expenditures for qualified investments in natural gas infrastructure underreceives MoPSC approval of an extension of the QIP rider. ATXI’s estimated capital expenditures include expenditures for the two MISO-approved multi-value transmission projects. For additional information regarding Ameren Missouri’s build-transfer wind agreements, IEIMA capital expenditure requirements, the QIP rider, and ATXI’s transmission projects, see Part I, Item 1, of this report.PISA through December 2028.
Ameren Missouri continually reviews its generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments within and outside our service territories. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.
Environmental Capital Expenditures
Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO2, NOx, and mercury emissions from its coal-fired energy centers. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws that affect, or may affect, our facilities and capital expenditures to comply with such laws.
Cash Flows from Financing Activities
Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the level of dividends, and our long-term debt maturities, among other things. As a result of capital market volatility, due, in part, to the COVID-19 pandemic, and to increase net available liquidity, Ameren (parent) accelerated a debt issuance to April 2020, which had been planned for later in 2020.
2018 versus 2017
Ameren’s cash provided by financing activities increased $103$1,393 million during 20182020, compared with 2017.2019. During 2018,2020, Ameren utilized net proceeds of $2,183 million from the issuance of $1,464 millionlong-term debt for general corporate purposes, including to repay then-outstanding short-term debt, including short-term debt incurred in connection with the repayment at maturity of long-term indebtednessdebt, to partially finance the acquisition of two wind generation facilities, and to repay other long-term debt. In addition, Ameren received cash proceeds of $425 million from the partial settlement of a forward sale agreement of common stock that were used to fund a portion of Ameren Missouri’s wind generation investments. Collectively, in 2020, Ameren repaid long-term debt of $442 million, received $50 million from net commercial paper issuances, and used cash on hand to repay $841 million of higher-cost long-term indebtedness andprovided by financing activities to fund, in part, investing activities. In comparison, during 2017,in 2019, Ameren utilized net proceeds of $1,527 million from the issuance of $1,345 millionlong-term debt to repay then-outstanding short-term debt, including short-term debt incurred in connection with the repayment at maturity of long-term indebtednessdebt, and to repay $681at maturity other long-term debt. Collectively, in 2019, Ameren repaid long-term debt of $580 million, repaid net short-term debt of higher-cost long-term indebtedness, to repay $74$157 million, of net commercial paper issuances, and used cash provided by financing activities to fund, in part, investing activities. During 2018,2020, Ameren made $451paid common stock dividends of $494 million, in dividend payments to shareholders, compared with $431$472 million, in dividend payments in 2017. Additionally, Ameren issued $74 million in common stock under its DRPlus and 401(k) plan during 2018. Ameren also issued $35 million2019.
Ameren Missouri’s cash used inprovided by financing activities decreased $48increased $1,040 million in 2018during 2020, compared with 2017.2019. During 2018,2020, Ameren Missouri utilized net proceeds of $1,012 million from the issuance of $439 millionlong-term debt to repay then-outstanding short-term debt, including short-term debt incurred in connection with the repayment at maturity of long-term indebtednessdebt, and to partially finance the acquisition of two wind generation facilities. Collectively, in 2020, Ameren Missouri repaid long-term debt of $92 million, repaid net commercial paper issuances, along withshort-term debt of $234 million, and used cash on hand, to repay $384 million of higher-cost long-term indebtedness andprovided by financing activities to fund, in part, investing activities. In comparison, during 2017,in 2019, Ameren Missouri utilized net proceeds of $778 million from the issuance of $438 millionlong-term debt to repay then-outstanding short-term debt, including short-term debt incurred in connection with the repayment at maturity of long-term indebtednessdebt, and to repay at maturity other long-term debt. Collectively, in 2019, Ameren Missouri repaid long-term debt of $580 million, received $179 million from net commercial paper issuances, along withand used cash on hand,provided by financing activities to repay $431 million of higher-cost long-term indebtedness. In 2018, Ameren Missouri paid $375 millionfund, in common stock dividends, compared with $362 million in dividend payments in 2017. Additionally, during 2018,part, investing activities. During 2020, Ameren Missouri received $45$491 million in capital contributions from Ameren (parent), of which, $67 million was associated with the tax allocation agreement, compared with $30$124 million in capital contributions received in 2017.2019. During 2020, Ameren Missouri paid common stock dividends of $66 million, compared with $430 million in dividend payments in 2019, due to an increase in investing cash needs, including the acquisition of wind generation facilities.
Ameren Illinois’ cash provided by financing activities increased $373$499 million during 2020, compared with 2019. During 2020, Ameren Illinois received $464 million in 2018,capital contributions from Ameren (parent), of which, $9 million was associated with the tax allocation agreement, compared with 2017. During 2018,$15 million in capital contributions received in 2019. In addition, Ameren Illinois utilized net proceeds of $373 million from the issuance of $939 million of long-term indebtedness and net commercial paper issuancesdebt to repay at maturity $457then-outstanding short-term debt. Collectively, in 2020, Ameren Illinois repaid net short-term debt of $53 million, of higher-cost long-term indebtedness and used cash provided by financing activities to fund, in part, investing activities. In comparison, during 2017,in 2019, Ameren Illinois issued $507 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay $250 million of higher-cost long-term indebtedness, and to fund, in part, investing activities. Additionally, during 2018, Ameren Illinois received $160 million in capital contributions from Ameren (parent), compared with $8 million received in 2017.
2017 versus 2016
Ameren’s financing activities provided net cash of $102 million in 2017 compared with using net cash of $258 million in 2016. During 2017, Ameren utilized net proceeds of $299 million from the issuance of $1,345 million of long-term indebtednessdebt to repay $681then-outstanding short-term debt. Collectively, in 2019 Ameren Illinois repaid net short-term debt of $19 million, of higher-cost long-term indebtedness, to repay $74 million of net commercial paper issuances, and used cash provided by financing activities to fund, in part, investing activities. In comparison,addition, during 2016,2020, Ameren utilized net proceedsIllinois borrowed $19 million from the issuancemoney pool and paid common stock dividends of $653 million of long-term indebtedness and net commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and to fund, in part, investing activities. Additionally, during 2017, Ameren made $431 million in dividend payments to shareholders, compared with $416 million in dividend payments in 2016.$9 million.
Ameren Missouri’s cash used in financing activities decreased $103 million in 2017 compared with 2016. During 2017, Ameren Missouri utilized net proceeds from the issuance of $438 million of long-term indebtedness and net commercial paper issuances to repay $431 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In 2017, Ameren Missouri paid $362 million in dividends to Ameren (parent), compared with $355 million dividends paid in 2016. Additionally, during 2017, Ameren Missouri received $30 million in capital contributions from Ameren (parent) associated with the tax allocation agreement, compared with $44 million received in 2016.
Ameren Illinois’ cash provided by financing activities increased by $204 million in 2017, compared with 2016. During 2017, Ameren Illinois utilized net proceeds from the issuance of $507 million of long-term indebtedness and net commercial paper issuances to repay at maturity $250 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Illinois issued $298 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay at maturity $129 million of higher-cost long-term indebtedness. Additionally, in 2017, no dividends were paid to Ameren (parent), compared with $110 million paid in 2016.
Credit Facility Borrowings and Liquidity
The liquidity needs of the Ameren Ameren Missouri, and Ameren IllinoisCompanies are typically supported through the use of available cash, or proceeds from borrowingsdrawings under the Credit Agreements,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, borrowings under Ameren’s money pool arrangements and related borrowings, and relevant interest rates.
The following table presents Ameren’s consolidated net available liquidity as of December 31, 2018:2020:
|
| | | | |
| | | Available at December 31, 2018 |
Ameren (parent) and Ameren Missouri (a): | | |
Missouri Credit Agreement – borrowing capacity | | $ | 1,000 |
|
| Less: Ameren (parent) commercial paper outstanding | | 274 |
|
| Less: Ameren Missouri commercial paper outstanding | | 55 |
|
| Less: Letters of credit | | 7 |
|
Missouri Credit Agreement – subtotal | | 664 |
|
Ameren (parent) and Ameren Illinois(b): | | |
Illinois Credit Agreement – borrowing capacity | | 1,100 |
|
| Less: Ameren (parent) commercial paper outstanding | | 196 |
|
| Less: Ameren Illinois commercial paper outstanding | | 72 |
|
| Less: Letters of credit | | 2 |
|
Illinois Credit Agreement – subtotal | | 830 |
|
| Subtotal | | $ | 1,494 |
|
| Cash and cash equivalents | | 16 |
|
| Net Available Liquidity | | $ | 1,510 |
|
| | | | | | | | |
(a) | The maximum aggregate amount available to | Available at
December 31, 2020 |
Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $700 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.(a): |
| |
(b)Missouri Credit Agreement – borrowing capacity | The maximum aggregate amount available to | $ | 1,200 | |
| Less: Ameren (parent) commercial paper outstanding | | 315 | |
| | |
| Less: Letters of credit | | 3 | |
Missouri Credit Agreement – subtotal | | 882 | |
Ameren (parent) and Ameren Illinois under the (b): | | |
Illinois Credit Agreement is $500 million– borrowing capacity | | 1,100 | |
| Less: Ameren (parent) commercial paper outstanding | | 175 | |
| | |
| Less: Letters of credit | | 1 | |
Illinois Credit Agreement – subtotal | | 924 | |
| Subtotal | | $ | 1,806 | |
Cash and $800 million, respectively. See Note 4 – Short-term Debt andcash equivalents | | 139 | |
Net Available Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements. | | $ | 1,945 | |
In December 2018, the Credit Agreements, which were scheduled to mature in December 2021, were extended and now mature in December 2022.(a) The Credit Agreements provide $2.1 billion of credit cumulatively through maturity. The maturity date may be extended for an additional one-year period upon mutual consent of the borrowers and lenders. Borrowings by Ameren (parent) under either of the Credit Agreements are due and payable no later than the maturity date, while borrowings by Ameren Missouri and Ameren Illinois are due and payable no later than the earlier of the maturity date or 364 days after the date of such borrowing (subject to the right of each borrower to re-borrow in accordance with the terms of the applicable Credit Agreement). The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the credit agreements aremaximum aggregate amount available to Ameren (parent) to support issuancesand Ameren Missouri under Ameren (parent)’s commercial paper program, subject to available credit capacity under the agreements. The Missouri Credit Agreement is $900 million and $850 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.
(b) The maximum aggregate amount available to support issuancesAmeren (parent) and Ameren Illinois under Ameren Missouri’s commercial paper program. Thethe Illinois Credit Agreement is available to support issuances$500 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Ameren Illinois’ commercial paper program. IssuancesPart II, Item 8, of this report for further discussion of the Credit Agreements.
The Credit Agreements, among other things, provide $2.3 billion of credit until maturity in December 2024. 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, 2020, Ameren (parent), Ameren Missouri, and Ameren Illinois commercial paper programs were available at lower interest rates than the interest rates of borrowingseach borrowed under the Credit Agreements. CommercialAgreements and issued commercial paper. Borrowings under the Credit Agreements and commercial paper issuances were thus preferred to credit facility borrowings asare based upon available interest rates at that time of the borrowing or issuance. As a sourceresult of third-party short-term debt.volatility in the capital markets, the Ameren Companies borrowed under the Credit Agreements in certain instances in the first quarter of 2020 rather than issuing commercial paper.
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. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a detailed explanation of the utility money pool arrangement.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval under the Federal Power Act. In 2018,2020, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 20202022 and September 2020,2022, respectively. In June 2017,July 2019, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2019.2021.
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.arrangements, or other arrangements may be made.
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, issuances, as well as issuances (net of issuance premiums or discounts), redemptions repurchases, and maturities of long-term debt for the years ended December 31, 2018, 2017,2020 and 2016.2019. For additional information related to the terms and uses of these issuances and effective registration statements, and Ameren’s forward sale agreement 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. Additionally, Ameren Illinois will redeem all outstanding shares of its 6.625% and 7.75% series preferred stock in March 2021.
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| | | | | | | | | | | | | |
| | Month Issued, Redeemed, Repurchased, or Matured | | 2018 | | 2017 | | 2016 |
| Issuances of Long-term Debt | | | | | | | |
| Ameren Missouri: | | | | | | | |
| 4.00% First mortgage bonds due 2048 | April | | $ | 423 |
| | $ | — |
| | $ | — |
|
| 2.95% Senior secured notes due 2027 | June | | — |
| | 399 |
| | — |
|
| 3.65% Senior secured notes due 2045 | June | | — |
| | — |
| | 149 |
|
| Ameren Illinois: | | | | | | | |
| 3.80% First mortgage bonds due 2028 | May | | 430 |
| | — |
| | — |
|
| 4.50% First mortgage bonds due 2049 | November | | 499 |
| | — |
| | — |
|
| 3.70% First mortgage bonds due 2047 | November | | — |
| | 496 |
| | — |
|
| 4.15% Senior secured notes due 2046 | December | | — |
| | — |
| | 247 |
|
| ATXI: | | | | | | | |
| 3.43% Senior notes due 2050 | June | | — |
| | 150 |
| | — |
|
| 3.43% Senior notes due 2050 | August | | — |
| | 300 |
| | — |
|
| Total long-term debt issuances | | | $ | 1,352 |
| | $ | 1,345 |
| | $ | 396 |
|
| Issuances of Common Stock | | | | | | | |
| Ameren: | | | | | | | |
| DRPlus and 401(k) | Various | | $ | 74 |
| (a)(b) | $ | — |
| | $ | — |
|
| Total common stock issuances | | | $ | 74 |
| | $ | — |
| | $ | — |
|
| Total Ameren long-term debt and common stock issuances | | | $ | 1,426 |
| | $ | 1,345 |
| | $ | 396 |
|
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | | | |
| Ameren Missouri: | | | | | | | |
| 6.00% Senior secured notes due 2018 | April | | 179 |
| | — |
| | — |
|
| 5.10% Senior secured notes due 2018 | August | | 199 |
| | — |
| | — |
|
| 6.40% Senior secured notes due 2017 | June | | — |
| | 425 |
| | — |
|
| 5.40% Senior secured notes due 2016 | February | | — |
| | — |
| | 260 |
|
| City of Bowling Green financing obligation (Peno Creek CT) | December | | 6 |
| | 6 |
| | 6 |
|
| Ameren Illinois: | | | | | | | |
| 6.25% Senior secured notes due 2018 | April | | 144 |
| | — |
| | — |
|
| 9.75% Senior secured notes due 2018 | November | | 313 |
| | — |
| | — |
|
| 6.125% Senior secured notes due 2017 | November | | — |
| | 250 |
| | — |
|
| 6.20% Senior secured notes due 2016 | June | | — |
| | — |
| | 54 |
|
| 6.25% Senior secured notes due 2016 | June | | — |
| | — |
| | 75 |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 841 |
| | $ | 681 |
| | $ | 395 |
|
| | | | | | | | | | | | | | | | | | | |
| Month Issued, Redeemed, Repurchased, or Matured | | 2020 | | 2019 | | |
| Issuances of Long-term Debt | | | | | | | |
| Ameren: | | | | | | | |
| 3.50% Senior unsecured notes due 2031 | April | | $ | 798 | | | $ | — | | | |
| 2.50% Senior unsecured notes due 2024 | September | | — | | | 450 | | | |
| Ameren Missouri: | | | | | | | |
| 2.95% First mortgage bonds due 2030 | March | | 465 | | | — | | | |
| 2.625% First mortgage bonds due 2051 (green bonds) | October | | 547 | | | — | | | |
| 3.50% First mortgage bonds due 2029 | March | | — | | | 450 | | | |
| 3.25% First mortgage bonds due 2049 | October | | — | | | 328 | | | |
| Ameren Illinois: | | | | | | | |
| 1.55% First mortgage bonds due 2030 | November | | 373 | | | — | | | |
| 3.25% First mortgage bonds due 2050 | November | | — | | | 299 | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total long-term debt issuances | | | $ | 2,183 | | | $ | 1,527 | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Issuances of Common Stock | | | | | | | |
| Ameren: | | | | | | | |
DRPlus and 401(k)(a)(b) | Various | | $ | 51 | | | $ | 68 | | | |
Forward sale agreement(c) | December | | 425 | | | — | | | |
| Total common stock issuances | | | $ | 476 | | | $ | 68 | | | |
| Total Ameren long-term debt and common stock issuances | | | $ | 2,659 | | | $ | 1,595 | | | |
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | | | |
| Ameren: | | | | | | | |
| 2.70% Senior unsecured notes due 2020 | October | | $ | 350 | | | $ | — | | | |
| Ameren Missouri: | | | | | | | |
| 5.00% Senior secured notes due 2020 | February | | 85 | | | — | | | |
| 6.70% Senior secured notes due 2019 | February | | — | | | 329 | | | |
| 5.10% Senior unsecured notes due 2019 | October | | — | | | 244 | | | |
| 5.45% First mortgage bonds due 2028 | October | | — | | | (d) | | |
| City of Bowling Green financing obligation (Peno Creek CT) | December | | 7 | | | 7 | | | |
| Ameren Illinois: | | | | | | | |
| 5.70% First mortgage bonds due 2024 | September | | — | | | (d) | | |
| 5.90% First mortgage bonds due 2023 | October | | — | | | (d) | | |
| | | | | | | |
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 442 | | | $ | 580 | | | |
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(a) Ameren issued a total of 1.20.7 million and 0.9 million shares of common stock under its DRPlus and 401(k) plan.plan in 2020 and 2019, respectively.
(b) Excludes 0.70.5 million and 0.8 million shares of common stock valued at $35$38 million and $54 million issued for no cash consideration in connection with stock-based compensation.compensation in 2020 and 2019, respectively.
(c) Ameren issued 5.9 million shares of common stock pursuant to a partial settlement of a forward sale agreement in December 2020.
(d) Amount less than $1 million.
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, 2018,2020, 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 agreement. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreement.
We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in
the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets.markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $451$494 million, or $1.8475$2.00 per share, in 2018, $4312020 and $472 million, or $1.7775$1.92 per share, in 2017, and $416 million, or $1.715 per share, in 2016.
2019. The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On February 8, 2019,12, 2021, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 47.555 cents per share, payable on March 29, 2019,31, 2021, to shareholders of record on March 13, 2019.10, 2021.
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, 2018,2020, 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 $2.8$3.3 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:
| | | | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | |
| Ameren | $ | 451 |
| | $ | 431 |
| | $ | 416 |
| Ameren | $ | 494 | | | $ | 472 | | |
| Ameren Missouri | 375 |
| | 362 |
| | 355 |
| Ameren Missouri | 66 | | | 430 | | |
| Ameren Illinois | — |
| | — |
| | 110 |
| Ameren Illinois | 9 | | | — | | |
| ATXI | 75 |
| | — |
| | — |
| ATXI | 30 | | | 15 | | |
Ameren Missouri and Ameren Illinois each have issued preferred stock, which provides for cumulative preferred stock 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.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2018.2020. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans, which are not included in the table below. In addition, routine short-term purchase order commitments are not included. |
| | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2020 – 2021 | | 2022 – 2023 | | 2024 and Thereafter | | Total |
Ameren:(a) | | | | | | | | | |
Long-term debt and financing obligations(b) | $ | 580 |
| | $ | 450 |
| | $ | 745 |
| | $ | 6,734 |
| | $ | 8,509 |
|
Interest payments(c) | 348 |
| | 653 |
| | 625 |
| | 4,281 |
| | 5,907 |
|
| Operating leases | 10 |
| | 15 |
| | 11 |
| | 9 |
| | 45 |
|
Other obligations(d) | 799 |
| | 746 |
| | 221 |
| | 166 |
| | 1,932 |
|
| Total cash contractual obligations | $ | 1,737 |
| | $ | 1,864 |
| | $ | 1,602 |
| | $ | 11,190 |
| | $ | 16,393 |
|
| Ameren Missouri: | | | | | | | | | |
Long-term debt and financing obligations(b) | $ | 580 |
| | $ | 100 |
| | $ | 295 |
| | $ | 3,054 |
| | $ | 4,029 |
|
Interest payments(c) | 176 |
| | 322 |
| | 319 |
| | 1,934 |
| | 2,751 |
|
| Operating leases | 8 |
| | 13 |
| | 10 |
| | 9 |
| | 40 |
|
Other obligations(d) | 467 |
| | 489 |
| | 195 |
| | 130 |
| | 1,281 |
|
| Total cash contractual obligations | $ | 1,231 |
| | $ | 924 |
| | $ | 819 |
| | $ | 5,127 |
| | $ | 8,101 |
|
| Ameren Illinois: | | | | | | | | | |
Long-term debt(b) | $ | — |
| | $ | — |
| | $ | 400 |
| | $ | 2,930 |
| | $ | 3,330 |
|
Interest payments(c) | 133 |
| | 266 |
| | 253 |
| | 2,140 |
| | 2,792 |
|
| Operating leases | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Other obligations(d) | 322 |
| | 243 |
| | 26 |
| | 20 |
| | 611 |
|
| Total cash contractual obligations | $ | 456 |
| | $ | 509 |
| | $ | 679 |
| | $ | 5,090 |
| | $ | 6,734 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022 – 2023 | | 2024 – 2025 | | 2026 and Thereafter | | Total |
| Ameren: | | | | | | | | | |
Long-term debt and financing obligations(a) | $ | 8 | | | $ | 745 | | | $ | 1,150 | | | $ | 9,287 | | | $ | 11,190 | |
| Interest payments | 431 | | | 843 | | | 741 | | | 4,876 | | | 6,891 | |
| Operating leases | 9 | | | 16 | | | 11 | | | 5 | | | 41 | |
Other obligations(b) | 788 | | | 697 | | | 289 | | | 195 | | | 1,969 | |
| Total cash contractual obligations | $ | 1,236 | | | $ | 2,301 | | | $ | 2,191 | | | $ | 14,363 | | | $ | 20,091 | |
| Ameren Missouri: | | | | | | | | | |
Long-term debt and financing obligations(a) | $ | 8 | | | $ | 295 | | | $ | 350 | | | $ | 4,499 | | | $ | 5,152 | |
| Interest payments | 216 | | | 427 | | | 358 | | | 2,412 | | | 3,413 | |
| Operating leases | 8 | | | 14 | | | 10 | | | 5 | | | 37 | |
Other obligations(b) | 503 | | | 503 | | | 258 | | | 126 | | | 1,390 | |
| Total cash contractual obligations | $ | 735 | | | $ | 1,239 | | | $ | 976 | | | $ | 7,042 | | | $ | 9,992 | |
| Ameren Illinois: | | | | | | | | | |
Long-term debt(a) | $ | — | | | $ | 400 | | | $ | 300 | | | $ | 3,288 | | | $ | 3,988 | |
| Interest payments | 148 | | | 283 | | | 268 | | | 2,166 | | | 2,865 | |
Other obligations(b) | 290 | | | 200 | | | 33 | | | 47 | | | 570 | |
| Total cash contractual obligations | $ | 438 | | | $ | 883 | | | $ | 601 | | | $ | 5,501 | | | $ | 7,423 | |
| |
(a) | Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations. |
| |
(b) | (a)Excludes unamortized discount and premium and debt issuance costs of $12 million, $48 million, and $42 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of this report, for discussion of items included herein. (b)See Other Obligations in Note 14 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein. Excludes unamortized discount and premium and debt issuance costs of $70 million, $31 million, and $34 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of this report, for discussion of items included herein.
|
| |
(c) | The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2018.
|
| |
(d) | See Other Obligations in Note 14 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein. |
Off-balance-sheet Arrangements
At December 31, 2018,2020, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business,forward sale agreement relating to common stock, which was fully settled by mid-February 2021, and variable interest entities, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries.entities. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for further detail concerning variable interest entities. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the forward sale agreement relating to common stock.
Credit Ratings
Our credit ratings affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.
The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:
|
| | | | | | | |
| Moody’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+ |
| Secured debt | A2 | A |
| Senior unsecured debt | Baa1 | Not Rated |
| Commercial paper | P-2 | A-2 |
| Ameren Illinois: | | |
| Issuer/corporate credit rating | A3 | BBB+ |
| Secured 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, and cash collateral posted by external parties were immaterial at December 31, 2018.2020. A sub-investment-grade issuer or senior unsecured debt rating (below “Baa3” from Moody’s or below “BBB-” from S&P) at December 31, 2018,2020, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade obligations amounting to $94$119 million, $64$105 million, and $30$14 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2018,2020, if market prices were 15% higher or lower than December 31, 2018,2020 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade obligations.
OUTLOOK
We seek to earn competitive returns on investments in our businesses. We seek to improve our regulatory frameworks and cost recovery mechanisms and are simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators, to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity and allocating capital resources to business opportunities that we expect will offer the most attractive risk-adjusted return potential.
As part of Ameren’s strategic plan, we pursue projects to meet our customers’ energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories. Ameren also evaluates competitive electric transmission investment opportunities as they arise. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition to a more diverse energy generation portfolio, including investments in renewable energy resources and the retirement of its coal-fired generation at the end of each energy center’s useful life.
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 20192021 and beyond.
The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. We continue to assess the impacts the pandemic is having on our businesses, including but not limited to impacts on our liquidity; demand for residential, commercial, and industrial electric and natural gas services; changes in deferred payment arrangements for customers; the timing and extent to which recovery of incremental costs incurred, net of savings, and forgone customer late fee revenues at Ameren Missouri is allowed by the MoPSC; changes in our ability to disconnect customers for nonpayment; bad debt expense; supply chain operations; the availability of our employees and contractors; counterparty credit; capital construction; infrastructure operations and maintenance; energy-efficiency programs; and pension valuations. For additional information regarding recent rate orders, lawsuits, and pending requests filed with state and federal regulatory commissions, including those discussed below, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Operations
•In 2020, we experienced a net decrease in our sales volumes, which have been, and continue to be, affected by the COVID-19 pandemic, among other things, but we expect gradual improvement in economic activities in 2021. Further, our customers’ payment for services has been adversely affected by the COVID-19 pandemic, which led to an increase in our accounts receivable balances that are past due or that are a part of a deferred payment arrangement. Because of their regulatory frameworks, Ameren Illinois’ and ATXI’s
revenues are largely decoupled from changes in sales volumes. Additionally, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Pursuant to a June 1, 2018, Missouri Senate Bill 564 was enacted. The provision2020 ICC order, Ameren Illinois’ electric bad debt rider provided for the recovery of the law applicablebad debt expense in 2020, which reverted to the TCJA was effective immediately;recovery of bad debt write-offs, net of any subsequent recoveries, in 2021. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri does not expect a material impact to earnings from increases in bad debt expense. See the remaining provisions, including the ability to elect PISA, became effective August 28, 2018. The law required the MoPSC to authorize a reductionResults of Operations section above for additional information on our accounts receivable balances and changes in Ameren Missouri’s ratessales volumes in 2020, compared to pass through the effect of the TCJA within 90 days of the law’s effective date. In July 2018, the MoPSC authorized Ameren Missouri2019, and sales volumes expected in 2021, compared to reduce its annual revenue requirement by $167 million and reflect that reduction in rates beginning August 1, 2018. The reduction included $74 million for the amortization of excess accumulated deferred income taxes. In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $60 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review.Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, and all approved PISA deferrals will be added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. PISA mitigates the impacts of regulatory lag between regulatory rate reviews. The remaining 15% of certain property, plant, and equipment placed in service and not eligible for recovery under PISA, unless eligible for recovery under the RESRAM, remain subject to regulatory lag.As a result of the PISA election, additional provisions of the new law apply to Ameren Missouri, including limitations on electric customer rate increases and an electric base rate freeze until April 2020. Both the rate increase limitation and PISA are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. SeeAdditionally, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Missouri Senate Bill 564.
In February 2019,on Ameren Missouri’s and Ameren Illinois’ reinstatement of customer disconnection and late fee charges for non-payment, requests filed with the MoPSC for accounting authority orders related to Ameren Missouri’s electric and natural gas services to allow Ameren Missouri announced its Smart Energy Plan,to accumulate certain costs incurred, net of savings, and forgone customer late fee revenues related to the COVID-19 pandemic for consideration of recovery in future regulatory rate reviews, and a June 2020 ICC order in a service disconnection moratorium proceeding, which includesrequired Ameren Illinois to implement more flexible credit and collection practices and allowed for recovery of costs incurred related to the COVID-19 pandemic and forgone late fees.
•In mid-February 2021, extremely cold weather in the central and southern United States, including in our service territories, caused a five-year capital investment overviewsignificant increase in customer demand for electricity and natural gas. These weather conditions resulted in industry natural gas supply disruptions and limitations, and operational issues at generation and transmission facilities throughout the regions. However, we did not experience significant generation or reliability issues. These events resulted in significant increases in power and natural gas prices in the energy markets. As a result of market purchases to serve incremental demand, Ameren Illinois and Ameren Missouri incurred additional natural gas costs of approximately $200 million and $50 million, respectively, for purchases made for resale between February 13, 2021, and February 17, 2021. These amounts are preliminary estimates and are subject to final settlement. The increase in our purchased power costs over the same time period was immaterial. Ameren Missouri and Ameren Illinois have riders to recover natural gas and purchased power costs. We do not expect this event will have a significant impact on our financial results or liquidity.
•The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on investments in certain property, plant, and equipment placed in service, and not included in base rates. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC, with all approved PISA deferrals added to rate base prospectively and recovered over a detailed one-year plan for 2019, designed to upgrade Ameren Missouri's electric infrastructure. The plan includes investments that will upgrade the grid and accommodate more renewable energy. Investmentsperiod of 20 years following a regulatory rate review. Additionally, under the plan are expected to total approximately $6.3 billion over the five-year period from 2019 through 2023, with costs largely recoverable under PISA and, for the portion of wind and other renewable generation investments that are not recoverable under PISA, recoverable under the RESRAM.
In June 2018, the MoPSC approvedRESRAM, Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to elect to receive up to 100% of their energy from renewable resources. The tariff-based programMissouri is designedpermitted 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. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Ameren Missouri recognizes the cost of debt on PISA deferrals in revenue, instead of using the applicable WACC, with the difference recognized in revenues when recovery of such deferrals is reflected in customer rates. As a result of the PISA election, netadditional provisions of changes in the market price of such energy. Based on customer contracts, the program enableslaw apply to Ameren Missouri, to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it could own. As applicable, the addition of generation byincluding limitations on electric customer rate increases. Ameren Missouri would be subjectdoes not expect to exceed these rate increase limitations in 2021. Both the issuance of a certificate of conveniencerate increase limitation and necessity bythe PISA are effective through December 2023, unless Ameren Missouri requests and the MoPSC obtaining transmission interconnection agreements with MISO or other RTOs, and FERC approval. This generation would be incremental to estimated capital expendituresapproves an extension through 2023 discussed below. Ameren Missouri anticipates finalizing customer interest and pursuing renewable energy projects to fulfill requirements in 2019. Without extension, the option to elect into the program will terminate in the third quarter of 2023.
December 2028.•In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 20212022 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism.rider. Ameren Missouri intends to invest $226$290 million over the life of the plan, including $65 million per year through 2021.in 2021 and $70 million in 2022. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100% ofgoals. If the target goals are achieved during the period ended December 2021. Additionalfor 2020, 2021, and 2022, additional revenues of $10 million, $13 million, and $11 million would be recognized in 2021, 2022, and 2022, respectively. Incremental additional revenues of $3 million, $3 million, and $1 million may be earned for 2020, 2021, and 2022, respectively, and would be recognized in the respective following year if Ameren Missouri exceeds 100% its targeted goals. Ameren Missouri’s ability to achieve and/or exceed targeted goals could be affected by the COVID-19 pandemic. Ameren Missouri recognized $6 million, $37 million, $11 million, and $28 million in revenues related to MEEIA performance incentives in 2020, 2019, 2018, and 2016, respectively.
•In March 2020, the MoPSC issued an order in Ameren Missouri’s July 2019 electric service regulatory rate review, resulting in a decrease of its$32 million to Ameren Missouri’s annual revenue requirement for electric retail service. The order reduced the annualized base level of net energy savings goals.costs pursuant to the FAC by approximately $115 million from the base level established in the MoPSC’s March 2017 electric rate order. The order also changed the annualized regulatory asset and liability amortization amounts and the base level of expenses for trackers. On an annualized basis, these changes reflect approximately $20 million of increased revenues and approximate decreases in purchased power expenses of $15 million, other operating and maintenance expenses of $60 million, and income tax
expenses of $20 million. Additionally, the annual revenue requirement incorporated increases of approximately $50 million for the reduction in sales volumes resulting from MEEIA programs and approximately $50 million of depreciation and amortization expense for amounts previously deferred under PISA. The increase in the annual revenue requirement related to the MEEIA programs is seasonally weighted to the summer. One of the stipulation and agreements approved by the MoPSC’s March 2020 order states that the net impact of the revenue and expense changes noted above reflects a 9.4% to 9.8% ROE on an unspecified percent of common equity applicable to rate base.The new rates, base level of expenses, and amortizations became effective on April 1, 2020.
•Ameren continues to make significant investments in FERC regulated electric transmission businesses. Ameren IllinoisMissouri expects to invest $2.2 billion infile for electric transmission assets from 2019 through 2023, to replace aging infrastructure and improve reliability. ATXI has three MISO-approved multi-value projects: the Spoon River, Illinois Rivers, and Mark Twain projects. The Spoon River project, located in northwest Illinois, was placed innatural gas service in February 2018. The Illinois Rivers project involves the construction of a transmission line from eastern Missouri across Illinois to western Indiana. Construction of the Illinois Rivers project is substantially complete, with the last section awaiting the outcome of certain legal proceedings, which will delay the expected completion date to 2020. This delay is not expected to materially affect 2019regulatory rate base or earnings. The Mark Twain project involves the construction of a transmission line from northeast Missouri, connecting the Illinois Rivers project to Iowa. Construction of the Mark Twain project began in the second quarter of 2018, and is expected to be completedreviews by the end of 2019. ATXI’s expected remaining investment in its multi-value projects is approximately $150 million in 2019, withMarch 2021. Ameren Missouri expects key drivers of the total investment expectedelectric service regulatory rate review to be more than $1.6 billion.
include increased infrastructure investments and other costs of service.•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 growth and the currently allowed 10.82% return on common equity,10.52% ROE, the
2019 revenue requirements included in 2021 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $297$380 million and $177$200 million, respectively. These revenue requirements represent an increase in Ameren Illinois'Illinois’ and ATXI’s revenue requirements of $24$67 million and $3$8 million, respectively, from the revenue requirements reflected in 2020 rates, primarily because ofdue to the expected rate base growth. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2019,2021, but will not determine their respective electric transmission service operating revenues, which will instead be based on 20192021 actual recoverable costs, rate base, and a return on common equityrate base at the applicable WACC as calculated under the FERC formula ratemaking framework.
•The return on common equityallowed base ROE for FERC-regulated transmission rates previously charged under the MISO transmission owners, including Ameren Illinois and ATXI,tariff is the subject of a FERC complaint casean appeal filed in February 2015 challengingwith the allowed base returnUnited States Court of Appeals for the District of Columbia Circuit. Depending on common equity. Ameren Illinoisthe outcome of the appeal, the transmission rates charged during previous periods and ATXIthe currently useeffective rates may be subject to change. A proposed rulemaking also has been issued by the FERC authorized total allowed return on common equityregarding the transmission incentives policy, including the basis points added for transmission owner participation in an RTO, and a separate notice of 10.82% in customer rates. A final FERC order would establishinquiry regarding the allowed return on common equity to be appliedbase ROE generally applicable to the 15-month period from February 2015 to May 2016 and also establish the return on common equity to be included in customer rates prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. In October 2018, the FERC issued an order addressing the remanded issues in an unrelated case. That order proposed a new methodology for determining the base return on equity and required further briefs from the participants. In November 2018, the FERC issued an order related to the February 2015 complaint case and the September 2016 final order, which required briefs from the participants to be filed in February 2019 regarding a new methodology for determining the base return on common equity and whether and how to apply the new methodology to the two MISO complaint cases.industry. Ameren is unable to predict the ultimate impact of any changes to the proposed methodologyFERC’s incentives policy, action on these complaint cases at this time. As the FERC is under no deadline to issue a final order, the timingnotice of the issuance of the final order in the February 2015 complaint case,inquiry on ROE, or any potential impact to the amounts refunded as a result of the September 2016 finalfurther order is uncertain. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding FERC complaint cases.on base ROE. A 50 basis point reductionchange in the FERC-allowed base return on common equityROE would reduceaffect Ameren’s and Ameren Illinois’ annual net income by an estimated $9$11 million and $5$7 million, respectively, based on each company’s 20192021 projected rate base.
•Ameren Illinois’ electric distribution service performance-based formula ratemaking framework allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the year. Unless extended, the performance-based formula ratemaking framework expires at the end of 2022. If not extended, Ameren Illinois would be required to establish future rates through a traditional regulatory rate review, which would allow the use of a future test year, with the ICC. The decoupling provisions extend beyond the end of the formula ratemaking by law, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. Ameren Illinois is actively pursuing constructive ratemaking, and filed a request with the ICC in April 2020, which, if approved, would allow Ameren Illinois to continue to reconcile electric distribution service rates to the last annual revenue requirement approved by the ICC under the performance-based formula ratemaking framework, for a period of up to two years after the framework expires or is no longer elected. Ameren Illinois expects a decision by the ICC in March 2021.
•In November 2018,December 2020, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $72$49 million increasedecrease in Ameren Illinois’ electric distribution service rates beginning in January 2019. However,2021. Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and investmenta return at the applicable WACC on year-end rate base in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois’ 20192021 electric distribution service revenues will be based on its 20192021 actual recoverable costs, 2021 year-end rate base, and a return on common equity as calculated underat the Illinois performance-based formula ratemaking framework. The 2019 revenue requirement is expected to be higher thanapplicable WACC, with the 2018 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of approximately 8%, and an expected increase inROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds. The 2019bonds plus 580 basis points. As of December 31, 2020, Ameren Illinois expects its 2021 year-end rate base to be $3.7 billion. With or without extension of the formula ratemaking framework, the 2021 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from, or refunded to, customers in 2021.2023. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8$10 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 20192021 projected year-end rate base. Ameren Illinois’ allowed ROE for 2020 was based on an annual average of the monthly yields of the 30-year United States Treasury bonds of 1.56%.
•Ameren Illinois is allowed to earnearns a return at the applicable WACC on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at its weighted-average cost of capital,the applicable WACC, with the equity returnROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ returnallowed 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. Pursuant to the FEJA, Ameren Illinois plans to invest up to approximately $100 million per year in electric energy-efficiency programs through 20232025, and will earn a return on those investments. TheWhile the ICC has approved a plan consistent with this spending level through 2021, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, or ifwhich could reduce the savings goals would require investment levels that exceed amounts allowed by legislation.investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not included in the electric distribution service performance-based formula ratemaking framework. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ energy-efficiency program.
•In November 2018,January 2021, the ICC issued an order approving a stipulation and agreement thatin Ameren Illinois’ February 2020 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas rate increasedelivery service of $32 million, based on a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. This increase reflects the reduction in the federal statutory corporate income tax rate enacted under the TCJA, as well as the increase in the Illinois corporate income tax rate that$76 million. The new rates became effective in July 2017, which collectively decreased annual rates by approximately $17 million. The new customer rates were effective in November 2018.January 2021. As a result of this order, the rate base under the QIP rider was reset to zero. Ameren Illinois used a 20192021 future test year in this proceeding.
•In February 2020, the MoPSC issued an order approving a stipulation and agreement allowing Ameren Missouri’s nextMissouri to defer and amortize maintenance expenses related to scheduled refueling and maintenance outageoutages at its Callaway Energy Center. Maintenance expenses are amortized over the period between refueling and maintenance outages, which is approximately 18 months. During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was conducted. Work has begun to replace certain key components of the generator in order to return the energy center to service. Ameren Missouri expects generator repairs of $65 million, which are expected to be largely capital expenditures. Due to the long lead time for the manufacture, repair, and installation of the components, the energy center is scheduled for the springexpected to return to service in late June or early July 2021. As of 2019. During the 2017 refueling,December 31, 2020, Ameren Missouri incurreddeferred, as a regulatory asset, $39 million in maintenance expenses related to its scheduled fall 2020 outage, which it began to amortize in January 2021. The regulatory asset will be amortized until the completion of $35 million. During a scheduledthe next refueling which occurs every 18 months,and maintenance expenses increase relative to non-outage years. Additionally, depending onoutage. For the availabilityduration 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 nonnuclear energy center maintenance costs in non-outage years.
unplanned outage, Ameren Missouri expects an increase to realize lower costsits purchased power expense and a decrease to its off-system sales, with changes to both items recovered under the FAC. Ameren Missouri does not expect a significant increase to other operations and maintenance expense as a result of fuelthe unplanned outage. Prior to 2020, maintenance expenses for generation through 2023, comparedrefueling and maintenance outages were expensed as incurred.
•Ameren Missouri and Ameren Illinois continue to 2018 levels, based on coalmake infrastructure investments and related transportation contractsexpect to seek increases to electric and management’s outlooknatural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, legislative solutions to address regulatory lag and to support investment in their utility infrastructure for future prices. Substantially all the benefit of these lower costs wouldtheir customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, economic impacts of COVID-19, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective technological advances, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be passed throughpartially offset by increased demand resulting from increased electrification of the economy for efficiencies and as a means to customers through the FAC.
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• | Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek regular electric and natural gas rate increases to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, 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, customer conservation efforts, the impacts of additional customer energy-efficiency programs, andaddress economy-wide CO2 emission concerns. We expect that increased customer use of increasingly cost-effective technological advances, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy for efficiencies and as a means to address CO2 emission concerns. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, will result in rate base and revenue growth but also higher depreciation and financing costs.
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For additional information regarding recent rate orders, lawsuits,base and pending requests filed with staterevenue growth but also higher depreciation and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.financing costs.
Liquidity and Capital Resources
•Our customers’ payment for our services has been adversely affected by the COVID-19 pandemic, resulting in a decrease to our cash flow from operations. See the Results of Operations section above for additional information on our accounts receivable balances. Further, our liquidity and our capital expenditure plans could be adversely affected by other impacts resulting from the COVID-19 pandemic, including but not limited to potential impacts on our ability to access the capital markets on reasonable terms and when needed, Ameren Missouri’s 2017expected wind generation additions remaining in 2021, and the timing of tax payments and the utilization of tax credits. We expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, however, disruptions to the capital markets and the ability of our suppliers and contractors to perform as required under their contracts could impact the execution of our capital investment strategy. For further discussion on the impacts to our ability to access the capital markets and Ameren Missouri’s expected wind generation additions remaining in 2021, see below.
•In February 2021, 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 2021. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4 billion over the five-year period from 2021 through 2025, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 and 2025 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028.
•In September 2020, Ameren Missouri filed its 2020 IRP with the MoPSC. In connection with the 2020 IRP filing, Ameren established a goal of achieving net-zero carbon emissions by 2050. Ameren is also targeting a 50% CO2 emission reduction by 2030 and an 85% reduction by 2040 from the 2005 level. The plan, which is subject to review by the MoPSC for compliance with Missouri law, targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power.power, and supports increased investment in new energy technologies. It also includes expanding renewable sources by adding at least 700 megawatts3,100 MWs of windrenewable generation by the end of 2020 in Missouri2030 and neighboring states and adding 100 megawattsa total of solar5,400 MWs of renewable generation by 2027.2040. These new renewable energy sources wouldamounts include the 700 MWs of wind generation projects discussed below, which will support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to customer rate increase limitations. Based on current and projected market prices for energy and for wind and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost option for customers.beginning in 2021. The plan also providesincludes advancing the retirement dates of the Sioux and Rush Island coal-fired energy centers to 2028 and 2039, respectively, which are subject to the approval of a change in the assets’ depreciable lives by the MoPSC in a future regulatory rate review, the continued implementation of customer energy-efficiency programs, and the expectation that Ameren Missouri will seek NRC approval for an extension of the operating license for the expected implementationCallaway Energy Center beyond its current 2044 expiration date. Additionally, the plan includes retiring the Meramec and Labadie coal-fired energy centers at the end of continued customer energy-efficiency programs.their useful lives (by 2022 and 2042, respectively). Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC, and any other required approvals for the addition of renewable resources, could beretirement of energy centers, and new or continued customer energy-efficiency programs; the ability of developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary materials and equipment, including those that are affected by the disruptions in the global supply chain caused by the COVID-19 pandemic, among other factors:things; the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind, solar, and solarother renewable generation and storage technologies; changes in environmental laws or requirements, including those related to carbon emissions; energy prices;prices and demand; and Ameren Missouri’s ability to obtain timely interconnection agreements with the MISO or other RTOs as well as the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC, and any other required project approvals.
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• | In connection with the 2017 IRP filing, Ameren Missouri established a goal of reducing CO2 emissions 80% by 2050 from a 2005 base level. Ameren Missouri is also targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level. In order to meet these goals, among other things, Ameren Missouri expects to retire its coal-fired generation at the end of each energy center’s useful life.
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In the second quarter of 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Terra-Gen, LLC to acquire, after construction, a 400-megawatt wind generation facility, whichat an acceptable cost. The next integrated resource plan is expected to be filed in September 2023.
•In December 2020, Ameren Missouri acquired a 400-MW wind generation project located in northeastern Missouri.Missouri for approximately $615 million, and placed the assets in service as the High Prairie Renewable Energy Center. In October 2018, the MoPSC issued an order approving a unanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. In December 2018,January 2021, Ameren Missouri received FERC approval to acquire the facility after construction. A transmission interconnection agreement with the MISO for this facility is expected in the fall of 2019. Also, in October 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of EDF Renewables, Inc. to acquire, after construction, aacquired an up-to 300-MW wind generation facility of up to 157 megawatts. In February 2019, Ameren Missouri filed with the MoPSC a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. The up to 157-megawatt facility is expected to beproject located in northwestern Missouri. A transmission interconnection agreementAt the date of this filing, Ameren Missouri placed 120 MWs in service as the Atchison Renewable Energy Center, with a purchase price of approximately $200 million. There have been changes to the MISOschedule for this facility is expected in early 2020. Both facilities are expectedproject, particularly as a result of component delivery delays. Ameren Missouri expects approximately 150 MWs of the up-to 300-MW project to be completedin service by the end of 2020 and would help Ameren Missouri comply with the Missouri renewable energy standard. Each acquisition is subject to certain conditions, including entering into a MISO transmission interconnection agreement at an acceptable cost for each facility and obtaining FERC approvalfirst quarter of 2021, and the issuance of a certificate of convenience and necessity by the MoPSC for the upremaining portion to 157-megawatt facility, as well as other customary contract terms and conditions. These agreements collectively represent approximately $1 billionbe in capital expenditures expectedservice later in 2020, which is included in Ameren Missouri’s Smart Energy Plan.In October and December 2018, the MoPSC issued orders approving a RESRAM that allows Ameren Missouri2021. See discussion below related to adjust customer rates on an annual basis without a traditional regulatory rate review.The RESRAM is designed to mitigate the impacts of regulatory lag for the cost of compliance with renewable energy standards, including recovery of investments in wind and
production tax credits.
other renewable generation, by providing more timely recovery of costs and a return on investments not already provided for in customer rates or recovered under PISA.
•Through 2023,2025, 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 $13.9$17.8 billion (Ameren Missouri – up to $7.1$9.3 billion; Ameren Illinois – up to $6.6$8.2 billion; ATXI – up to $0.2 billion) of capital expenditures during the period from 20192021 through 2023. Any additional2025. Ameren’s and Ameren Missouri’s estimates include 300 MWs of wind generation at the Atchison Renewable Energy Center, but exclude incremental renewable generation investment opportunities of 1,200 MWs by 2025, which are included in Ameren Missouri’s 2020 IRP. As of the date of this filing, no contractual agreements have been entered into, and no regulatory approvals have been requested, related to these opportunities. These planned investments by Ameren Missouri beyondare based on the two facilitiesassumption of continued constructive regulatory frameworks, including an assumption that Ameren Missouri has agreedrequests and receives MoPSC approval of an extension of the PISA through December 2028.
•Environmental regulations, including those related to acquire after constructionCO2 emissions, or other actions taken by the EPA, or requirements that may result from the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, could result in significant increases in capital expenditures and operating costs. Regulations enacted by a prior federal administration and under legal challenge can be reviewed or recommended for repeal by the EPA, and new replacement or alternative regulations can be proposed, or adopted by the current federal administration, the EPA and state regulators. The ultimate implementation of any of these regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal-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 incrementalrecovered 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 these estimates.comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.
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• | Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. Certain of these regulations are being challenged through litigation, are being reviewed or recommended for repeal by the EPA or new replacement or alternative regulations are being contemplated or proposed by the EPA and state regulators; therefore, the ultimate implementation of any of these regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal-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.
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•The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1$2.3 billion of credit through December 2022,2024, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $2.5$2.7 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. The Ameren Companies have no material maturities of long-term debt until
2022. With the recently completed Ameren Missouri and Ameren Illinois debt issuances and availability under the Credit Agreements, as well as the proceeds from the recent settlement of the forward sale agreement, Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, including expected wind generation additions remaining in 2021, and related financing plans. The Ameren Companies continue to monitor the effect of the COVID-19 pandemic on their liquidity, including as a result of decreased sales and increased customer nonpayment. To date, the Ameren Companies have been able to access the capital markets on reasonable terms when needed. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
Federal income tax legislation enacted under the TCJA will continue to have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA, among other things, reduced the federal statutory corporate income tax rate from 35% to 21%, effective January 1, 2018. Customer rates were reduced to reflect the lower income tax rate, without a corresponding reduction in income tax payments because of our use of net operating losses and tax credit carryforwards until about 2020. Customer rates were also reduced to reflect the return of excess deferred taxes. The result of these customer rate reductions is a decrease in operating cash flows in the near term. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts resulting from lower accumulated deferred income tax liabilities.
Ameren Missouri expects a decrease in operating cash flows of approximately $100 million in 2019 compared with 2018, as a result of the TCJA. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts, once approved by the MoPSC, resulting from lower accumulated deferred income tax liabilities.
The following table presents the net regulatory liabilities associated with excess deferred taxes as of December 31, 2018, and the related amortization periods:
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| Amortization Period | Ameren Missouri | | Ameren Illinois | | ATXI | | Total |
30 – 60 years | $ | 947 |
| | $ | 796 |
| | $ | 84 |
| | $ | 1,827 |
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7 – 10 years | 524 |
| | (4 | ) | | 2 |
| | 522 |
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| Total | $ | 1,471 |
| | $ | 792 |
| | $ | 86 |
| | $ | 2,349 |
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In 2018, our rate-regulated businesses began to amortize excess deferred taxes. Ameren Illinois and ATXI's 2018 income tax expense reflect a full year of amortization, while Ameren Missouri's 2018 income tax expense reflects five months of amortization related to its electric business, in accordance with a MoPSC order received in July 2018. The amortization of such balances related to Ameren Missouri’s gas business started in January 2019, in accordance with a MoPSC order received in December 2018. These amortizations reduce our income tax expense and effective tax rates. Due to formula ratemaking, Ameren Illinois Electric Distribution and Ameren Transmission have an offsetting reduction in revenue from customers, with no overall impact on earnings. Ameren Missouri and Ameren
Illinois Natural Gas 2019 interim period earnings may be affected by timing differences between income tax expense and revenue reductions based on their revenue patterns; however, no material impact to year-over-year earnings is expected.
As of December 31, 2018, Ameren had $91 million in tax benefits from federal and state net operating loss carryforwards and $127 million in federal and state income tax credit carryforwards. These carryforwards are expected to largely offset income tax obligations in 2019. Ameren does not expect to make material federal or state income tax payments over the next five years based on planned capital expenditures and related income tax credits. Consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries, Ameren Missouri expects to make material income tax payments to Ameren (parent) in 2019 and 2020 and immaterial payments in 2021 through 2023 based on planned capital expenditures and related income tax credits, while Ameren Illinois expects to make material income tax payments to Ameren (parent) in 2020 through 2023.
•Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. ToAs part of its plan to fund a portion of these cash flow requirements, beginning in the first quarter of 2018, Ameren beganis using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under itsthe DRPlus and employee benefit plans and expects to continue to do so overthrough at least 2025. Ameren expects these issuances to provide equity of about $100 million annually. In addition to the next five years. issuance of common shares in connection with the 2021 settlement of the remaining portion of the forward sale agreement, Ameren also plans to issue incremental common equity of about $150 million in 2021 and about $300 million each year from 2022 to fund a portion of2025. Ameren Missouri’s wind generation investments. Ameren, Ameren Missouri, and Ameren Illinois expect their respectiveexpects its equity to total capitalization levels over the period ending December 2023 to remain in-line with their respective equity to total capitalization levels as ofbe about 45% through December 31, 2018.2025, with the long-term intent to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent).
•As of December 31, 2020, Ameren had $90 million in tax benefits related to federal and state income tax credit carryforwards and $7 million in tax benefits from state net operating loss carryforwards, which will be utilized in future periods. Ameren expects federal income tax payments at the required minimum levels from 2021 to 2025 resulting from the anticipated use of production tax credits that will be generated by Ameren Missouri’s High Prairie and Atchison renewable energy centers and existing tax credit carryforwards.
The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are the most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
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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 opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments •Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under performance-based formula ratemaking framework •Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks •Ameren Missouri’s estimate of revenue recovery under the MEEIA plans |
Regulatory Mechanisms and Cost Recovery
We defer costs and recognize revenues that we intend to collect in future rates.
Regulatory environment and external regulatory decisions and requirements
Anticipated future regulatory decisions and our assessment of their impact
The impact of prudence reviews, complaint cases, limitations on electric rate increases in Missouri, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments
Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under performance-based formula ratemaking framework
Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks
Ameren Missouri’s estimate of revenue recovery under the MEEIA plans
Basis for Judgment
The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, legislation, or historical experience, as well as discussions with legal counsel. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers. We also recognize revenues for alternative revenue programs authorized by our regulators that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months following the end of the annual period in which they are recognized. Under performance-based formula ratemaking, which expires at the end of 2022 unless extended, Ameren Illinois estimates its annual electric distribution revenue requirement under performance-based formula ratemaking for interim periods by using internal forecasted rate base and published forecasted data regarding the annual average of the monthly yields of the 30-year United States Treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31 of each year using that year’s actual operating results and assesses the probability of recovery from or refund to customers that the ICC will order at the end of the following year. Variations in investments made or orders by the ICC or courts can result in a subsequent change in Ameren Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates lost electric margins resulting from its MEEIA customer energy-efficiency programs. Ameren Missouri uses aprograms, which are subsequently recovered through the MEEIA rider to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers.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. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for a listing of regulatory mechanisms used by Ameren Missouri and Ameren Illinois.
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs67
Future rate of return on pension and other plan assets
Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable
Discount rate
Future compensation increase assumption
Health care cost trend rates
Timing of employee retirements and mortality assumptions
Ability to recover certain benefit plan costs from our customers
Changing market conditions that may affect investment and interest rate environments
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| Accounting Estimate | | Uncertainties Affecting Application |
| Benefit Plan Accounting | | |
| Based on actuarial calculations, we accrue costs of providing future employee benefits for the benefit plans we offer our employees. See Note 10 – Retirement Benefits under Part II, Item 8, of this report. | | •Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable •Discount rate •Cash balance plan interest crediting rate on certain plans •Future compensation increase assumption •Health care cost trend rates •Assumptions on the timing of employee retirements, terminations, benefit payments, and mortality •Ability to recover certain benefit plan costs from our customers •Changing market conditions that may affect investment and interest rate environments •Future rate of return on pension and other plan assets |
Basis for Judgment
Ameren has defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren has defined benefit pension plans covering substantially all of its non-union employees and has postretirement benefit plans covering non-union employees hired before October 2015.2015 and union employees hired before January 2020. Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable. We also make mortality assumptions to estimate our pension and other postretirement benefit obligations. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for these assumptions and the sensitivity of Ameren’s benefit plans to potential changes in these assumptions.
Accounting for Contingencies
We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and that the amount of the loss can be reasonably estimated.
Estimating financial impact of events
Estimating likelihood of various potential outcomes
Regulatory and political environments and requirements
Outcome of legal proceedings, settlements, or other factors
Changes in regulation, expected scope of work, technology or timing of environmental remediation
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| Accounting Estimate | | Uncertainties Affecting Application |
| Accounting for Contingencies | | |
| We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and that the amount of the loss can be reasonably estimated. | | •Estimating financial impact of events •Estimating likelihood of various potential outcomes •Regulatory and political environments and requirements •Outcome of legal proceedings, settlements, or other factors •Changes in regulation, expected scope of work, technology, or timing of environmental remediation |
Basis for Judgment
The determination of a loss contingency requires significant judgment as to the expected outcome of the contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider the nature of the litigation, the claim or assessment, opinions or views of legal counsel, and the expected outcome of potential litigation, among other things. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. The amount recorded for any contingency may differ from actual costs incurred when the contingency is resolved. Contingencies are normally resolved over long periods of time. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. See Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for information on the Ameren Companies’ contingencies.
Accounting 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,
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
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| 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. See Note 12 – Income Taxes under Part II, Item 8, of this report for the amount of deferred income taxes recorded at December 31, 2018.2020.
| | | | | | | | |
| Accounting Estimate | | Uncertainties Affecting Application |
| Accounting for Asset Retirement Obligations | | |
| We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report. | | •Discount rates •Cost escalation rates •Changes in regulation, expected scope of work, technology, or timing of environmental remediation •Estimates as to the probability, timing, or amount of cash expenditures associated with AROs |
Basis for Judgment
We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs for accretion and changes in the estimated fair values of the obligations, with a corresponding increase or decrease in the asset book value for the fair value changes. We estimate the fair value of our AROs using present value techniques, in which we make various assumptions about discount rates and cost escalation rates. In addition, these estimates include assumptions of the probability, timing, and amount of cash expenditures to settle the ARO, and are based on currently available technology. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with the decommissioning of Ameren Missouri’s Callaway and High Prairie Renewable energy centers, CCR facilities, and river structures. Also, Ameren, Ameren Missouri, and Ameren Illinois have recorded AROs for retirement costs associated with asbestos removal and the disposal of certain transformers. An increase of 0.25% in the assumed escalation rates would increase Ameren’s AROs at December 31, 2020, by $78 million. See Note 15 – Supplemental Information under Part II, Item 8, of this report for the amount of AROs recorded at December 31, 2020.
Impact of New Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
EFFECTS OF INFLATION AND CHANGING PRICES
Ameren’s rates for retail electric and natural gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by the FERC. Rate regulation is generally based on the recovery of historical or projected costs. As a result, revenue increases could lag behind changing prices. The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, customer rates designed to provide recovery of historical costs through depreciation might not be adequate to replace plant in future years.
Ameren Illinois participates in performance-based formula ratemaking for its electric distribution business and its electric energy-efficiency investments. Within Ameren Illinois’ formulathose ratemaking mechanisms,frameworks, the annual average of the monthly yields of the 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity.allowed ROE. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the annual return on equityallowed ROE applicable to Ameren Illinois’ electric distribution business and electric energy-efficiency investments. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates in a subsequent year.
Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. However, the FAC excludes substantially all transmission revenues and charges. Ameren Missouri is therefore exposed to transmission charges to the extent that they exceed transmission revenues. Ameren Illinois is required to purchase all of its expected power supply through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.
In our Missouri and Illinois retail natural gas utility jurisdictions, changes in natural gas costs are generally reflected in billings to natural gas customers through PGA clauses.
See Part I, Item 1, and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on our cost recovery mechanisms.
| |
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
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 a risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
long-term and •short-term variable-rate debt;
•fixed-rate debt;
•United States Treasury bonds; and
•the discount rate applicable to asset retirement obligations, goodwill, and defined pension and postretirement benefit plans.
We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio and by monitoring the effects of market changes on interest rates. For defined pension and postretirement benefit plans, we control the duration and the portfolio mix of our plan assets. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information related to asset retirement obligations, goodwill, and the defined pension and postretirement benefit plans.
The estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 100 basis points on variable-rate debt outstanding at December 31, 20182020 is immaterial.
The return on equity componentallowed ROE under Ameren Illinois’ electric distribution service and its electric energy-efficiency investments formula ratemaking recovery mechanisms is equal tobased on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equityROE for its electric distribution business is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8$10 million change in Ameren’s and Ameren Illinois’ annual net income, based on its 20192021 projected rate base. Interest rate levels also influence the return on equityROE allowed by our regulators in our other ratemaking jurisdictions.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, 2018.2020.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2018,2020, no nonaffiliated customer represented more than 10% of our accounts receivable. Additionally, Ameren Illinois faces risks associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois may be required to purchase the supplier’s receivables relating to Ameren Illinois’ distribution customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers to reflect charges for electric distribution and purchased receivables. As of December 31, 2018,2020, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $33$28 million. The risk associated with Ameren Illinois’ electric and natural gas trade receivables is also mitigated by a rate adjustment mechanismrider 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 increasing rates on customer collections, as applicable.applicable, and increasing customer account balances largely associated with the COVID-19 pandemic. 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 1 – Summary of Significant Accounting Policies 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, 2020. In addition, for information regarding Ameren Missouri’s and Ameren Illinois’ suspensions and reinstatement of customer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Investment Price Risk
Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and company-owned life insurance contracts include equity and debt securities. The equity securities are exposed to price fluctuations in equity markets. The debt securities are exposed to changes in interest rates.
Our costs for providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to ensure that sufficient funds are available to provide benefits at the time they are payable, while also maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class are estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjust the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns, and for the effect of expenses paid from plan assets. Contributions to the plans and future costs could increase materially if we do not achieve pension and postretirement asset portfolio investment returns equal to or in excess of our 20192021 assumed return on plan assets of 7.00%6.50%.
Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2018,2020, this fund was invested in domestic equity securities (62%(69%) and debt securities (37%(30%). By
maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the trust assets to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Additionally, Ameren and Ameren Illinois have company-owned life insurance contracts with net asset values of $131$165 million and $9$8 million, respectively, as of December 31, 2018.2020. 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 businessesbusinesses’ 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 proceeding,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, and zero emission credit, and renewable energy credit costs and expects full recovery of such costs. Ameren Illinois is required to serve as the provider of last resort for electric customers in its service territory who have not chosen an alternative retail electric supplier. In 2018,2020, Ameren Illinois suppliedprocured power on behalf of its customers for 23% of its total kilowatthour sales to its electric customers.sales. Ameren Illinois purchases energy and capacity through the MISO and through bilateral contracts resulting from IPA procurement events. The IPA has proposed and the ICC has approved multiple procurement events covering portions of years through 20202023 for capacity and 2021 for energy. Ameren Illinois has also entered into ICC-approved contracts for zero emission credits through 2026 and for renewable energy credits with various terms, including contracts with a 20-year term ending 2032, and contracts entered into beginning 2018 with 15-year terms commencing on the date of first renewable energy credit delivery. Ameren Illinois does not generate earnings based on the resale of power or purchase of zero emission credits or renewable energy credits but rather on the delivery of the energy.
Ameren Missouri and Ameren Illinois have PGA clauses that permit costs incurred for natural gas to be recovered directly from utility customers without a traditional regulatory rate proceeding,review, subject to prudence review.reviews.
The following table presents, as of December 31, 2018,2020, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri'sMissouri’s coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway energy center,Energy Center, natural gas for Ameren Missouri'sMissouri’s retail distribution, and purchased power for Ameren Illinois that are price-hedged over the period 20192021 through 2023.2025. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 – 2025 |
| Ameren: | | | | | |
| Coal | 100 | % | | 87 | % | | 39 | % |
| Coal transportation | 100 | | | 99 | | | 98 | |
Nuclear fuel(a) | — | | | 82 | | | 53 | |
| | | | | |
Natural gas for distribution(b) | 73 | | | 31 | | | 10 | |
Purchased power for Ameren Illinois(c) | 69 | | | 35 | | | 11 | |
| Ameren Missouri: | | | | | |
| Coal | 100 | % | | 87 | % | | 39 | % |
| Coal transportation | 100 | | | 99 | | | 98 | |
Nuclear fuel(a) | — | | | 82 | | | 53 | |
| | | | | |
Natural gas for distribution(b) | 68 | | | 36 | | | 21 | |
| Ameren Illinois: | | | | | |
Natural gas for distribution(b) | 73 | % | | 30 | % | | 8 | % |
Purchased power(c) | 69 | | | 35 | | | 11 | |
(a)The Callaway Energy Center has historically required refueling at 18-month intervals. During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was conducted. Work has begun to replace certain key components of the generator in order to return the energy center to service. As of the date of this filing, due to the long lead time for the manufacture, repair, and installation of these components, the energy center is expected to return to service in late June or early July 2021. As there are no refuelings scheduled to occur during 2021 or 2024, there are also no nuclear fuel deliveries anticipated to occur in these years. |
| | | | | | | | |
| | 2019 | | 2020 | | 2021 - 2023 |
| Ameren: | | | | | |
| Coal | 98 | % | | 67 | % | | 28 | % |
| Coal transportation | 100 |
| | 99 |
| | 97 |
|
| Nuclear fuel | 100 |
| | 85 |
| | 61 |
|
Natural gas for distribution(a) | 74 |
| | 33 |
| | 13 |
|
Purchased power for Ameren Illinois(b) | 69 |
| | 35 |
| | 11 |
|
| Ameren Missouri: | | | | | |
| Coal | 98 | % | | 67 | % | | 28 | % |
| Coal transportation | 100 |
| | 99 |
| | 97 |
|
| Nuclear fuel | 100 |
| | 85 |
| | 61 |
|
Natural gas for distribution(a) | 62 |
| | 27 |
| | 5 |
|
| Ameren Illinois: | | | | | |
Natural gas for distribution(a) | 76 | % | | 34 | % | | 14 | % |
Purchased power(b) | 69 |
| | 35 |
| | 11 |
|
| |
(a) | Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2019 represents January 2019 through March 2019. The year 2020 represents November 2019 through March 2020. This continues each successive year through March 2023. |
| |
(b) | Represents the percentage of purchased power price-hedged for fixed-price residential and non-residential customers with less than 150 kilowatts of demand. |
(c)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 ultra-low-sulfurlow-sulfur coal is part of Ameren Missouri’s environmental compliance strategy. Ameren Missouri has agreements with multiple suppliers to purchase ultra-low-sulfurlow-sulfur coal through 20222025 to comply with environmental regulations. Disruptions to the deliveries of ultra-low-sulfurlow-sulfur coal from a supplier could compromise Ameren Missouri’s ability to operate in compliance with emission standards. The suppliers of ultra-low-sulfurlow-sulfur coal are limited, and the construction of pollution control equipment requires significant lead time. In addition, low-sulfur coal suppliers have experienced financial hardships in recent years and could continue to experience financial hardships that could impact their ability to deliver shipments of low-sulfur coal in accordance with existing supply contracts. If Ameren Missouri were to experience a temporary disruption of ultra-low-sulfurlow-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of ultra-low-sulfurlow-sulfur coal were not available, Ameren Missouri would have to use its existing emission allowances, purchase emission allowances to achieve compliance with environmental regulations, or purchase power necessary to meet demand.
Currently, the Callaway energy center uses nuclear fuel assemblies ofEnergy Center has a design fabricated by only a single supplier. That supplier is currently the only NRC-licensed supplier able to provide fuel assemblies to the Callaway energy center.Energy Center. Ameren Missouri is pursuing a program to qualify an alternate NRC-licensed supplier, and expects to obtain NRC approval in 2021.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for natural gas and power, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2018. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 8 – Fair Value Measurements under Part II, Item 8, of this report for additional information regarding the methods used to determine the fair value of these contracts.2023.
|
| | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fair value of contracts at beginning of year, net assets (liabilities) | $ | 8 |
| | $ | (217 | ) | | $ | (209 | ) |
| Contracts realized or otherwise settled during the period | (8 | ) | | 25 |
| | 17 |
|
| Fair value of new contracts entered into during the period | (7 | ) | | 2 |
| | (5 | ) |
| Other changes in fair value | (3 | ) | | (4 | ) | | (7 | ) |
| Fair value of contracts outstanding at end of year, net assets (liabilities) | $ | (10 | ) | | $ | (194 | ) | | $ | (204 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| Sources of Fair Value | 2019 | | 2020 – 2021 | | 2022 – 2023 | | 2024 and Thereafter | | Total Fair Value |
| Ameren Missouri: |
| |
| |
| |
| |
|
| Level 1 | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) |
Level 2(a) | (4 | ) | | (1 | ) | | — |
| | — |
| | (5 | ) |
Level 3(b) | (1 | ) | | (3 | ) | | — |
| | — |
| | (4 | ) |
| Total | $ | (5 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | (10 | ) |
| Ameren Illinois: |
|
| |
|
| |
|
| |
|
| |
|
|
| Level 1 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Level 2(a) | (5 | ) | | (3 | ) | | — |
| | — |
| | (8 | ) |
Level 3(b) | (16 | ) | | (30 | ) | | (30 | ) | | (110 | ) | | (186 | ) |
| Total | $ | (21 | ) | | $ | (33 | ) | | $ | (30 | ) | | $ | (110 | ) | | $ | (194 | ) |
| Ameren: | | | | | | | | | |
| Level 1 | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) |
Level 2(a) | (9 | ) | | (4 | ) | | — |
| | — |
| | (13 | ) |
Level 3(b) | (17 | ) | | (33 | ) | | (30 | ) | | (110 | ) | | (190 | ) |
| Total | $ | (26 | ) | | $ | (38 | ) | | $ | (30 | ) | | $ | (110 | ) | | $ | (204 | ) |
| |
(a)
| Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps. |
| |
(b) | Principally power forward contract values based on information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on an option valuation model. |
| |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 20182020 and 2017,2019, 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, 2018,2020, 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, 2018,2020, 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, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2020 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, 2018,2020, 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”)(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.
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. 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 returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2020, the Company’s consolidated balance sheet reflected $1.2 billion of regulatory assets and $5.4 billion of regulatory liabilities. As disclosed by management, in some cases, management must apply judgment related to the probability of recovery if regulatory balances are recorded before approval has been received from the regulator or probability of refund of amounts collected in rates that may be returned to customers. 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, legislation, or external legal counsel correspondence, (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 26, 201922, 2021
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.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric Company:Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Union Electric Company (the “Company”) as of December 31, 20182020 and 2017,2019, 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, 2018,2020, 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, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2020 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’sfinancial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(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. 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 returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2020, the Company’s balance sheet reflected $0.4 billion of regulatory assets and $3.1 billion of regulatory liabilities. As disclosed by management, in some cases, management must apply judgment related to the probability of recovery if regulatory balances are recorded before approval has been received from the regulator or probability of refund of amounts collected in rates that may be returned to customers. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, and (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, which in turn led to a high degree of auditor judgment, subjectivity, and audit effort when performing audit procedures and
evaluating audit evidence obtained related to management’s application of regulatory accounting and assessment of probability of recovery of regulatory assets and refund of regulatory liabilities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders, legislation, or external legal counsel correspondence, and (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities.
/s/ PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 201922, 2021
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.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois Company:Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ameren Illinois Company (the “Company”) as of December 31, 20182020 and 2017,2019, and the related 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, 2018,2020, 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, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2020 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Thesefinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’sfinancial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(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. 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 returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2020, the Company’s balance sheet reflected $0.8 billion of regulatory assets and $2.2 billion of regulatory liabilities. As disclosed by management, in some cases, management must apply judgment related to the probability of recovery if regulatory balances are recorded before approval has been received from the regulator or probability of refund of amounts collected in rates that may be returned to customers. 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 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, legislation, or external legal counsel correspondence, (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 26, 201922, 2021
We have served as the Company’s auditor since 1998.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions, except per share amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 5,339 |
| | $ | 5,307 |
| | $ | 5,196 |
|
| Natural gas | 952 |
| | 867 |
| | 880 |
|
| Total operating revenues | 6,291 |
| | 6,174 |
| | 6,076 |
|
| Operating Expenses: |
| |
| | |
| Fuel | 769 |
| | 737 |
| | 745 |
|
| Purchased power | 581 |
| | 638 |
| | 623 |
|
| Natural gas purchased for resale | 374 |
| | 311 |
| | 341 |
|
| Other operations and maintenance | 1,772 |
| | 1,705 |
| | 1,733 |
|
| Depreciation and amortization | 955 |
| | 896 |
| | 845 |
|
| Taxes other than income taxes | 483 |
| | 477 |
| | 467 |
|
| Total operating expenses | 4,934 |
| | 4,764 |
| | 4,754 |
|
| Operating Income | 1,357 |
| | 1,410 |
| | 1,322 |
|
| Other Income, Net | 102 |
| | 86 |
| | 101 |
|
| Interest Charges | 401 |
| | 391 |
| | 382 |
|
| Income Before Income Taxes | 1,058 |
| | 1,105 |
| | 1,041 |
|
| Income Taxes | 237 |
| | 576 |
| | 382 |
|
| Net Income | 821 |
| | 529 |
| | 659 |
|
| Less: Net Income Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 815 |
| | $ | 523 |
| | $ | 653 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 821 |
| | $ | 529 |
| | $ | 659 |
|
| Other Comprehensive Income (Loss), Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $3, and $(7), respectively | (4 | ) | | 5 |
| | (20 | ) |
| Comprehensive Income | 817 |
| | 534 |
| | 639 |
|
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 811 |
| | $ | 528 |
| | $ | 633 |
|
| | | | | | |
| | | | | | |
| Earnings per Common Share – Basic | $ | 3.34 |
| | $ | 2.16 |
| | $ | 2.69 |
|
| | | | | | |
| Earnings per Common Share – Diluted | $ | 3.32 |
| | $ | 2.14 |
| | $ | 2.68 |
|
| | | | | | |
| Weighted-average Common Shares Outstanding – Basic | 243.8 |
| | 242.6 |
| | 242.6 |
|
| Weighted-average Common Shares Outstanding – Diluted | 245.8 |
| | 244.2 |
| | 243.4 |
|
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions, except per share amounts)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Operating Revenues: | | | | | |
| Electric | $ | 4,911 | | | $ | 4,981 | | | $ | 5,339 | |
| Natural gas | 883 | | | 929 | | | 952 | |
| Total operating revenues | 5,794 | | | 5,910 | | | 6,291 | |
| Operating Expenses: | | | | | |
| Fuel | 490 | | | 535 | | | 769 | |
| Purchased power | 513 | | | 556 | | | 581 | |
| Natural gas purchased for resale | 272 | | | 331 | | | 374 | |
| Other operations and maintenance | 1,661 | | | 1,745 | | | 1,772 | |
| | | | | |
| Depreciation and amortization | 1,075 | | | 995 | | | 955 | |
| Taxes other than income taxes | 483 | | | 481 | | | 483 | |
| Total operating expenses | 4,494 | | | 4,643 | | | 4,934 | |
| Operating Income | 1,300 | | | 1,267 | | | 1,357 | |
| | | | | |
| | | | | |
| | | | | |
| Other Income, Net | 151 | | | 130 | | | 102 | |
| Interest Charges | 419 | | | 381 | | | 401 | |
| Income Before Income Taxes | 1,032 | | | 1,016 | | | 1,058 | |
| Income Taxes | 155 | | | 182 | | | 237 | |
| | | | | |
| | | | | |
| Net Income | 877 | | | 834 | | | 821 | |
| Less: Net Income Attributable to Noncontrolling Interests | 6 | | | 6 | | | 6 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 871 | | | $ | 828 | | | $ | 815 | |
| | | | | |
| | | | | |
| Net Income | $ | 877 | | | $ | 834 | | | $ | 821 | |
| Other Comprehensive Income (Loss), Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $5, $1, and $(1), respectively | 16 | | | 5 | | | (4) | |
| Comprehensive Income | 893 | | | 839 | | | 817 | |
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 6 | | | 6 | | | 6 | |
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 887 | | | $ | 833 | | | $ | 811 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Earnings per Common Share – Basic | $ | 3.53 | | | $ | 3.37 | | | $ | 3.34 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Earnings per Common Share – Diluted | $ | 3.50 | | | $ | 3.35 | | | $ | 3.32 | |
| | | | | |
| Weighted-average Common Shares Outstanding – Basic | 247.0 | | | 245.6 | | | 243.8 | |
| Weighted-average Common Shares Outstanding – Diluted | 248.7 | | | 247.1 | | | 245.8 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) |
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 16 |
| | $ | 10 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $18 and $19, respectively) | 463 |
| | 445 |
|
| Unbilled revenue | 295 |
| | 323 |
|
| Miscellaneous accounts receivable | 79 |
| | 70 |
|
| Inventories | 483 |
| | 522 |
|
| Current regulatory assets | 134 |
| | 144 |
|
| Other current assets | 63 |
| | 98 |
|
| Total current assets | 1,533 |
| | 1,612 |
|
| Property, Plant, and Equipment, Net | 22,810 |
| | 21,466 |
|
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 684 |
| | 704 |
|
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 1,127 |
| | 1,230 |
|
| Other assets | 650 |
| | 522 |
|
| Total investments and other assets | 2,872 |
| | 2,867 |
|
| TOTAL ASSETS | $ | 27,215 |
| | $ | 25,945 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 580 |
| | $ | 841 |
|
| Short-term debt | 597 |
| | 484 |
|
| Accounts and wages payable | 817 |
| | 902 |
|
| Taxes accrued | 53 |
| | 52 |
|
| Interest accrued | 93 |
| | 99 |
|
| Customer deposits | 116 |
| | 108 |
|
| Current regulatory liabilities | 149 |
| | 128 |
|
| Other current liabilities | 282 |
| | 326 |
|
| Total current liabilities | 2,687 |
| | 2,940 |
|
| Long-term Debt, Net | 7,859 |
| | 7,094 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 2,623 |
| | 2,506 |
|
| Accumulated deferred investment tax credits | 43 |
| | 49 |
|
| Regulatory liabilities | 4,637 |
| | 4,387 |
|
| Asset retirement obligations | 627 |
| | 638 |
|
| Pension and other postretirement benefits | 558 |
| | 545 |
|
| Other deferred credits and liabilities | 408 |
| | 460 |
|
| Total deferred credits and other liabilities | 8,896 |
| | 8,585 |
|
| Commitments and Contingencies (Notes 2, 9, and 14) |
|
| |
|
|
| Ameren Corporation Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 244.5 and 242.6, respectively | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,627 |
| | 5,540 |
|
| Retained earnings | 2,024 |
| | 1,660 |
|
| Accumulated other comprehensive loss | (22 | ) | | (18 | ) |
| Total Ameren Corporation shareholders’ equity | 7,631 |
| | 7,184 |
|
| Noncontrolling Interests | 142 |
| | 142 |
|
| Total equity | 7,773 |
| | 7,326 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 27,215 |
| | $ | 25,945 |
|
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 139 | | | $ | 16 | |
| Accounts receivable – trade (less allowance for doubtful accounts of $50 and $17, respectively) | 415 | | | 393 | |
| Unbilled revenue | 269 | | | 278 | |
| Miscellaneous accounts receivable | 65 | | | 63 | |
| Inventories | 521 | | | 494 | |
| | | |
| Current regulatory assets | 109 | | | 69 | |
| | | |
| Other current assets | 135 | | | 118 | |
| | | |
| Total current assets | 1,653 | | | 1,431 | |
| Property, Plant, and Equipment, Net | 26,807 | | | 24,376 | |
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 982 | | | 847 | |
| Goodwill | 411 | | | 411 | |
| | | |
| Regulatory assets | 1,100 | | | 992 | |
| Other assets | 1,077 | | | 876 | |
| | | |
| Total investments and other assets | 3,570 | | | 3,126 | |
| TOTAL ASSETS | $ | 32,030 | | | $ | 28,933 | |
| LIABILITIES AND EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 8 | | | $ | 442 | |
| Short-term debt | 490 | | | 440 | |
| Accounts and wages payable | 958 | | | 874 | |
| | | |
| Interest accrued | 114 | | | 94 | |
| | | |
| | | |
| Current regulatory liabilities | 121 | | | 164 | |
| Other current liabilities | 489 | | | 491 | |
| | | |
| Total current liabilities | 2,180 | | | 2,505 | |
| | | |
| Long-term Debt, Net | 11,078 | | | 8,915 | |
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 3,211 | | | 2,919 | |
| | | |
| Regulatory liabilities | 5,282 | | | 4,887 | |
| Asset retirement obligations | 696 | | | 638 | |
| Pension and other postretirement benefits | 37 | | | 401 | |
| Other deferred credits and liabilities | 466 | | | 467 | |
| | | |
| Total deferred credits and other liabilities | 9,692 | | | 9,312 | |
| Commitments and Contingencies (Notes 2, 9, and 14) | 0 | | 0 |
| Ameren Corporation Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 253.3 and 246.2, respectively | 3 | | | 2 | |
| Other paid-in capital, principally premium on common stock | 6,179 | | | 5,694 | |
| Retained earnings | 2,757 | | | 2,380 | |
| Accumulated other comprehensive loss | (1) | | | (17) | |
| Total Ameren Corporation shareholders’ equity | 8,938 | | | 8,059 | |
| Noncontrolling Interests | 142 | | | 142 | |
| Total equity | 9,080 | | | 8,201 | |
| TOTAL LIABILITIES AND EQUITY | $ | 32,030 | | | $ | 28,933 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 821 |
| | $ | 529 |
| | $ | 659 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 938 |
| | 876 |
| | 835 |
|
| Amortization of nuclear fuel | 95 |
| | 76 |
| | 88 |
|
| Amortization of debt issuance costs and premium/discounts | 20 |
| | 22 |
| | 22 |
|
| Deferred income taxes and investment tax credits, net | 224 |
| | 539 |
| | 386 |
|
| Allowance for equity funds used during construction | (36 | ) | | (24 | ) | | (27 | ) |
| Stock-based compensation costs | 20 |
| | 17 |
| | 17 |
|
| Other | 44 |
| | (10 | ) | | 4 |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | (24 | ) | | (53 | ) | | (71 | ) |
| Inventories | 39 |
| | 17 |
| | 11 |
|
| Accounts and wages payable | (22 | ) | | 32 |
| | 19 |
|
| Taxes accrued | (10 | ) | | 55 |
| | 13 |
|
| Regulatory assets and liabilities | 201 |
| | 36 |
| | 215 |
|
| Assets, other | 2 |
| | 34 |
| | (21 | ) |
| Liabilities, other | (117 | ) | | (7 | ) | | (17 | ) |
| Pension and other postretirement benefits | (25 | ) | | (21 | ) | | (16 | ) |
| Net cash provided by operating activities | 2,170 |
| | 2,118 |
| | 2,117 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (2,286 | ) | | (2,132 | ) | | (2,076 | ) |
| Nuclear fuel expenditures | (52 | ) | | (63 | ) | | (55 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (315 | ) | | (321 | ) | | (322 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 299 |
| | 305 |
| | 304 |
|
| Other | 18 |
| | 7 |
| | (9 | ) |
| Net cash used in investing activities | (2,336 | ) | | (2,204 | ) | | (2,158 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (451 | ) | | (431 | ) | | (416 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt, net | 112 |
| | (74 | ) | | 257 |
|
| Maturities of long-term debt | (841 | ) | | (681 | ) | | (395 | ) |
| Issuances of long-term debt | 1,352 |
| | 1,345 |
| | 396 |
|
| Issuances of common stock | 74 |
| | — |
| | — |
|
| Debt issuance costs | (14 | ) | | (11 | ) | | (9 | ) |
| Repurchases of common stock for stock-based compensation | — |
| | (24 | ) | | (51 | ) |
| Employee payroll taxes related to stock-based compensation | (19 | ) | | (15 | ) | | (32 | ) |
| Other | (2 | ) | | (1 | ) | | (2 | ) |
| Net cash provided by (used in) financing activities | 205 |
| | 102 |
| | (258 | ) |
| Net change in cash, cash equivalents, and restricted cash | 39 |
| | 16 |
| | (299 | ) |
| Cash, cash equivalents, and restricted cash at beginning of year | 68 |
| | 52 |
| | 351 |
|
| Cash, cash equivalents, and restricted cash at end of year | $ | 107 |
| | $ | 68 |
| | $ | 52 |
|
| | | | | | |
| Noncash financing activity – Issuance of common stock for stock-based compensation | $ | 35 |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $21, $14, and $15 capitalized, respectively) | $ | 387 |
| | $ | 370 |
| | $ | 358 |
|
| Income taxes, net | 21 |
| | (19 | ) | | (12 | ) |
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 877 | | | $ | 834 | | | $ | 821 | |
| | | | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| Depreciation and amortization | 1,085 | | | 1,002 | | | 938 | |
| Amortization of nuclear fuel | 68 | | | 79 | | | 95 | |
| Amortization of debt issuance costs and premium/discounts | 22 | | | 19 | | | 20 | |
| Deferred income taxes and investment tax credits, net | 148 | | | 167 | | | 224 | |
| Allowance for equity funds used during construction | (32) | | | (28) | | | (36) | |
| Stock-based compensation costs | 21 | | | 20 | | | 20 | |
| | | | | |
| Other | 22 | | | (14) | | | 44 | |
| Changes in assets and liabilities: | | | | | |
| Receivables | (47) | | | 79 | | | (24) | |
| Inventories | (25) | | | (10) | | | 39 | |
| Accounts and wages payable | 40 | | | (3) | | | (22) | |
| Taxes accrued | 34 | | | (8) | | | (10) | |
| Regulatory assets and liabilities | (254) | | | 164 | | | 201 | |
| Assets, other | (83) | | | (59) | | | 2 | |
| Liabilities, other | (111) | | | (33) | | | (117) | |
| Pension and other postretirement benefits | (38) | | | (39) | | | (25) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net cash provided by operating activities | 1,727 | | | 2,170 | | | 2,170 | |
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (2,669) | | | (2,411) | | | (2,286) | |
| Wind generation expenditures | (564) | | | 0 | | | 0 | |
| Nuclear fuel expenditures | (66) | | | (31) | | | (52) | |
| Purchases of securities – nuclear decommissioning trust fund | (224) | | | (256) | | | (315) | |
| Sales and maturities of securities – nuclear decommissioning trust fund | 183 | | | 260 | | | 299 | |
| Purchase of bonds | 0 | | | (207) | | | 0 | |
| Proceeds from sale of remarketed bonds | 0 | | | 207 | | | 0 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Other | 11 | | | 3 | | | 18 | |
| | | | | |
| | | | | |
| | | | | |
| Net cash used in investing activities | (3,329) | | | (2,435) | | | (2,336) | |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (494) | | | (472) | | | (451) | |
| Dividends paid to noncontrolling interest holders | (6) | | | (6) | | | (6) | |
| Short-term debt, net | 50 | | | (157) | | | 112 | |
| | | | | |
| Maturities of long-term debt | (442) | | | (580) | | | (841) | |
| | | | | |
| | | | | |
| Issuances of long-term debt | 2,183 | | | 1,527 | | | 1,352 | |
| Issuances of common stock | 476 | | | 68 | | | 74 | |
| | | | | |
| | | | | |
| | | | | |
| Employee payroll taxes related to stock-based compensation | (20) | | | (29) | | | (19) | |
| Debt issuance costs | (20) | | | (17) | | | (14) | |
| Other | 0 | | | 0 | | | (2) | |
| Net cash provided by financing activities | 1,727 | | | 334 | | | 205 | |
| | | | | |
| | | | | |
| Net change in cash, cash equivalents, and restricted cash | 125 | | | 69 | | | 39 | |
| Cash, cash equivalents, and restricted cash at beginning of year | 176 | | | 107 | | | 68 | |
| Cash, cash equivalents, and restricted cash at end of year | $ | 301 | | | $ | 176 | | | $ | 107 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Cash Paid During the Year: | | | | | |
| Interest (net of $16, $20, and $21 capitalized, respectively) | $ | 383 | | | $ | 367 | | | $ | 387 | |
| Income taxes, net | 13 | | | 13 | | | 21 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 | | 2016 |
| Common Stock | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 5,540 |
| | 5,556 |
| | 5,616 |
|
| Shares issued under the DRPlus and 401(k) plan | 74 |
| | — |
| | — |
|
| Stock-based compensation activity | 13 |
| | (16 | ) | | (60 | ) |
| Other paid-in capital, end of year | 5,627 |
| | 5,540 |
| | 5,556 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 1,660 |
| | 1,568 |
| | 1,331 |
|
| Net income attributable to Ameren common shareholders | 815 |
| | 523 |
| | 653 |
|
| Dividends | (451 | ) | | (431 | ) | | (416 | ) |
| Retained earnings, end of year | 2,024 |
| | 1,660 |
| | 1,568 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| Deferred retirement benefit costs, beginning of year | (18 | ) | | (23 | ) | | (3 | ) |
| Change in deferred retirement benefit costs | (4 | ) | | 5 |
| | (20 | ) |
| Deferred retirement benefit costs, end of year | (22 | ) | | (18 | ) | | (23 | ) |
| Total accumulated other comprehensive loss, end of year | (22 | ) | | (18 | ) | | (23 | ) |
| Total Ameren Corporation Shareholders’ Equity | $ | 7,631 |
| | $ | 7,184 |
| | $ | 7,103 |
|
| | | | | | |
| Noncontrolling Interests: | | | | | |
| Beginning of year | 142 |
| | 142 |
| | 142 |
|
| Net income attributable to noncontrolling interest holders | 6 |
| | 6 |
| | 6 |
|
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Noncontrolling interests, end of year | 142 |
| | 142 |
| | 142 |
|
| Total Equity | $ | 7,773 |
| | $ | 7,326 |
| | $ | 7,245 |
|
| | | | | | |
| | | | | | |
| Common stock shares outstanding at beginning of year | 242.6 |
| | 242.6 |
| | 242.6 |
|
| Shares issued under the DRPlus and 401(k) plan | 1.2 |
| | — |
| | — |
|
| Shares issued for stock-based compensation | 0.7 |
| | — |
| | — |
|
| Common stock shares outstanding at end of year | 244.5 |
| | 242.6 |
| | 242.6 |
|
| | | | | | |
| Dividends per common share | $ | 1.8475 |
| | $ | 1.7775 |
| | $ | 1.7150 |
|
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 | | 2018 |
| Common Stock: | | | | | |
| Beginning of year | $ | 2 | | | $ | 2 | | | $ | 2 | |
| Settlement of forward sale agreement through common shares issuance | 1 | | | 0 | | | — | |
| Common stock, end of year | 3 | | | 2 | | | 2 | |
| | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 5,694 | | | 5,627 | | | 5,540 | |
| Settlement of forward sale agreement through common shares issuance | 424 | | | 0 | | | 0 | |
| Shares issued under the DRPlus and 401(k) plan | 51 | | | 68 | | | 74 | |
| Stock-based compensation activity | 10 | | | (1) | | | 13 | |
| | | | | |
| Other paid-in capital, end of year | 6,179 | | | 5,694 | | | 5,627 | |
| | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 2,380 | | | 2,024 | | | 1,660 | |
| Net income attributable to Ameren common shareholders | 871 | | | 828 | | | 815 | |
| Dividends on common stock | (494) | | | (472) | | | (451) | |
| | | | | |
| Retained earnings, end of year | 2,757 | | | 2,380 | | | 2,024 | |
| | | | | |
| Accumulated Other Comprehensive Loss: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Deferred retirement benefit costs, beginning of year | (17) | | | (22) | | | (18) | |
| Change in deferred retirement benefit costs | 16 | | | 5 | | | (4) | |
| | | | | |
| Deferred retirement benefit costs, end of year | (1) | | | (17) | | | (22) | |
| Total accumulated other comprehensive loss, end of year | (1) | | | (17) | | | (22) | |
| Total Ameren Corporation Shareholders’ Equity | $ | 8,938 | | | $ | 8,059 | | | $ | 7,631 | |
| | | | | |
| Noncontrolling Interests: | | | | | |
| Beginning of year | 142 | | | 142 | | | 142 | |
| Net income attributable to noncontrolling interest holders | 6 | | | 6 | | | 6 | |
| Dividends paid to noncontrolling interest holders | (6) | | | (6) | | | (6) | |
| | | | | |
| | | | | |
| | | | | |
| Noncontrolling interests, end of year | 142 | | | 142 | | | 142 | |
| Total Equity | $ | 9,080 | | | $ | 8,201 | | | $ | 7,773 | |
| | | | | |
| | | | | |
| Common stock shares outstanding at beginning of year | 246.2 | | | 244.5 | | | 242.6 | |
| Shares issued under forward sale agreement | 5.9 | | | 0 | | | 0 | |
| Shares issued under the DRPlus and 401(k) plan | 0.7 | | | 0.9 | | | 1.2 | |
| Shares issued for stock-based compensation | 0.5 | | | 0.8 | | | 0.7 | |
| Common stock shares outstanding at end of year | 253.3 | | | 246.2 | | | 244.5 | |
| | | | | |
| Dividends per common share | $ | 2.0000 | | | $ | 1.9200 | | | $ | 1.8475 | |
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 |
| 2017 | | 2016 |
| Operating Revenues: |
|
|
| | |
| Electric | $ | 3,451 |
|
| $ | 3,411 |
| | $ | 3,396 |
|
| Natural gas | 138 |
|
| 126 |
| | 128 |
|
| Total operating revenues | 3,589 |
|
| 3,537 |
| | 3,524 |
|
| Operating Expenses: |
|
|
| | |
| Fuel | 769 |
|
| 737 |
| | 745 |
|
| Purchased power | 164 |
|
| 245 |
| | 254 |
|
| Natural gas purchased for resale | 56 |
| | 47 |
| | 49 |
|
| Other operations and maintenance | 972 |
| | 925 |
| | 912 |
|
| Depreciation and amortization | 550 |
| | 533 |
| | 514 |
|
| Taxes other than income taxes | 329 |
| | 328 |
| | 325 |
|
| Total operating expenses | 2,840 |
| | 2,815 |
| | 2,799 |
|
| Operating Income | 749 |
| | 722 |
| | 725 |
|
| Other Income, Net | 56 |
| | 65 |
| | 62 |
|
| Interest Charges | 200 |
| | 207 |
| | 211 |
|
| Income Before Income Taxes | 605 |
| | 580 |
| | 576 |
|
| Income Taxes | 124 |
| | 254 |
| | 216 |
|
| Net Income | $ | 481 |
| | $ | 326 |
| | $ | 360 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 478 |
| | $ | 323 |
| | $ | 357 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
STATEMENT OF INCOME
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Operating Revenues: | | | | | |
| Electric | $ | 2,984 | | | $ | 3,109 | | | $ | 3,451 | |
| Natural gas | 125 | | | 134 | | | 138 | |
| | | | | |
| Total operating revenues | 3,109 | | | 3,243 | | | 3,589 | |
| Operating Expenses: | | | | | |
| Fuel | 490 | | | 535 | | | 769 | |
| Purchased power | 171 | | | 193 | | | 164 | |
| Natural gas purchased for resale | 43 | | | 53 | | | 56 | |
| Other operations and maintenance | 886 | | | 960 | | | 972 | |
| | | | | |
| Depreciation and amortization | 604 | | | 556 | | | 550 | |
| Taxes other than income taxes | 328 | | | 329 | | | 329 | |
| Total operating expenses | 2,522 | | | 2,626 | | | 2,840 | |
| Operating Income | 587 | | | 617 | | | 749 | |
| | | | | |
| | | | | |
| | | | | |
| Other Income, Net | 76 | | | 58 | | | 56 | |
| Interest Charges | 190 | | | 178 | | | 200 | |
| Income Before Income Taxes | 473 | | | 497 | | | 605 | |
| Income Taxes | 34 | | | 68 | | | 124 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net Income | 439 | | | 429 | | | 481 | |
| Preferred Stock Dividends | 3 | | | 3 | | | 3 | |
| Net Income Available to Common Shareholder | $ | 436 | | | $ | 426 | | | $ | 478 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) |
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively) | 223 |
| | 200 |
|
| Accounts receivable – affiliates | 14 |
| | 11 |
|
| Unbilled revenue | 155 |
| | 165 |
|
| Miscellaneous accounts receivable | 42 |
| | 35 |
|
| Inventories | 358 |
| | 388 |
|
| Current regulatory assets | 14 |
| | 56 |
|
| Other current assets | 26 |
| | 50 |
|
| Total current assets | 832 |
| | 905 |
|
| Property, Plant, and Equipment, Net | 12,103 |
| | 11,751 |
|
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 684 |
| | 704 |
|
| Regulatory assets | 366 |
| | 395 |
|
| Other assets | 306 |
| | 288 |
|
| Total investments and other assets | 1,356 |
| | 1,387 |
|
| TOTAL ASSETS | $ | 14,291 |
| | $ | 14,043 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 580 |
| | $ | 384 |
|
| Short-term debt | 55 |
| | 39 |
|
| Accounts and wages payable | 428 |
| | 475 |
|
| Accounts payable – affiliates | 69 |
| | 60 |
|
| Taxes accrued | 27 |
| | 30 |
|
| Interest accrued | 52 |
| | 54 |
|
| Current regulatory liabilities | 68 |
| | 19 |
|
| Other current liabilities | 123 |
| | 103 |
|
| Total current liabilities | 1,402 |
| | 1,164 |
|
| Long-term Debt, Net | 3,418 |
| | 3,577 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 1,534 |
| | 1,650 |
|
| Accumulated deferred investment tax credits | 42 |
| | 48 |
|
| Regulatory liabilities | 2,799 |
| | 2,664 |
|
| Asset retirement obligations | 623 |
| | 634 |
|
| Pension and other postretirement benefits | 228 |
| | 213 |
|
| Other deferred credits and liabilities | 16 |
| | 12 |
|
| Total deferred credits and other liabilities | 5,242 |
| | 5,221 |
|
| 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 | 1,903 |
| | 1,858 |
|
| Preferred stock | 80 |
| | 80 |
|
| Retained earnings | 1,735 |
| | 1,632 |
|
| Total shareholders’ equity | 4,229 |
| | 4,081 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 14,291 |
| | $ | 14,043 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
BALANCE SHEET
(In millions, except per share amounts)
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 136 | | | $ | 9 | |
| Advances to money pool | 139 | | | 0 | |
| Accounts receivable – trade (less allowance for doubtful accounts of $16 and $7, respectively) | 166 | | | 164 | |
| Accounts receivable – affiliates | 57 | | | 30 | |
| Unbilled revenue | 133 | | | 139 | |
| Miscellaneous accounts receivable | 36 | | | 33 | |
| Inventories | 386 | | | 373 | |
| Current regulatory assets | 60 | | | 8 | |
| Other current assets | 79 | | | 58 | |
| Total current assets | 1,192 | | | 814 | |
| Property, Plant, and Equipment, Net | 13,879 | | | 12,635 | |
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 982 | | | 847 | |
| | | |
| Regulatory assets | 347 | | | 285 | |
| Other assets | 383 | | | 356 | |
| Total investments and other assets | 1,712 | | | 1,488 | |
| TOTAL ASSETS | $ | 16,783 | | | $ | 14,937 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 8 | | | $ | 92 | |
| | | |
| Short-term debt | 0 | | | 234 | |
| Accounts and wages payable | 501 | | | 465 | |
| Accounts payable – affiliates | 46 | | | 52 | |
| Taxes accrued | 42 | | | 24 | |
| Interest accrued | 53 | | | 48 | |
| Current asset retirement obligations | 60 | | | 53 | |
| Current regulatory liabilities | 26 | | | 62 | |
| Other current liabilities | 97 | | | 96 | |
| Total current liabilities | 833 | | | 1,126 | |
| Long-term Debt, Net | 5,096 | | | 4,098 | |
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 1,742 | | | 1,612 | |
| | | |
| Regulatory liabilities | 3,110 | | | 2,937 | |
| Asset retirement obligations | 691 | | | 634 | |
| Pension and other postretirement benefits | 35 | | | 141 | |
| Other deferred credits and liabilities | 66 | | | 40 | |
| Total deferred credits and other liabilities | 5,644 | | | 5,364 | |
| Commitments and Contingencies (Notes 2, 9, 13, and 14) | 0 | | 0 |
| 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 | 2,518 | | | 2,027 | |
| Preferred stock | 80 | | | 80 | |
| Retained earnings | 2,101 | | | 1,731 | |
| Total shareholders’ equity | 5,210 | | | 4,349 | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 16,783 | | | $ | 14,937 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 481 |
| | $ | 326 |
| | $ | 360 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 533 |
| | 514 |
| | 506 |
|
| Amortization of nuclear fuel | 95 |
| | 76 |
| | 88 |
|
| Amortization of debt issuance costs and premium/discounts | 6 |
| | 6 |
| | 6 |
|
| Deferred income taxes and investment tax credits, net | (9 | ) | | 82 |
| | 179 |
|
| Allowance for equity funds used during construction | (27 | ) | | (21 | ) | | (23 | ) |
| Other | 17 |
| | 4 |
| | 5 |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | (32 | ) | | (46 | ) | | 5 |
|
| Inventories | 30 |
| | 18 |
| | (4 | ) |
| Accounts and wages payable | (21 | ) | | 27 |
| | (18 | ) |
| Taxes accrued | (1 | ) | | (1 | ) | | 11 |
|
| Regulatory assets and liabilities | 201 |
| | 26 |
| | 84 |
|
| Assets, other | 2 |
| | 31 |
| | (25 | ) |
| Liabilities, other | (13 | ) | | (23 | ) | | (1 | ) |
| Pension and other postretirement benefits | (2 | ) | | (2 | ) | | (4 | ) |
| Net cash provided by operating activities | 1,260 |
| | 1,017 |
| | 1,169 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (914 | ) | | (773 | ) | | (738 | ) |
| Nuclear fuel expenditures | (52 | ) | | (63 | ) | | (55 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (315 | ) | | (321 | ) | | (322 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 299 |
| | 305 |
| | 304 |
|
| Money pool advances, net | — |
| | 161 |
| | (125 | ) |
| Other | 6 |
| | 7 |
| | (1 | ) |
| Net cash used in investing activities | (976 | ) | | (684 | ) | | (937 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (375 | ) | | (362 | ) | | (355 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 16 |
| | 39 |
| | — |
|
| Maturities of long-term debt | (384 | ) | | (431 | ) | | (266 | ) |
| Issuances of long-term debt | 423 |
| | 399 |
| | 149 |
|
| Debt issuance costs | (5 | ) | | (3 | ) | | (3 | ) |
| Capital contribution from parent | 45 |
| | 30 |
| | 44 |
|
| Net cash used in financing activities | (283 | ) | | (331 | ) | | (434 | ) |
| Net change in cash, cash equivalents, and restricted cash | 1 |
| | 2 |
| | (202 | ) |
| Cash, cash equivalents, and restricted cash at beginning of year | 7 |
| | 5 |
| | 207 |
|
| Cash, cash equivalents, and restricted cash at end of year | $ | 8 |
| | $ | 7 |
| | $ | 5 |
|
| | | | | | |
| Cash Paid During the Year: | | | | | |
| Interest (net of $14, $10, and $12 capitalized, respectively) | $ | 196 |
| | $ | 202 |
| | $ | 209 |
|
| Income taxes, net | 128 |
| | 178 |
| | 27 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
STATEMENT OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 439 | | | $ | 429 | | | $ | 481 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Depreciation and amortization | 613 | | | 564 | | | 533 | |
| Amortization of nuclear fuel | 68 | | | 79 | | | 95 | |
| | | | | |
| Amortization of debt issuance costs and premium/discounts | 6 | | | 5 | | | 6 | |
| Deferred income taxes and investment tax credits, net | 17 | | | (19) | | | (9) | |
| Allowance for equity funds used during construction | (19) | | | (19) | | | (27) | |
| Other | 22 | | | 13 | | | 17 | |
| Changes in assets and liabilities: | | | | | |
| Receivables | (8) | | | 75 | | | (32) | |
| Inventories | (11) | | | (13) | | | 30 | |
| Accounts and wages payable | 26 | | | 16 | | | (21) | |
| Taxes accrued | 9 | | | (15) | | | (1) | |
| Regulatory assets and liabilities | (166) | | | 17 | | | 201 | |
| Assets, other | (2) | | | (28) | | | 2 | |
| Liabilities, other | (80) | | | (32) | | | (13) | |
| Pension and other postretirement benefits | (3) | | | (5) | | | (2) | |
| | | | | |
| | | | | |
| Net cash provided by operating activities | 911 | | | 1,067 | | | 1,260 | |
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,102) | | | (1,076) | | | (914) | |
| Wind generation expenditures | (564) | | | 0 | | | 0 | |
| Nuclear fuel expenditures | (66) | | | (31) | | | (52) | |
| Purchases of securities – nuclear decommissioning trust fund | (224) | | | (256) | | | (315) | |
| Sales and maturities of securities – nuclear decommissioning trust fund | 183 | | | 260 | | | 299 | |
| Purchase of bonds | 0 | | | (207) | | | 0 | |
| Proceeds from sale of remarketed bonds | 0 | | | 207 | | | 0 | |
| Money pool advances, net | (139) | | | 0 | | | 0 | |
| | | | | |
| Other | 8 | | | 8 | | | 6 | |
| Net cash used in investing activities | (1,904) | | | (1,095) | | | (976) | |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (66) | | | (430) | | | (375) | |
| | | | | |
| Dividends on preferred stock | (3) | | | (3) | | | (3) | |
| Short-term debt, net | (234) | | | 179 | | | 16 | |
| | | | | |
| | | | | |
| Maturities of long-term debt | (92) | | | (580) | | | (384) | |
| Issuances of long-term debt | 1,012 | | | 778 | | | 423 | |
| Debt issuance costs | (9) | | | (9) | | | (5) | |
| Capital contribution from parent | 491 | | | 124 | | | 45 | |
| | | | | |
| Net cash provided by (used in) financing activities | 1,099 | | | 59 | | | (283) | |
| Net change in cash, cash equivalents, and restricted cash | 106 | | | 31 | | | 1 | |
| Cash, cash equivalents, and restricted cash at beginning of year | 39 | | | 8 | | | 7 | |
| Cash, cash equivalents, and restricted cash at end of year | $ | 145 | | | $ | 39 | | | $ | 8 | |
| | | | | |
| | | | | |
| | | | | |
| Cash Paid During the Year: | | | | | |
| Interest (net of $10, $12, and $14 capitalized, respectively) | $ | 190 | | | $ | 190 | | | $ | 196 | |
| Income taxes, net | 25 | | | 101 | | | 128 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 | | 2016 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 1,858 |
| | 1,828 |
| | 1,822 |
|
| Capital contribution from parent | 45 |
| | 30 |
| | 6 |
|
| Other paid-in capital, end of year | 1,903 |
| | 1,858 |
| | 1,828 |
|
| | | | | | |
| Preferred Stock | 80 |
| | 80 |
| | 80 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,632 |
| | 1,671 |
| | 1,669 |
|
| Net income | 481 |
| | 326 |
| | 360 |
|
| Common stock dividends | (375 | ) | | (362 | ) | | (355 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,735 |
| | 1,632 |
| | 1,671 |
|
| | | | | | |
| Total Shareholders’ Equity | $ | 4,229 |
| | $ | 4,081 |
| | $ | 4,090 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 | | 2018 |
| Common Stock | $ | 511 | | | $ | 511 | | | $ | 511 | |
| | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 2,027 | | | 1,903 | | | 1,858 | |
| Capital contribution from parent | 491 | | | 124 | | | 45 | |
| | | | | |
| Other paid-in capital, end of year | 2,518 | | | 2,027 | | | 1,903 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Preferred Stock | 80 | | | 80 | | | 80 | |
| | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,731 | | | 1,735 | | | 1,632 | |
| Net income | 439 | | | 429 | | | 481 | |
| Dividends on common stock | (66) | | | (430) | | | (375) | |
| Dividends on preferred stock | (3) | | | (3) | | | (3) | |
| Retained earnings, end of year | 2,101 | | | 1,731 | | | 1,735 | |
| | | | | |
| Total Shareholders’ Equity | $ | 5,210 | | | $ | 4,349 | | | $ | 4,229 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| Operating Revenues: | | | | | | Operating Revenues: | | | | | |
| Electric | $ | 1,761 |
| | $ | 1,784 |
| | $ | 1,735 |
| Electric | $ | 1,775 | | | $ | 1,730 | | | $ | 1,761 | |
| Natural gas | 815 |
| | 743 |
| | 754 |
| Natural gas | 760 | | | 797 | | | 815 | |
| | Total operating revenues | 2,576 |
| | 2,527 |
| | 2,489 |
| Total operating revenues | 2,535 | | | 2,527 | | | 2,576 | |
| Operating Expenses: | | | | | | Operating Expenses: | | | | | |
| Purchased power | 429 |
| | 417 |
| | 399 |
| Purchased power | 355 | | | 368 | | | 429 | |
| Natural gas purchased for resale | 318 |
| | 264 |
| | 292 |
| Natural gas purchased for resale | 229 | | | 278 | | | 318 | |
| Other operations and maintenance | 799 |
| | 799 |
| | 828 |
| Other operations and maintenance | 775 | | | 782 | | | 799 | |
| Depreciation and amortization | 374 |
| | 341 |
| | 319 |
| Depreciation and amortization | 434 | | | 406 | | | 374 | |
| Taxes other than income taxes | 144 |
| | 137 |
| | 132 |
| Taxes other than income taxes | 140 | | | 143 | | | 144 | |
| Total operating expenses | 2,064 |
| | 1,958 |
| | 1,970 |
| Total operating expenses | 1,933 | | | 1,977 | | | 2,064 | |
| Operating Income | 512 |
| | 569 |
| | 519 |
| Operating Income | 602 | | | 550 | | | 512 | |
| | Other Income, Net | 42 |
| | 12 |
| | 34 |
| Other Income, Net | 59 | | | 53 | | | 42 | |
| Interest Charges | 149 |
| | 144 |
| | 140 |
| Interest Charges | 155 | | | 147 | | | 149 | |
| Income Before Income Taxes | 405 |
| | 437 |
| | 413 |
| Income Before Income Taxes | 506 | | | 456 | | | 405 | |
| Income Taxes | 98 |
| | 166 |
| | 158 |
| Income Taxes | 124 | | | 110 | | | 98 | |
| Net Income | 307 |
| | 271 |
| | 255 |
| Net Income | 382 | | | 346 | | | 307 | |
| Other Comprehensive Loss, Net of Taxes: | | | | | | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $-, $-, and $(1), respectively | — |
| | — |
| | (5 | ) | |
| Comprehensive Income | $ | 307 |
| | $ | 271 |
| | $ | 250 |
| |
| | | | | | | |
| | | | | | | |
| Net Income | $ | 307 |
| | $ | 271 |
| | $ | 255 |
| |
| | Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
| Preferred Stock Dividends | 3 | | | 3 | | | 3 | |
| Net Income Available to Common Shareholder | $ | 304 |
| | $ | 268 |
| | $ | 252 |
| Net Income Available to Common Shareholder | $ | 379 | | | $ | 343 | | | $ | 304 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) BALANCE SHEET (In millions) |
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $11 and $12, respectively) | 224 |
| | 234 |
|
| Accounts receivable – affiliates | 21 |
| | 9 |
|
| Unbilled revenue | 140 |
| | 158 |
|
| Miscellaneous accounts receivable | 40 |
| | 35 |
|
| Inventories | 125 |
| | 134 |
|
| Current regulatory assets | 110 |
| | 87 |
|
| Other current assets | 16 |
| | 15 |
|
| Total current assets | 676 |
| | 672 |
|
| Property, Plant, and Equipment, Net | 9,198 |
| | 8,293 |
|
| Investments and Other Assets: | | | |
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 759 |
| | 822 |
|
| Other assets | 275 |
| | 147 |
|
| Total investments and other assets | 1,445 |
| | 1,380 |
|
| TOTAL ASSETS | $ | 11,319 |
| | $ | 10,345 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | — |
| | $ | 457 |
|
| Short-term debt | 72 |
| | 62 |
|
| Accounts and wages payable | 302 |
| | 337 |
|
| Accounts payable – affiliates | 58 |
| | 70 |
|
| Taxes accrued | 23 |
| | 19 |
|
| Interest accrued | 31 |
| | 33 |
|
| Customer deposits | 76 |
| | 69 |
|
| Current environmental remediation | 42 |
| | 42 |
|
| Current regulatory liabilities | 62 |
| | 92 |
|
| Other current liabilities | 130 |
| | 177 |
|
| Total current liabilities | 796 |
| | 1,358 |
|
| Long-term Debt, Net | 3,296 |
| | 2,373 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 1,119 |
| | 1,021 |
|
| Regulatory liabilities | 1,741 |
| | 1,629 |
|
| Pension and other postretirement benefits | 280 |
| | 285 |
|
| Environmental remediation | 109 |
| | 134 |
|
| Other deferred credits and liabilities | 204 |
| | 235 |
|
| Total deferred credits and other liabilities | 3,453 |
| | 3,304 |
|
| 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 | 2,173 |
| | 2,013 |
|
| Preferred stock | 62 |
| | 62 |
|
| Retained earnings | 1,539 |
| | 1,235 |
|
| Total shareholders’ equity | 3,774 |
| | 3,310 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 11,319 |
| | $ | 10,345 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
BALANCE SHEET
(In millions)
| | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 0 | | | $ | 0 | |
| Accounts receivable – trade (less allowance for doubtful accounts of $34 and $10, respectively) | 234 | | | 215 | |
| Accounts receivable – affiliates | 64 | | | 28 | |
| Unbilled revenue | 136 | | | 139 | |
| Miscellaneous accounts receivable | 12 | | | 25 | |
| Inventories | 135 | | | 121 | |
| Current regulatory assets | 37 | | | 57 | |
| | | |
| Other current assets | 29 | | | 29 | |
| Total current assets | 647 | | | 614 | |
| Property, Plant, and Equipment, Net | 11,201 | | | 10,083 | |
| Investments and Other Assets: | | | |
| Goodwill | 411 | | | 411 | |
| Regulatory assets | 742 | | | 694 | |
| Other assets | 534 | | | 383 | |
| Total investments and other assets | 1,687 | | | 1,488 | |
| TOTAL ASSETS | $ | 13,535 | | | $ | 12,185 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| | | |
| Short-term debt | $ | 0 | | | $ | 53 | |
| Borrowings from money pool | 19 | | | 0 | |
| Accounts and wages payable | 363 | | | 299 | |
| Accounts payable – affiliates | 51 | | | 82 | |
| | | |
| | | |
| Customer deposits | 74 | | | 77 | |
| | | |
| | | |
| Current regulatory liabilities | 88 | | | 84 | |
| Other current liabilities | 221 | | | 249 | |
| Total current liabilities | 816 | | | 844 | |
| Long-term Debt, Net | 3,946 | | | 3,575 | |
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 1,367 | | | 1,224 | |
| | | |
| Regulatory liabilities | 2,063 | | | 1,849 | |
| Pension and other postretirement benefits | 69 | | | 214 | |
| Environmental remediation | 57 | | | 87 | |
| Other deferred credits and liabilities | 251 | | | 260 | |
| Total deferred credits and other liabilities | 3,807 | | | 3,634 | |
| Commitments and Contingencies (Notes 2, 13, and 14) | 0 | | 0 |
| Shareholders’ Equity: | | | |
| Common stock, 0 par value, 45.0 shares authorized – 25.5 shares outstanding | 0 | | | 0 | |
| Other paid-in capital | 2,652 | | | 2,188 | |
| Preferred stock | 62 | | | 62 | |
| Retained earnings | 2,252 | | | 1,882 | |
| | | |
| Total shareholders’ equity | 4,966 | | | 4,132 | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 13,535 | | | $ | 12,185 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 307 |
| | $ | 271 |
| | $ | 255 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 375 |
| | 341 |
| | 318 |
|
| Amortization of debt issuance costs and premium/discounts | 13 |
| | 13 |
| | 14 |
|
| Deferred income taxes and investment tax credits, net | 88 |
| | 171 |
| | 154 |
|
| Other | 11 |
| | — |
| | (1 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | — |
| | (7 | ) | | (72 | ) |
| Inventories | 8 |
| | (1 | ) | | 15 |
|
| Accounts and wages payable | (13 | ) | | 19 |
| | 12 |
|
| Taxes accrued | (13 | ) | | 18 |
| | 1 |
|
| Regulatory assets and liabilities | 1 |
| | 16 |
| | 120 |
|
| Assets, other | (1 | ) | | (2 | ) | | (3 | ) |
| Liabilities, other | (92 | ) | | 3 |
| | (9 | ) |
| Pension and other postretirement benefits | (25 | ) | | (14 | ) | | (8 | ) |
| Net cash provided by operating activities | 659 |
| | 828 |
| | 796 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,258 | ) | | (1,076 | ) | | (924 | ) |
| Other | 10 |
| | 6 |
| | 6 |
|
| Net cash used in investing activities | (1,248 | ) | | (1,070 | ) | | (918 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | — |
| | — |
| | (110 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 10 |
| | 11 |
| | 51 |
|
| Maturities of long-term debt | (457 | ) | | (250 | ) | | (129 | ) |
| Issuances of long-term debt | 929 |
| | 496 |
| | 247 |
|
| Debt issuance costs | (9 | ) | | (6 | ) | | (4 | ) |
| Capital contribution from parent | 160 |
| | 8 |
| | — |
|
| Other | (2 | ) | | (1 | ) | | (1 | ) |
| Net cash provided by financing activities | 628 |
| | 255 |
| | 51 |
|
| Net change in cash and cash equivalents | 39 |
| | 13 |
| | (71 | ) |
| Cash, cash equivalents, and restricted cash at beginning of year | 41 |
| | 28 |
| | 99 |
|
| Cash, cash equivalents, and restricted cash at end of year | $ | 80 |
| | $ | 41 |
| | $ | 28 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $7, $4, and $3 capitalized, respectively) | $ | 144 |
| | $ | 139 |
| | $ | 127 |
|
| Income taxes, net | 28 |
| | (22 | ) | | 8 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 382 | | | $ | 346 | | | $ | 307 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 434 | | | 405 | | | 375 | |
| Amortization of debt issuance costs and premium/discounts | 12 | | | 12 | | | 13 | |
| Deferred income taxes and investment tax credits, net | 118 | | | 80 | | | 88 | |
| Other | 8 | | | 7 | | | 11 | |
| Changes in assets and liabilities: | | | | | |
| Receivables | (28) | | | 11 | | | 0 | |
| Inventories | (15) | | | 2 | | | 8 | |
| Accounts and wages payable | 15 | | | (19) | | | (13) | |
| Taxes accrued | (23) | | | 21 | | | (13) | |
| Regulatory assets and liabilities | (72) | | | 155 | | | 1 | |
| Assets, other | (76) | | | (23) | | | (1) | |
| Liabilities, other | (46) | | | (5) | | | (92) | |
| Pension and other postretirement benefits | (30) | | | (30) | | | (25) | |
| Net cash provided by operating activities | 679 | | | 962 | | | 659 | |
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,447) | | | (1,208) | | | (1,258) | |
| | | | | |
| Other | 3 | | | 3 | | | 10 | |
| Net cash used in investing activities | (1,444) | | | (1,205) | | | (1,248) | |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (9) | | | 0 | | | 0 | |
| Dividends on preferred stock | (3) | | | (3) | | | (3) | |
| Short-term debt, net | (53) | | | (19) | | | 10 | |
| Money pool borrowings, net | 19 | | | 0 | | | 0 | |
| | | | | |
| Maturities of long-term debt | 0 | | | 0 | | | (457) | |
| | | | | |
| Issuances of long-term debt | 373 | | | 299 | | | 929 | |
| Debt issuance costs | (4) | | | (4) | | | (9) | |
| | | | | |
| | | | | |
| Capital contribution from parent | 464 | | | 15 | | | 160 | |
| Other | 0 | | | 0 | | | (2) | |
| Net cash provided by financing activities | 787 | | | 288 | | | 628 | |
| Net change in cash, cash equivalents, and restricted cash | 22 | | | 45 | | | 39 | |
| Cash, cash equivalents, and restricted cash at beginning of year | 125 | | | 80 | | | 41 | |
| Cash, cash equivalents, and restricted cash at end of year | $ | 147 | | | $ | 125 | | | $ | 80 | |
| | | | | |
| Cash Paid During the Year: | | | | | |
| Interest (net of $6, $8, and $7 capitalized, respectively) | $ | 137 | | | $ | 127 | | | $ | 144 | |
| Income taxes, net | 41 | | | 4 | | | 28 | |
| | | | | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 | | 2016 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Other Paid-in Capital |
| |
| |
|
| Beginning of year | 2,013 |
| | 2,005 |
| | 2,005 |
|
| Capital contribution from parent | 160 |
| | 8 |
| | — |
|
| Other paid-in capital, end of year | 2,173 |
| | 2,013 |
| | 2,005 |
|
| | | | | | |
| Preferred Stock | 62 |
| | 62 |
| | 62 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,235 |
| | 967 |
| | 825 |
|
| Net income | 307 |
| | 271 |
| | 255 |
|
| Common stock dividends | — |
| | — |
| | (110 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,539 |
| | 1,235 |
| | 967 |
|
| | | | | | |
| Accumulated Other Comprehensive Income: | | | | | |
| Deferred retirement benefit costs, beginning of year | — |
| | — |
| | 5 |
|
| Change in deferred retirement benefit costs | — |
| | — |
| | (5 | ) |
| Deferred retirement benefit costs, end of year | — |
| | — |
| | — |
|
| Total accumulated other comprehensive income, end of year | — |
| | — |
| | — |
|
| | | | | | |
| Total Shareholders’ Equity | $ | 3,774 |
| | $ | 3,310 |
| | $ | 3,034 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2020 | | 2019 | | 2018 |
| Common Stock | $ | 0 | | | $ | 0 | | | $ | 0 | |
| | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 2,188 | | | 2,173 | | | 2,013 | |
| Capital contribution from parent | 464 | | | 15 | | | 160 | |
| | | | | |
| Other paid-in capital, end of year | 2,652 | | | 2,188 | | | 2,173 | |
| | | | | |
| | | | | |
| Preferred Stock | 62 | | | 62 | | | 62 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,882 | | | 1,539 | | | 1,235 | |
| Net income | 382 | | | 346 | | | 307 | |
| Dividends on common stock | (9) | | | 0 | | | 0 | |
| Dividends on preferred stock | (3) | | | (3) | | | (3) | |
| | | | | |
| Retained earnings, end of year | 2,252 | | | 1,882 | | | 1,539 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total Shareholders’ Equity | $ | 4,966 | | | $ | 4,132 | | | $ | 3,774 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBERDecember 31, 20182020
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 40,00043,700 square mile area in central and southern Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 0.8 million customers.
•Ameren Transmission Company of Illinois, doing business as ATXI, operates a FERC rate-regulated electric transmission business.business in the MISO. ATXI was incorporated in Illinois in 2006. In December 2020, ATXI is constructingcompleted construction of the ninth and final line segment of the Illinois Rivers transmission line, a MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, andline. ATXI also operates the Spoon River project,and Mark Twain transmission lines, which waswere placed in service in February 2018.2018 and December 2019, respectively.
The COVID-19 pandemic continues to be a constantly evolving situation. In 2020, we experienced a net decrease in our sales volumes, an increase in our accounts receivable balances that were past due or that were a part of a deferred payment arrangement, and a decline in our cash collections from customers. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. Shelter-in-place orders began taking effect in our service territories in mid-March 2020. These orders generally required individuals to remain at home and precluded or limited the operation of businesses that were deemed nonessential. While our business operations were deemed essential and were not directly impacted by the shelter-in-place orders, approximately 65% of our workforce transitioned to remote working arrangements in mid-March 2020. In order to work more effectively in certain areas, a portion of our workforce returned to our work locations in early June 2020 under a phased approach, and, as of the date of this filing, approximately 50% of our workforce continues to work remotely. In mid-May 2020, shelter-in-place orders effective in our service territories began to be relaxed, with fewer restrictions on social activities and nonessential businesses beginning to reopen. However, certain restrictions remain in place that limit individual activities and the operation of nonessential businesses. Additional restrictions may be imposed in the future.
We continue to assess the impacts the pandemic is having on our businesses, including but not limited to impacts on our liquidity; demand for residential, commercial, and industrial electric and natural gas services; changes in deferred payment arrangements for customers; the timing and extent to which recovery of incremental costs incurred, net of savings, and forgone customer late fee revenues at Ameren also evaluates competitiveMissouri is allowed by the MoPSC; changes in our ability to disconnect customers for nonpayment; bad debt expense; supply chain operations; the availability of our employees and contractors; counterparty credit; capital construction; infrastructure operations and maintenance; energy-efficiency programs; and pension valuations. While the revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission investment opportunitiesbusinesses are decoupled from changes in sales volumes, changes in sales volumes at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers may affect net income. With respect to uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Pursuant to a June 2020 ICC order, Ameren Illinois’ electric bad debt rider provided for the recovery of bad debt expense in 2020, which reverted to the recovery of bad debt write-offs, net of any subsequent recoveries, in 2021. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri does not expect a material impact to earnings from increases in bad debt expense. In October 2020,
Ameren Missouri filed requests with the MoPSC for accounting authority orders related to certain impacts resulting from the COVID-19 pandemic. If issued as they arise.
requested, the orders would allow Ameren Missouri to accumulate certain costs incurred related to the COVID-19 pandemic, including bad debt write-offs, net of cost savings, as well as forgone customer late fee and reconnection fee revenues, for a specified time period, for potential recovery in future electric and natural gas service regulatory rate reviews. Our customers’ payment for our services has been adversely affected by the COVID-19 pandemic, resulting in a decrease to our cash flow from operations. As of December 31, 2020, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 29%, 22%, and 35%, or $133 million, $40 million, and $93 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. As of December 31, 2019, these percentages were 18%, 18%, and 20%, or $75 million, $30 million, and $45 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. For information regarding Ameren Missouri’s and Ameren Illinois’ suspension and subsequent reinstatement of customer disconnections and late fee charges for nonpayment and Ameren Missouri’s requests for accounting authority orders related to the COVID-19 pandemic, see Note 2 – Rate and Regulatory Matters below.The Coronavirus Aid, Relief, and Economic Security Act is a federal law enacted in March 2020. Provisions in the act include temporary changes to the utilization of net operating losses, deferral of the payment of the employer portion of Social Security taxes, and additional funding for customer energy assistance, among other things. As of December 31, 2020, the implementation of the act by the Ameren Companies had no material impact to their financial statements.
Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated.eliminated, except as disclosed inNote 13 – Related-party Transactions. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
WeOur 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 returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. Ameren Missouri and Ameren Illinois have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs without a traditional regulatory rate review.
In Ameren Missouri’s and Ameren Illinois’ natural gas businesses, changes in natural gas costs are reflected in billings to their respective customers through PGA clauses. 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.
Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year, without a traditional rate proceeding, for a pass-through to customers of 95% of the variance in net energy costs from the amount set in base rates, subject to MoPSC prudence review. The difference between the actual amounts incurred for these items and the amounts recovered from Ameren Missouri customers’ base rates is deferred as a regulatory asset or liability. The deferred amounts are either billed or refunded to customers in a subsequent period.
In Ameren Illinois’ electric distribution business, changes in purchased power and transmission service costs are reflected in billings to its customers through pass-through rate-adjustment clauses. The difference between actual purchased power and transmission service 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.
In addition to the rate-adjustment mechanisms discussed above, Ameren Missouri and Ameren Illinois have approvals from rate regulators to use other cost recovery mechanisms. Ameren Missouri has a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a tracker on certain excess deferred taxes, a renewable energy standards cost tracker, a solar rebate program tracker, PISA, and a RESRAM. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Ameren Illinois participates in performance-based formula ratemaking for its electric distribution business and its electric energy-efficiency investments. Ameren Illinois also has environmental cost riders, an asbestos-related litigation rider, a natural gas energy-efficiency rider, a QIP rider, a VBA rider, a bad debt rider, and cost recovery mechanisms for renewable energy credits and zero emission credits. See Note 2 – Rate and Regulatory Matters for additional information on theour regulatory frameworks, regulatory recovery mechanisms, and regulatory assets and liabilities recorded at December 31, 20182020 and 2017.2019.
Ameren, Ameren Missouri, and Ameren IllinoisWe continually assess the recoverability of theirour respective regulatory assets. Regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that reductions in customerscustomers’ rates or refunds to customers related to regulatory liabilities are no longer probable, the amounts are credited to earnings.
Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents include short-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash.
In November 2016, the FASB issued authoritative guidance that requires, including on a retrospective basis, restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. Our adoption of this guidance, effective January 2018, did not result in material changes to previously reported cash flows from operating, investing, or financing activities. The changes in our restricted cash balances during the year ended December 31, 2018, were primarily reflected as increases in cash provided by operating activities as a result of our adoption of this guidance.
The following table provides See Note 15 – Supplemental Information for a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets asand the statements of December 31, 2018and2017:
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| Ameren | Ameren
Missouri | Ameren
Illinois | Ameren | Ameren
Missouri | Ameren
Illinois |
| Cash and cash equivalents | $ | 16 |
| $ | — |
| $ | — |
| | $ | 10 |
| $ | — |
| $ | — |
|
| Restricted cash included in “Other current assets” | 13 |
| 4 |
| 6 |
| | 21 |
| 5 |
| 6 |
|
| Restricted cash included in “Other assets” | 74 |
| — |
| 74 |
| | 35 |
| — |
| 35 |
|
| Restricted cash included in “Nuclear decommissioning trust fund” | 4 |
| 4 |
| — |
| | 2 |
| 2 |
| — |
|
| Total cash, cash equivalents, and restricted cash | $ | 107 |
| $ | 8 |
| $ | 80 |
| | $ | 68 |
| $ | 7 |
| $ | 41 |
|
Restricted cash included in Ameren’s other current assets primarily represents participant funds from Ameren (parent)’s DRPlus and funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees. Restricted cash included in Ameren Missouri’s and Ameren Illinois’ other current assets primarily represents funds held by the VEBA trust.
Restricted cash included in Ameren’s and Ameren Illinois’ other assets primarily represents amounts in a trust fund restricted for the use of funding certain asbestos-related claims and amounts collected under a cost recovery rider that are restricted for use in the procurement of renewable energy credits.
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, 2018 and 2017, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $33 million and $31 million, respectively.
For the years ended December 31, 2018, 2017, and 2016 the Ameren Companies recorded immaterial bad debt expense.
flows.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a bad debt riderriders that adjustsadjust rates for net write-offs of customer accounts receivable above or below those being collected in rates. In 2020, the rider for electric distribution allowed for recovery of bad debt expense recognized under GAAP. See Note 2 – Rate and Regulatory Matters for additional information.
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. The following table presents a breakdownSee Note 15 – Supplemental Information for the components of inventories for each of the Ameren Companies at December 31, 2018 and 2017:inventories.
|
| | | | | | | | | | | | |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2018 | | | | | | |
Fuel(a) | | $ | 123 |
| | $ | — |
| | $ | 123 |
|
| Natural gas stored underground | | 7 |
| | 64 |
| | 71 |
|
| Materials, supplies, and other | | 228 |
| | 61 |
| | 289 |
|
| Total inventories | | $ | 358 |
| | $ | 125 |
| | $ | 483 |
|
| 2017 | | | | | | |
Fuel(a) | | $ | 154 |
| | $ | — |
| | $ | 154 |
|
| Natural gas stored underground | | 8 |
| | 74 |
| | 82 |
|
| Materials, supplies, and other | | 226 |
| | 60 |
| | 286 |
|
| Total inventories | | $ | 388 |
| | $ | 134 |
| | $ | 522 |
|
| |
(a) | Consists of coal, oil, and propane. |
Property, Plant, and Equipment, Net
We capitalize the cost of additions to, and betterments of, units of property, plant, and equipment. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures includingare expensed as incurred. Beginning in 2020, maintenance expenses related to scheduled Callaway nuclear refueling and maintenance outages, arewhich were previously expensed as incurred.incurred, are deferred and amortized over the number of expected months until the completion of the next refueling outage, which historically has been approximately 18 months. When units of depreciable property are retired, the original costs, lessand the associated removal cost, net of salvage, values, are charged to accumulated depreciation. If environmental expenditures are related to assets currently in use, as in the case of the installation of pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset. See Asset Retirement Obligations section below and Note 3 – Property, Plant, and Equipment, Net for additional information.
Ameren Missouri’s cost of nuclear fuel is capitalized as a part of “Property, Plant, and Equipment, Net” on the balance sheet and then amortized to fuel expense on a unit-of-production basis. The cost is charged to “Operating Expenses – Fuel” in the statement of income.income on a unit-of-production basis.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The composite rates include a provision for the estimated removal cost of property, plant, and equipment retired from service, net of salvage. The provision for depreciation for the Ameren Companies in 2018, 2017,2020, 2019, and 20162018 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
WeAs a part of “Property, Plant, and Equipment, Net” on the balance sheet, we capitalize allowance for funds used during construction, orwhich is the cost of borrowed funds and the cost of equity funds (preferred and common shareholders’ equity) applicable to eligible rate-regulated construction expenditures,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. This accounting practice offsets the effect on earnings of the cost of financing during construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
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. The following table presents the average allowance for funds used during construction debt and equity blended rates that were applied to construction projects in 2018, 2017, and 2016:
|
| | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Ameren Missouri | 7 | % | | 7 | % | | 7 | % |
| Ameren Illinois | 5 | % | | 4 | % | | 5 | % |
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, 20182020 and 2017.2019. Ameren has four4 reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois has three3 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, 20182020 and 2017.2019. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 20182020 and 2017.2019.
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 andoccur 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, on an annual basis.test.
Ameren and Ameren Illinois elected to perform a qualitative assessment for their annual goodwill impairment test conducted as of October 31, 2018.2020. 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 significantly exceeded its carrying value as of October 31, 2018,2020, resulting in no0 impairment of Ameren’s or Ameren Illinois’ goodwill. The following factors, among others, were considered by Ameren and Ameren Illinois when they assessed whether it was more likely than not that the fair value of each of their reporting units exceeded its carrying value as of October 31, 2018:
macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
pending regulatory rate review outcomes and projections of future regulatory rate review outcomes;
changes in laws and potential law changes;
observable industry market multiples;
achievement of IEIMA and FEJA performance metrics and the yield of the 30-year United States Treasury bonds;
changes in the FERC-allowed return on equity with respect to transmission services; and
projected operating results and cash flows.
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets to the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount by which the carrying value exceeds the estimated fair value of the assets. In the period in which we determine that an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its estimated fair value less cost to sell. We did not identify any events or changes in circumstances that indicated that the carrying value of long-lived assets may not be recoverable in 2018 and 2017.2020 or 2019.
Variable Interest Entities
As of December 31, 2018,2020 and 2019, Ameren and Ameren Missouri had interests in unconsolidated variable interest entities that were established to construct wind generation facilities and, ultimately, sell those constructed facilities to Ameren Missouri. Neither Ameren nor Ameren Missouri are the primary beneficiary of these variable interest entities because neither has the power to direct matters that most significantly affect the entities' activities, which include designing, financing, and constructing the wind generation facilities. Asinterests as a result, these variable interest entities are not required to be consolidated. As of December 31, 2018, the maximum exposure to loss related to these variable interest entities was approximately $16 million, which represents the portion of interconnection study costs that may be incurred by Ameren and Ameren Missouri. The risk of a loss was assessed to be remote and, accordingly, Ameren and Ameren Missouri have not recognized a liability associated with any portion of the maximum exposure to loss. See Note 2 – Rate and Regulatory Matters for additional information on the agreements to acquire these wind generation facilities.
As of December 31, 2018 and 2017, Ameren also hadlimited partner in various equity method investments, in unconsolidated variable interest entities totaling $22$37 million and $17$28 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. These investments are accounted for as equity method investments. Ameren is not the primary beneficiary of these variable interest entitiesinvestments because it does not have the power to direct matters that most significantly affect the entities' activities. As a result,activities of these variable interest entities are not required to be consolidated.entities. As of December 31, 2018,2020, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $22$37 million plus associated outstanding funding commitments of $16 million.$35 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
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 based onfor accretion and changes in the estimated fair values of the obligations, with a corresponding increase or decrease in the asset book value.value for the fair value changes. Asset book values, reflected within “Property, Plant, and Equipment, Net” on the balance sheet, are depreciated over the remaining useful life of the related asset. Due to regulatory recovery, that depreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $14$28 million $26, $18 million, and $31$14 million for the years ended December 31, 2018, 2017,2020, 2019, and 2016,2018, respectively, which was deferred as a reduction to the net regulatory liability. The net regulatory liability also reflects deferrals of net realized and unrealized gains and losses withina deferral for the nuclear decommissioning trust fund balance for the Callaway energy center.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 High Prairie Renewable energy center decommissioning,centers, CCR facilities, and river structures. Also,Additionally, Ameren, Ameren Missouri, and Ameren Illinois have recorded AROs for retirement costs associated with asbestos removal and the disposal of certain transformers. Asset removal costs that do not constitute legal obligations are classified as regulatory liabilities. See Note 215 – Rate and Regulatory Matters.
The following table providesSupplemental Information for a reconciliation of the beginning and ending carrying amountamounts of AROsAROs.
Estimated funds collected from customers to pay for the years ended December 31, 2018future removal cost of property, plant, and 2017: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.
|
| | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren | |
| Balance at December 31, 2016 | $ | 644 |
| | $ | 6 |
| | $ | 650 |
| |
| Liabilities settled | (12 | ) | | (1 | ) | | (13 | ) | |
Accretion(a) | 26 |
| | — |
| | 26 |
| |
Change in estimates(b) | (18 | ) | | (1 | ) | | (19 | ) | |
| Balance at December 31, 2017 | $ | 640 |
| (c) | $ | 4 |
| (d) | $ | 644 |
| (c) |
| Liabilities settled | (7 | ) | | — |
| | (7 | ) | |
Accretion(a) | 27 |
| | — |
| | 27 |
| |
Change in estimates(e) | (14 | ) | | — |
| | (14 | ) | |
| Balance at December 31, 2018 | $ | 646 |
| (c) | $ | 4 |
| (d) | $ | 650 |
| (c) |
| |
(a) | Ameren Missouri’s accretion expense was deferred as a decrease to regulatory liabilities. |
| |
(b) | Ameren Missouri changed its fair value estimate primarily because of an extension of the remediation period of certain CCR storage facilities, an update to the decommissioning of the Callaway energy center to reflect the cost study and funding analysis filed with the MoPSC in 2017, and an increase in the assumed discount rate. |
| |
(c) | Balance included $23 million and $6 million in “Other current liabilities” on the balance sheet as of December 31, 2018 and 2017, respectively.
|
| |
(d) | Included in “Other deferred credits and liabilities” on the balance sheet. |
| |
(e) | Ameren Missouri changed its fair value estimate primarily due to a reduction in the cost estimate for closure of certain CCR storage facilities. |
Company-owned Life Insurance
Ameren and Ameren Illinois have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of December 31, 2018,2020, the cash surrender value of company-owned life insurance at Ameren and Ameren Illinois was $244$272 million (December 31, 20172019 – $265$264 million) and $122$115 million (December 31, 20172019 – $129$123 million), respectively, while total borrowings against the policies were $113$107 million (December 31, 20172019 – $120$114 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.
Noncontrolling Interests
As The net cash surrender value of December 31, 2018 and 2017, Ameren’s noncontrolling interests includedcompany-owned life insurance is affected by the preferred stockinvestment performance of a separate account in which Ameren Missouri and Ameren Illinois.holds a beneficial interest.
Operating Revenues
In the first quarter of 2018, we adopted authoritative accounting guidance related to revenue from contracts with customers using the full retrospective method, with no material changes to the amount or timing of revenue recognition. 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. MISO-related capacityCapacity and ancillary service revenues and wholesale bilateral capacity revenues are earned as services are provided.
Retail distribution, electric transmission, and off-system revenues, including the underlying components described above, represent a series of goods or services that are substantially the same and have the same pattern of transfer over time to our customers. Revenues from contracts with customers are equal to the amounts billed and our estimate of electric and natural gas retail distribution services provided but unbilled at the end of each accounting period. RevenuesCustomers are billed at least monthly, and payments are due less than one month after goods and/or services are provided. See Note 1516 – 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 VBA.the DCA. 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, 2020 and 2019, 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. As of December 31, 2018 and 2017, our remaining performance obligations were immaterial.
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. Revenues are recognized once the resettlement amount is received. There were no0 material MISO resettlements in 2018, 2017,2020, 2019, or 2016.2018.
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. See Note 11 – Stock-based Compensation for additional information.
Deferred Compensation
As of December 31, 2018, and 2017, “Other deferred credits and liabilities” on Ameren’s balance sheet included deferred compensation obligations of $80 million and $86 million, respectively, recorded at the present value of future benefits to be paid.
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, 2018, 2017, and 2016:
|
| | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | |
| Ameren Missouri | $ | 164 |
| | $ | 153 |
| | $ | 151 |
| |
| Ameren Illinois | 118 |
| | 112 |
| (a) | 108 |
| (a) |
| Ameren | $ | 282 |
| | $ | 265 |
| | $ | 259 |
| |
| |
(a) | Amounts have been adjusted from those previously reported to reflect additional excise taxes for the years ended December 31, 2017 and 2016. |
Unamortized Debt Discounts, Premiums, and Issuance Costs
Long-term debt discounts, premiums, and issuance costs are amortized over the lives of the related issuances. Credit agreement fees are amortized over the term of the agreement.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We expect that regulators will reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in certain deferred tax liabilities that were recorded because of decreases in the statutory rate have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery through future customer rates of tax benefits related to the equity component of allowance for funds used during construction, as well as the effects of tax rate increases. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes is recorded as a regulatory asset or liability on the balance sheet and will be collected from, or refunded to, customers. For deferred tax balances not included in rate base, the revaluation of deferred taxes is recorded as an adjustment to income tax expense on the income statement. See Note 12 – Income Taxes for further information regarding the revaluation of deferred taxes related to the TCJA and Missouri and Illinois state corporate income tax rate changes.
Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren (parent) that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax using a stand-alone calculation, which is similar to that whichwhat would be owed or refunded had the party been separately subject to tax without considering the impact of consolidation. Any net benefit attributable to Ameren (parent) is reallocated to the other parties. This reallocation is treated as a capital contribution to the party receiving the benefit. See Note 13 – Related-party Transactions for information regarding capital contributions under the tax allocation agreement.
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 period. Earnings per diluted share reflects the potential dilution that would occur if certain stock-based performance share units and restricted stock units were settled. The number of shares from performance share units assumed to be settled was 2.0 million, 1.6 million, and 0.8 million for the years ended December 31, 2018, 2017, and 2016, respectively. The number of shares from restricted stock units assumed to be settled was immaterial for the year ended December 31, 2018, and not applicable for the years ended December 31, 2017 and 2016. There were no potentially dilutive securities excluded from the diluted earnings per share calculations for the years ended December 31, 2018, 2017, and 2016.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance, as well as guidance issued but not yet adopted, that could affect the Ameren Companies.
In the first quarter of 2018,2020, the Ameren Companies adopted authoritative accounting guidance that requires credit losses on various topics. See the Operating Revenues section above for more information on our adoption of the guidance on revenue from contracts with customers. See Note 10 – Retirement Benefits for more information on our adoption of the guidance on the presentation of net periodic pension and postretirement benefit cost. See the Cash, Cash Equivalents, and Restricted Cash section above for more information on our adoption of the guidance on
restricted cash. Our adoption of the guidance on the recognition and measurement ofmost financial assets carried at amortized cost and off-balance sheet credit exposures, such as financial liabilities did not have a material impact on our results of operationsguarantees or financial position.
Leases
In February 2016, the FASB issued authoritative guidance that requires an entity to recognize assets and liabilities arising from all leases with a term greater than one year. This guidance will affect the Ameren Companies’ financial position by increasing the assets and liabilities recorded relating to operating leases. Ameren expects both its assets and liabilities to increase by approximately $40 million, largely due to an increase at Ameren Missouri. We do not expect the impacts of this guidanceloan commitments, to be material to our results of operations or cash flows. Consistent withmeasured using a current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend on its classification as a finance lease or operating lease. The guidance also requires additional disclosures to enable users of financial statements to understand the amount, timing, and uncertainty of cash flows arising from leases. We will adopt this guidance using the January 1, 2019 effective date as the date of our application of the standard. No adjustment to comparative periods will be made. This guidance will be effective for the Ameren Companies in the first quarter of 2019. See Note 14 – Commitments and Contingencies for additional information on our leases.
Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued authoritative guidance that requires an entity to recognize an allowance for financial instruments that reflects its current estimate ofexpected credit losses expected to be incurred over the life of the financial instruments.loss (CECL) model. The guidance requires an entity to measure expected credit losses using relevant information about past events, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. We are currently assessingIn addition, the impactsguidance made certain changes to the impairment model applicable to available-for-sale debt securities, such as requiring credit losses to be presented as an allowance rather than a write-down on impaired debt securities for which there is neither an intent nor a more-likely-than-not requirement to sell. Our adoption of this guidance did not have a material impact on our results of operations, financial position, and disclosures. This guidance will be effective for the Ameren CompaniesCompanies’ financial statements and did not result in the first quarter of 2020, and will require changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date.
Fair Value Measurement Disclosures See Note 15 – Supplemental Information for additional information regarding credit losses on accounts receivable.
In August 2018, the FASB issued authoritative guidance that affects disclosure requirements for fair value measurements. This guidance will be effective for the Ameren Companies in the first quarter of 2020, with early adoption permitted. We are currently assessing the impacts of this guidance on our disclosures.
Defined Benefit Plan Disclosures
In August 2018, the FASB issued authoritative guidance that affects disclosure requirements for defined benefit plans. This guidance will be effective for the Ameren Companies adopted authoritative accounting guidance that altered certain disclosure requirements in relation to fair value measurements. See Note 8 – Fair Value Measurements for our fair value measurement disclosures.
In the fourth quarter of 2020, and will require changes to be applied retrospectively to each period presented. Early adoption is permitted. We are currently assessing the impacts of this guidance on our disclosures.
Implementation Costs Incurred in Certain Cloud Computing Arrangements
In August 2018, the FASB issued authoritative guidance that aligns the requirements for capitalizing implementation costs incurred in certain hosting arrangements with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This guidance requires capitalized implementation costs to be expensed over the term of the hosting arrangement and presented in the same line item in the statement of income as the fees of the associated hosting arrangement. Capitalized implementation costs must be presented in the balance sheet in the same line item that a prepayment for the fees of the associated hosting arrangement would be presented, and payments for capitalized implementation costs must be classified in the statement of cash flows in the same manner as payments for hosting arrangement fees. The Ameren Companies early adopted this guidance in the third quarter of 2018 and applied the guidance prospectively to all implementation costs incurred after the date of adoption. Implementation costs capitalized in 2018 were immaterial.
Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued authoritative guidance that specifies the classification and presentation of certain cash flow items to reduce diversity in practice. This guidance was effective for the Ameren Companies adopted authoritative accounting guidance that altered certain disclosure requirements in the first quarter of 2018 and was applied retrospectively. Our adoption of this guidance did not result in material changesrelation to previously reported cash flows from operating, investing, or financing activities.defined benefit plans. See Note 10 – Retirement Benefits for our defined benefit plan disclosures.
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
Missouri
The MoPSC regulates rates and other matters for Ameren Missouri’s electric service and natural gas distribution businesses. The rates Ameren Missouri Senate Bill 564charges 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 allowed ROE established in the review.
On June 1, 2018,Ameren Missouri Senate Bill 564 was enacted. The provision of the law applicable to the TCJA was effective immediately; the remaining provisions,has recovery mechanisms, including the ability to elect PISA, became effective August 28, 2018. The law required the MoPSC to authorize a reduction in Ameren Missouri’sRESRAM, FAC, MEEIA, PGA, DCA, and ISRS, that allow customer rates to pass throughbe adjusted without a traditional regulatory rate review. These riders, along with the effectPISA, each described in more detail below, partially mitigate the effects of the TCJA within 90 daysregulatory lag. Ameren Missouri also employs other recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain income tax position tracker, a tracker on certain excess deferred income taxes, a renewable energy standard cost tracker, and a solar rebate program cost tracker. Each of the law’s effective date. In July 2018, the MoPSC authorizedthese trackers allows Ameren Missouri to reduce its annual revenue requirement by $167 milliondefer the difference between actual costs incurred and reflect that reductioncosts included in customer rates beginning August 1, 2018.as a regulatory asset or regulatory liability. The reduction included $74 million for the amortization of excess accumulated deferred income taxes. In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $60 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liabilitydifference will be reflected in customerbase rates overin a periodsubsequent MoPSC rate order. Ameren Missouri’s cost recovery under any of timeits recovery mechanisms is subject to be determined by the MoPSC in the next regulatory rate review.prudence reviews.
Pursuant to itsThe PISA election,permits Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and earn a weighted-average cost of capital return at the applicable WACC on rate base oninvestments in certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. The rate base on which the return is calculated incorporates qualifying capital expenditures since the PISA election date, and changes in totalregulatory asset for accumulated depreciation excluding retirements and plant-related deferred income taxes. The debt return on rate base is recognized in earnings as a reduction of “Interest Charges” until PISA deferrals are reflected in customer rates, while the equityalso earns a return is recognized in earnings as “Operating Revenues – Electric” when billed to customers. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, andapplicable WACC, with all approved PISA deferrals will be added to rate
base prospectively and recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, mitigatesand earn a return at the impacts ofapplicable WACC for investments in renewable generation plant placed in service. The deferrals are a regulatory lag between regulatory rate reviews. Theasset until they are included in customer rates and collected in a subsequent period. Those investments not eligible for recovery under the PISA and the remaining15% of certain property, plant, and equipment placed in service, and not eligible for recovery under PISA, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. See below for discussionAmeren Missouri recognizes the cost of debt on PISA deferrals in revenue, instead of using the RESRAM. Amounts deferred under PISA were immaterialapplicable WACC, with the difference recognized in revenues when recovery of such deferrals is reflected in customer rates. Under Missouri law, as of December 31, 2018.
As a result of Ameren Missouri’sthe PISA election, additional provisions ofapply to Ameren Missouri, law apply, including provisions limitinglimitations on electric customer rate increases to a 2.85% compound annual growth rate in the average overall customer rate per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in the July 2018 MoPSC order. Additionally, Ameren Missouri’s electric base rates, as determined in the July 2018 MoPSC order, are frozen until April 1, 2020. Customer rates under the MEEIA, the FAC, and the RESRAM riders have not been frozen.increases. If rate changes from the FAC or the RESRAM riders would cause rates to temporarily exceed the2.85%rate cap, the overage would be deferred for future recovery in the next regulatory rate review; however, rates established in such regulatory rate review willwould be subject to the rate cap. Any deferred overages approved for recovery willwould be recovered in a manner consistent with costs recovered under the PISA. Excluding customer rates under the MEEIA rider, which are not subject to the rate cap, Ameren Missouri would incur a penalty equal to the amount of deferred overage that would cause customer rates to exceed the 2.85% rate cap. Ameren Missouri did not incur a penalty related to the rate cap in 2020. Both the rate capincrease limitation and the PISA election are effective through December 2023, unless2023. Missouri law provides for the ability to use the PISA, if Ameren Missouri requests and receives MoPSC approval of anfor extension, through December 2028.
Wind Generation Facilities andThe RESRAM
In the second quarter of 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Terra-Gen, LLC to acquire, after construction, a 400-megawatt wind generation facility, which is expected to be located in northeastern Missouri. In October 2018, the MoPSC issued an order approving a unanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. In December 2018, Ameren Missouri received FERC approval to acquire the facility after construction. A transmission interconnection agreement with the MISO for this facility is expected in the fall of 2019. Also, in October 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of EDF Renewables, Inc. to acquire, after construction, a wind generation facility of up to 157 megawatts. In February 2019, Ameren Missouri filed with the MoPSC a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. The up to 157-megawatt facility is expected to be located in northwestern Missouri. A transmission interconnection agreement with the MISO for this facility is expected in early 2020. Both facilities are expected to be completed by the end of 2020 and would help Ameren Missouri comply with the Missouri renewable energy standard. Each acquisition is subject to certain conditions, including entering into a MISO transmission interconnection agreement at an acceptable cost for each facility and obtaining FERC approval and the issuance of a certificate of convenience and necessity by the MoPSC for the up to 157-megawatt facility, as well as other customary contract terms and conditions. These agreements collectively represent approximately $1 billion in capital expenditures expected in 2020, which is included in Ameren Missouri’s Smart Energy Plan.
As a part of its May 2018 filing, Ameren Missouri requested the MoPSC to authorize a proposed RESRAM that would allow permits Ameren Missouri to adjustrecover or refund, through customer rates, the difference between the cost of compliance with Missouri’s renewable energy standard and the amount set in base rates. Customer rates are adjusted for the RESRAM on an annual basis without a traditional regulatory rate review. In Octoberreview, subject to MoPSC prudence reviews. The difference between actual compliance costs and December 2018, the MoPSC issued orders approving the RESRAM. In January 2019, the MoOPC filed an appeal with the Missouri Court of Appeals, Western District, challenging the MoPSC’s December 2018 order allowingcosts 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 through the RESRAM, the 15% of capital investment not recovered under PISA. Ameren Missouri expects a decision by the end of 2019. The RESRAM is designed to mitigate the impacts of
regulatory lag for the cost of compliance with renewable energy standards, including recovery of investments in wind generation and other renewables related to compliance with Missouri’s renewable generation, by providing more timely recovery of costsenergy standard, and earn a return at the applicable WACC on those investments not already provided for in customer rates or recovered under PISA. RESRAMany other recovery mechanism.
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. Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense. The difference between actual net energy 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. FAC regulatory assets earn carrying costs at short-term interest rates.
Renewable Choice Program
In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalitiesbase rates for electric service are required to electbe reset at least every four years to receive up to 100% of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election, net of changes in the market price of such energy. Based on customer contracts, the program enables Ameren Missouri to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it could own. As applicable, the addition of generation by Ameren Missouri would be subject to the issuance of a certificate of convenience and necessity by the MoPSC, obtaining transmission interconnection agreements with MISO or other RTOs, and FERC approval. Ameren Missouri anticipates finalizing customer interest and pursuing renewable energy projects to fulfill requirements in 2019. Without extension, the option to elect into the program will terminate in the third quarter of 2023.
MEEIA
In July 2018, the Missouri Supreme Court overturned a 2016 decision by the Missouri Court of Appeals, Western District, which had upheld a 2015 MoPSC order regarding the determination of a certain input used to calculate the MEEIA 2013 performance incentive, and remanded the matter to the MoPSC. In January 2019, the MoPSC issued an order approving an additional $9 million MEEIA 2013 performance incentive. Accordingly, Ameren Missouri recognized the additional performance incentive in the first quarter of 2019. In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a stipulation and agreement among Ameren Missouri, the MoPSC staff, and the MoOPC. Ameren Missouri collected $28 million of the performance incentive over a two-year period that began in February 2017.
The MEEIA 2016 plan provides Ameren Missouri with a performance incentive to earn additional revenues by achieving certain customer energy-efficiency goals, including $27 million if 100% of the goals are achieved during the three-year period beginning March 2016, with the potential to earn more if Ameren Missouri’s energy savings exceed those goals. In September 2017, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings resultsallow for the first year of the MEEIA 2016 plan. In October 2018, Ameren Missouri received an order from the MoPSC approving Ameren Missouri’s energy savings results for the second year of the MEEIA 2016 plan. As a result of these orders and in accordance with revenue recognition guidance, Ameren Missouri recognized $5 million of revenues in the first quarter of 2018, $6 million of additional revenues in the fourth quarter of 2018, and $11 million of additional revenues in the first quarter of 2019 relating to the MEEIA 2016 performance incentive.
In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65 million per year through 2021. The plan includes the continued use of the FAC.
The MEEIA rider, which allowspermits Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIArecover customer energy-efficiency program costs, andthe related lost electric margins, and the amounts collected from customers. In addition, the plan includes aany performance incentive that provides through the MEEIA without a traditional regulatory rate review. MEEIA assets earn carrying costs at short-term interest rates.
Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100%is a member of the goals are achieved duringMISO, and its transmission rate is calculated in accordance with the period ended December 2021. Additional revenues may be earned ifMISO 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, bundled retail rates include an amount for transmission-related costs and revenues.
The PGA allows Ameren Missouri exceeds 100%to recover prudently incurred costs of natural gas purchased on behalf of its energy savings goals.
2018 Natural Gas Delivery Service Regulatory Rate Review
In December 2018,customers without a traditional regulatory rate review. These pass-through purchased gas costs do not affect Ameren Missouri filedMissouri’s natural gas margins, as any change in costs is offset by a request withcorresponding 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 DCA ensures recoverability of the MoPSC to increase its annual revenues for natural gas delivery service by approximately $4 million.revenue requirement that is dependent on sales volumes for nearly all customers. The DCA allows Ameren Missouri to adjust natural gas delivery service rates without a traditional regulatory rate increase request was based on a 10.30% return on equity, a capital structure composed of 51.84% common equity, a rate base of $259 million, and a test year ended June 30, 2018, with certain pro-forma adjustments through the anticipated true-up date of May 31, 2019. In December 2018, the MoPSC issued an order approving a stipulation and agreement for an interim rate reduction of $2 million to reflect cost of service updates including the reductionreview when changes occur in the federal corporate income tax rate and the amortization of excess deferred taxes as a result of the TCJA. The interim rate reduction became effective January 2, 2019, and will continue until new rates aresales volumes from those volumes approved by the MoPSC in thisthe previous regulatory rate review.
Mark Twain Project Return The difference between actual gas delivery service revenues billed to customers and revenues approved by the MoPSC in a given period is deferred as a regulatory asset or liability. DCA regulatory assets earn carrying costs at short-term interest rates. The deferred amount is either billed or refunded to customers in a subsequent period. In addition, the ISRS permits certain prudently incurred natural gas infrastructure replacement costs to be recovered from customers on Equity Incentive Adder
In November 2018, the FERC issued an order approving a 50more timely basis point return on equity incentive adderbetween regulatory rate reviews. The ROE currently used by Ameren Missouri for the Mark Twain project, effective as of February 14, 2018, based on the unique nature of risks involved in the project. This incentive adder is in addition to the current 50 basis point incentive adder for participation in an RTO and the total return on equity, inclusive of all incentive adders, is subject to the toppurposes of the zone of reasonableness. The impact to Ameren’s 2018 earnings was immaterial.
ISRS tariff is 9.725%.
Illinois
IEIMA & FEJA
Under a formula ratemaking framework effective through 2022,The ICC regulates rates and other matters for Ameren Illinois’ electric distribution service and natural gas distribution businesses. The
rates Ameren Illinois charges customers for electric distribution service are subjectcalculated under a performance-based formula ratemaking framework. 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 an annual revenue requirement reconciliationallowed ROE established in the review.
Ameren Illinois’ election to its actual recoverable costs and allowed return on equity. Theuse the electric distribution service performance-based formula ratemaking framework qualifies as an alternative revenue program under GAAP. Each year,allowed by state law, described below, permits Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement reflected inadjust customer rates for that year and its estimateto recover the cost of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC. As of December 31, 2018, Ameren Illinois had recorded regulatory assets of $16 million and $54 million, including interest, to reflect its expected 2018 and its approved 2017 revenue requirement reconciliation adjustments, respectively. As of December 31, 2017, Ameren Illinois had recorded a $24 million regulatory asset to reflect its approved 2016 revenue requirement reconciliation adjustment, which was collected, with interest, from customers during 2018.
In November 2018, the ICC issuedelectric distribution service on an order in Ameren Illinois’ annual update filing that approved a $72 million increase inbasis. Ameren Illinois’ electric distribution service also has other cost recovery mechanisms in place that allow customer rates beginningto be adjusted without a traditional regulatory rate review. Ameren Illinois’ electric distribution service business has riders for power procurement and transmission services incurred on behalf of its customers, renewable energy credit compliance, zero emission credits, and certain environmental costs, as well as bad debt write-offs and the costs of certain asbestos-related claims not recovered in January 2019. This order reflected an increasebase 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 the annualICC prudence reviews.
Ameren Illinois’ electric distribution service performance-based formula rate based on 2017ratemaking framework allows Ameren Illinois to reconcile electric distribution service rates to its actual costs and expected net plant additions for 2018, and an increase to include the 2017 revenue requirement reconciliation adjustment. It also includedon an annual basis. If a decrease for the conclusion of the 2016given year’s revenue requirement reconciliation adjustment, which was fullyvaries from the amount collected from customers, in 2018, consistentan adjustment is made to electric operating revenues with the ICC’s December 2017 annual update filing order.
The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking framework through 2022, and clarifyingan offset to a regulatory asset or liability to reflect that a common equity ratio up to and including 50% is prudent. Beginning in 2017, the FEJA permitted Ameren Illinois to recover, within the following two years, its electric distributionyear’s actual revenue requirement, for a given year, independent of actual sales volumes.
The FEJA allowsregulatory balance is then collected from, or refunded to, customers within two years from the end of the year. In addition, Ameren Illinois to earn aIllinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for both its electric distribution service and its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments, the revenue requirements are deferred asbased on recoverable costs, year-end rate base, and a regulatory assetyear-end ratemaking capital structure, and earn a return at its weighted-average costthe applicable WACC. The ROE component of capital, with the equity returnapplicable WACC is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion ofpoints and any performance-related basis point adjustments, described in more detail below. Therefore, Ameren Illinois’ annual ROE for its electric distribution business is directly correlated to the yields on such bonds. In addition, regulatory assets applicable to formula ratemaking for both electric distribution service and electric energy-efficiency investments earn a return at the applicable WACC. However, Ameren Illinois recognizes the cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates.
Unless extended, the performance-based formula ratemaking framework expires at the end of 2022. If not extended, Ameren Illinois would be required to establish future rates through a traditional regulatory rate review, which would allow the use of a future test year, with the ICC. The decoupling provisions extend beyond the end of the formula ratemaking by law, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. See below for information regarding a request filed by Ameren Illinois to continue reconciling electric distribution service rates to the last annual revenue requirement approved by the ICC under the formula ratemaking framework after the framework expires or is no longer elected.
Ameren Illinois electric distribution service business is also subject to performance standards. Failure to achieve the standards would result in a reduction in the company’s allowed ROE calculated under the formulas. The performance standards applicable to electric distribution service include improvements in service reliability to reduce both the frequency and duration of outages, a reduction in the number of estimated bills, a reduction of consumption from inactive meters, and a reduction in bad debt expense. The electric distribution service regulatory framework provides for ROE penalties up to 38 basis points annually in 2021 and 2022 if these performance standards are not met. The allowed ROE on energy-efficiency investments can be increased or decreased by 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 2020, 2019, and 2018, there were no performance-related basis point adjustments.adjustments that materially affected financial results.
Ameren Illinois’ natural gas distribution business has recovery mechanisms, including the QIP, PGA, and VBA, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, described in more detail below, mitigate the effects of regulatory lag. Ameren Illinois employs other riders for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expenses and invested capital taxes not recovered in base rates. Pass-through costs under the riders do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
The QIP provides Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that are placed in service between regulatory rate reviews. Infrastructure investments under the QIP earn a return at the applicable WACC. Eligible natural gas investments include projects to improve safety and reliability and modernization investments, such as smart meters. The deferrals are a regulatory asset until they are included in customer rates in a subsequent period. Recovery of the regulatory asset begins two months after the qualifying natural gas plant is placed in service and continues until such plant is included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP is subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. If the rate impact limitation was met in a particular year, the amount of rate base causing the QIP
rate to exceed the limitation would be exposed to regulatory lag until a year when that amount could be recovered under QIP or is added to rate base as a part of a regulatory rate review. Upon issuance of a natural gas delivery service rate order, QIP rate base is transferred to base rates and the QIP is reset to zero, which mitigates the risk that the QIP will exceed its statutory limitations in future years and ensures timely recovery of capital investments. Without legislative action, the QIP will sunset after December 2023.
The PGA allows Ameren Illinois to recover prudently incurred costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review. These pass-through purchased gas costs do not affect Ameren Illinois natural gas margins, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The VBA ensures recoverability of the natural gas distribution service revenue requirement that is dependent on sales volumes for residential and small nonresidential customers. For these rate classes, the VBA allows Ameren Illinois to adjust natural gas distribution service rates without a traditional regulatory rate review when changes occur in sales volumes from those volumes approved by the ICC in a previous regulatory rate review. The difference between allowed sales revenues and amounts billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is collected from, or refunded to, customers in a subsequent period. VBA regulatory assets for a given year that are not fully collected by the end of the following year begin earning carrying costs at short-term interest rates.
Federal
The FERC regulates rates and other matters for Ameren Illinois’ transmission business and ATXI, as well as for Ameren Missouri. See discussion above related to Ameren Missouri. Both Ameren Illinois and ATXI are members of the MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated annually and become effective each January with forecasted information. The formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed ROE. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is collected from, or refunded to, customers within two years from the end of the year. FERC revenue requirement reconciliation adjustment regulatory assets earn carrying costs at each company’s short-term interest rates, while each company incurs interest at a FERC-prescribed rate on related regulatory liabilities. In addition, the FERC has approved transmission rate incentives, including a 50 basis point incentive adder to the allowed base ROE for Ameren Illinois and ATXI for participation in an RTO.
Proceedings and Updates
Missouri
March 2020 MoPSC Electric Rate Order
In March 2020, the MoPSC issued an order in Ameren Missouri’s July 2019 electric service regulatory rate review, approving nonunanimous stipulation and agreements. The order resulted in a decrease of $32 million to Ameren Missouri’s annual revenue requirement for electric retail service, which reflected infrastructure investments as of December 31, 2019. The order also provided for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, and certain excess deferred income taxes that the MoPSC previously authorized in earlier electric rate orders. The order reduced the annualized base level of net energy costs pursuant to the FAC by approximately $115 million from the base level established in the MoPSC’s March 2017 electric rate order. The order also changed the annualized regulatory asset and liability amortization amounts and the base level of expenses for trackers. On an annualized basis, these changes reflect approximately $20 million of increased revenues and approximate decreases in purchased power expenses of $15 million, other operating and maintenance expenses of $60 million, and income tax expenses of $20 million. Additionally, the annual revenue requirement incorporated increases of approximately $50 million for the reduction in sales volumes resulting from MEEIA programs and approximately $50 million of depreciation and amortization expense for amounts previously deferred under PISA. The increase in the annual revenue requirement related to the MEEIA programs is seasonally weighted to the summer. One of the stipulation and agreements approved by the MoPSC’s March 2020 order states that the net impact of the revenue and expense changes noted above reflects a 9.4% to 9.8% ROE on an unspecified percent of common equity applicable to rate base. In addition, the order required Ameren Missouri to donate $8 million to low-income assistance programs, which was reflected in results of operations in the first quarter of 2020. The new rates, base level of expenses, and amortizations became effective on April 1, 2020. In April 2020, the MoPSC issued another order in Ameren Missouri’s July 2019 electric service regulatory rate review, reaffirming the existing percentage of net energy cost variances allowed to be recovered or refunded under the FAC.
Wind Generation Facilities
In December 2020, Ameren Missouri acquired a 400-MW wind generation project located in northeastern Missouri for approximately $615 million, and placed the assets in service as the High Prairie Renewable Energy Center. The purchase price included $564 million of cash, a deferred purchase price obligation withheld as credit support in relation to certain potential claims, contingent consideration, and transaction costs. In January 2021, Ameren Missouri acquired an up-to 300-MW wind generation project located in northwestern Missouri. At the date of this filing, Ameren Missouri placed 120 MWs in service as the Atchison Renewable Energy Center, with a purchase price of approximately $200 million, including transaction costs. There have been changes to the schedule for this project, particularly as a result of component delivery delays. Ameren Missouri expects approximately 150 MWs of the up-to 300-MW project to be in service by the end of the first quarter of 2021, and the remaining portion to be in service later in 2021. Both renewable energy centers are expected to support Ameren Missouri’s compliance with the Missouri renewable energy standard.
MEEIA
In August 2020, the MoPSC issued an order approving a unanimous stipulation and agreement with respect to the 2022 program year of Ameren Missouri’s six-year MEEIA 2019 program. The order established performance incentives that would provide Ameren Missouri an opportunity to earn additional revenues, including $11 million if Ameren Missouri achieves certain energy-efficiency goals during the 2022 program year and an additional $1 million if Ameren Missouri exceeds its targeted energy-efficiency goals. Ameren Missouri intends to invest $70 million in energy-efficiency programs during the 2022 program year. The August 2020 order also approved Ameren Missouri’s energy savings results for the first year of the MEEIA 2019 program. As a result of this order and in accordance with revenue recognition guidance, Ameren Missouri recognized revenues of $6 million during 2020. As a result of MoPSC orders issued in September 2017, October 2018, January 2019, and September 2019 related to performance incentives for the MEEIA 2013 and MEEIA 2016 programs, and in accordance with revenue recognition guidance, Ameren Missouri recognized revenues of $37 million and $11 million during 2019 and 2018, respectively.
Requests for Accounting Authority Orders Related to COVID-19 Pandemic Costs
Ameren Missouri suspended disconnections for customer nonpayment and late fees in mid-March 2020, and resumed those activities for commercial and industrial customers in mid-July 2020 and residential customers in early August 2020. In October 2020, Ameren Missouri filed requests with the MoPSC for accounting authority orders related to its electric and natural gas services. If issued as requested, the orders would allow Ameren Missouri to accumulate certain costs incurred related to the COVID-19 pandemic, including bad debt write-offs, net of cost savings, as well as forgone customer late fee and reconnection fee revenues, for a specified time period, for potential recovery in future electric and natural gas service regulatory rate reviews. Costs incurred, net of savings, and forgone customer late fee and reconnection fee revenues related to the COVID-19 pandemic from March 2020 through December 2020 were immaterial. The MoPSC is under no deadline to issue orders, and Ameren Missouri cannot predict the ultimate outcome of these regulatory proceedings.
Illinois
Electric Distribution Service Rates
In December 2020, the ICC issued an order approvingin Ameren Illinois’ implementationannual update filing that approved a $49 million decrease in Ameren Illinois’ electric distribution service rates beginning in January 2021. This order reflected a decrease to the annual formula rate based on 2019 actual costs, a decrease to include the 2019 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the FEJA electric energy-efficiency savings targets and investments for 2018 through 2021. Ameren Illinois plans to invest approximately $100 million per year in electric energy-efficiency programs through 2023, consistent with targets established by the FEJA. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments arerevenue requirement reconciliation adjustment, which was fully collected from customers throughin 2020, consistent with the ICC’s December 2019 annual update filing order. It also reflected an increase based on expected net plant additions for 2020.
Request to Continue Electric Distribution Service Rate Reconciliation
In April 2020, Ameren Illinois filed a rider and are not included inrequest with the ICC, which, if approved, would allow Ameren Illinois to continue to reconcile electric distribution service rates to the last annual revenue requirement approved by the ICC under the performance-based formula ratemaking framework.framework, for a period of up to two years after the framework expires or is no longer elected. Ameren Illinois expects a decision by the ICC in March 2021.
Electric Customer Energy-Efficiency Investments
In June 2018,May 2020, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to establish the revenue requirement to be used for 20192021 rates with the ICC. In November 2018,December 2020, the ICC issued an order that approved 2019 rates of $35 million for2021 electric customer energy-efficiency investments,rates of $51 million, which represents an increase of $20$7 million from 20182020 rates.
January 2021 Natural Gas Delivery Service Regulatory Rate ReviewOrder
In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual rates for natural gas delivery service. In November 2018,2021, the ICC issued an order approving a stipulation and agreement thatin Ameren Illinois’ February 2020 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas rate increasedelivery service of $32$76 million based on a 9.87% return on common equity,9.67% allowed ROE, a capital structure composed of 50%52% common equity, and a rate base of $1.6$2.1 billion. This increase reflects the reduction in the federal statutory corporate income tax rate enacted under the TCJA, as well as the increase in the Illinois corporate income tax rate thatThe new rates became effective in July 2017, which collectively decreased annual rates by approximately $17 million. The new customer rates were effective in November 2018.January 2021. As a result of this order, the rate base under the QIP rider was reset to zero. Ameren Illinois used a 20192021 future test year in this proceeding.
Income Tax Regulatory MechanismsQIP Prudence Review
In FebruaryMarch 2019, Ameren Illinois filed a request for an ICC prudence review of natural gas infrastructure investments recovered under the QIP during 2018. In November 2019, the Illinois Attorney General’s office challenged the recovery of capital investments, among other things, that were made during 2018, alleging that the amount of investments is excessive based on a comparison to historical investment levels. The Illinois Attorney General’s office is not alleging imprudence or that the investments do not qualify for recovery. In March 2020, the ICC grantedstaff filed testimony that supports the prudence and reasonableness of the capital investments made during 2018. Ameren Illinois’ request, filed2018 QIP rate recovery under review by the ICC is within the rate increase limitations allowed by law. Ameren Illinois expects a decision by the ICC in January 2018,this proceeding within the first half of 2021.
Service Disconnection Moratorium Proceeding
In March 2020, the ICC issued an order requiring all Illinois electric distribution and natural gas utilities to establishsuspend disconnections and late fees for customer nonpayment, on an interim basis, effective March 18, 2020. Pursuant to an ICC order issued in June 2020 and following a ridervoluntary extension of the suspension of residential disconnections, Ameren Illinois resumed disconnection activities for commercial and industrial customers for nonpayment in early August 2020 and residential customers in mid-September 2020, with the exception of residential customers classified as low income, expressing a financial hardship, or relying on medical equipment. Disconnections for nonpayment for these and all other residential customers are expected to reducebegin in April 2021, which is after the annual winter moratorium period on disconnections that ends March 31, 2021. Ameren Illinois began the winter moratorium on November 18, 2020, which has historically started at the beginning of December. Ameren Illinois also resumed charging late fees to all customers in late July 2020. The June 2020 order requires Ameren Illinois to implement more flexible credit and collection practices, on a temporary basis, including longer deferred payment arrangements, extending to 24 months in certain cases, and programs to provide financial assistance to customers. In addition, the order allows Ameren Illinois to recover up to $8 million in costs incurred related to the financial assistance programs. The portion of these costs associated with Ameren Illinois’ electric distribution customer rates for the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJAbusiness will be recovered through its bad debt rider and the return of excess deferred taxes, net of the increase in state income taxes enacted in July 2017. Ameren Illinois' electricportion associated with its natural gas distribution customer rates were reduced as a result of the rider beginning in the first quarter of 2018. The estimated reduction of approximately $50 million per year will continue through 2019, as base ratesbusiness will be adjusted to reflectrecovered through a special purpose rider established by the current income tax rates starting in 2020.
In April 2018, the ICC approved a rider for the difference between revenues billed under natural gas rates established pursuant to Ameren Illinois’ most recent natural gas rateorder. The order and the revenues that would have been billed had the state and federal tax rate changes
discussed above been in effect. The rider requiredalso allows Ameren Illinois to record this difference as a regulatory liability beginning January 25, 2018.recover forgone customer late fees and costs incurred related to the COVID-19 pandemic. The portion of these forgone late fees and costs associated with Ameren Illinois’ electric distribution business will be recovered through formula rates and the portion associated with its natural gas customer rates were reduceddistribution business will be recovered through the special purpose rider. In addition, the order allows Ameren Illinois’ electric distribution business to recover bad debt expense for 2020, instead of write-offs net of subsequent recoveries, through future true-ups in its bad debt rider. The bad debt rider reverted to the recovery of bad debt write-offs, net of any subsequent recoveries, in 2021.
Federal
Transmission Formula Rate Revisions
In February 2020, the MISO, on behalf of Ameren Missouri, Ameren Illinois, and ATXI, filed requests with the FERC to revise each company’s transmission formula rate calculations with respect to calculation inputs for materials and supplies. In May 2020, the FERC issued orders approving the revisions prospectively. In addition, the FERC declined to order refunds for earlier periods, as a resultrequested by intervenors in Ameren Illinois’ filing, but directed its audit staff to review historical rate recovery in connection with an ongoing FERC audit. This review could lead the FERC to ultimately require refunds for periods prior to 2019. In June 2020, Ameren Missouri, Ameren Illinois, and ATXI filed requests for rehearing arguing, among other things, the revisions should be applied retrospectively to include the period January 1, 2019, to June 1, 2020, and that the FERC should not require refunds for periods prior to 2019. In July 2020, the FERC denied the rehearing requests without addressing the issues raised. In July 2020, Ameren Missouri, Ameren Illinois, and ATXI filed an appeal of the rider beginning in May 2018. As base rates were updated with the November 2018 natural gas rate order discussed above, a reduction of approximately $15 million will be reflected in customer rates substantially over a one-year period.
ATXI’s Illinois Rivers Project
In August 2017, the Illinois Circuit Court for Edgar County dismissed several of ATXI’s condemnation cases related to one line segment in the Illinois Rivers project. These cases had been filed to obtain easements and rights of way necessary to complete the line segment. The court found that required notice was not givenJuly 2020 rehearing denials to the relevant landowners duringUnited States Court of Appeals for the underlying ICC proceeding. Upon appeal, inDistrict of Columbia Circuit, which is under no deadline to address the appeal. In October 2018,2020, the Illinois Supreme Court reversed the Illinois Circuit Court for Edgar County’s decision and remanded the case for further proceedings. In December 2018, the Illinois Supreme CourtFERC issued an order reaffirming its May 2020 order and denying the arguments raised in the rehearing requests filed by Ameren Missouri, Ameren Illinois, and ATXI. Pursuant to stay its October 2018 ruling. In Februarythe May 2020 order, in the second quarter of 2020, Ameren and Ameren Illinois recorded a $2 million reduction to revenue for the period of January 2019 the landowners filed an appeal with the United States Supreme Court. The October 2018 ruling is further stayed pending resolutionthrough May 2020. Regardless of the appeal. Constructionoutcome of the Illinois Rivers project is substantially complete. Delays associated withappeal, the condemnation proceedings or a rehearing arising fromimpacts of the Illinois Supreme Court’s ruling will delay the expected completion date toMay 2020 which isand October 2020 orders are not expected to materially affect 2019 earnings. The estimated line segment capital expenditure investment is approximately $81 million,be material to Ameren’s, Ameren Missouri’s, or Ameren Illinois’ results of which $38 million was invested as of December 31, 2018. The other eight line segments of the Illinois Rivers project are not affected by these proceedings.
Federaloperations, financial position, or liquidity.
FERC Complaint Cases
In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base return on common equityROE for FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a finalan order in the November 2013 complaint case, which lowered the allowed base return on common equityROE to 10.32%, or a 10.82% total allowed return on common equityROE with the inclusion of a 50 basis point incentive adder for participation in an RTO, that was effective sincefrom late September 2016. In 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively related to2016 forward. The September 2016 order also required refunds for the period November 2013 complaint case. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in theto February 2015, complaint case, discussed below.
Sincewhich were paid in 2017. With the maximum FERC-allowed refund period for the November 2013 complaint case ended in February 2015, another customer complaint case was filed in February 2015. MISO transmission owners subsequently filed a motion to dismiss the February 2015, complaint, as discussed below. The February 2015 complaint case seeksseeking a further reduction in the allowed base return on common equityROE for FERC-regulated transmission rate base under the MISO tariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case. If approved by the FERC, it would lower the allowed base return on common equity for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total2016. In November 2019, the FERC issued an order addressing the November 2013 complaint case, which set the allowed return on equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. It would also require customerbase ROE at 9.88% and required refunds, with interest, for that 15-month period. A finalthe periods November 2013 to February 2015 and from late September 2016 forward. The order also dismissed the February 2015 complaint case. In December 2019, Ameren and the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed requests for rehearing with the FERC. Additionally, in December 2019, various parties filed requests for rehearing with the FERC, challenging the dismissal of the February 2015 complaint case. In May 2020, the FERC issued an order would also establishaddressing the requests for rehearing, which set the allowed return on common equity thatbase ROE at 10.02%, superseding the 9.88% previously ordered, and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. The May 2020 order also denied rehearing of the FERC’s dismissal of the February 2015 complaint case. In June 2020, various parties filed requests for rehearing with the FERC, challenging the new ROE methodology established by the May 2020 order. In July 2020, the FERC denied the rehearing requests without addressing the issues raised, and indicated it will apply prospectively fromaddress the effective daterequests for rehearing in a future order. Also in July 2020, Ameren Missouri, Ameren Illinois, and ATXI filed an appeal of suchthe May 2020 order replacing the current 10.82% total return on common equity.In the second quarter of 2017,to the United States Court of Appeals for the District of Columbia Circuit vacated and remandedchallenging the refunds for the period from September 2016 to May 2020. The court is under no deadline to address the FERC an order in an unrelated case in which the FERC established the allowed base return on common equity methodology subsequently used in the two MISO complaint cases described above.appeal. In October 2018,November 2020, the FERC issued an order addressing the remanded issuesreaffirming its May 2020 order in an unrelated case. That order proposed a new methodology for determining the base return on equity and required further briefs from the participants. In November 2018, the FERC issued an order relatedregards to the February 2015 complaint case10.02% allowed base ROE and the September 2016 final order, which required briefs fromrefund periods and denying the participants to be filed in February 2019 regarding a new methodology for determining the base return on common equity and whether and how to apply the new methodology to the two MISO complaint cases. Ameren is unable to predict the ultimate impact of the proposed methodology on these complaint cases at this time. As the FERC is under no deadline to issue a final order, the timing of the issuance of the final orderarguments raised in the February 2015 complaint case, or any potential impact to the amounts refunded asrehearing requests.
As a result of the May 2020 order, which increased the FERC-allowed ROE from 9.88% to 10.02% for the periods November 2013 to February 2015 and late September 2016 final order, is uncertain.
In September 2017, MISO transmission owners, includingforward, Ameren Missouri,and Ameren Illinois recognized income of $13 million and ATXI, filed a motion to dismiss$7 million, respectively, during the February 2015 complaint case with the FERC. The MISO transmission owners maintain that the February 2015 complaint was predicated on the now superseded 12.38% allowed base return on common equity and is therefore inapplicable given the current 10.32% allowed base return on common equity. The MISO transmission owners further maintain that the current 10.32% allowed base return on common equity has not been proven to be unjust and unreasonable based on information provided, including the base return on common equity methodology ranges set forth in the February 2015 complaint case and in the initial decision issued by an administrative law judge in June 2016. Additionally, the MISO transmission owners maintain that the February 2015 complaint should be dismissed because the approach utilized in the case to assert that a return on common equity was unjust and unreasonable was insufficient. That same approach was rejected by the United States Courtsecond quarter of Appeals for the District of Columbia Circuit in an unrelated case, as discussed above. The FERC is under no deadline to issue an order on this motion.
2020. As of December 31, 2018,2020, Ameren and Ameren Illinois had recorded current regulatory liabilities of $44$15 million and $26$7 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equitybase ROE set by the May 2020 order in the initial decision in the February 2015November 2013 complaint case. Ameren Missouri does not expect that a reductionThe increase in the FERC-allowed base return on common equity would beROE resulting from the May 2020 order is not material to itsAmeren Missouri’s results of operations, financial position, or liquidity.
FERC Federal Income Tax Proceeding and Formula Rate Change
In March 2018, the FERC granted a request filed in February 2018 by MISO transmission owners with forward-looking rate formulas, including Ameren Illinois and ATXI, to allow revisions to their 2018 electric transmission rates to reflect the effectIn May 2018, the FERC accepted Ameren Illinois, and ATXI’s tariff filings to change the formula rate calculation. The change allows for the recovery or refund of both excess deferred taxes resulting from tax law or rate changes and the effect of permanent income tax differences and were reflected in Ameren Illinois’ and ATXI’s electric transmission rates starting in January 2019.
Regulatory Assets and Liabilities
The following table presents our regulatory assets and regulatory liabilities at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | | 2019 |
| | Ameren
Missouri | | Ameren
Illinois | | Ameren | | | Ameren
Missouri | | Ameren
Illinois | | Ameren |
| Regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a) | | $ | 48 | | | $ | 0 | | | $ | 48 | | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Under-recovered Illinois electric power costs(b) | | 0 | | | 4 | | | 4 | | | | 0 | | | 4 | | | 4 | |
| | | | | | | | | | | | | |
MTM derivative losses(c) | | 21 | | | 200 | | | 221 | | | | 12 | | | 242 | | | 254 | |
| | | | | | | | | | | | | |
IEIMA revenue requirement reconciliation adjustment(d)(e) | | 0 | | | 0 | | | 0 | | | | 0 | | | 17 | | | 17 | |
FERC revenue requirement reconciliation adjustment(f) | | 0 | | | 28 | | | 50 | | | | 0 | | | 1 | | | 16 | |
Under-recovered VBA(g) | | 0 | | | 11 | | | 11 | | | | 0 | | | 0 | | | 0 | |
Pension and postretirement benefit costs(h) | | 0 | | | 0 | | | 0 | | | | 7 | | | 26 | | | 33 | |
Income taxes(i) | | 117 | | | 65 | | | 183 | | | | 114 | | | 61 | | | 177 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Bad debt rider(j) | | 0 | | | 11 | | | 11 | | | | 0 | | | 0 | | | 0 | |
Callaway costs(e)(k) | | 14 | | | 0 | | | 14 | | | | 18 | | | 0 | | | 18 | |
Callaway refueling and maintenance outage costs(l) | | 39 | | | 0 | | | 39 | | | | 0 | | | 0 | | | 0 | |
Unamortized loss on reacquired debt(m) | | 52 | | | 22 | | | 74 | | | | 55 | | | 31 | | | 86 | |
Environmental cost riders(n) | | 0 | | | 93 | | | 93 | | | | 0 | | | 127 | | | 127 | |
Storm costs(e)(o) | | 0 | | | 7 | | | 7 | | | | 0 | | | 7 | | | 7 | |
| | | | | | | | | | | | | |
Workers’ compensation claims(p) | | 4 | | | 5 | | | 9 | | | | 4 | | | 7 | | | 11 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Allowance for funds used during construction for pollution control equipment(e)(q) | | 15 | | | 0 | | | 15 | | | | 15 | | | 0 | | | 15 | |
Customer generation rebate program(e)(r) | | 0 | | | 17 | | | 17 | | | | 0 | | | 1 | | | 1 | |
Solar rebate program(s) | | 5 | | | 0 | | | 5 | | | | 5 | | | 0 | | | 5 | |
| | | | | | | | | | | | | |
PISA(e)(t) | | 78 | | | 0 | | | 78 | | | | 41 | | | 0 | | | 41 | |
RESRAM(u) | | 2 | | | 0 | | | 2 | | | | 9 | | | 0 | | | 9 | |
FEJA energy-efficiency rider(e)(v) | | 0 | | | 283 | | | 283 | | | | 0 | | | 211 | | | 211 | |
| Other | | 12 | | | 33 | | | 45 | | | | 13 | | | 16 | | | 29 | |
| Total regulatory assets | | $ | 407 | | | $ | 779 | | | $ | 1,209 | | | | $ | 293 | | | $ | 751 | | | $ | 1,061 | |
| Less: current regulatory assets | | (60) | | | (37) | | | (109) | | | | (8) | | | (57) | | | (69) | |
| Noncurrent regulatory assets | | $ | 347 | | | $ | 742 | | | $ | 1,100 | | | | $ | 285 | | | $ | 694 | | | $ | 992 | |
| Regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(a) | | $ | 10 | | | $ | 0 | | | $ | 10 | | | | $ | 39 | | | $ | 0 | | | $ | 39 | |
Over-recovered Illinois electric power costs(b) | | 0 | | | 15 | | | 15 | | | | 0 | | | 11 | | | 11 | |
Over-recovered PGA(b) | | 7 | | | 15 | | | 22 | | | | 8 | | | 14 | | | 22 | |
Over-recovered VBA(g) | | 0 | | | 0 | | | 0 | | | | 0 | | | 8 | | | 8 | |
MTM derivative gains(c) | | 11 | | | 10 | | | 21 | | | | 18 | | | 3 | | | 21 | |
| | | | | | | | | | | | | |
IEIMA revenue requirement reconciliation adjustment(d) | | 0 | | | 22 | | | 22 | | | | 0 | | | 18 | | | 18 | |
FERC revenue requirement reconciliation adjustment(f) | | 0 | | | 21 | | | 21 | | | | 0 | | | 37 | | | 38 | |
| | | | | | | | | | | | | |
Estimated refund for FERC complaint cases(w) | | 0 | | | 7 | | | 15 | | | | 0 | | | 23 | | | 40 | |
Income taxes(i) | | 1,317 | | | 790 | | | 2,192 | | | | 1,428 | | | 813 | | | 2,326 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Cost of removal(x) | | 1,027 | | | 873 | | | 1,923 | | | | 1,041 | | | 827 | | | 1,884 | |
AROs(y) | | 436 | | | 0 | | | 436 | | | | 303 | | | 0 | | | 303 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Pension and postretirement benefit costs(h) | | 198 | | | 177 | | | 375 | | | | 0 | | | 0 | | | 0 | |
Pension and postretirement benefit costs tracker(z) | | 55 | | | 0 | | | 55 | | | | 72 | | | 0 | | | 72 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Renewable energy credits and zero emission credits(aa) | | 0 | | | 200 | | | 200 | | | | 0 | | | 155 | | | 155 | |
| | | | | | | | | | | | | |
Excess income taxes collected in 2018(ab) | | 45 | | | 0 | | | 45 | | | | 60 | | | 0 | | | 60 | |
| Other | | 30 | | | 21 | | | 51 | | | | 30 | | | 24 | | | 54 | |
| Total regulatory liabilities | | $ | 3,136 | | | $ | 2,151 | | | $ | 5,403 | | | | $ | 2,999 | | | $ | 1,933 | | | $ | 5,051 | |
| Less: current regulatory liabilities | | (26) | | | (88) | | | (121) | | | | (62) | | | (84) | | | $ | (164) | |
| Noncurrent regulatory liabilities | | $ | 3,110 | | | $ | 2,063 | | | $ | 5,282 | | | | $ | 2,937 | | | $ | 1,849 | | | $ | 4,887 | |
(a)Under-recovered or over-recovered fuel costs to be recovered or refunded through the FAC. Specific accumulation periods aggregate the under-recovered or over-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from, or refund to, customers that occurs over the next eight months.
(b)Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(c)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.
(d)The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recovery or over-recovery will be recovered from, or refunded to, customers with interest within two years.
(e)These assets earn a return at the applicable WACC.
(f)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.
(g)Under-recovered or over-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 or refunded to customers from April through December of the following year.
(h)Under-recovered or 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.
(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 changes. The regulatory liabilities represent amounts that will be refunded to customers for deferred income taxes related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 34, 26, and 42 years.
(j)A rider for the difference between the level of bad debt write-offs, net of any subsequent recoveries, incurred by Ameren Illinois and the level of such costs included in electric distribution and natural gas delivery service rates. Pursuant to the June 2020 ICC order in the service disconnection moratorium proceeding discussed above, Ameren Illinois’ electric distribution bad debt rider provided for the recovery of bad debt expense in 2020. The under-recovery or over-recovery for each year is recovered from, or refunded to, customers over a twelve-month period beginning June the following year.
(k)Ameren Missouri’s Callaway Energy Center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the original remaining life of the energy center.
(l)In February 2020, the MoPSC issued an order approving a stipulation and agreement allowing Ameren Missouri to defer and amortize maintenance expenses related to scheduled refueling and maintenance outages at its Callaway Energy Center. Maintenance expenses are amortized over the period between refueling and maintenance outages, which has historically been approximately 18 months. Amortization began in January 2021 and will continue until the completion of the next refueling and maintenance outage.
(m)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.
(n)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.
(o)Storm costs from 2016, 2018, and 2017:2020 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred.
(p)The period of recovery will depend on the timing of actual expenditures.
(q)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 2033.
(r)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid.
(s)Costs associated with Ameren Missouri’s solar rebate program. The amortization period for these assets will be determined in a future electric service regulatory rate review.
(t)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 after September 1, 2018, and not included in base rates. Accumulated PISA deferrals are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.
(u)Costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Costs incurred over a twelve-month period beginning each August are amortized over a twelve-month period beginning February the following year.
(v)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 6 to 13 years.
(w)The 2020 balances represent the estimated refunds to transmission customers related to the May 2020 FERC order in the November 2013 FERC complaint case. The 2019 balances represent the estimated refunds to transmission customers related to the November 2019 FERC order in the November 2013 FERC complaint case. See further discussion of the FERC ROE complaint cases above.
(x)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment retired from service, net of salvage.
(y)The ARO regulatory liability includes the nuclear decommissioning trust fund balance (December 31, 2020 - $982 million), net of recoverable removal costs for AROs (December 31, 2020 - $546 million). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
(z)A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For costs incurred prior to 2019, the weighted-average remaining amortization period is four years. For costs incurred during 2019 and after, the amortization period will be determined in a future electric service regulatory rate review.
(aa)Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased.
(ab)The excess amount collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability is being amortized over a three-year period, which began in April 2020.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2018 | | 2017 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a) | | $ | 3 |
| | $ | — |
| | $ | 3 |
| | | $ | 47 |
| | $ | — |
| | $ | 47 |
|
Under-recovered PGA(b) | | — |
| | 7 |
| | 7 |
| | | 1 |
| | 13 |
| | 14 |
|
MTM derivative losses(c) | | 19 |
|
| 197 |
| | 216 |
| | | 12 |
| | 217 |
| | 229 |
|
IEIMA revenue requirement reconciliation adjustment(d)(e) | | — |
| | 70 |
| | 70 |
| | | — |
| | 78 |
| | 78 |
|
FERC revenue requirement reconciliation adjustment(f) | | — |
| | 16 |
| | 30 |
| | | — |
| | 25 |
| | 37 |
|
Under-recovered VBA rider(g) | | — |
| | — |
| | — |
| | | — |
| | 15 |
| | 15 |
|
Pension and postretirement benefit costs(h) | | 103 |
| | 149 |
| | 252 |
| | | 84 |
| | 215 |
| | 299 |
|
Income taxes(i) | | 119 |
| | 68 |
| | 185 |
| | | 139 |
| | 56 |
| | 197 |
|
Callaway costs(e)(j) | | 22 |
| | — |
| | 22 |
| | | 25 |
| | — |
| | 25 |
|
Unamortized loss on reacquired debt(k) | | 58 |
| | 40 |
| | 98 |
| | | 61 |
| | 49 |
| | 110 |
|
Environmental cost riders(l) | | — |
| | 148 |
| | 148 |
| | | — |
| | 173 |
| | 173 |
|
Storm costs(e)(m) | | — |
| | 13 |
| | 13 |
| | | — |
| | 10 |
| | 10 |
|
Demand-side costs before the MEEIA implementation(e)(n) | | 5 |
| | — |
| | 5 |
| | | 11 |
| | — |
| | 11 |
|
Workers’ compensation claims(o) | | 4 |
| | 7 |
| | 11 |
| | | 5 |
| | 7 |
| | 12 |
|
Construction accounting for pollution control equipment(e)(p) | | 16 |
| | — |
| | 16 |
| | | 18 |
| | — |
| | 18 |
|
Solar rebate program(e)(q) | | 14 |
| | — |
| | 14 |
| | | 31 |
| | — |
| | 31 |
|
FEJA energy-efficiency riders(e)(r) | | — |
| | 136 |
| | 136 |
| | | — |
| | 41 |
| | 41 |
|
| Other | | 17 |
| | 18 |
| | 35 |
| | | 17 |
| | 10 |
| | 27 |
|
| Total regulatory assets | | $ | 380 |
| | $ | 869 |
| | $ | 1,261 |
| | | $ | 451 |
| | $ | 909 |
| | $ | 1,374 |
|
| Less: current regulatory assets | | (14 | ) | | (110 | ) | | (134 | ) | | | (56 | ) | | (87 | ) | | (144 | ) |
| Noncurrent regulatory assets | | $ | 366 |
| | $ | 759 |
| | $ | 1,127 |
| | | $ | 395 |
| | $ | 822 |
| | $ | 1,230 |
|
| Regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(a) | | $ | 34 |
| | $ | — |
| | $ | 34 |
| | | $ | 4 |
| | $ | — |
| | $ | 4 |
|
Over-recovered Illinois electric power costs(b) | | — |
| | 12 |
| | 12 |
| | | — |
| | 16 |
| | 16 |
|
Over-recovered PGA(b) | | 7 |
| | 3 |
| | 10 |
| | | — |
| | 1 |
| | 1 |
|
Over-recovered VBA rider(g) | | — |
| | 8 |
| | 8 |
| | | — |
| | — |
| | — |
|
MTM derivative gains(c) | | 5 |
| | 3 |
| | 8 |
|
| | 16 |
| | — |
| | 16 |
|
FERC revenue requirement reconciliation adjustment(f) | | — |
| | 17 |
| | 19 |
| | | — |
| | — |
| | — |
|
Energy-efficiency riders(s) | | 19 |
| | 3 |
| | 22 |
| | | 2 |
| | 40 |
| | 42 |
|
Estimated refund for FERC complaint case(t) | | — |
| | 26 |
| | 44 |
| | | — |
| | 25 |
| | 42 |
|
Income taxes(i) | | 1,484 |
| | 843 |
| | 2,413 |
| | | 1,392 |
| | 842 |
| | 2,323 |
|
Asset removal costs(u) | | 1,027 |
| | 774 |
| | 1,811 |
| | | 995 |
| | 725 |
| | 1,725 |
|
AROs(v) | | 175 |
| | — |
| | 175 |
| | | 223 |
| | — |
| | 223 |
|
Pension and postretirement benefit costs tracker(w) | | 43 |
| | — |
| | 43 |
| | | 35 |
| | — |
| | 35 |
|
Renewable energy credits and zero emission credits(x) | | — |
| | 102 |
| | 102 |
| | | — |
| | 58 |
| | 58 |
|
Excess income taxes collected in 2018(y) | | 60 |
| | — |
| | 60 |
| | | — |
| | — |
| | — |
|
| Other | | 13 |
| | 12 |
| | 25 |
| | | 16 |
| | 14 |
| | 30 |
|
| Total regulatory liabilities | | $ | 2,867 |
| | $ | 1,803 |
| | $ | 4,786 |
| | | $ | 2,683 |
| | $ | 1,721 |
| | $ | 4,515 |
|
| Less: current regulatory liabilities | | (68 | ) | | (62 | ) | | (149 | ) | | | (19 | ) | | (92 | ) | | $ | (128 | ) |
| Noncurrent regulatory liabilities | | $ | 2,799 |
| | $ | 1,741 |
| | $ | 4,637 |
| | | $ | 2,664 |
| | $ | 1,629 |
| | $ | 4,387 |
|
| |
(a) | Under-recovered or over-recovered fuel costs to be recovered or refunded through the FAC. Specific accumulation periods aggregate the under-recovered or over-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from, or refund to, customers that occurs over the next eight months. |
| |
(b) | Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. |
| |
(c) | Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information. |
| |
(d) | The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recovery or over-recovery will be recovered from, or refunded to, customers with interest within two years. |
| |
(e) | These assets earn a return. |
| |
(f) | 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. |
| |
(g) | Under-recovered or over-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, or refunded to, customers from April through December of the following year. |
| |
(h) | These 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. |
| |
(i) | The regulatory assets represent deferred income taxes that will be recovered from customers related to the equity component of allowance for funds used during construction and the effects of tax rate changes from the TCJA and the increased income tax rate in Illinois. The regulatory liabilities represent deferred income taxes that will be refunded to customers related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. The amortization periods for depreciation differences are determined in rate orders by the applicable regulators and range from 7 to 60 years. See Note 12 – Income Taxes for amounts related to the revaluation of deferred income taxes under the TCJA. |
| |
(j) | Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the original remaining life of the energy center. |
| |
(k) | 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. |
| |
(l) | 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. |
| |
(m) | Storm costs from 2015, 2016, and 2018 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred. |
| |
(n) | Demand-side costs incurred prior to implementation of the MEEIA in 2013, including the costs of developing, implementing, and evaluating customer energy-efficiency and demand response programs. The MoPSC’s March 2017 electric rate order modified certain amortization periods for these costs. Costs incurred from May 2008 through September 2008, and from January 2010 through July 2012, are being amortized over a two-year period that began in April 2017. Costs incurred from October 2008 through December 2009 are no longer being amortized as of April 2017, and a new amortization period for these costs will be determined in a future regulatory rate review. Costs incurred from August 2012 through December 2012 are being amortized over a six-year period that began in June 2015. |
| |
(o) | The period of recovery will depend on the timing of actual expenditures. |
| |
(p) | 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 2033. |
| |
(q) | Costs associated with Ameren Missouri’s solar rebate program to fulfill its renewable energy requirements. Costs incurred from 2010 to 2014 are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. Costs incurred from 2015 to 2016 are being amortized over a three-year period that began in April 2017. |
| |
(r) | Electric energy-efficiency program investment deferrals which earn a return at Ameren Illinois’ weighted-average cost of capital with the equity return based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The 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 8 to 12 years. |
| |
(s) | The Ameren Missouri balance relates to the MEEIA. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs, lost electric margins, and the performance incentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, and lost electric margins are incurred or any performance incentive are earned. The Ameren Illinois balance relates to a regulatory tracking mechanism to recover its electric pre-FEJA costs and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. Any under-recovery or over-recovery will be collected from, or refunded to, customers over the year following the plan year. |
| |
(t) | Estimated refunds to transmission customers related to the February 2015 FERC complaint case discussed above. |
| |
(u) | Estimated funds collected for the eventual dismantling and removal of plant retired from service, net of salvage value. |
| |
(v) | Recoverable or refundable removal costs for AROs, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations. |
| |
(w) | A regulatory tracking 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. For costs incurred prior to August 2012, the amounts are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. For costs incurred between August 2012 and December 2014, the MoPSC’s May 2015 electric rate order directed the amortization period to occur over a five-year period that began in June 2015. For costs incurred between January 2015 and December 2016, the MoPSC’s March 2017 electric rate order directed the amortization period to occur over a five-year period that began in April 2017. For costs incurred after December 2016, the amortization period will be determined in a future electric regulatory rate review. |
| |
(x) | 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. |
| |
(y) | The excess amount collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review. |
NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET
The following table presents property, plant, and equipment, net, at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri(a) | | Ameren
Illinois | | Other | | Ameren(a) |
| 2020 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation: | | | | | | | | |
Coal(c) | | $ | 4,875 | | | $ | 0 | | | $ | 0 | | | $ | 4,875 | |
| Natural gas and oil | | 1,097 | | | 0 | | | 0 | | | 1,097 | |
| Nuclear | | 5,608 | | | 0 | | | 0 | | | 5,608 | |
Renewable(d) | | 1,301 | | | 0 | | | 0 | | | 1,301 | |
| Electric distribution | | 6,784 | | | 6,649 | | | 0 | | | 13,433 | |
| Electric transmission | | 1,482 | | | 3,575 | | | 1,774 | | | 6,831 | |
| Natural gas | | 561 | | | 3,308 | | | 0 | | | 3,869 | |
Other(e) | | 1,390 | | | 1,070 | | | 245 | | | 2,705 | |
| | 23,098 | | | 14,602 | | | 2,019 | | | 39,719 | |
| Less: Accumulated depreciation and amortization | | 9,689 | | | 3,780 | | | 304 | | | 13,773 | |
| | 13,409 | | | 10,822 | | | 1,715 | | | 25,946 | |
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 75 | | | 0 | | | 0 | | | 75 | |
| Other | | 395 | | | 379 | | | 12 | | | 786 | |
| Property, plant, and equipment, net | | $ | 13,879 | | | $ | 11,201 | | | $ | 1,727 | | | $ | 26,807 | |
| 2019 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation: | | | | | | | | |
Coal(c) | | $ | 4,730 | | | $ | 0 | | | $ | 0 | | | $ | 4,730 | |
| Natural gas and oil | | 1,090 | | | 0 | | | 0 | | | 1,090 | |
| Nuclear | | 5,414 | | | 0 | | | 0 | | | 5,414 | |
Renewable(d) | | 646 | | | 0 | | | 0 | | | 646 | |
| Electric distribution | | 6,371 | | | 6,299 | | | 0 | | | 12,670 | |
| Electric transmission | | 1,405 | | | 3,101 | | | 1,642 | | | 6,148 | |
| Natural gas | | 528 | | | 3,024 | | | 0 | | | 3,552 | |
Other(e) | | 1,173 | | | 993 | | | 236 | | | 2,402 | |
| | 21,357 | | | 13,417 | | | 1,878 | | | 36,652 | |
| Less: Accumulated depreciation and amortization | | 9,195 | | | 3,536 | | | 275 | | | 13,006 | |
| | 12,162 | | | 9,881 | | | 1,603 | | | 23,646 | |
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 135 | | | 0 | | | 0 | | | 135 | |
| Other | | 338 | | | 202 | | | 55 | | | 595 | |
| Property, plant, and equipment, net | | $ | 12,635 | | | $ | 10,083 | | | $ | 1,658 | | | $ | 24,376 | |
(a)Amounts include 2 CTs that have related financing obligations. The gross cumulative asset value of those agreements was $240 million and $236 million at December 31, 2020 and 2019, respectively. The total accumulated depreciation associated with the 2 CTs was $99 million and $95 million at December 31, 2020 and 2019, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.
(b)The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydro generating assets, which have useful lives of the Ameren Companies at December 31, 2018up 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 2017:5 to 55 years for other.
(c)Includes $36 million of oil-fired generation in both 2019 and 2020. |
| | | | | | | | | | | | | | | | |
| | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) |
| 2018 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 11,432 |
| | $ | — |
| | $ | — |
| | $ | 11,432 |
|
| Electric distribution | | 5,989 |
| | 5,970 |
| | — |
| | 11,959 |
|
| Electric transmission | | 1,277 |
| | 2,647 |
| | 1,385 |
| | 5,309 |
|
| Natural gas | | 500 |
| | 2,701 |
| | — |
| | 3,201 |
|
Other(c) | | 1,008 |
| | 863 |
| | 230 |
| | 2,101 |
|
| | | 20,206 |
| | 12,181 |
| | 1,615 |
| | 34,002 |
|
| Less: Accumulated depreciation and amortization | | 8,726 |
| | 3,294 |
| | 253 |
| | 12,273 |
|
| | | 11,480 |
| | 8,887 |
| | 1,362 |
| | 21,729 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 217 |
| | — |
| | — |
| | 217 |
|
| Other | | 406 |
| | 311 |
| | 147 |
| | 864 |
|
| Property, plant, and equipment, net | | $ | 12,103 |
| | $ | 9,198 |
| | $ | 1,509 |
| | $ | 22,810 |
|
| 2017 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 11,132 |
| | $ | — |
| | $ | — |
| | $ | 11,132 |
|
| Electric distribution | | 5,766 |
| | 5,649 |
| | — |
| | 11,415 |
|
| Electric transmission | | 1,201 |
| | 2,298 |
| | 1,167 |
| | 4,666 |
|
| Natural gas | | 474 |
| | 2,419 |
| | — |
| | 2,893 |
|
Other(c) | | 922 |
| | 757 |
| | 242 |
| | 1,921 |
|
| | | 19,495 |
| | 11,123 |
| | 1,409 |
| | 32,027 |
|
| Less: Accumulated depreciation and amortization | | 8,305 |
| | 3,082 |
| | 246 |
| | 11,633 |
|
| | | 11,190 |
| | 8,041 |
| | 1,163 |
| | 20,394 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 148 |
| | — |
| | — |
| | 148 |
|
| Other | | 413 |
| | 252 |
| | 259 |
| | 924 |
|
| Property, plant, and equipment, net | | $ | 11,751 |
| | $ | 8,293 |
| | $ | 1,422 |
| | $ | 21,466 |
|
| |
(a) | Amounts in Ameren and Ameren Missouri include two CTs under separate agreements. The gross cumulative asset value of those agreements was $235 million and $233 million at December 31, 2018 and 2017, respectively. The total accumulated depreciation associated with the two CTs was $89 million and $83 million at December 31, 2018 and 2017, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements. |
| |
(b) | The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydro 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 5 to 55 years for other. |
| |
(c) | Other property, plant, and equipment includes assets used to support electric and natural gas services. |
(e)Other property, plant, and equipment includes assets used to support electric and natural gas services.
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 53 to 10 years. The following table presents the amortization, expensegross carrying value, and related accumulated amortization of capitalized software the gross carrying value of capitalized software, and the related accumulated amortization by year:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Amortization Expense | | Gross Carrying Value | | Accumulated Amortization |
| | 2020 | 2019 | 2018 | | 2020 | 2019 | | 2020 | 2019 |
| | | | | | | | | | |
| Ameren | | $ | 93 | | $ | 78 | | $ | 71 | | | $ | 1,021 | | $ | 901 | | | $ | (640) | | $ | (584) | |
| Ameren Missouri | | 44 | | 30 | | 24 | | | 398 | | 303 | | | (189) | | (153) | |
| Ameren Illinois | | 45 | | 45 | | 44 | | | 397 | | 377 | | | (238) | | (221) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Amortization Expense(a) | | Gross Carrying Value | | Accumulated Amortization |
| | | 2018 | 2017 | 2016 | | 2018 | 2017 | | 2018 | 2017 |
| Ameren | | $ | 71 |
| $ | 58 |
| $ | 52 |
| | $ | 734 |
| $ | 655 |
| | $ | (514 | ) | $ | (466 | ) |
| Ameren Missouri | | 24 |
| 20 |
| 17 |
| | 223 |
| 191 |
| | (125 | ) | (107 | ) |
| Ameren Illinois | | 44 |
| 36 |
| 33 |
| | 297 |
| 241 |
| | (183 | ) | (146 | ) |
| |
(a) | AsAnnual amortization expense for capitalized costs for software placed in service as of December 31, 2018, the estimated amortization expense of capitalized software for each of the five succeeding years is not expected to differ materially from the current year expense. |
The following table provides accrued capital and nuclear fuel expenditures at December 31, 2018, 2017, and 2016, which represent noncash investing activity excluded from the accompanying statements of cash flows:2020, is estimated to be as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2022 | | 2023 | | 2024 | | 2025 |
| Ameren | | $ | 105 | | | $ | 94 | | | $ | 81 | | | $ | 55 | | | $ | 23 | |
| Ameren Missouri | | 55 | | | 49 | | | 45 | | | 33 | | | 15 | |
| Ameren Illinois | | 46 | | | 42 | | | 34 | | | 21 | | | 7 | |
|
| | | | | | | | | | | |
| | Ameren | | Ameren Missouri | | Ameren Illinois |
| Accrued capital expenditures: | | | | | |
| 2018 | $ | 272 |
| | $ | 121 |
| | $ | 138 |
|
| 2017 | 361 |
| | 159 |
| | 175 |
|
| 2016 | 251 |
| | 116 |
| | 87 |
|
| Accrued nuclear fuel expenditures: | | | | | |
| 2018 | $ | 20 |
| | $ | 20 |
| | $ | — |
|
| 2017 | 10 |
| | 10 |
| | — |
|
| 2016 | 20 |
| | 20 |
| | — |
|
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.
Credit AgreementsShort-Term Borrowings
In December 2018, the Credit Agreements, which were scheduled to mature in December 2021, were extended and now mature in December 2022. The Credit Agreements provide $2.1$2.3 billion of credit cumulatively through maturity.maturity in December 2024. The total facility size of the Missouri Credit Agreement and Illinois Credit Agreement is $1.2 billion and $1.1 billion, respectively. The maturity date may be extended for antwo additional one-year periodperiods upon mutual consent of the borrowers and lenders. Credit available under the agreements is provided by a group of 22 international, national, and regional lenders, with no single lender providing more than $118$130 million of credit in aggregate.
The obligations of each borrower under the respective Credit Agreements to which it is a party are several and not joint. Except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective Credit Agreements are not guaranteed by Ameren (parent) or any other subsidiary of Ameren. The following table presents the maximum aggregate amount available to each borrower under each facility: | | | | | Missouri Credit Agreement | Illinois Credit Agreement | | Missouri
Credit Agreement | Illinois
Credit Agreement |
| Ameren (parent) | | $ | 700 |
| $ | 500 |
| Ameren (parent) | | $ | 900 | | $ | 500 | |
| Ameren Missouri | | 800 |
| (a) |
| Ameren Missouri | | 850 | | (a) |
| Ameren Illinois | | (a) |
| 800 |
| Ameren Illinois | | (a) | 800 | |
(a)Not applicable.
The borrowers have the option to seek additional commitments from existing or new lenders to increase the total facility size of the Credit Agreements to a maximum of $1.2$1.4 billion for the Missouri Credit Agreement and $1.3 billion for the Illinois Credit Agreement. Ameren (parent) borrowings are due and payable no later than the maturity date of the Credit Agreements. Ameren Missouri and Ameren Illinois borrowings under the applicable Credit Agreement are due and payable no later than the earlier of the maturity date or 364 days after the originating date of the borrowing.
The obligations of the borrowers under the Credit Agreements are unsecured. Loans are available on a revolving basis under each of the Credit Agreements. Funds borrowed may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate plus the margin applicable to the particular borrower and/or the eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower’s long-term unsecured credit ratings or, if no such ratings are in effect, the borrower’s corporate/issuer ratings then in effect. The borrowers have received commitments from the lenders to issue letters of credit up to $100 million under each of the Credit Agreements. In addition, the issuance of letters of credit is subject to the $2.1$2.3 billion overall combined facility borrowing limitations of the Credit Agreements.
The borrowers will use the proceeds from any borrowings under the Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, issuance of letters of credit, 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.sublimits, as well as to support issuance of letters of credit for the borrowers. As of December 31, 2018,2020, based on commercial paper outstanding and letters of credit issued under the Credit Agreements, along with cash and cash equivalents, the net liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $1.5$1.9 billion.
Ameren, Ameren Missouri, and Ameren Illinois did not borrow under the Credit Agreements for the years ended December 31, 2018 and 2017.
Commercial Paper
The following table summarizes the borrowing activity and relevant interest rates under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programsissuances and borrowings under the Credit Agreements in the aggregate for the years ended December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren (parent) | | Ameren Missouri | | Ameren Illinois | | Ameren Consolidated | |
| 2020 | | | | | | | | | |
| Average daily amount outstanding | | $ | 108 | | | $ | 109 | | | $ | 46 | | | $ | 263 | | |
| Commercial paper issuances outstanding at period-end | | 490 | | | 0 | | | 0 | | | 490 | | |
| Weighted-average interest rate | | 1.04 | % | | 1.73 | % | | 0.97 | % | | 1.31 | % | |
Peak amount outstanding during period(a) | | $ | 490 | | | $ | 573 | | | $ | 250 | | | $ | 908 | | |
| Peak interest rate | | 3.30 | % | (b) | 5.05 | % | (b) | 3.40 | % | | 5.05 | % | (b) |
| 2019 | | | | | | | | | |
| Average daily amount outstanding | | $ | 421 | | | $ | 122 | | | $ | 157 | | | $ | 700 | | |
| Commercial paper issuances outstanding at period-end | | 153 | | | 234 | | | 53 | | | 440 | | |
| Weighted-average interest rate | | 2.66 | % | | 2.62 | % | | 2.43 | % | | 2.60 | % | |
Peak amount outstanding during period(a) | | $ | 651 | | | $ | 549 | | | $ | 356 | | | $ | 1,113 | | |
| Peak interest rate | | 3.80 | % | (c) | 2.97 | % | | 5.00 | % | (c) | 5.00 | % | (c) |
|
| | | | | | | | | | | | | | |
| | | Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated |
| 2018 | | | | | | |
| Average daily commercial paper outstanding | | $ | 410 |
| | $ | 61 |
| $ | 108 |
| $ | 579 |
|
| Outstanding borrowings at period-end | | 470 |
| | 55 |
| 72 |
| 597 |
|
| Weighted-average interest rate | | 2.31 | % | | 1.94 | % | 2.26 | % | 2.26 | % |
Peak outstanding commercial paper during period(a) | | $ | 543 |
| | $ | 481 |
| $ | 442 |
| $ | 1,295 |
|
| Peak interest rate | | 3.10 | % | | 2.80 | % | 2.85 | % | 3.10 | % |
| 2017 | | | | | | |
| Average daily commercial paper outstanding | | $ | 573 |
| | $ | 5 |
| $ | 90 |
| $ | 668 |
|
| Outstanding borrowings at period-end | | 383 |
| | 39 |
| 62 |
| 484 |
|
| Weighted-average interest rate | | 1.30 | % | | 1.24 | % | 1.35 | % | 1.31 | % |
Peak outstanding commercial paper during period(a) | | $ | 841 |
| | $ | 64 |
| $ | 469 |
| $ | 948 |
|
| Peak interest rate | | 1.90 | % | | 1.78 | % | 2.00 | % | 2.00 | % |
| |
(a) | The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of the peak amounts presented by the companies may not equal the Ameren consolidated peak amount for the period. |
(b) Ameren’s and Ameren Missouri’s peak interest rate was affected by temporary disruptions in the commercial paper market in the first quarter of 2020.
(c) Ameren’s and Ameren Illinois’ peak interest rate was affected by temporary disruptions in the commercial paper market in the third quarter of 2019.
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, 2018,2020, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 53%56%, 47%48%, and 48%45%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
The Credit Agreements contain default provisions that apply separately to each borrower. However, a default of Ameren Missouri or Ameren Illinois under the applicable credit agreement is also deemed to constitute a default of Ameren (parent) under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $100 million in the aggregate (including under the other credit agreement). However, under the default provisions of the Credit Agreements, any default of Ameren (parent) under either credit agreement that results solely from a default of Ameren Missouri or Ameren Illinois does not result in a cross-default of Ameren (parent) under the other credit agreement. Further, the Credit Agreements default provisions provide that an Ameren (parent) default under either of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.
None of the Credit Agreements or financing agreements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. The Ameren Companies were in compliance with the provisions and covenants of the Credit Agreements at December 31, 20182020.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.
Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the money pool from
participants. The primary sources of external funds for the utility money pool are the Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but it is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2018,2020, was 2.10% (20170.64% (2019 – 1.19%2.48%).
See Note 13 – Related-party Transactions for the amount of interest income and expense from the utility money pool agreement recorded by the Ameren CompaniesMissouri and Ameren Illinois for the years ended December 31, 2018, 2017,2020, 2019, and 2016.2018.
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding, including maturities due within one year, foras of December 31, 2020 and 2019:
| | | | | | | | | | | |
| 2020 | | 2019 |
| Ameren (Parent): | | | |
| 2.70% Senior unsecured notes due 2020 | $ | 0 | | | $ | 350 | |
| 2.50% Senior unsecured notes due 2024 | 450 | | | 450 | |
| 3.65% Senior unsecured notes due 2026 | 350 | | | 350 | |
| 3.50% Senior unsecured notes due 2031 | 800 | | | 0 | |
| Total long-term debt, gross | 1,600 | | | 1,150 | |
| Less: Unamortized discount and premium | (2) | | | 0 | |
| Less: Unamortized debt issuance costs | (10) | | | (6) | |
| Less: Maturities due within one year | 0 | | | (350) | |
| Long-term debt, net | $ | 1,588 | | | $ | 794 | |
| Ameren Missouri: | | | |
| Bonds and notes: | | | |
5.00% Senior secured notes due 2020(a) | 0 | | | 85 | |
1.60% 1992 Series bonds due 2022(b) | 47 | | | 47 | |
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(d) | 450 | | | 450 | |
2.95% First mortgage bonds due 2030(d) | 465 | | | 0 | |
2.90% 1998 Series A bonds due 2033(b) | 60 | | | 60 | |
2.90% 1998 Series B bonds due 2033(b) | 50 | | | 50 | |
2.75% 1998 Series C bonds due 2033(b) | 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)(c) | 350 | | | 350 | |
3.90% Senior secured notes due 2042(a)(c) | 485 | | | 485 | |
3.65% Senior secured notes due 2045(a) | 400 | | | 400 | |
4.00% First mortgage bonds due 2048(d) | 425 | | | 425 | |
3.25% First mortgage bonds due 2049(d) | 330 | | | 330 | |
2.625% First mortgage bonds due 2051 (green bonds)(d) | 550 | | | 0 | |
| Finance obligations: | | | |
City of Bowling Green agreement (Peno Creek CT) due 2022(e) | 16 | | | 23 | |
Audrain County agreement (Audrain County CT) due 2023(e) | 240 | | | 240 | |
| Total long-term debt, gross | 5,152 | | | 4,229 | |
| Less: Unamortized discount and premium | (12) | | | (9) | |
| Less: Unamortized debt issuance costs | (36) | | | (30) | |
| Less: Maturities due within one year | (8) | | | (92) | |
| Long-term debt, net | $ | 5,096 | | | $ | 4,098 | |
| | | | | | | | | | | |
| 2020 | | 2019 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
2.70% Senior secured notes due 2022(f)(g) | $ | 400 | | | $ | 400 | |
3.25% Senior secured notes due 2025(f) | 300 | | | 300 | |
6.125% Senior secured notes due 2028(f) | 60 | | | 60 | |
3.80% First mortgage bonds due 2028(h) | 430 | | | 430 | |
1.55% First mortgage bonds due 2030(h) | 375 | | | 0 | |
6.70% Senior secured notes due 2036(f) | 61 | | | 61 | |
6.70% Senior secured notes due 2036(f) | 42 | | | 42 | |
4.80% Senior secured notes due 2043(f) | 280 | | | 280 | |
4.30% Senior secured notes due 2044(f) | 250 | | | 250 | |
4.15% Senior secured notes due 2046(f) | 490 | | | 490 | |
3.70% First mortgage bonds due 2047(h) | 500 | | | 500 | |
4.50% First mortgage bonds due 2049(h) | 500 | | | 500 | |
3.25% First mortgage bonds due 2050(h) | 300 | | | 300 | |
| Total long-term debt, gross | 3,988 | | | 3,613 | |
| Less: Unamortized discount and premium | (6) | | | (4) | |
| Less: Unamortized debt issuance costs | (36) | | | (34) | |
| | | |
| Long-term debt, net | $ | 3,946 | | | $ | 3,575 | |
| ATXI: | | | |
3.43% Senior unsecured notes due 2050(i) | $ | 450 | | | $ | 450 | |
| Total long-term debt, gross | 450 | | | 450 | |
| | | |
| Less: Unamortized debt issuance costs | (2) | | | (2) | |
| | | |
| Long-term debt, net | $ | 448 | | | $ | 448 | |
| Ameren consolidated long-term debt, net | $ | 11,078 | | | $ | 8,915 | |
(a)These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren CompaniesMissouri 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 December 31, 2018all first mortgage bonds, including first mortgage bonds currently outstanding and 2017:
|
| | | | | | | |
| | 2018 | | 2017 |
| Ameren (Parent): | | | |
| 2.70% Senior unsecured notes due 2020 | $ | 350 |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | 350 |
| | 350 |
|
| Total long-term debt, gross | 700 |
| | 700 |
|
| Less: Unamortized debt issuance costs | (3 | ) | | (4 | ) |
| Long-term debt, net | $ | 697 |
| | $ | 696 |
|
| Ameren Missouri: | | | |
| Bonds and notes: | | | |
6.00% Senior secured notes due 2018(a) | — |
| | 179 |
|
5.10% Senior secured notes due 2018(a) | — |
| | 199 |
|
6.70% Senior secured notes due 2019(a)(b) | 329 |
| | 329 |
|
5.10% Senior secured notes due 2019(a) | 244 |
| | 244 |
|
5.00% Senior secured notes due 2020(a) | 85 |
| | 85 |
|
1992 Series bonds due 2022(c)(d) | 47 |
| | 47 |
|
3.50% Senior secured notes due 2024(a) | 350 |
| | 350 |
|
2.95% Senior secured notes due 2027(a) | 400 |
| | 400 |
|
5.45% First mortgage bonds due 2028(e) | (e) |
| | (e) |
|
1998 Series A bonds due 2033(c)(d) | 60 |
| | 60 |
|
1998 Series B bonds due 2033(c)(d) | 50 |
| | 50 |
|
1998 Series C bonds due 2033(c)(d) | 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)(b) | 350 |
| | 350 |
|
3.90% Senior secured notes due 2042(a)(b) | 485 |
| | 485 |
|
3.65% Senior secured notes due 2045(a) | 400 |
| | 400 |
|
4.00% First mortgage bonds due 2048(f) | 425 |
| | — |
|
| Finance obligations: | | | |
City of Bowling Green agreement (Peno Creek CT) due 2022(g) | 30 |
| | 36 |
|
Audrain County agreement (Audrain County CT) due 2023(g) | 240 |
| | 240 |
|
| Total long-term debt, gross | 4,029 |
| | 3,988 |
|
| Less: Unamortized discount and premium | (9 | ) | | (7 | ) |
| Less: Unamortized debt issuance costs | (22 | ) | | (20 | ) |
| Less: Maturities due within one year | (580 | ) | | (384 | ) |
| Long-term debt, net | $ | 3,418 |
| | $ | 3,577 |
|
|
| | | | | | | |
| | 2018 | | 2017 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
6.25% Senior secured notes due 2018(h) | — |
| | 144 |
|
9.75% Senior secured notes due 2018(h) | — |
| | 313 |
|
2.70% Senior secured notes due 2022(h)(i) | 400 |
| | 400 |
|
5.90% First mortgage bonds due 2023(j) | (j) |
| | (j) |
|
5.70% First mortgage bonds due 2024(k) | (k) |
| | (k) |
|
3.25% Senior secured notes due 2025(h) | 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(h) | 60 |
| | 60 |
|
1993 Series B-1 Senior unsecured notes due 2028(d) | 17 |
| | 17 |
|
3.80% First mortgage bonds due 2028(l) | 430 |
| | — |
|
6.70% Senior secured notes due 2036(h) | 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(m) | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(h) | 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(h) | 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(h) | 490 |
| | 490 |
|
3.70% First mortgage bonds due 2047(l) | 500 |
| | 500 |
|
4.50% First mortgage bonds due 2049(l) | 500 |
| | — |
|
| Total long-term debt, gross | 3,330 |
| | 2,857 |
|
| Less: Unamortized discount and premium | (3 | ) | | (3 | ) |
| Less: Unamortized debt issuance costs | (31 | ) | | (24 | ) |
| Less: Maturities due within one year | — |
| | (457 | ) |
| Long-term debt, net | $ | 3,296 |
| | $ | 2,373 |
|
| ATXI: | | | |
3.43% Senior notes due 2050(n) | $ | 450 |
| | $ | 450 |
|
| Total long-term debt, gross | 450 |
| | 450 |
|
| Less: Unamortized debt issuance costs | (2 | ) | | (2 | ) |
| Long-term debt, net | $ | 448 |
| | $ | 448 |
|
| Ameren consolidated long-term debt, net | $ | 7,859 |
| | $ | 7,094 |
|
| |
(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 2048 maturity of the 4.00% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (b)any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2051 maturity of the 2.625% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (d) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away. |
| |
(b) | 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 6.70% senior secured notes due 2019 and 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. |
| |
(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. The bonds are also backed by an insurance guarantee policy. |
| |
(d) | The interest rates and the periods during which such rates apply vary depending on our selection of defined rate modes. Maximum interest rates could reach 18%, depending on the series of bonds. The average interest rates for 2018 and 2017 were as follows:
|
|
| | | |
| | 2018 | | 2017 |
| Ameren Missouri 1992 Series due 2022 | 2.37% | | 1.43% |
| Ameren Missouri 1998 Series A due 2033 | 2.76% | | 1.77% |
| Ameren Missouri 1998 Series B due 2033 | 2.79% | | 1.75% |
| Ameren Missouri 1998 Series C due 2033 | 2.83% | | 1.73% |
| Ameren Illinois 1993 Series B-1 due 2028 | 1.58% | | 1.08% |
| |
(e) | These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture. They are secured by substantially all Ameren Missouri property and franchises. Less than $1 million principal amount of the bonds remain outstanding. |
| |
(f) | 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. |
| |
(g) | Payments due related to these financing obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the city/county and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the financing obligations and the related investments in debt securities, recorded in "Other Assets," was $270 million and $276 million, respectively, as of December 31, 2018 and 2017. |
| |
(h) | These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under its 1992 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 2049 maturity date of the 4.50% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these |
notes to fall away.
| |
(i) | Ameren Illinois has agreed that so long as any of the 2.70% senior secured notes due 2022 are outstanding, Ameren Illinois will not permit a release date to occur. |
| |
(j) | These bonds are first mortgage bonds issued by Ameren Illinois under its 1933 mortgage indenture. They are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value. Less than $1 million principal amount of the bonds remain outstanding. |
| |
(k) | These bonds are first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS. The bonds are also backed by an insurance guarantee policy. Less than $1 million principal amount of the bonds remains outstanding. |
| |
(l) | These bonds are first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS. |
| |
(m) | These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its 1933 mortgage indenture. They are secured by substantially all property of the former CILCO. The notes have a fall-away lien provision, and Ameren Illinois could cause these notes to become unsecured at any time by redeeming the 5.90% first mortgage bonds due 2023 (of which less than $1 million principal amount remains outstanding). |
| |
(n) | The following table presents the principal maturities schedule for the 3.43% senior notes due 2050: |
(b)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.
(c)Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions.
(d)These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri bond indenture. They are secured by substantially all Ameren Missouri property and franchises.
(e)Payments due related to these financing obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the city/county and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the financing obligations and the related investments in debt securities, recorded in “Other Assets,” was $256 million and $263 million, respectively, as of December 31, 2020 and 2019.
(f)These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under its mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2050 maturity date of the 3.25% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.
(g)Ameren Illinois has agreed that so long as any of the 2.70% senior secured notes due 2022 are outstanding, Ameren Illinois will not permit a release date to occur.
(h)These bonds are first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises.
(i)The following table presents the principal maturities schedule for the 3.43% senior notes due 2050:
| | | | | | | | |
| Payment Date | | Principal Payment |
| August 2022 | $ | 49.5 |
| August 2024 | | 49.5 |
| August 2027 | | 49.5 |
| August 2030 | | 49.5 |
| August 2032 | | 49.5 |
| August 2038 | | 49.5 |
| August 2043 | | 76.5 |
| August 2050 | | 76.5 |
| Total | $ | 450.0 |
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated(a) |
| 2021 | $ | 0 | | | $ | 8 | | | $ | 0 | | | $ | 0 | | | $ | 8 | |
| 2022 | 0 | | | 55 | | | 400 | | | 50 | | | 505 | |
| 2023 | 0 | | | 240 | | | 0 | | | 0 | | | 240 | |
| 2024 | 450 | | | 350 | | | 0 | | | 50 | | | 850 | |
| 2025 | 0 | | | 0 | | | 300 | | | 0 | | | 300 | |
| Thereafter | 1,150 | | | 4,499 | | | 3,288 | | | 350 | | | 9,287 | |
| Total | $ | 1,600 | | | $ | 5,152 | | | $ | 3,988 | | | $ | 450 | | | $ | 11,190 | |
(a)Excludes unamortized discount, unamortized premium, and debt issuance costs of $12 million, $48 million, $42 million, and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI, respectively.
|
| | | | | | | | | | | | | | | | | | | |
| | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated |
| 2019 | $ | — |
| | $ | 580 |
| | $ | — |
| | $ | — |
| | $ | 580 |
|
| 2020 | 350 |
| | 92 |
| | — |
| | — |
| | 442 |
|
| 2021 | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| 2022 | — |
| | 55 |
| | 400 |
| | 50 |
| | 505 |
|
| 2023 | — |
| | 240 |
| | — |
| | — |
| | 240 |
|
| Thereafter | 350 |
| | 3,054 |
| | 2,930 |
| | 400 |
| | 6,734 |
|
| Total | $ | 700 |
| | $ | 4,029 |
| | $ | 3,330 |
| | $ | 450 |
| | $ | 8,509 |
|
| |
(a) | Excludes unamortized discount, unamortized premium, and debt issuance costs of $3 million, $31 million, $34 million and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois and ATXI, respectively.
|
All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends, have voting rights, and are not subject to mandatory redemption. The preferred stock of Ameren’s subsidiaries is included in “Noncontrolling Interests” on Ameren’s consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois, which is redeemable at the option of the issuer, at the prices shown below as of December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| Shares Outstanding | | Redemption Price (per share) | | 2020 | | 2019 |
| Ameren Missouri: | | | | | | | |
| Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | |
| $3.50 Series | 130,000 shares | | $ | 110.00 | | | $ | 13 | | | $ | 13 | |
| $3.70 Series | 40,000 shares | | 104.75 | | | 4 | | | 4 | |
| $4.00 Series | 150,000 shares | | 105.625 | | | 15 | | | 15 | |
| $4.30 Series | 40,000 shares | | 105.00 | | | 4 | | | 4 | |
| $4.50 Series | 213,595 shares | | 110.00 | | (a) | 21 | | | 21 | |
| $4.56 Series | 200,000 shares | | 102.47 | | | 20 | | | 20 | |
| $4.75 Series | 20,000 shares | | 102.176 | | | 2 | | | 2 | |
| $5.50 Series A | 14,000 shares | | 110.00 | | | 1 | | | 1 | |
| Total | | | | $ | 80 | | | $ | 80 | |
| Ameren Illinois: | | | | | | | |
| With par value of $100 per share, 2 million shares authorized | | | | | | |
| 4.00% Series | 144,275 shares | | $ | 101.00 | | | $ | 14 | | | $ | 14 | |
| 4.08% Series | 45,224 shares | | 103.00 | | | 5 | | | 5 | |
| 4.20% Series | 23,655 shares | | 104.00 | | | 2 | | | 2 | |
| 4.25% Series | 50,000 shares | | 102.00 | | | 5 | | | 5 | |
| 4.26% Series | 16,621 shares | | 103.00 | | | 2 | | | 2 | |
| 4.42% Series | 16,190 shares | | 103.00 | | | 2 | | | 2 | |
| 4.70% Series | 18,429 shares | | 104.30 | | | 2 | | | 2 | |
| 4.90% Series | 73,825 shares | | 102.00 | | | 7 | | | 7 | |
| 4.92% Series | 49,289 shares | | 103.50 | | | 5 | | | 5 | |
| 5.16% Series | 50,000 shares | | 102.00 | | | 5 | | | 5 | |
| 6.625% Series | 124,274 shares | | 100.00 | | | 12 | | | 12 | |
| 7.75% Series | 4,542 shares | | 100.00 | | | 1 | | | 1 | |
| Total | | | | $ | 62 | | | $ | 62 | |
| Total Ameren | | | | $ | 142 | | | $ | 142 | |
|
| | | | | | | | | | | | | |
| | | | Redemption Price (per share) | | 2018 | | 2017 |
| 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 | | 103.00 |
| | 2 |
| | 2 |
|
| 4.90% Series | 73,825 shares | | 102.00 |
| | 7 |
| | 7 |
|
| 4.92% Series | 49,289 shares | | 103.50 |
| | 5 |
| | 5 |
|
| 5.16% Series | 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
|
| 6.625% Series | 124,274 shares | | 100.00 |
| | 12 |
| | 12 |
|
| 7.75% Series | 4,542 shares | | 100.00 |
| | 1 |
| | 1 |
|
| Total | | | | $ | 62 |
| | $ | 62 |
|
| Total Ameren | | | | $ | 142 |
| | $ | 142 |
|
| |
(a) | In the event of voluntary liquidation, $105.50.
|
Ameren has 100 million shares of $0.01$0.01 par value preferred stock authorized, with no0 such shares outstanding. Ameren Missouri has 7.5 million shares of $1$1 par value preference stock authorized, with no0 such shares outstanding. Ameren Illinois has 2.6 million shares of no0 par value preferred stock authorized, with no0 such shares outstanding.
Ameren
In 2018,Under the DRPlus and its 401(k) plan, Ameren issued a total of0.7 million, 0.9 million, and 1.2 million shares of common stock under its DRPlusin 2020, 2019, and 401(k) plan,2018, respectively, and received proceeds of $51 million, $68 million, and $74 million.million for the respective years. In addition, in 2018, Ameren issued 0.5 million, 0.8 million, and 0.7 million shares of common stock valued at $38 million, $54 million, and $35 million uponin 2020, 2019, 2018, respectively, for no cash consideration in connection with stock-based compensation.
In May 2020, Ameren filed a Form S-3 registration statement with the vestingSEC, authorizing the offering of stock-based compensation. Ameren did not issue any4 million additional shares of its common stock under the DRPlus, which expires in 2017May 2023. Shares of common stock sold under the DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or 2016.shares purchased in the open market or in privately negotiated transactions.
In October 2020, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuance of an unspecified amount of certain types of securities. This registration statement expires in October 2023.
In October 2018, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 4 million additional shares of its common stock under its 401(k) plan. Shares of common stock issuable under the 401(k) plan are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions.
In December 2017,August 2019, Ameren Ameren Missouri, and Ameren Illinois filedentered into a Form S-3 shelf registration statementforward sale agreement with the SEC, registering the issuance of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing and expires in December 2020.
Ameren filed a Form S-3 registration statement with the SEC in May 2017, authorizing the offering of 6counterparty relating to 7.5 million additional shares of its common stock understock. In
December 2020, pursuant to the DRPlus, which expires in 2020. Sharesagreement terms, Ameren partially settled the forward sale agreement by physically delivering 5.9 million shares of common stock sold underfor cash proceeds of $425 million. In February 2021, Ameren settled the DRPlus are, at Ameren’s option, newly issuedremainder of the forward sale agreement by physically delivering 1.6 million shares treasury shares, or shares purchased inof common stock for cash proceeds of $113 million. The proceeds were used to fund a portion of Ameren Missouri’s wind generation investments. See Note 2 – Rate and Regulatory Matters for additional information about the open market or in privately negotiated transactions. As of December 31, 2018 and 2017, the DRPlus participant funds of $1 million and $8 million, respectively, were reflected on Ameren’s consolidated balance sheets in “Other current assets.”
Ameren Missouriwind generation facilities.
In April 2018,2020, Ameren Missouri(parent) issued $425$800 million of 4.00% first mortgage bonds3.50% senior unsecured notes due April 2048,January 2031, with interest payable semiannually on April 1January 15 and October 1July 15 of each year, beginning July 15, 2020. Ameren received net proceeds of $793 million, which were used for general corporate purposes, including to repay outstanding short-term debt, and were used to fund the repayment of Ameren’s $350 million of 2.70% senior unsecured notes, which were redeemed at par plus accrued interest in October 1, 2018.2020.
In September 2019, Ameren issued $450 million of 2.50% senior unsecured notes due September 2024, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2020. Ameren received net proceeds of $447 million, which were used to repay outstanding short-term debt.
Ameren Missouri
In March 2020, Ameren Missouri issued $465 million of 2.95% first mortgage bonds due March 2030, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2020. Ameren Missouri received net proceeds of $419$462 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $179$85 million of its 6.00%5.00% senior secured notes that matured April 1, 2018.in February 2020.
In August 2018, $199 million principal amount of Ameren Missouri’s 5.10% senior secured notes matured and were repaid with cash on hand.
In June 2017,October 2020, Ameren Missouri issued $400$550 million of 2.95% senior secured notes2.625% first mortgage bonds due June 2027,March 2051, with interest payable semiannually on JuneMarch 15 and DecemberSeptember 15 of each year, beginning DecemberMarch 15, 2017.2021. The bonds were issued as green bonds; therefore, the proceeds will be used for eligible green projects. Ameren Missouri received net proceeds of $396$543 million, which were used in conjunctionto partially finance the acquisition of 2 wind generation facilities. See Note 2 – Rate and Regulatory Matters for information about the wind generation facilities.
In March 2019, Ameren Missouri issued $450 million of 3.50% first mortgage bonds due March 2029, with other available funds,interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2019. Ameren Missouri received net proceeds of $447 million, which were used to repay at maturity $425outstanding short-term debt, including short-term debt that Ameren Missouri incurred in connection with the repayment of $329 million of Ameren Missouri’s 6.40%its 6.70% senior secured notes that matured February 1, 2019.
In June and July 2019, all of the 1992 Series bonds, 1998 Series A bonds, 1998 Series B bonds, and 1998 Series C bonds issued by the Missouri Environmental Authority on behalf of Ameren Missouri were subject to purchase in June 2017.lieu of redemption or a mandatory tender as a result of a change in the method of determining the interest rates on the bonds. The interest rate method of each of the series of bonds, as well as Ameren Missouri’s first mortgage bonds that collaterally secure each of the series of bonds, was changed from a variable rate to a fixed rate. Upon the change in the method of determining the interest rate, the bonds, totaling $207 million, were remarketed to new investors. The following table provides additional information on the bonds:
| | | | | | | | | | | | | | |
| 1992 Series | 1998 Series A | 1998 Series B | 1998 Series C |
| Transaction month | June 2019 | July 2019 | July 2019 | June 2019 |
| Principal amount | $47 | $60 | $50 | $50 |
| Fixed interest rate | 1.60% | 2.90% | 2.90% | 2.75% |
Variable interest rate(a) | 2.58% | 3.43% | 3.57% | 3.43% |
| Maturity | December 2022 | September 2033 | September 2033 | September 2033 |
| Interest payment dates | June 1 and December 1 | March 1 and September 1 | March 1 and September 1 | March 1 and September 1 |
| Initial interest payment date | December 2019 | September 2019 | September 2019 | September 2019 |
(a)Represents the variable interest rate of the bonds effective prior to the change in method of determining the interest rate.
In October 2019, Ameren Missouri issued $330 million of 3.25% first mortgage bonds due October 2049, with interest payable semiannually on April 1 and October 1 of each year, beginning April 1, 2020. Ameren Missouri received net proceeds of $326 million, which were used to repay $244 million of its 5.10% senior unsecured notes due October 1, 2019, with the remaining proceeds used to repay a portion of its short-term debt.
In October 2019, Ameren Missouri redeemed the remaining amount outstanding of its 5.45% first mortgage bonds due 2028 for less than $1 million.
For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
Ameren Illinois
In May 2018,November 2020, Ameren Illinois issued $430$375 million of 3.80%1.55% first mortgage bonds due May 2028,November 2030, with interest payable semiannually on May 15 and November 15 of each year, beginning NovemberMay 15, 2018.2021. Ameren Illinois received net proceeds of $427$371 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $144 million of its 6.25% senior secured notes that matured April 1, 2018.debt.
In November 2018,2019, Ameren Illinois issued $500$300 million of 4.50%3.25% first mortgage bonds due March 2049,2050, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2019.2020. Ameren Illinois received net proceeds of $495$296 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $313 million of its 9.75% senior secured notes that matured November 15, 2018.
In November 2017, Ameren Illinois issued $500 million of 3.70% first mortgage bonds due December 2047, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2018. Ameren Illinois received proceeds of $492 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $250 million of its 6.125% senior secured notes that matured in November 2017.debt.
For information on Ameren Illinois’ capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
ATXI
In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes, due 2050, with interest payable semiannually on the last day of February and August of each year, beginning February 28, 2018, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes, which were used by ATXI to repay existing short-term and long-term affiliate 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, 2018,2020, at an assumed interest rate of 5% and dividend rate of 6%.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Required Interest Coverage Ratio(a) | Actual Interest
Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend
Coverage Ratio | Preferred Stock
Issuable | |
| Ameren Missouri | >2.0 | 3.4 | $5,025 | | >2.5 | 128.5 | $2,872 | |
| Ameren Illinois | >2.0 | 7.1 | 7,229 | | >1.5 | 3.3 | 203 | (d) |
|
| | | | | | | | | | | | | | |
| | 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 | 5.5 |
| $ | 4,688 |
| | >2.5 | 140.8 |
| $ | 3,153 |
| |
| Ameren Illinois | >2.0 | 6.9 |
| 4,234 |
| (d) | >1.5 | 3.2 |
| 203 |
| (e) |
| |
(a) | Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. |
(b)Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $2,442 million and $643 million at Ameren Missouri and Ameren Illinois, respectively.
| |
(b) | Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $2,006 million and $985 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. |
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(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. |
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(d) | Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under its 1992 mortgage indenture. |
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(e) | Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation. |
Ameren’s indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million, or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including borrowings under the Credit Agreements or the Ameren commercial paper program, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.
Ameren Missouri and Ameren Illinois and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on their respective stock unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois has made a commitment to the FERC to maintain a minimum 30% ratio of common stock equity to total capitalization. As of December 31, 2018,2020, using the FERC-agreed upon calculation method, Ameren Illinois’ ratio of common stock equity to total capitalization was 51%54%.
ATXI’s note purchase agreement 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, 2018,2020, 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 agreement. 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, 2018,2020, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business,forward sale agreement relating to common stock, which was fully settled by mid-February 2021, and variable interest entities, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries.entities. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.
NOTE 6 – OTHER INCOME, NET
The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| Ameren: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 32 | | | $ | 28 | | | $ | 36 | |
| Interest income on industrial development revenue bonds | 25 | | | 25 | | | 26 | |
| Other interest income | 4 | | | 8 | | | 7 | |
Non-service cost components of net periodic benefit income (a) | 116 | | | 90 | | | 70 | |
| Miscellaneous income | 13 | | | 6 | | | 8 | |
| Donations | (25) | | (b) | (12) | | | (33) | |
| Miscellaneous expense | (14) | | | (15) | | | (12) | |
| Total Other Income, Net | $ | 151 | | | $ | 130 | | | $ | 102 | |
| Ameren Missouri: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 19 | | | $ | 19 | | | $ | 27 | |
| Interest income on industrial development revenue bonds | 25 | | | 25 | | | 26 | |
| Other interest income | 1 | | | 1 | | | 2 | |
Non-service cost components of net periodic benefit income (a) | 46 | | | 18 | | | 17 | |
| Miscellaneous income | 4 | | | 5 | | | 4 | |
| Donations | (12) | | (b) | (3) | | | (14) | |
| Miscellaneous expense | (7) | | | (7) | | | (6) | |
| Total Other Income, Net | $ | 76 | | | $ | 58 | | | $ | 56 | |
| Ameren Illinois: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 13 | | | $ | 9 | | | $ | 9 | |
| Interest income | 3 | | | 6 | | | 6 | |
Non-service cost components of net periodic benefit income (a) | 48 | | | 47 | | | 34 | |
| Miscellaneous income | 6 | | | 3 | | | 3 | |
| Donations | (5) | | | (5) | | | (6) | |
| Miscellaneous expense | (6) | | | (7) | | | (4) | |
| Total Other Income, Net | $ | 59 | | | $ | 53 | | | $ | 42 | |
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| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Ameren: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 36 |
| | $ | 24 |
| | $ | 27 |
|
| Interest income on industrial development revenue bonds | 26 |
| | 26 |
| | 27 |
|
| Other interest income | 7 |
| | 8 |
| | 13 |
|
| Non-service cost components of net periodic benefit income | 70 |
| (a) | 44 |
| | 56 |
|
| Other income | 8 |
| | 5 |
| | 10 |
|
| Donations | (33 | ) | | (8 | ) | | (16 | ) |
| Other expense | (12 | ) | | (13 | ) | | (16 | ) |
| Total Other Income, Net | $ | 102 |
| | $ | 86 |
| | $ | 101 |
|
| Ameren Missouri: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 27 |
| | $ | 21 |
| | $ | 23 |
|
| Interest income on industrial development revenue bonds | 26 |
| | 26 |
| | 27 |
|
| Other interest income | 2 |
| | 1 |
| | 1 |
|
| Non-service cost components of net periodic benefit income | 17 |
| (a) | 22 |
| | 18 |
|
| Other income | 4 |
| | 3 |
| | 3 |
|
| Donations | (14 | ) | | (2 | ) | | (4 | ) |
| Other expense | (6 | ) | | (6 | ) | | (6 | ) |
| Total Other Income, Net | $ | 56 |
| | $ | 65 |
| | $ | 62 |
|
| Ameren Illinois: | | | | | |
| Other Income, Net | | | | | |
| Allowance for equity funds used during construction | $ | 9 |
| | $ | 3 |
| | $ | 4 |
|
| Interest income | 6 |
| | 7 |
| | 12 |
|
| Non-service cost components of net periodic benefit income | 34 |
| | 10 |
| | 24 |
|
| Other income | 3 |
| | 2 |
| | 6 |
|
| Donations | (6 | ) | | (5 | ) | | (6 | ) |
| Other expense | (4 | ) | | (5 | ) | | (6 | ) |
| Total Other Income, Net | $ | 42 |
| | $ | 12 |
| | $ | 34 |
|
.(b)Includes $8 million pursuant to Ameren Missouri’s March 2020 electric rate order. See Note 2 – Rate and Regulatory Matters for additional information.
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(a) | For the year ended December 31, 2018, the non-service cost components of net periodic benefit income were partially offset by a $17 million deferral 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 power,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; and
•actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.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.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2018 and 2017. As of December 31, 2018, these contracts extended through October 2021, March 2023, and May 2032 for fuel oils, natural gas, and power, respectively.
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| | Quantity (in millions) |
| | 2018 | 2017 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
Fuel oils (in gallons)(a) | 66 |
| — |
| 66 |
| 28 |
| — |
| 28 |
|
| Natural gas (in mmbtu) | 19 |
| 154 |
| 173 |
| 24 |
| 139 |
| 163 |
|
| Power (in megawatthours) | 1 |
| 8 |
| 9 |
| 3 |
| 9 |
| 12 |
|
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(a) | Consists of ultra-low-sulfur diesel products. |
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, 20182020 and 2017,2019, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Cash flows for all derivative financial instruments are classified in cash flows from operating activities.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2020 and 2019. As of December 31, 2020, these contracts extended through October 2023, March 2026, May 2032, and March 2023 for fuel oils, natural gas, power, and uranium, respectively.
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| Quantity (in millions, except as indicated) |
| 2020 | 2019 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
| Fuel oils (in gallons) | 43 | | 0 | | 43 | | 58 | | 0 | | 58 | |
| Natural gas (in mmbtu) | 33 | | 114 | | 147 | | 20 | | 136 | | 156 | |
| Power (in MWhs) | 6 | | 7 | | 13 | | 5 | | 7 | | 12 | |
| Uranium (pounds in thousands) | 365 | | 0 | | 365 | | 565 | | 0 | | 565 | |
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The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of December 31, 20182020 and 2017:2019:
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| | 2018 | | | 2017 |
| Commodity | Balance Sheet Location | | Ameren Missouri | | | Ameren Illinois | | | Ameren | | | | Ameren Missouri | | | Ameren Illinois | | | Ameren |
| Fuel oils | Other current assets | $ | 3 |
| | $ | — |
| | $ | 3 |
| | | $ | 5 |
| | $ | — |
| | $ | 5 |
|
| | Other assets | | 5 |
| | | — |
| | | 5 |
| | | | 2 |
| | | — |
| | | 2 |
|
| Natural gas | Other current assets | | — |
| | | 1 |
| | | 1 |
| | | | — |
| | | — |
| | | — |
|
| | Other assets | | — |
| | | 2 |
| | | 2 |
| | | | 1 |
| | | — |
| | | 1 |
|
| Power | Other current assets | | 4 |
| | | — |
| | | 4 |
| | | | 9 |
| | | — |
| | | 9 |
|
| | Total assets | $ | 12 |
| | $ | 3 |
| | $ | 15 |
| | | $ | 17 |
| | $ | — |
| | $ | 17 |
|
| Fuel oils | Other current liabilities | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
| | Other deferred credits and liabilities | | 9 |
| | | — |
| | | 9 |
| | | | — |
| | | — |
| | | — |
|
| Natural gas | Other current liabilities | | 4 |
| | | 8 |
| | | 12 |
| | | | 5 |
| | | 12 |
| | | 17 |
|
| | Other deferred credits and liabilities | | 1 |
| | | 6 |
| | | 7 |
| | | | 3 |
| | | 10 |
| | | 13 |
|
| Power | Other current liabilities | | 4 |
| | | 14 |
| | | 18 |
| | | | 1 |
| | | 13 |
| | | 14 |
|
| | Other deferred credits and liabilities | | — |
| | | 169 |
| | | 169 |
| | | | — |
| | | 182 |
| | | 182 |
|
| | Total liabilities | $ | 22 |
| | $ | 197 |
| | $ | 219 |
| | | $ | 9 |
| | $ | 217 |
| | $ | 226 |
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Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges; these contracts have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master netting arrangements or similar agreements, and reporting daily exposure to senior management.
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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | | 2019 |
| Commodity | Balance Sheet Location | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren | | | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren |
| Fuel oils | Other current assets | $ | 2 | | | $ | 0 | | | $ | 2 | | | | $ | 4 | | | $ | 0 | | | $ | 4 | |
| Other assets | | 0 | | | | 0 | | | | 0 | | | | | 2 | | | | 0 | | | | 2 | |
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| Natural gas | Other current assets | | 1 | | | | 8 | | | | 9 | | | | | 0 | | | | 3 | | | | 3 | |
| Other assets | | 2 | | | | 2 | | | | 4 | | | | | 0 | | | | 1 | | | | 1 | |
| | | | | | | | | | | | | | | | | | | |
| Power | Other current assets | | 7 | | | | 0 | | | | 7 | | | | | 14 | | | | 0 | | | | 14 | |
| | Other assets | | 0 | | | | 0 | | | | 0 | | | | | 2 | | | | 0 | | | | 2 | |
| | | | | | | | | | | | | | | | | | | |
| | Total assets | $ | 12 | | | $ | 10 | | | $ | 22 | | | | $ | 22 | | | $ | 4 | | | $ | 26 | |
| | | | | | | | | | | | | | | | | | | |
| Fuel oils | Other current liabilities | $ | 7 | | | $ | 0 | | | $ | 7 | | | | $ | 4 | | | $ | 0 | | | $ | 4 | |
| Other deferred credits and liabilities | | 2 | | | | 0 | | | | 2 | | | | | 3 | | | | 0 | | | | 3 | |
| | | | | | | | | | | | | | | | | | | |
| Natural gas | Other current liabilities | | 1 | | | | 1 | | | | 2 | | | | | 1 | | | | 12 | | | | 13 | |
| Other deferred credits and liabilities | | 0 | | | | 1 | | | | 1 | | | | | 1 | | | | 6 | | | | 7 | |
| | | | | | | | | | | | | | | | | | | |
| Power | Other current liabilities | | 3 | | | | 17 | | | | 20 | | | | | 2 | | | | 17 | | | | 19 | |
| Other deferred credits and liabilities | | 8 | | | | 181 | | | | 189 | | | | | 1 | | | | 207 | | | | 208 | |
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| Uranium | Other deferred credits and liabilities | | 0 | | | | 0 | | | | 0 | | | | | 1 | | | | 0 | | | | 1 | |
| | Total liabilities | $ | 21 | | | $ | 200 | | | $ | 221 | | | | $ | 13 | | | $ | 242 | | | $ | 255 | |
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The Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement at the gross amounts on the balance sheet. However, if the gross amounts recognized on
the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at December 31, 20182020 and 2017.2019.
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. We calculate maximum exposures based on the gross fair value of financial instruments, including NPNS and other accrual contracts. These exposures are calculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. As of December 31, 2018,2020, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contractsCertain 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 following table presents, as of December 31, 2018, 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. 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 on December 31, 2018, and (2) those counterparties with rights to do so requested collateral. As of December 31, 2020, the aggregate fair value of derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require were each immaterial to Ameren, Ameren Missouri, and Ameren Illinois.
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| | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| Ameren Missouri | $ | 76 |
| | $ | 4 |
| | $ | 64 |
|
| Ameren Illinois | 37 |
| | — |
| | 30 |
|
| Ameren | $ | 113 |
| | $ | 4 |
| | $ | 94 |
|
| |
(a) | Before consideration of master netting arrangements or similar agreements and including NPNS and other accrual contract exposures. |
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(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. |
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, and assets, including 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. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. 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. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.
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 escalationtrend rates. Our development and corroboration process entails reasonableness reviews and an evaluation of all sources to identify any anomalies or potential errors.
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 counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. 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 2018, 2017,2020, 2019, or 2016.2018. At December 31, 20182020 and 2017,2019, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 | | | December 31, 2019 | |
| | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | 0 | | $ | 0 | | $ | 2 | | $ | 2 | | | | $ | 0 | | $ | 0 | | $ | 6 | | $ | 6 | | |
| Natural gas | 0 | | 3 | | 0 | | 3 | | | | 0 | | 0 | | 0 | | 0 | | |
| Power | 2 | | 0 | | 5 | | 7 | | | | 0 | | 2 | | 14 | | 16 | | |
| | | | | | | | | | | | |
| Total derivative assets – commodity contracts | $ | 2 | | $ | 3 | | $ | 7 | | $ | 12 | | | | $ | 0 | | $ | 2 | | $ | 20 | | $ | 22 | | |
| Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | | | | | | | | | | | |
| Equity securities: | | | | | | | | | | | |
| U.S. large capitalization | $ | 680 | | $ | 0 | | $ | 0 | | $ | 680 | | | | $ | 569 | | $ | 0 | | $ | 0 | | $ | 569 | | |
| Debt securities: | | | | | | | | | | | |
| U.S. Treasury and agency securities | 0 | | 115 | | 0 | | 115 | | | | 0 | | 107 | | 0 | | 107 | | |
| Corporate bonds | 0 | | 115 | | 0 | | 115 | | | | 0 | | 93 | | 0 | | 93 | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Other | 0 | | 67 | | 0 | | 67 | | | | 0 | | 73 | | 0 | | 73 | | |
| Total nuclear decommissioning trust fund | $ | 680 | | $ | 297 | | $ | 0 | | $ | 977 | | (a) | | $ | 569 | | $ | 273 | | $ | 0 | | $ | 842 | | (a) |
| Total Ameren Missouri | $ | 682 | | $ | 300 | | $ | 7 | | $ | 989 | | | | $ | 569 | | $ | 275 | | $ | 20 | | $ | 864 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | 0 | | $ | 6 | | $ | 4 | | $ | 10 | | | | $ | 0 | | $ | 1 | | $ | 3 | | $ | 4 | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Ameren | | | | | | | | | | | |
| Derivative assets – commodity contracts(b) | $ | 2 | | $ | 9 | | $ | 11 | | $ | 22 | | | | $ | 0 | | $ | 3 | | $ | 23 | | $ | 26 | | |
| Nuclear decommissioning trust fund(c) | 680 | | 297 | | 0 | | 977 | | (a) | | 569 | | 273 | | 0 | | 842 | | (a) |
| Total Ameren | $ | 682 | | $ | 306 | | $ | 11 | | $ | 999 | | | | $ | 569 | | $ | 276 | | $ | 23 | | $ | 868 | | |
| Liabilities: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | 6 | | $ | 0 | | $ | 3 | | $ | 9 | | | | $ | 1 | | $ | 0 | | $ | 6 | | $ | 7 | | |
| Natural gas | 0 | | 1 | | 0 | | 1 | | | | 0 | | 2 | | 0 | | 2 | | |
| Power | 8 | | 0 | | 3 | | 11 | | | | 0 | | 2 | | 1 | | 3 | | |
| Uranium | 0 | | 0 | | 0 | | 0 | | | | 0 | | 0 | | 1 | | 1 | | |
| Total Ameren Missouri | $ | 14 | | $ | 1 | | $ | 6 | | $ | 21 | | | | $ | 1 | | $ | 4 | | $ | 8 | | $ | 13 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | 0 | | $ | 1 | | $ | 1 | | $ | 2 | | | | $ | 3 | | $ | 12 | | $ | 3 | | $ | 18 | | |
| Power | 0 | | 0 | | 198 | | 198 | | | | 0 | | 0 | | 224 | | 224 | | |
| Total Ameren Illinois | $ | 0 | | $ | 1 | | $ | 199 | | $ | 200 | | | | $ | 3 | | $ | 12 | | $ | 227 | | $ | 242 | | |
| Ameren | | | | | | | | | | | |
| Derivative liabilities – commodity contracts(b) | $ | 14 | | $ | 2 | | $ | 205 | | $ | 221 | | | | $ | 4 | | $ | 16 | | $ | 235 | | $ | 255 | | |
(a)Balance excludes $5 million and $5 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2020 and 2019, respectively.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | | December 31, 2017 |
| | | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | | | | | | | | | | |
| Ameren | | | | | | | | | | | |
| | Derivative assets – commodity contracts(a): | | | | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| $ | 7 |
| $ | 8 |
| | | $ | 4 |
| $ | — |
| $ | 3 |
| $ | 7 |
| |
| | Natural gas | — |
| 2 |
| 1 |
| 3 |
| | | — |
| — |
| 1 |
| 1 |
| |
| | Power | — |
| 1 |
| 3 |
| 4 |
| | | — |
| 1 |
| 8 |
| 9 |
| |
| | Total derivative assets – commodity contracts | $ | 1 |
| $ | 3 |
| $ | 11 |
| $ | 15 |
| | | $ | 4 |
| $ | 1 |
| $ | 12 |
| $ | 17 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | Equity securities: | | | | | | | | | | | |
| | U.S. large capitalization | $ | 427 |
| $ | — |
| $ | — |
| $ | 427 |
| | | $ | 468 |
| $ | — |
| $ | — |
| $ | 468 |
| |
| | Debt securities: | | | | | | | | | | | |
| | U.S. Treasury and agency securities | — |
| 148 |
| — |
| 148 |
| | | — |
| 125 |
| — |
| 125 |
| |
| | Corporate bonds | — |
| 72 |
| — |
| 72 |
| | | — |
| 82 |
| — |
| 82 |
| |
| | Other | — |
| 32 |
| — |
| 32 |
| | | — |
| 25 |
| — |
| 25 |
| |
| | Total nuclear decommissioning trust fund | $ | 427 |
| $ | 252 |
| $ | — |
| $ | 679 |
| (b) | | $ | 468 |
| $ | 232 |
| $ | — |
| $ | 700 |
| (b) |
| | Total Ameren | $ | 428 |
| $ | 255 |
| $ | 11 |
| $ | 694 |
| | | $ | 472 |
| $ | 233 |
| $ | 12 |
| $ | 717 |
| |
| Ameren Missouri | | | | | | | | | | | |
| | Derivative assets – commodity contracts(a): | | | | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| $ | 7 |
| $ | 8 |
| | | $ | 4 |
| $ | — |
| $ | 3 |
| $ | 7 |
| |
| | Natural gas | — |
| — |
| — |
| — |
| | | — |
| — |
| 1 |
| 1 |
| |
| | Power | — |
| 1 |
| 3 |
| 4 |
| | | — |
| 1 |
| 8 |
| 9 |
| |
| | Total derivative assets – commodity contracts | $ | 1 |
| $ | 1 |
| $ | 10 |
| $ | 12 |
| | | $ | 4 |
| $ | 1 |
| $ | 12 |
| $ | 17 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | Equity securities: | | | | | | | | | | | |
| | U.S. large capitalization | $ | 427 |
| $ | — |
| $ | — |
| $ | 427 |
| | | $ | 468 |
| $ | — |
| $ | — |
| $ | 468 |
| |
| | Debt securities: | | | | | | | | | | | |
| | U.S. Treasury and agency securities | — |
| 148 |
| — |
| 148 |
| | | — |
| 125 |
| — |
| 125 |
| |
| | Corporate bonds | — |
| 72 |
| — |
| 72 |
| | | — |
| 82 |
| — |
| 82 |
| |
| | Other | — |
| 32 |
| — |
| 32 |
| | | — |
| 25 |
| — |
| 25 |
| |
| | Total nuclear decommissioning trust fund | $ | 427 |
| $ | 252 |
| $ | — |
| $ | 679 |
| (b) | | $ | 468 |
| $ | 232 |
| $ | — |
| $ | 700 |
| (b) |
| | Total Ameren Missouri | $ | 428 |
| $ | 253 |
| $ | 10 |
| $ | 691 |
| | | $ | 472 |
| $ | 233 |
| $ | 12 |
| $ | 717 |
| |
| Ameren Illinois | | | | | | | | | | | |
| | Derivative assets – commodity contracts(a): | | | | | | | | | | | |
| | Natural gas | $ | — |
| $ | 2 |
| $ | 1 |
| $ | 3 |
| | | $ | — |
| $ | — |
| $ | — |
| $ | — |
| |
| Liabilities: | | | | | | | | | | | |
| Ameren | | | | | | | | | | | |
| | Derivative liabilities – commodity contracts(a): | | | | | | | | | | | |
| | Fuel oils | $ | 2 |
| $ | — |
| $ | 11 |
| $ | 13 |
| | | $ | — |
| $ | — |
| $ | — |
| $ | — |
| |
| | Natural gas | — |
| 15 |
| 4 |
| 19 |
| | | 1 |
| 25 |
| 4 |
| 30 |
| |
| | Power | — |
| 1 |
| 186 |
| 187 |
| | | — |
| — |
| 196 |
| 196 |
| |
| | Total Ameren | $ | 2 |
| $ | 16 |
| $ | 201 |
| $ | 219 |
| | | $ | 1 |
| $ | 25 |
| $ | 200 |
| $ | 226 |
| |
| Ameren Missouri | | | | | | | | | | | |
| | Derivative liabilities – commodity contracts(a): | | | | | | | | | | | |
| | Fuel oils | $ | 2 |
| $ | — |
| $ | 11 |
| $ | 13 |
| | | $ | — |
| $ | — |
| $ | — |
| $ | — |
| |
| | Natural gas | — |
| 5 |
| — |
| 5 |
| | | — |
| 7 |
| 1 |
| 8 |
| |
| | Power | — |
| 1 |
| 3 |
| 4 |
| | | — |
| — |
| 1 |
| 1 |
| |
| | Total Ameren Missouri | $ | 2 |
| $ | 6 |
| $ | 14 |
| $ | 22 |
| | | $ | — |
| $ | 7 |
| $ | 2 |
| $ | 9 |
| |
| Ameren Illinois | | | | | | | | | | | |
| | Derivative liabilities – commodity contracts(a): | | | | | | | | | | | |
| | Natural gas | $ | — |
| $ | 10 |
| $ | 4 |
| $ | 14 |
| | | $ | 1 |
| $ | 18 |
| $ | 3 |
| $ | 22 |
| |
| | Power | — |
| — |
| 183 |
| 183 |
| | | — |
| — |
| 195 |
| 195 |
| |
| | Total Ameren Illinois | $ | — |
| $ | 10 |
| $ | 187 |
| $ | 197 |
| | | $ | 1 |
| $ | 18 |
| $ | 198 |
| $ | 217 |
| |
| |
(a) | The derivative asset and liability balances are presented net of registrant and counterparty credit considerations. |
| |
(b) | Balance excludes $5 million and $4 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2018 and 2017, respectively. |
(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, 20182020 and 2017.2019.
Level 3 fuel oils, and 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, 20182020 and 2017:2019:
|
| | | | | | | | | | | | | | | | | | | | |
| | 2018 | | | 2017 |
| | Ameren Missouri | Ameren Illinois | Ameren | | | Ameren Missouri | Ameren Illinois | Ameren |
| Beginning balance at January 1 | $ | 7 |
| $ | (195 | ) | $ | (188 | ) | | | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | (6 | ) | — |
| (6 | ) | | | (4 | ) | (21 | ) | (25 | ) |
| Purchases | 5 |
| — |
| 5 |
| | | 14 |
| — |
| 14 |
|
| Sales | — |
| — |
| — |
| | | 1 |
| — |
| 1 |
|
| Settlements | (5 | ) | 12 |
| 7 |
| | | (11 | ) | 11 |
| — |
|
| Transfers out of Level 3 | (1 | ) | — |
| (1 | ) | | | — |
| — |
| — |
|
| Ending balance at December 31 | $ | — |
| $ | (183 | ) | $ | (183 | ) | | | $ | 7 |
| $ | (195 | ) | $ | (188 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | (1 | ) | $ | (2 | ) | $ | (3 | ) | | | $ | — |
| $ | (22 | ) | $ | (22 | ) |
Transfers into or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level, but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3, but were recategorized to a higher level because the lowest significant input became observable during the period. For the years ended December 31, 2018 and 2017, there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or Level 2 and Level 3 related to derivative commodity contracts. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | | 2019 |
| Ameren
Missouri | Ameren
Illinois | Ameren | | | Ameren
Missouri | Ameren
Illinois | Ameren |
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| Beginning balance at January 1 | $ | 13 | | $ | (224) | | $ | (211) | | | | $ | 0 | | $ | (183) | | $ | (183) | |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | 15 | | 8 | | 23 | | | | 23 | | (56) | | (33) | |
| | | | | | | | |
| | | | | | | | |
| Settlements | (26) | | 18 | | (8) | | | | (7) | | 15 | | 8 | |
| | | | | | | | |
| Transfers out of Level 3 | 0 | | 0 | | 0 | | | | (3) | | 0 | | (3) | |
| Ending balance at December 31 | $ | 2 | | $ | (198) | | $ | (196) | | | | $ | 13 | | $ | (224) | | $ | (211) | |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | 1 | | $ | 9 | | $ | 10 | | | | $ | 12 | | $ | (54) | | $ | (42) | |
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All gains or losses related to our Level 3 derivative commodity contracts are expected to be recovered or returned through customer rates; therefore, there is no impact to either net income or other comprehensive income resulting from changes in the fair value of these instruments.
The following table describes the valuation techniques and significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value | | | | | Weighted Average(b) |
| Commodity | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input(a) | Range |
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| | | | | | | | |
| 2020 | Power(c) | $ | 5 | | $ | (201) | | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 23 – 37 | 29 |
| | | | | | | | |
| | | | | | Nodal basis ($/MWh) | (6) – 0 | (2) |
| | | | | | | | |
| | | | | | | | |
| | | | | | Trend rate (%) | 2 – 6 | 3 |
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| 2019 | Power(d) | $ | 14 | | $ | (225) | | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 22 – 34 | 25 |
| | | | | | Nodal basis ($/MWh) | (6) – 0 | (2) |
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| | | | | | Trend rate (%) | (1) – 0 | 0 |
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(a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.
(b)Unobservable inputs were weighted by relative fair value.
(c)Valuations through 2029 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2029 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
(d)Valuations through 2028 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2028 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
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| | | | | | | | | | | | |
| | | Fair Value(a) | | | | | Weighted |
| | Commodity | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| 2018 | Power(b) | $ | 3 |
| $ | (186 | ) |
| Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(c) | 23 – 39 | 28 |
| | | | |
| | Nodal basis($/MWh)(c) | (9) – 0 | (2) |
| | | | |
| Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(c) | 3 – 4 | 3 |
| | | | |
| | Escalation rate(%)(c)(d) | 4 – 5
| 4 |
| 2017 | Power(b) | $ | 8 |
| $ | (196 | ) |
| Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(c) | 24 – 46 | 28 |
| | | | |
| | Nodal basis($/MWh)(c) | (10) – 0 | (2) |
| | | | |
| Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(c) | 3 – 4 | 3 |
| | | | |
| | Escalation rate(%)(c)(d) | 5 | 5 |
| |
(b) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2022 and 2021 for December 31, 2018 and 2017, respectively. Valuations beyond 2022 and 2021 for December 31, 2018 and 2017, respectively, use fundamentally modeled pricing by month for peak and off-peak demand. |
| |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
| |
(d) | Escalation rate applies to power prices in 2031 and beyond. |
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, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Carrying
Amount | | Fair Value | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Ameren: | December 31, 2020 |
| Cash, cash equivalents, and restricted cash | $ | 301 | | | $ | 301 | | | $ | 0 | | | $ | 0 | | | $ | 301 | |
Investments in industrial development revenue bonds(a) | 256 | | | 0 | | | 256 | | | 0 | | | 256 | |
| Short-term debt | 490 | | | 0 | | | 490 | | | 0 | | | 490 | |
Long-term debt (including current portion)(a) | 11,086 | | (b) | 0 | | | 12,778 | | | 537 | | (c) | 13,315 | |
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 145 | | | $ | 145 | | | $ | 0 | | | $ | 0 | | | $ | 145 | |
| Advances to money pool | 139 | | | 0 | | | 139 | | | 0 | | | 139 | |
Investments in industrial development revenue bonds(a) | 256 | | | 0 | | | 256 | | | 0 | | | 256 | |
| | | | | | | | | |
| | | | | | | | | |
Long-term debt (including current portion)(a) | 5,104 | | (b) | 0 | | | 6,160 | | | 0 | | | 6,160 | |
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 147 | | | $ | 147 | | | $ | 0 | | | $ | 0 | | | $ | 147 | |
| | | | | | | | | |
| | | | | | | | | |
| Borrowings from money pool | 19 | | | 0 | | | 19 | | | 0 | | | 19 | |
| Long-term debt (including current portion) | 3,946 | | (b) | 0 | | | 4,822 | | | 0 | | | 4,822 | |
| December 31, 2019 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 176 | | | $ | 176 | | | $ | 0 | | | $ | 0 | | | $ | 176 | |
Investments in industrial development revenue bonds(a) | 263 | | | 0 | | | 263 | | | 0 | | | 263 | |
| Short-term debt | 440 | | | 0 | | | 440 | | | 0 | | | 440 | |
Long-term debt (including current portion)(a) | 9,357 | | (b) | 0 | | | 9,957 | | | 484 | | (c) | 10,441 | |
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 39 | | | $ | 39 | | | $ | 0 | | | $ | 0 | | | $ | 39 | |
| | | | | | | | | |
Investments in industrial development revenue bonds(a) | 263 | | | 0 | | | 263 | | | 0 | | | 263 | |
| Short-term debt | 234 | | | 0 | | | 234 | | | 0 | | | 234 | |
| | | | | | | | | |
Long-term debt (including current portion)(a) | 4,190 | | (b) | 0 | | | 4,772 | | | 0 | | | 4,772 | |
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 125 | | | $ | 125 | | | $ | 0 | | | $ | 0 | | | $ | 125 | |
| | | | | | | | | |
| Short-term debt | 53 | | | 0 | | | 53 | | | 0 | | | 53 | |
| | | | | | | | | |
| Long-term debt (including current portion) | 3,575 | | (b) | 0 | | | 4,019 | | | 0 | | | 4,019 | |
(a)Ameren and Ameren Missouri have investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the finance obligations for the Peno Creek and Audrain CT energy centers. As of December 31, 2020 and 2019, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value.
(b)Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $84 million, $36 million, and $36 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2020. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $72 million, $30 million, and $34 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2019.
(c)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| | Carrying Amount | | Fair Value | | |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 107 |
| | $ | 107 |
| | $ | — |
| | $ | — |
| | $ | 107 |
|
Investments in held-to-maturity debt securities(a) | 270 |
| | — |
| | 270 |
| | — |
| | 270 |
|
| Short-term debt | 597 |
| | — |
| | 597 |
| | — |
| | 597 |
|
Long-term debt (including current portion)(a) | 8,439 |
| (b) | — |
| | 8,240 |
| | 429 |
| (c) | 8,669 |
|
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
Investments in held-to-maturity debt securities(a) | 270 |
| | — |
| | 270 |
| | — |
| | 270 |
|
| Short-term debt | 55 |
| | — |
| | 55 |
| | — |
| | 55 |
|
Long-term debt (including current portion)(a) | 3,998 |
| (b) | — |
| | 4,156 |
| | — |
| | 4,156 |
|
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 80 |
| | $ | 80 |
| | $ | — |
| | $ | — |
| | $ | 80 |
|
| Short-term debt | 72 |
| | — |
| | 72 |
| | — |
| | 72 |
|
| Long-term debt (including current portion) | 3,296 |
| (b) | — |
| | 3,391 |
| | — |
| | 3,391 |
|
| | December 31, 2017 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 68 |
| | $ | 68 |
| | $ | — |
| | $ | — |
| | $ | 68 |
|
Investments in held-to-maturity debt securities(a) | 276 |
| | — |
| | 276 |
| | — |
| | 276 |
|
| Short-term debt | 484 |
| | — |
| | 484 |
| | — |
| | 484 |
|
Long-term debt (including current portion)(a) | 7,935 |
| (b) | — |
| | 8,531 |
| | — |
| | 8,531 |
|
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 7 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
Investments in held-to-maturity debt securities(a) | 276 |
| | — |
| | 276 |
| | — |
| | 276 |
|
| Short-term debt | 39 |
| | — |
| | 39 |
| | — |
| | 39 |
|
Long-term debt (including current portion)(a) | 3,961 |
| (b) | — |
| | 4,348 |
| | — |
| | 4,348 |
|
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 41 |
| | $ | 41 |
| | $ | — |
| | $ | — |
| | $ | 41 |
|
| Short-term debt | 62 |
| | — |
| | 62 |
| | — |
| | 62 |
|
| Long-term debt (including current portion) | 2,830 |
| (b) | — |
| | 3,028 |
| | — |
| | 3,028 |
|
| |
(a) | Ameren and Ameren Missouri have investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the finance obligations for the Peno Creek and Audrain CT energy centers. As of December 31, 2018 and 2017, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value. |
| |
(b) | Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $58 million, $22 million, and $31 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2018. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $50 million, $20 million, and $24 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2017. |
| |
(c) | The Level 3 fair value amount consists of ATXI’s senior unsecured notes. In the first quarter of 2018, the amount was transferred to Level 3 because inputs to the valuation model became unobservable during the period. |
NOTE 9 – CALLAWAY ENERGY CENTER
Maintenance Outage
During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was conducted. Work has begun to replace certain key components of the generator in order to return the energy center to service. Ameren Missouri expects generator repairs of $65 million, which are expected to be largely capital expenditures. Due to the long lead time for the manufacture, repair, and installation of the components, the energy center is expected to return to service in late June or early July 2021. Ameren Missouri will evaluate all of its options for losses, including the applicability of insurance coverages. See below for additional information about Ameren Missouri’s insurance coverage for the Callaway Energy Center.
Spent Nuclear Fuel
Under the NWPA,Nuclear Waste Policy Act of 1982, as amended, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy centerEnergy Center and other commercial nuclear energy centers. As required by the NWPA,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 has 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 of $11 million, $3 million,in the years ended December 31, 2020, 2019, and $24 million in 2018, 2017, and 2016, respectively.2018. 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 centerEnergy Center is not expected to adversely affect the continued operations of the energy center.
Decommissioning
Electric rates charged to customers provide for the recovery of the Callaway energy center’sEnergy 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’sEnergy Center’s decommissioning. It is assumed that the Callaway energy centerEnergy 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 centerEnergy Center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. 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.Energy Center. An updated cost study and funding analysis was filed with the MoPSC in September 2017November 2020 and reflected within the ARO. In January 2018, the MoPSC approvedAmeren Missouri’s filing supported no change in electric service rates for decommissioning costs consistentcosts. 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, 2020 and 2019. Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with Ameren Missouri’s updated cost study and funding analysis.the balance invested in debt securities.
The fair value of the trust fund for Ameren Missouri’s Callaway energy centerEnergy 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.liability recorded at December 31, 2020. 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.
Ameren Missouri has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway energy center. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 2018 and 2017. 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 following table presents proceeds from the sale and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| Proceeds from sales and maturities | $ | 183 | | | $ | 260 | | | $ | 299 | |
| Gross realized gains | 10 | | | 10 | | | 18 | |
| Gross realized losses | 3 | | | 2 | | | 5 | |
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Proceeds from sales and maturities | $ | 299 |
| | $ | 305 |
| | $ | 304 |
|
| Gross realized gains | 18 |
| | 13 |
| | 7 |
|
| Gross realized losses | 5 |
| | 5 |
| | 4 |
|
Net realized and unrealized gains and losses are deferred and are currently reflected in the regulatory liability related to AROs on Ameren’s and Ameren Missouri’s balance sheets. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by Ameren Missouri’s customers. See Note 2 – Rate and Regulatory Matters.
The following table presents the costscost and fair valuesvalue of investments in debt and equity securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund at December 31, 20182020 and 2017:December 31, 2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2020 | | | | | | | |
| Debt securities | $ | 272 | | | $ | 25 | | | $ | 0 | | | $ | 297 | |
| Equity securities | 198 | | | 491 | | | 9 | | | 680 | |
| Cash and cash equivalents | 4 | | | 0 | | | 0 | | | 4 | |
Other(a) | 1 | | | 0 | | | 0 | | | 1 | |
| Total | $ | 475 | | | $ | 516 | | | $ | 9 | | | $ | 982 | |
| 2019 | | | | | | | |
| Debt securities | $ | 262 | | | $ | 11 | | | $ | 0 | | | $ | 273 | |
| Equity securities | 183 | | | 393 | | | 7 | | | 569 | |
| Cash and cash equivalents | 26 | | | 0 | | | 0 | | | 26 | |
Other(a) | (21) | | | 0 | | | 0 | | | (21) | |
| Total | $ | 450 | | | $ | 404 | | | $ | 7 | | | $ | 847 | |
(a)Represents net receivables and payables relating to pending securities sales, interest, and securities purchases.
|
| | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2018 | | | | | | | |
| Debt securities | $ | 253 |
| | $ | 3 |
| $ | 4 |
| | $ | 252 |
|
| Equity securities | 162 |
| | 277 |
| | 12 |
| | 427 |
|
| Cash and cash equivalents | 3 |
| | — |
| | — |
| | 3 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 420 |
| | $ | 280 |
| $ | 16 |
| | $ | 684 |
|
| 2017 | | | | | | | |
| Debt securities | $ | 228 |
| | $ | 5 |
| $ | 1 |
| | $ | 232 |
|
| Equity securities | 155 |
| | 318 |
| | 5 |
| | 468 |
|
| Cash and cash equivalents | 2 |
| | — |
| | — |
| | 2 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 387 |
| | $ | 323 |
| $ | 6 |
| | $ | 704 |
|
| |
(a) | Represents net receivables and payables relating to pending security sales, interest, and security purchases. |
The following table presents the costs and fair values of investments in debt securities in Ameren’s and Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2018:2020:
| | | | | | | | | | | |
| Cost | | Fair Value |
| Less than 5 years | $ | 120 | | | $ | 123 | |
| 5 years to 10 years | 69 | | | 75 | |
| Due after 10 years | 83 | | | 99 | |
| Total | $ | 272 | | | $ | 297 | |
|
| | | | | | | |
| | Cost | | Fair Value |
| Less than 5 years | $ | 140 |
| | $ | 140 |
|
| 5 years to 10 years | 48 |
| | 47 |
|
| Due after 10 years | 65 |
| | 65 |
|
| Total | $ | 253 |
| | $ | 252 |
|
There are unrealized losses relating to certain available-for-sale investments included in the nuclear decommissioning trust fund, deferred within the regulatory liability as discussed above. Decommissioning will not occur until Ameren Missouri’s nuclear energy center is retired. The Callaway energy center’s operating license expires in 2044.
Insurance
The following table presents insurance coverage at Ameren Missouri’s Callaway energy centerEnergy Center at December 31, 2018.2020:
| | | | | | | | | | | | | | | | | |
| 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, 2021 | $ | 450 | | | $ | 0 | | |
| Pool participation | (a) | 13,348 | | (a) | 138 | | (b) |
| | $ | 13,798 | | (c) | $ | 138 | | |
| Property damage: | | | | | |
| NEIL and EMANI | April 1, 2020 | $ | 3,200 | | (d) | $ | 25 | | (e) |
| Replacement power: | | | | | |
| NEIL | April 1, 2020 | $ | 490 | | (f) | $ | 7 | | (e) |
(a)Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.
(b)Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $21 million per year.
(c)Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors.
(d)NEIL provides $2.7 billion in property coveragedamage, 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 nuclear liability coverage renewal datesaccumulated funds from NEIL.
(f)Provides replacement power cost insurance 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 April 1 and January 1, respectively, of each year. Both coverages were renewed in 2018.limited to $328 million.
|
| | | | | | | | |
| Type and Source of Coverage | Maximum Coverages | | Maximum Assessments for Single Incidents | |
| Public liability and nuclear worker liability: | | | | |
| American Nuclear Insurers | $ | 450 |
| | $ | — |
| |
| Pool participation | 13,623 |
| (a) | 138 |
| (b) |
| | $ | 14,073 |
| (c) | $ | 138 |
| |
| Property damage: | | | | |
| NEIL and EMANI | $ | 3,200 |
| (d) | $ | 27 |
| (e) |
| Replacement power: | | | | |
| NEIL | $ | 490 |
| (f) | $ | 7 |
| (e) |
| |
(a) | Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program. |
| |
(b) | Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $21 million per year. |
| |
(c) | Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed 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) | Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million. |
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in November 2018. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share the limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination.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 centerEnergy Center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.
NOTE 10 – RETIREMENT BENEFITS
The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren has defined benefit pension and postretirement benefit plans covering
substantially all of its union employees. Ameren has defined benefit pension plans covering substantially all of its non-union employees and has a postretirement benefit plansplan covering non-union employees hired before October 2015.2015 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 July 1, 2013, and Ameren Illinois union employees hired after October 15, 2012, participate in a cash balance pension plan. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Ameren also has an unfunded nonqualified pension plan, the Ameren
Supplemental Retirement Plan, which is available to provide certain management employees and retirees with a supplemental benefit when their qualified pension plan benefits are capped in compliance with Internal Revenue Code limitations. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Only Ameren subsidiaries participate in the plans listed above.
Ameren’s pension and other postretirement benefit plans were overfunded by $249 million in the aggregate as of December 31, 2020. Ameren’s total unfunded obligation under its pension and other postretirement benefit plans was $481 million and $551$216 million as of December 31, 2018 and 2017, respectively.2019. These net assets and liabilities are recorded in “Other assets,” “Other current liabilities,” and “Pension and other postretirement benefits,” and “Other assets”benefits” on Ameren’s consolidated balance sheet. The decreaseincrease in the unfunded obligationoverfunded pension and postretirement benefit plans during 20182020 was primarily the result of an increase in the return on plan assets of the pension and postretirement trusts offset by a 75 basis point increasedecrease in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligation offset by a decrease in the return on plan assets of theobligation. The overfunded pension and other postretirement trusts. The decrease in the unfunded obligationbenefit plans also resulted in a decrease to “Regulatory assets”regulatory liabilities on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets.
The following table presents the net benefit liabilityliability/(asset) recorded on the balance sheets of each of the Ameren Companies as of December 31, 20182020 and 2017:December 31, 2019:
| | | | | | | | | | | |
| 2020 | | 2019 |
Ameren(a) | $ | (249) | | | $ | 216 | |
Ameren Missouri(a) | (25) | | | 142 | |
Ameren Illinois(a) | (210) | | | (16) | |
(a)Assets associated with pension and other postretirement benefits are recorded in “Other assets” on the balance sheet.
|
| | | | | | |
| | 2018 |
| 2017 |
|
Ameren(a) | $ | 481 |
| $ | 551 |
|
| Ameren Missouri | 229 |
| 215 |
|
Ameren Illinois(a) | 120 |
| 213 |
|
| |
(a) | Assets associated with other postretirement benefits are recorded in “Other assets” on the balance sheet. |
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.assets or liabilities. The following table presents the funded status of Ameren’s pension and postretirement benefit plans as of December 31, 20182020 and 2017.December 31, 2019. It also provides the amounts included in regulatory assets or liabilities and accumulated OCI at December 31, 20182020 and 2017,December 31, 2019, that have not been recognized in net periodic benefit costs.
| | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| Pension
Benefits | | Postretirement
Benefits | | Pension
Benefits | | Postretirement
Benefits |
| Accumulated benefit obligation at end of year | $ | 5,213 | | $ | (a) | | $ | 4,735 | | $ | (a) |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,967 | | $ | 1,110 | | | $ | 4,459 | | $ | 1,034 | |
| Service cost | 110 | | | 19 | | | 88 | | | 18 | |
| Interest cost | 174 | | | 39 | | | 187 | | | 43 | |
| Plan amendments | 0 | | | 0 | | | 0 | | | 2 | |
| Participant contributions | 0 | | | 8 | | | 0 | | | 8 | |
| Actuarial loss | 508 | | | 91 | | | 469 | | | 69 | |
| | | | | | | |
| Benefits paid | (249) | | | (63) | | | (236) | | | (64) | |
| | | | | | | |
| | | | | | | |
| Net benefit obligation at end of year | 5,510 | | | 1,204 | | | 4,967 | | | 1,110 | |
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 4,564 | | | 1,297 | | | 3,899 | | | 1,113 | |
| Actual return on plan assets | 1,143 | | | 209 | | | 878 | | | 237 | |
| Employer contributions | 52 | | | 2 | | | 23 | | | 3 | |
| | | | | | | |
| | | | | | | |
| Participant contributions | 0 | | | 8 | | | 0 | | | 8 | |
| | | | | | | |
| | | | | | | |
| Benefits paid | (249) | | | (63) | | | (236) | | | (64) | |
| Fair value of plan assets at end of year | 5,510 | | | 1,453 | | | 4,564 | | | 1,297 | |
| Funded status – deficiency (surplus) | 0 | | | (249) | | | 403 | | | (187) | |
| Accrued benefit cost (asset) at December 31 | $ | 0 | | $ | (249) | | | $ | 403 | | $ | (187) | |
| Amounts recognized in the balance sheet consist of: | | | | | | | |
Noncurrent asset(b) | $ | (39) | | $ | (249) | | | $ | 0 | | $ | (187) | |
Current liability(c) | 2 | | | 0 | | | 2 | | | 0 | |
| Noncurrent liability | 37 | | | 0 | | | 401 | | | 0 | |
| Net liability (asset) recognized | $ | 0 | | $ | (249) | | | $ | 403 | | $ | (187) | |
| Amounts recognized in regulatory assets or liabilities consist of: | | | | | | | |
| Net actuarial (gain) loss | $ | (138) | | $ | (200) | | | $ | 244 | | $ | (170) | |
| Prior service credit | 0 | | | (37) | | | 0 | | | (41) | |
| | | | | | | |
| Amounts recognized in accumulated OCI (pretax) consist of: | | | | | | | |
| Net actuarial loss | 5 | | | 6 | | | 26 | | | 4 | |
| | | | | | | |
| Total | $ | (133) | | $ | (231) | | | $ | 270 | | $ | (207) | |
|
| | | | | | | | | | | | | |
| | 2018 | | 2017 |
| | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits |
| Accumulated benefit obligation at end of year | $ | 4,258 |
| $ | (a) |
| | $ | 4,577 |
| $ | (a) |
|
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,827 |
| $ | 1,240 |
| | $ | 4,518 |
| $ | 1,170 |
|
| Service cost | 100 |
| | 21 |
| | 93 |
| | 21 |
|
| Interest cost | 169 |
| | 40 |
| | 179 |
| | 47 |
|
| Plan amendments | — |
| | (49 | ) | | — |
| | — |
|
| Participant contributions | — |
| | 9 |
| | — |
| | 8 |
|
| Actuarial (gain) loss | (401 | ) | | (163 | ) | | 255 |
| | 53 |
|
| Benefits paid | (236 | ) | | (64 | ) | | (218 | ) | | (59 | ) |
| Net benefit obligation at end of year | 4,459 |
| | 1,034 |
| | 4,827 |
| | 1,240 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 4,293 |
| | 1,223 |
| | 3,813 |
| | 1,101 |
|
| Actual return on plan assets | (218 | ) | | (57 | ) | | 634 |
| | 171 |
|
| Employer contributions | 60 |
| | 2 |
| | 64 |
| | 2 |
|
| Participant contributions | — |
| | 9 |
| | — |
| | 8 |
|
| Benefits paid | (236 | ) | | (64 | ) | | (218 | ) | | (59 | ) |
| Fair value of plan assets at end of year | 3,899 |
| | 1,113 |
| | 4,293 |
| | 1,223 |
|
| Funded status – deficiency (surplus) | 560 |
| | (79 | ) | | 534 |
| | 17 |
|
| Accrued benefit cost (asset) at December 31 | $ | 560 |
| $ | (79 | ) | | $ | 534 |
| $ | 17 |
|
| Amounts recognized in the balance sheet consist of: | | | | | | | |
Noncurrent asset(b) | $ | — |
| $ | (79 | ) | | $ | — |
| $ | — |
|
Current liability(c) | 2 |
| | — |
| | 3 |
| | 3 |
|
| Noncurrent liability | 558 |
| | — |
| | 531 |
| | 14 |
|
| Net liability (asset) recognized | $ | 560 |
| $ | (79 | ) | | $ | 534 |
| $ | 17 |
|
| Amounts recognized in regulatory assets consist of: | | | | | | | |
| Net actuarial (gain) loss | $ | 393 |
| $ | (91 | ) | | $ | 374 |
| $ | (69 | ) |
| Prior service credit | (2 | ) | | (48 | ) | | (3 | ) | | (3 | ) |
| Amounts (pretax) recognized in accumulated OCI consist of: | | | | | | | |
| Net actuarial loss | 35 |
| | 3 |
| | 30 |
| | 2 |
|
| Total | $ | 426 |
| $ | (136 | ) | | $ | 401 |
| $ | (70 | ) |
| |
(b) | Included in “Other assets” on Ameren’s consolidated balance sheet. |
| |
(c) | Included in “Other current liabilities” on Ameren’s consolidated balance sheet. |
(b)Included in “Other assets” on Ameren’s consolidated balance sheet.
(c)Included in “Other current liabilities” on Ameren’s consolidated balance sheet.
The following table presents the assumptions used to determine our benefit obligations at December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Discount rate at measurement date | 2.75 | % | | 3.50 | % | | 2.75 | % | | 3.50 | % |
| Increase in future compensation | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | |
| Cash balance pension plan interest crediting rate | 5.00 | | | 5.00 | | | (a) | | (a) |
Medical cost trend rate (initial)(b) | (a) | | (a) | | 5.00 | | | 5.00 | |
Medical cost trend rate (ultimate)(b) | (a) | | (a) | | 5.00 | | | 5.00 | |
| | | | | | | |
|
| | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2018 | | 2017 | | 2018 | | 2017 |
| Discount rate at measurement date | 4.25 | % | | 3.50 | % | | 4.25 | % | | 3.50 | % |
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial)(a) | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate)(a) | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
|
| |
(a) | Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%. |
(b)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%.
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 nearly 600more than 830 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 addition, during 2018,During 2020, Ameren adopted the updated Society of Actuaries mortality table and adopted the Society of Actuaries 20182020 Mortality Improvement
Scale. The updated mortality table reflects lower life expectancy in aggregate compared with the 2019 Society of Actuaries mortality table. The updated improvement scale assumes a lower rate of mortality improvement, as compared towith the 20172019 Mortality Improvement Scale that Ameren used in 2017, resultingScale. The impact of the adoption of the table and the scale results in a decrease to our pension and other postretirement benefit obligations.
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, and other regulatory requirements. As a result, Ameren expects to fund its pension plan at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on its assumptions at December 31, 2018,2020, its investment performance in 2018,2020, and its pension funding policy, Ameren expects to make annualaggregate contributions of approximately $20$60 million to $70 million in each of over the next five years, with aggregate estimated contributions of $200 million.years. Ameren Missouri and Ameren Illinois estimate that their portion of the future funding requirements will be 30% and 60%, respectively. These estimates 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 planplans and to our postretirement plansplan during 2018, 2017,2020, 2019, and 2016:2018:
| | | | Pension Benefits | | Postretirement Benefits | | Pension Benefits | | Postretirement Benefits | |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 | |
| Ameren Missouri | $ | 18 |
| | $ | 19 |
| | $ | 21 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| Ameren Missouri | $ | 17 | | | $ | 3 | | | $ | 18 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | |
| Ameren Illinois | 35 |
| | 37 |
| | 30 |
| | 1 |
| | 1 |
| | 1 |
| Ameren Illinois | 27 | | | 19 | | | 35 | | | 1 | | | 1 | | | 1 | | |
| Other | 7 |
| | 8 |
| | 6 |
| | — |
| | — |
| | — |
| Other | 8 | | | 1 | | | 7 | | | 0 | | | 1 | | | 0 | | |
| Ameren | $ | 60 |
| | $ | 64 |
| | $ | 57 |
| | $ | 2 |
| | $ | 2 |
| | $ | 2 |
| Ameren | $ | 52 | | | $ | 23 | | | $ | 60 | | | $ | 2 | | | $ | 3 | | | $ | 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 adjusted 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 7.00%6.50% in 2019. No plan assets are expected to be returned to Ameren during 2019.2021.
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, private equity)estate), duration, market capitalization, country, style (growth or value), and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk.
Effective January 2020, Ameren’s investment committee developed and implemented a liability hedging investment strategy for its qualified pension plans designed to reduce interest rate risk as part of an objective for its long-term investment strategy. The plan invests in derivative instruments mainly consisting of interest rate futures intended to extend the duration of the pension plan assets so that the assets are more closely aligned with the duration of the liabilities. In addition, part of Ameren’s investment strategy includes participation in a securities lending program, which allows it to lend eligible securities to third party borrowers. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested in the form of cash, government obligations, and U.S. agency obligations.
Ameren’s fair value of securities loaned was $365 million and $246 million as of December 31, 2020, and 2019, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2020 and 2019.
The following table presents our target allocations for 20192021 and our pension and postretirement plans’ asset categories as of December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | |
Asset
Category | Target Allocation
2020 | | Percentage of Plan Assets at December 31, |
| 2020 | | 2019 |
| Pension Plan: | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 3 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 21% – 31% | | 26 | % | | 27 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 7 | % |
| International | 9% – 19% | | 15 | % | | 14 | % |
| Global | 3% – 13% | | 9 | % | | 9 | % |
| Total equity | 51% – 61% | | 59 | % | | 57 | % |
| Debt securities | 35% – 45% | | 36 | % | | 36 | % |
| Real estate | 0% – 9% | | 4 | % | | 4 | % |
| Private equity | 0% – 5% | | (a) | | (a) |
| Total | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | |
| Cash and cash equivalents | 0% – 7% | | 3 | % | | 1 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 23% – 33% | | 31 | % | | 31 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 8 | % | | 9 | % |
| International | 9% – 19% | | 15 | % | | 14 | % |
| Global | 5% – 15% | | 10 | % | | 11 | % |
| Total equity | 55% – 65% | | 64 | % | | 65 | % |
| Debt securities | 33% – 43% | | 33 | % | | 34 | % |
| Total | | | 100 | % | | 100 | % |
|
| | | | | | | |
Asset Category | Target Allocation 2019 | | Percentage of Plan Assets at December 31, |
| 2018 | �� | 2017 |
| Pension Plan: | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 1 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 21% – 31% | | 24 | % | | 34 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 7 | % | | 9 | % |
| International | 9% – 19% | | 13 | % | | 14 | % |
| Global | 3% – 13% | | 8 | % | | — | % |
| Total equity | 51% – 61% | | 52 | % | | 57 | % |
| Debt securities | 35% – 45% | | 42 | % | | 37 | % |
| Real estate | 0% – 9% | | 5 | % | | 5 | % |
| Private equity | 0% – 5% | | (a) |
| | (a) |
|
| Total | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | |
| Cash and cash equivalents | 0% – 7% | | 2 | % | | 2 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 34% – 44% | | 40 | % | | 41 | % |
| U.S. small- and mid-capitalization | 2% – 12% | | 7 | % | | 8 | % |
| International | 9% – 19% | | 13 | % | | 14 | % |
| Total equity | 55% – 65% | | 60 | % | | 63 | % |
| Debt securities | 33% – 43% | | 38 | % | | 35 | % |
| Total | | | 100 | % | | 100 | % |
| |
(a)
| Less than 1% of plan assets. |
In general, the United States large-capitalization equity investments are passively managed or indexed, whereas the international, global, United States small-capitalization, and United States mid-capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed-income vehicles. Debt security investments in high-yield securities and non-United-States-dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. Additionally,In addition to the derivative investments included in the liability hedging investment strategy described above, Ameren’s investment committee allowsalso allows investment managers to use derivatives, such as index futures, foreign exchange futures, and options, in certain situations to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2018.2020. The fair value of an asset is the amount that would be received upon its sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. 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, 2018:2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | December 31, 2019 |
| Level 1 | | Level 2 | | | NAV | | Total | | | Level 1 | | Level 2 | | | NAV | | Total |
| Cash and cash equivalents | $ | 0 | | | $ | 0 | | | | $ | 145 | | | $ | 145 | | | | $ | 0 | | | $ | 0 | | | | $ | 139 | | | $ | 139 | |
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 0 | | | 0 | | | | 1,511 | | | 1,511 | | | | 0 | | | 0 | | | | 1,253 | | | 1,253 | |
| U.S. small- and mid-capitalization | 513 | | | 0 | | | | 0 | | | 513 | | | | 344 | | | 0 | | | | 0 | | | 344 | |
| International | 375 | | | 0 | | | | 492 | | | 867 | | | | 296 | | | 0 | | | | 363 | | | 659 | |
| Global | 0 | | | 0 | | | | 546 | | | 546 | | | | 0 | | | 0 | | | | 407 | | | 407 | |
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | 0 | | | 506 | | | | 17 | | | 523 | | | | 0 | | | 597 | | | | 13 | | | 610 | |
| Municipal bonds | 0 | | | 50 | | | | 0 | | | 50 | | | | 0 | | | 75 | | | | 0 | | | 75 | |
| U.S. Treasury and agency securities | 3 | | | 1,325 | | | | 0 | | | 1,328 | | | | 5 | | | 1,010 | | | | 0 | | | 1,015 | |
| Other | (5) | | | 8 | | | | 0 | | | 3 | | | | 0 | | | 8 | | | | 0 | | | 8 | |
| Real estate | 0 | | | 0 | | | | 208 | | | 208 | | | | 0 | | | 0 | | | | 211 | | | 211 | |
| Private equity | 0 | | | 0 | | | | 2 | | | 2 | | | | 0 | | | 0 | | | | 2 | | | 2 | |
| Total | $ | 886 | | | $ | 1,889 | | | | $ | 2,921 | | | $ | 5,696 | | | | $ | 645 | | | $ | 1,690 | | | | $ | 2,388 | | | $ | 4,723 | |
Less: Medical benefit assets(a) | | | | | | | | (219) | | | | | | | | | | | (176) | |
Plus: Net receivables(b) | | | | | | | | 33 | | | | | | | | | | | 17 | |
| Fair value of pension plans’ assets | | | | | | | | $ | 5,510 | | | | | | | | | | | $ | 4,564 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | 41 |
| | $ | 41 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 955 |
| | 955 |
|
| U.S. small- and mid-capitalization | 272 |
| | — |
| | — |
| | — |
| | 272 |
|
| International | 224 |
| | — |
| | — |
| | 298 |
| | 522 |
|
| Global | — |
| | — |
| | — |
| | 321 |
| | 321 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 701 |
| | — |
| | 19 |
| | 720 |
|
| Municipal bonds | — |
| | 87 |
| | — |
| | — |
| | 87 |
|
| U.S. Treasury and agency securities | — |
| | 891 |
| | — |
| | — |
| | 891 |
|
| Other | 1 |
| | 11 |
| | — |
| | — |
| | 12 |
|
| Real estate | — |
| | — |
| | — |
| | 202 |
| | 202 |
|
| Private equity | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
| Total | $ | 497 |
| | $ | 1,690 |
| | $ | — |
| | $ | 1,839 |
| | $ | 4,026 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | | | (144 | ) |
Plus: Net receivables at December 31(b) | | | | | | | | | 17 |
|
| Fair value of pension plans’ assets at December 31 | | | | | | | | | $ | 3,899 |
|
| |
(a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. |
| |
(b) | Receivables related to pending security(b)Receivables related to pending securities sales, offset by payables related to pending security purchases. |
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 as of December 31, 2017:payables related to pending securities purchases.
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | 25 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,523 |
| | 1,523 |
|
| U.S. small- and mid-capitalization | 379 |
| | — |
| | — |
| | — |
| | 379 |
|
| International | 179 |
| | — |
| | — |
| | 450 |
| | 629 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 726 |
| | — |
| | 15 |
| | 741 |
|
| Municipal bonds | — |
| | 91 |
| | — |
| | — |
| | 91 |
|
| U.S. Treasury and agency securities | 8 |
| | 816 |
| | — |
| | — |
| | 824 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Real estate | — |
| | — |
| | — |
| | 196 |
| | 196 |
|
| Private equity | — |
| | — |
| | — |
| | 4 |
| | 4 |
|
| Total | $ | 566 |
| | $ | 1,640 |
| | $ | — |
| | $ | 2,213 |
| | $ | 4,419 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | | | (153 | ) |
Plus: Net receivables at December 31(b) | | | | | | | | | 27 |
|
| Fair value of pension plans’ assets at December 31 | | | | | | | | | $ | 4,293 |
|
| |
(a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. |
| |
(b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans’ assets measured at fair value and NAV as of December 31, 2018:2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | December 31, 2019 |
| Level 1 | | Level 2 | | | NAV | | Total | | | Level 1 | | Level 2 | | | NAV | | Total |
| Cash and cash equivalents | $ | 38 | | | $ | 0 | | | | $ | 0 | | | $ | 38 | | | | $ | 12 | | | $ | 0 | | | | $ | 0 | | | $ | 12 | |
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 279 | | | 0 | | | | 107 | | | 386 | | | | 238 | | | 0 | | | | 112 | | | 350 | |
| U.S. small- and mid-capitalization | 104 | | | 0 | | | | 0 | | | 104 | | | | 93 | | | 0 | | | | 0 | | | 93 | |
| International | 75 | | | 0 | | | | 107 | | | 182 | | | | 59 | | | 0 | | | | 102 | | | 161 | |
| Global | 0 | | | 0 | | | | 120 | | | 120 | | | | 0 | | | 0 | | | | 120 | | | 120 | |
| | | | | | | | | | | | | | | | | | |
| Debt securities: | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Municipal bonds | 0 | | | 106 | | | | 0 | | | 106 | | | | 0 | | | 107 | | | | 0 | | | 107 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | 0 | | | 0 | | | | 295 | | | 295 | | | | 0 | | | 0 | | | | 277 | | | 277 | |
| Total | $ | 496 | | | $ | 106 | | | | $ | 629 | | | $ | 1,231 | | | | $ | 402 | | | $ | 107 | | | | $ | 611 | | | $ | 1,120 | |
Plus: Medical benefit assets(a) | | | | | | | | 219 | | | | | | | | | | | 176 | |
Plus: Net receivables(b) | | | | | | | | 3 | | | | | | | | | | | 1 | |
| Fair value of postretirement benefit plans’ assets | | | | | | | | $ | 1,453 | | | | | | | | | | | $ | 1,297 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | 32 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 32 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | 297 |
| | — |
| | — |
| | 89 |
| | 386 |
|
| U.S. small- and mid-capitalization | 63 |
| | — |
| | — |
| | — |
| | 63 |
|
| International | 45 |
| | — |
| | — |
| | 84 |
| | 129 |
|
| Other | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 144 |
| | — |
| | — |
| | 144 |
|
| Municipal bonds | — |
| | 107 |
| | — |
| | — |
| | 107 |
|
| U.S. Treasury and agency securities | — |
| | 62 |
| | — |
| | — |
| | 62 |
|
| Other | — |
| | 7 |
| | — |
| | 34 |
| | 41 |
|
| Total | $ | 437 |
| | $ | 332 |
| | $ | — |
| | $ | 207 |
| | $ | 976 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | | | 144 |
|
Less: Net payables at December 31(b) | | | | | | | | | (7 | ) |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | $ | 1,113 |
|
| |
(a) | (a)Medical benefit (health and welfare) component for 401(h) 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) | Payables related to pending security purchases, offset by interest receivables and receivables related to pending security sales. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the postretirement benefit plans’obligation. These 401(h) assets measured at fair value asare included in the pension plan assets shown above.
(b)Receivables related to pending securities sales, offset by payables related to pending securities purchases.
|
| | | | | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Measured at NAV | | Total |
| Cash and cash equivalents | $ | 44 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 44 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | 332 |
| | — |
| | — |
| | 110 |
| | 442 |
|
| U.S. small- and mid-capitalization | 80 |
| | — |
| | — |
| | — |
| | 80 |
|
| International | 53 |
| | — |
| | — |
| | 101 |
| | 154 |
|
| Other | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 144 |
| | — |
| | — |
| | 144 |
|
| Municipal bonds | — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 76 |
| | — |
| | — |
| | 76 |
|
| Other | — |
| | 4 |
| | — |
| | 34 |
| | 38 |
|
| Total | $ | 509 |
| | $ | 342 |
| | $ | — |
| | $ | 245 |
| | $ | 1,096 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | | | 153 |
|
Less: Net payables at December 31(b) | | | | | | | | | (26 | ) |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | $ | 1,223 |
|
| |
(a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
(b) | Payables related to pending security purchases, offset by interest receivables and receivables related to pending security sales. |
Net Periodic Benefit Cost
In March 2017, the FASB issued authoritative guidance that requires an entity to report, including on a retrospective basis, the non-service cost or income components of net periodic benefit cost separately from the service cost component and outside of operating income. The Ameren Companies adopted this guidance, effective January 1, 2018, and as a result, $44 million, $22 million, and $10 million of net benefit income has been retrospectively reclassified from “Operating Expenses – Other operations and maintenance” to “Other Income, Net” on Ameren's, Ameren Missouri’s, and Ameren Illinois’ respective statements of income for the year ended December 31, 2017. Net benefit income of $56 million, $18 million, and $24 million has been similarly retrospectively reclassified on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ respective statements of income for the year ended December 31, 2016.
The guidance also requires an entity to capitalize only the service cost component as part of an asset, such as inventory or property, plant, and equipment, on a prospective basis. Previously all of the net benefit cost components were eligible for capitalization. This change in the capitalization of net benefit costs is not expected to affect our ability to recover total net benefit cost through customer rates.
The following table presents the components of the net periodic benefit cost of Ameren’s pension and postretirement benefit plans during 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | Pension Benefits | | | Postretirement Benefits |
| | Pension Benefits | | Postretirement Benefits | | 2020 | | 2019 | | 2018 | | | 2020 | | 2019 | | 2018 |
| 2018 | | | | |
Service cost(a) | $ | 100 |
| | $ | 21 |
| Service cost(a) | $ | 110 | | | $ | 88 | | | $ | 100 | | | | $ | 19 | | | $ | 18 | | | $ | 21 | |
| Non-service cost components: | | | | Non-service cost components: | | | |
| Interest cost | 169 |
| | 40 |
| Interest cost | 174 | | | 187 | | | 169 | | | | 39 | | | 43 | | | 40 | |
| Expected return on plan assets | (276 | ) | | (77 | ) | Expected return on plan assets | (291) | | | (276) | | | (276) | | | | (80) | | | (77) | | | (77) | |
| Amortization of: | | | | Amortization of: | | | |
| | Prior service credit | (1 | ) | | (4 | ) | Prior service credit | (1) | | | (1) | | | (1) | | | | (4) | | | (5) | | | (4) | |
| Actuarial (gain) loss | 68 |
| | (6 | ) | Actuarial (gain) loss | 60 | | | 25 | | | 68 | | | | (9) | | | (15) | | | (6) | |
| Total non-service cost components(b) | $ | (40 | ) | | $ | (47 | ) | Total non-service cost components(b) | $ | (58) | | | $ | (65) | | | $ | (40) | | | | $ | (54) | | | $ | (54) | | | $ | (47) | |
| Net periodic benefit cost (income) | $ | 60 |
| | $ | (26 | ) | Net periodic benefit cost (income) | $ | 52 | | | $ | 23 | | | $ | 60 | | | | $ | (35) | | | $ | (36) | | | $ | (26) | |
| 2017 | | | | |
Service cost(a) | $ | 93 |
| | $ | 21 |
| |
| Non-service cost components: | | | | |
| Interest cost | 179 |
| | 47 |
| |
| Expected return on plan assets | (262 | ) | | (75 | ) | |
| Amortization of: | | | | |
| Prior service credit | (1 | ) | | (5 | ) | |
| Actuarial (gain) loss | 55 |
| | (6 | ) | |
Total non-service cost components(b) | $ | (29 | ) | | $ | (39 | ) | |
| Net periodic benefit cost (income) | $ | 64 |
| | $ | (18 | ) | |
| 2016 | | | | |
Service cost(a) | $ | 81 |
| | $ | 19 |
| |
| Non-service cost components: | | | | |
| Interest cost | 185 |
| | 50 |
| |
| Expected return on plan assets | (253 | ) | | (72 | ) | |
| Amortization of: | | | | |
| Prior service credit | (1 | ) | | (5 | ) | |
| Actuarial (gain) loss | 32 |
| | (11 | ) | |
Total non-service cost components(b) | $ | (37 | ) | | $ | (38 | ) | |
| Net periodic benefit cost (income) | $ | 44 |
| | $ | (19 | ) | |
|
(a) Service cost, net of capitalization, is reflected in “Operating Expenses - Other operations and maintenance” on Ameren’s statement of income.
| |
(b) | 2018 amounts and the non-capitalized portion of 2017 and 2016’s non-service(b) Non-service cost components as discussed above, are reflected in “Other Income, Net” on Ameren’s statement of income. See Note 5 - Other Income, Net for additional information. |
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into Ameren’s net periodic benefit cost in 2019 are as follows:consolidated statement of income. See Note 6 – Other Income, Net for additional information.
|
| | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| Regulatory assets: | | | |
| Prior service credit | $ | (1 | ) | | $ | (5 | ) |
| Net actuarial (gain) loss | 24 |
| | (15 | ) |
| Accumulated OCI: | | | |
| Net actuarial loss | 2 |
| | — |
|
| Total | $ | 25 |
| | $ | (20 | ) |
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 subject to amortization are amortized on a straight-line basis over 10 years.
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Costs | | Postretirement Costs |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
Ameren Missouri(a) | $ | 22 | | | $ | 5 | | | $ | 22 | | | $ | (5) | | | $ | (6) | | | $ | (1) | |
| Ameren Illinois | 32 | | | 20 | | | 39 | | | (31) | | | (30) | | | (25) | |
| Other | (2) | | | (2) | | | (1) | | | 1 | | | 0 | | | 0 | |
| Ameren | $ | 52 | | | $ | 23 | | | $ | 60 | | | $ | (35) | | | $ | (36) | | | $ | (26) | |
(a)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Costs | | Postretirement Costs |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
Ameren Missouri(a) | $ | 22 |
| | $ | 24 |
| | $ | 26 |
| | $ | (1 | ) | | $ | (4 | ) | | $ | (5 | ) |
| Ameren Illinois | 39 |
| | 41 |
| | 22 |
| | (25 | ) | | (14 | ) | | (13 | ) |
| Other | (1 | ) | | (1 | ) | | (4 | ) | | — |
| | — |
| | (1 | ) |
| Ameren | 60 |
| | 64 |
| | 44 |
| | (26 | ) | | (18 | ) | | (19 | ) |
| |
(a) | Does not include the impact of the regulatory tracking 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 expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, as of December 31, 2018,2020, 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 | | |
| 2021 | $ | 260 | | | $ | 2 | | | $ | 58 | | | $ | 2 | | | |
| 2022 | 267 | | | 2 | | | 60 | | | 2 | | | |
| 2023 | 274 | | | 3 | | | 61 | | | 2 | | | |
| 2024 | 278 | | | 3 | | | 62 | | | 2 | | | |
| 2025 | 283 | | | 3 | | | 61 | | | 2 | | | |
2026 – 2030 | 1,454 | | | 12 | | | 303 | | | 11 | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Paid from Qualified Trust Funds | | Paid from Company Funds | | Paid from Qualified Trust Funds | | Paid from Company Funds |
| 2019 | $ | 267 |
| | $ | 3 |
| | $ | 57 |
| | $ | 2 |
|
| 2020 | 272 |
| | 3 |
| | 59 |
| | 2 |
|
| 2021 | 282 |
| | 3 |
| | 61 |
| | 2 |
|
| 2022 | 285 |
| | 3 |
| | 62 |
| | 2 |
|
| 2023 | 286 |
| | 3 |
| | 64 |
| | 2 |
|
2024 – 2028 | 1,439 |
| | 12 |
| | 315 |
| | 12 |
|
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, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Discount rate at measurement date | 3.50 | % | | 4.25 | % | | 3.50 | % | | 3.50 | % | | 4.25 | % | | 3.50 | % |
| Expected return on plan assets | 7.00 | | | 7.00 | | | 7.00 | | | 7.00 | | | 7.00 | | | 7.00 | |
| Increase in future compensation | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | | | 3.50 | |
| Cash balance pension plan interest crediting rate | 5.00 | | | 5.00 | | | 5.00 | | | (a) | | (a) | | (a) |
Medical cost trend rate (initial)(b) | (a) | | (a) | | (a) | | 5.00 | | | 5.00 | | | 5.00 | |
Medical cost trend rate (ultimate)(b) | (a) | | (a) | | (a) | | 5.00 | | | 5.00 | | | 5.00 | |
| | | | | | | | | | | |
(a)Not applicable.
(b)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%.
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Discount rate at measurement date | 3.50 | % | | 4.00 | % | | 4.50 | % | | 3.50 | % | | 4.00 | % | | 4.50 | % |
| Expected return on plan assets | 7.00 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
| | 7.00 |
|
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
Medical cost trend rate (initial)(a) | (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
Medical cost trend rate (ultimate)(a) | (b) |
| | (b) |
| | (b) |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
| |
(a) | Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%. |
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:assumptions for the year ended December 31, 2020:
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Service Cost and Interest Cost | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Postretirement Benefit Obligation |
| 0.25% decrease in discount rate | $ | (2 | ) | | $ | 135 |
| | $ | — |
| | $ | 33 |
|
| 0.25% increase in salary scale | 2 |
| | 12 |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | 4 |
| | 58 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | (4 | ) | | (58 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Service Cost
and Interest
Cost | | Expected
Return on
Assets | | Projected
Benefit
Obligation | | Service Cost
and Interest
Cost | | Expected
Return on
Assets | | Postretirement
Benefit
Obligation |
| 0.25% decrease in discount rate | $ | (1) | | | $ | 0 | | | $ | 195 | | | $ | 0 | | | $ | 0 | | | $ | 42 | |
| 0.25% decrease in return on assets | 0 | | | 10 | | | 0 | | | 0 | | | 3 | | | 0 | |
| 0.25% increase in future compensation | 2 | | | 0 | | | 20 | | | 0 | | | 0 | | | 0 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible Ameren employees at December 31, 2018.2020. 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, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| Ameren Missouri | $ | 20 | | | $ | 19 | | | $ | 17 | |
| Ameren Illinois | 17 | | | 16 | | | 15 | |
| Other | 1 | | | 0 | | | 1 | |
| Ameren | $ | 38 | | | $ | 35 | | | $ | 33 | |
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Ameren Missouri | $ | 17 |
| | $ | 16 |
| | $ | 16 |
|
| Ameren Illinois | 15 |
| | 13 |
| | 12 |
|
| Other | 1 |
| | 1 |
| | 1 |
|
| Ameren | $ | 33 |
| | $ | 30 |
| | $ | 29 |
|
NOTE 11 – STOCK-BASED COMPENSATION
The 2014 Omnibus Incentive Compensation Plan is Ameren’s long-term stock-based compensation plan for eligible employees and directors. The 2014 Incentive PlanIt provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors. At December 31, 2018,2020, there were 3.82.3 million common shares remaining for grant under the 2014 Incentive Plan. The 2014 Incentive Plan awardsgrant. Awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2020, 2019, and 2018, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2019.2021.
The following table summarizes Ameren’s nonvested performance share unit and restricted stock unit activity for the year ended December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Share Units – Market Condition(a) | | Performance Share Units – Performance Condition(b) | | Restricted Stock Units |
| Share
Units | | Weighted-average Fair Value per Share Unit | | Shares | | Weighted-average Fair Value per Share Unit | | Stock
Units | | Weighted-average Fair Value per Stock Unit |
Nonvested at January 1, 2020(c) | 539,877 | | | $ | 63.79 | | | 0 | | | $ | 0 | | | 220,277 | | | $ | 61.13 | |
Granted(d) | 267,154 | | | 82.49 | | | 43,052 | | | 76.69 | | | 173,571 | | | 76.91 | |
| Forfeitures | (16,303) | | | 73.42 | | | (1,155) | | | 76.80 | | | (7,507) | | | 69.89 | |
Vested and undistributed(e) | (178,802) | | | 69.87 | | | (7,607) | | | 76.78 | | | (80,180) | | | 66.72 | |
| Vested and distributed | (147,787) | | | 59.16 | | | 0 | | | 0 | | | (2,466) | | | 54.30 | |
| Performance share adjustment | 0 | | | 0 | | | (2,394) | | | 76.66 | | | 0 | | | 0 | |
Nonvested at December 31, 2020(f) | 464,139 | | | $ | 73.34 | | | 31,896 | | | $ | 76.66 | | | 303,695 | | | $ | 68.52 | |
(a)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the specified market conditions. Compensation cost on nonforfeited awards is recognized regardless of whether Ameren achieves the specified market conditions.
(b)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. Compensation cost is recognized ratably over the requisite service period only for awards for which it is probable that the performance condition will be satisfied. The performance share adjustment represents the change in the probability that a performance condition will be satisfied.
(c)Does not include 503,283 performance share units for market performance and 79,854 restricted stock units that were vested and undistributed.
(d)In September 2020, certain executive officers were granted an additional 37,104 restricted stock units with a grant date fair value of $3 million, which will vest after three years on September 17, 2023. The awards do not provide for pro rata vesting in connection with the executive officer’s retirement.
(e)Vested and undistributed units are awards that vest on a pro-rata basis due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For vested and undistributed performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.
(f)Does not include 366,243 of performance share units for market performance, 7,607 of performance share units based on the achievement of renewable generation and energy storage installation targets, and 160,034 of restricted stock units that were vested and undistributed.
|
| | | | | | | | | | | | | |
| | Performance Share Units | | Restricted Stock Units |
| | Share Units | | Weighted-average Fair Value per Share Unit | | Stock Units | | Weighted-average Fair Value per Stock Unit |
Nonvested at January 1, 2018(a) | 895,489 |
| | $ | 52.28 |
| | — |
| | $ | — |
|
| Granted | 316,875 |
| | 62.88 |
| | 187,273 |
| | 57.66 |
|
| Forfeitures | (65,106 | ) | | 51.11 |
| | (5,463 | ) | | 58.99 |
|
Vested and undistributed(b) | (288,404 | ) | | 53.63 |
| | (26,557 | ) | | 59.02 |
|
| Vested and distributed | (176,043 | ) | | 52.88 |
| | — |
| | — |
|
Nonvested at December 31, 2018(c) | 682,811 |
| | $ | 56.58 |
| | 155,253 |
| | $ | 57.38 |
|
| |
(a) | Does not include 712,572 undistributed vested performance share units. |
| |
(b) | Vested and undistributed units are awards that vested due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For vested and undistributed performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period. |
| |
(c) | Does not include 619,783 of vested and undistributed performance share units and 26,557 of vested and undistributed restricted stock units. |
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 years of service, awards vest on a pro ratapro-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 performance goals.specified market conditions.
The fair value of each share unit awarded under the 2014 Incentive Plan is based on Ameren’s closing common share price at December 31st of the year prior to the award year and lattice simulations. Lattice simulations area Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on Ameren’s total shareholder returnTSR for a three-year performance period relative to the designated peer group beginning January 1st of the award year. The simulationssimulation can produce a greater fair value for the share unit than the applicable closing common share price because they includeit includes the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also include a three-year risk-free rate, Ameren’s common stock volatility, volatility for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period. The following table presents the fair value of each share unit awarded under the 2014 Incentive Plan along with the significant assumptions used to calculate the fair value of each share unit for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | |
| 2020 | 2019 | 2018 |
| Fair value of share units awarded | $82.49 | $67.42 | $62.88 |
| | | |
| Three-year risk-free rate | 1.62% | 2.46% | 1.98% |
Ameren’s common stock volatility(a) | 15% | 17% | 17% |
Volatility range for the peer group(a) | 14% – 28% | 15% – 25% | 15% – 23% |
|
| | | |
| | 2018 | 2017 | 2016 |
| Fair value of share units awarded | $62.88 | $59.16 | $44.13 |
| Ameren’s closing common share price at December 31 of the prior year | $61.69 | $52.46 | $43.23 |
| Three-year risk-free rate | 1.98% | 1.47% | 1.31% |
Volatility range for the peer group(a) | 15% – 23% | 15% – 21% | 15% – 20% |
| |
(a) | Based on a historical period that is equal to the remaining term of the performance period as of the grant date. |
Performance Share Units – Performance Condition
A performance condition share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has met the specified performance condition and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual performance conditions achieved. The specified performance condition is based on Ameren’s clean energy goals, specifically the achievement of renewable generation and energy storage installation targets. 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 years of service, awards vest on a pro-rata basis, except for retention RSUs that are periodically granted, which do not provide for pro rata basis.vesting in connection with the employee’s retirement. 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, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| Ameren Missouri | $ | 5 | | | $ | 4 | | | $ | 4 | |
| Ameren Illinois | 3 | | | 3 | | | 3 | |
Other(a) | 13 | | | 13 | | | 13 | |
| Ameren | 21 | | | 20 | | | 20 | |
| Less income tax benefit | 6 | | | 5 | | | 6 | |
| Stock-based compensation expense, net | $ | 15 | | | $ | 15 | | | $ | 14 | |
(a)Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above.
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Ameren Missouri | $ | 4 |
| | $ | 4 |
| | $ | 4 |
|
| Ameren Illinois | 3 |
| | 2 |
| | 2 |
|
Other(a) | 13 |
| | 12 |
| | 11 |
|
| Ameren | 20 |
| | 18 |
| | 17 |
|
| Less income tax benefit | 6 |
| | 7 |
| | 6 |
|
| Stock-based compensation expense, net | $ | 14 |
| | $ | 11 |
| | $ | 11 |
|
| |
(a) | Represents compensation expense of 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 $54$58 million, $39$83 million, and $83$54 million for the years ended December 31, 2018, 2017,2020, 2019, and 2016.2018. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2018, 2017,2020, 2019, and 2016.2018. As of December 31, 2018,2020, total compensation cost of $29$34 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.months.
Ameren realized income tax benefits for settled performance share units of $13 million, $15 million, and $31 million forFor the years ended December 31, 2020, 2019, and 2018, 2017, and 2016.
NOTE 12 – INCOME TAXES
Federal Tax Reform
The TCJA was enacted on December 22, 2017. Substantially all of the provisions of the TCJA affecting the Ameren Companies, other than certain transition depreciation rules, are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code, including amendments that significantly change the taxation of business entities and specific provisions related to regulated public utilities. The most significant change that affects the Ameren Companies is the reduction in the federal corporate statutory income tax rate from 35% to 21%. Specific provisions related to regulated public utilities generally allow for the continued deductibility of interest expense, the elimination of accelerated depreciationexcess tax benefits from certain regulated utility capital investments acquired after September 27, 2017, andassociated with the continuationsettlement of certain rate normalization requirements related to the flow back of excess deferred taxes. Ameren (parent) is subject to provisions of the TCJA that limit the deductibility of interest expense, but such limitation did not affect Ameren in 2018.
In accordance with GAAP, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted. GAAP also requires deferred tax assets and liabilities to be measured at the tax rate that is expected to apply when temporary differences are realized or settled. Thus, in December 2017, the Ameren Companies’ deferred taxes were revalued using the new tax rate. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes was deferred 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 was recorded as income tax expense. As of December 31, 2017, the Ameren Companies made reasonable estimates for the measurement and accounting of certain effects of the TCJA, which have been reflected in their financial statements. We recorded provisional estimates primarily related to depreciation transition rules and 2017 property, plant, and equipment,stock-based compensation and pension-related deductions which would impact our revaluation of deferred taxes at December 31, 2017. The TCJA had the following provisional effects on the Ameren Companies for the year ended December 31, 2017:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| Increase (Decrease) | | | | | | | |
| Accumulated deferred income taxes, net | $ | (1,419 | ) | | $ | (871 | ) | | $ | 37 |
| | $ | (2,253 | ) |
| Income tax expense (benefit) | 32 |
| | (5 | ) | | 127 |
| | 154 |
|
| Noncurrent regulatory assets | (89 | ) | | (24 | ) | | (1 | ) | | (114 | ) |
| Noncurrent regulatory liabilities | 1,362 |
| | 842 |
| | 89 |
| | 2,293 |
|
During the year ended December 31, 2018, Ameren, Ameren Missouri, and Ameren Illinois updated their respective provisional estimates in accordance with SEC staff guidance and recorded $13 million, $4 million, and $4 million, respectively, ofawards reduced income tax expense primarily due to the application of proposed IRS regulations on depreciation transition rules. The offsetting impact to Ameren’s, Ameren Missouri’s,by $8 million, $15 million, and Ameren Illinois’ regulatory asset and regulatory liability balances was immaterial. As of December 31, 2018, Ameren, Ameren Missouri, and Ameren Illinois have completed their accounting for certain effects of the TCJA.$6 million, respectively.
For our regulated operations, reductions in accumulated deferred income tax balances due to the reduction in the federal statutory corporate income tax rate to 21% will result in amounts previously collected from utility customers for these deferred taxes being refundable to those customers, generally through reductions in future rates. The TCJA includes provisions related to the IRS normalization rules that address the time period in which certain plant-related components of the excess deferred taxes are to be reflected in customer rates. This time period for the Ameren Companies is approximately 30 to 60 years. Other components of the excess deferred taxes will be reflected in customer rates as determined by our state and federal regulators, which could be a shorter time period than that applicable to certain plant-related components. See Note 2NOTE 12 – Rate and Regulatory Matters for information regarding the various proceedings for the TCJA impacts with our regulators.INCOME TAXES
Missouri Income Tax Rate
In 2018, legislation modifying Missouri tax law was enacted to decrease the state'sstate’s corporate income tax rate from 6.25% to 4%, effective January 1, 2020. As a result, in 2018, Ameren’s and Ameren Missouri’s accumulated deferred tax balances were revalued, resulting in a net decrease of $122 million to their accumulated deferred tax liability, which was offset by a regulatory liability. Additionally, Ameren recorded an immaterial amount to income tax expense. As a result of its PISA election under Missouri Senate Bill 564, which prohibits a change in electric base rates prior to Aprilthe March 2020 Ameren Missouri anticipates thatrate order, the effect of this tax decrease will bewas reflected in customer rates upon completion of its next regulatory rate review. Ameren (parent) and nonregistrant subsidiaries do not expect thison April 1, 2020. This income tax decrease todid not have a material impact on net income.
Illinois Income Tax Rate
In July 2017, Illinois enacted a law that increased the state’s corporate income tax rate from 7.75% to 9.5% as of July 1, 2017. The law made the increase in the state’s corporate income taxrate permanent. That rate was previously scheduled to go to 7.3% in 2025. In 2017, Ameren recorded an expense of $14 million at Ameren (parent) due to the revaluation of accumulated deferred taxes and the estimated state apportionment of such taxes. Beyond this expense, Ameren and Ameren Illinois do not expect this tax increase to have a material impact on their net income prospectively. The tax increase is not expected to materially affect the earnings of the Ameren Illinois Electric Distribution, the Ameren Transmission, or the Ameren Illinois Transmission segments, since these businesses operate under formula ratemaking frameworks. The tax increase unfavorably affected the 2017 net income of the Ameren Illinois Natural Gas segment by less than $1 million. In addition, in 2017, Ameren’s(parent) and Ameren Illinois’ accumulated deferred tax balances were revalued using the state’s new corporate income tax rate, which resulted in a net increase to the liability balances of $97 million and $79 million, respectively. These increased liabilities were offset by a regulatory asset, as well as income tax expense, as discussed above.nonregistrant subsidiaries.
The following table presents the principal reasons for the difference between the effective income tax rate and the federal statutory corporate income tax rate for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois | | Ameren |
| 2020 | | | | | |
| Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % |
| Increases (decreases) from: | | | | | |
| Amortization of excess deferred income taxes | (16) | | | (3) | | | (9) | |
| | | | | |
| Amortization of deferred investment tax credit | (1) | | | (1) | | | (1) | |
| State tax | 3 | | | 7 | | | 5 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Stock-based compensation | 0 | | | 0 | | | (1) | |
| Effective income tax rate | 7 | % | | 24 | % | | 15 | % |
| 2019 | | | | | |
| Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % |
| Increases (decreases) from: | | | | | |
| Amortization of excess deferred income taxes | (11) | | | (4) | | | (7) | |
| | | | | |
| Amortization of deferred investment tax credit | (1) | | | 0 | | | (1) | |
| State tax | 5 | | | 7 | | | 6 | |
| | | | | |
| Stock-based compensation | 0 | | | 0 | | | (1) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Effective income tax rate | 14 | % | | 24 | % | | 18 | % |
| 2018 | | | | | |
| Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % |
| Increases (decreases) from: | | | | | |
| Amortization of excess deferred income taxes | (4) | | | (4) | | | (4) | |
| Depreciation differences | 0 | | | (1) | | | 0 | |
| Amortization of deferred investment tax credit | (1) | | | 0 | | | (1) | |
| State tax | 4 | | | 7 | | | 6 | |
| TCJA | 1 | | | 1 | | | 1 | |
| | | | | |
| | | | | |
| | | | | |
| Tax credits | (1) | | | 0 | | | 0 | |
| Other permanent items | 0 | | | 0 | | | (1) | |
| Effective income tax rate | 20 | % | | 24 | % | | 22 | % |
|
| | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2018 | | | | | |
| Federal statutory corporate income tax rate: | 21 | % | | 21 | % | | 21 | % |
| Increases (decreases) from: | | | | | |
| Amortization of excess deferred taxes | (4 | ) | | (4 | ) | | (4 | ) |
| Other depreciation differences | — |
| | (1 | ) | | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 4 |
| | 7 |
| | 6 |
|
| TCJA | 1 |
| | 1 |
| | 1 |
|
| Tax credits | (1 | ) | | — |
| | — |
|
| Other permanent items | — |
| | — |
| | (1 | ) |
| Effective income tax rate | 20 | % | | 24 | % | | 22 | % |
| 2017 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | 1 |
| | (1 | ) | | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 4 |
| | 6 |
| | 6 |
|
| TCJA | 6 |
| | (1 | ) | | 14 |
|
| Tax credits | (1 | ) | | — |
| | — |
|
| Other permanent items | — |
| | (1 | ) | | (2 | ) |
| Effective income tax rate | 44 | % | | 38 | % | | 52 | % |
| 2016 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | 1 |
| | — |
| | — |
|
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | — |
|
| State tax | 3 |
| | 5 |
| | 4 |
|
Stock-based compensation(a) | — |
| | — |
| | (2 | ) |
| Valuation allowance | — |
| | — |
| | 1 |
|
| Other permanent items | — |
| | (2 | ) | | (1 | ) |
| Effective income tax rate | 38 | % | | 38 | % | | 37 | % |
| |
(a) | Reflects the adoption of authoritative accounting guidance related to stock-based compensation, which resulted in the recognition of a $21 million income tax benefit in 2016. |
The following table presents the components of income tax expense for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018: | | | | | | | | | | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren | |
| 2020 | | 2020 | |
| Current taxes: | | Current taxes: | |
| Federal | | Federal | $ | 14 | | | $ | 12 | | | $ | (24) | | | $ | 2 | |
| State | | State | 3 | | | (6) | | | 8 | | | 5 | |
| Deferred taxes: | | Deferred taxes: | |
| Federal | | Federal | 82 | | | 81 | | | 24 | | | 187 | |
| State | | State | 15 | | | 52 | | | (10) | | | 57 | |
| Amortization of excess deferred income taxes | | Amortization of excess deferred income taxes | (75) | | | (15) | | | (1) | | | (91) | |
| Amortization of deferred investment tax credits | | Amortization of deferred investment tax credits | (5) | | | 0 | | | 0 | | | (5) | |
| Total income tax expense | | Total income tax expense | $ | 34 | | | $ | 124 | | | $ | (3) | | | $ | 155 | |
| 2019 | | 2019 | |
| Current taxes: | | Current taxes: | |
| Federal | | Federal | $ | 65 | | | $ | 19 | | | $ | (88) | | | $ | (4) | |
| State | | State | 22 | | | 11 | | | (14) | | | 19 | |
| Deferred taxes: | | Deferred taxes: | |
| Federal | | Federal | 37 | | | 66 | | | 82 | | | 185 | |
| State | | State | 5 | | | 29 | | | 25 | | | 59 | |
| Amortization of excess deferred income taxes | | Amortization of excess deferred income taxes | (56) | | | (15) | | | (1) | | | (72) | |
| Amortization of deferred investment tax credits | | Amortization of deferred investment tax credits | (5) | | | 0 | | | 0 | | | (5) | |
| Total income tax expense | | Total income tax expense | $ | 68 | | | $ | 110 | | | $ | 4 | | | $ | 182 | |
| 2018 | | | | | | | | 2018 | |
| Current taxes: | | | | | | | | Current taxes: | |
| Federal | $ | 104 |
| | $ | 4 |
| | $ | (118 | ) | | $ | (10 | ) | Federal | $ | 104 | | | $ | 4 | | | $ | (118) | | | $ | (10) | |
| State | 29 |
| | 6 |
| | (12 | ) | | 23 |
| State | 29 | | | 6 | | | (12) | | | 23 | |
| Deferred taxes: | | | | | | | | Deferred taxes: | |
| Federal | 22 |
| | 75 |
| | 123 |
| | 220 |
| Federal | 22 | | | 75 | | | 123 | | | 220 | |
| State | (2 | ) | | 28 |
| | 23 |
| | 49 |
| State | (2) | | | 28 | | | 23 | | | 49 | |
| Amortization of excess deferred taxes | (24 | ) | | (15 | ) | | (1 | ) | | (40 | ) | |
| Amortization of excess deferred income taxes | | Amortization of excess deferred income taxes | (24) | | | (15) | | | (1) | | | (40) | |
| Amortization of deferred investment tax credits | (5 | ) | | — |
| | — |
| | (5 | ) | Amortization of deferred investment tax credits | (5) | | | 0 | | | 0 | | | (5) | |
| Total income tax expense | $ | 124 |
| | $ | 98 |
| | $ | 15 |
| | $ | 237 |
| Total income tax expense | $ | 124 | | | $ | 98 | | | $ | 15 | | | $ | 237 | |
| 2017 | | | | | | | | |
| Current taxes: | | | | | | | | |
| Federal | $ | 149 |
| | $ | (34 | ) | | $ | (110 | ) | | $ | 5 |
| |
| State | 23 |
| | 29 |
| | (20 | ) | | 32 |
| |
| Deferred taxes: | | | | | | | | |
| Federal | 76 |
| | 185 |
| | 250 |
| | 511 |
| |
| State | 11 |
| | (13 | ) | | 36 |
| | 34 |
| |
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) | |
| Total income tax expense | $ | 254 |
| | $ | 166 |
| | $ | 156 |
| | $ | 576 |
| |
| 2016 | | | | | | | | |
| Current taxes: | | | | | | | | |
| Federal | $ | 31 |
| | $ | (8 | ) | | $ | (24 | ) | | $ | (1 | ) | |
| State | 6 |
| | 12 |
| | (21 | ) | | (3 | ) | |
| Deferred taxes: | | | | | | | | |
| Federal | 161 |
| | 117 |
| | 21 |
| | 299 |
| |
| State | 23 |
| | 37 |
| | 32 |
| | 92 |
| |
| Amortization of deferred investment tax credits | (5 | ) | | — |
| | — |
| | (5 | ) | |
| Total income tax expense | $ | 216 |
| | $ | 158 |
| | $ | 8 |
| | $ | 382 |
| |
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, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2020 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,112 | | | $ | 1,559 | | | $ | 205 | | | $ | 3,876 | |
| | | | | | | |
| | | | | | | |
| Regulatory assets and liabilities, net | (285) | | | (207) | | | (23) | | | (515) | |
| Deferred employee benefit costs | (58) | | | 8 | | | (54) | | | (104) | |
| | | | | | | |
| Tax carryforwards | (26) | | | (6) | | | (65) | | | (97) | |
| Other | (35) | | | 13 | | | 39 | | | 17 | |
| Total net accumulated deferred income tax liabilities (assets) | 1,708 | | | 1,367 | | | 102 | | | 3,177 | |
| Accumulated deferred investment tax credits | 34 | | | 0 | | | 0 | | | 34 | |
| Accumulated deferred income taxes and investment tax credits | $ | 1,742 | | | $ | 1,367 | | | $ | 102 | | | $ | 3,211 | |
| 2019 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,000 | | | $ | 1,423 | | | $ | 193 | | | $ | 3,616 | |
| | | | | | | |
| | | | | | | |
| Regulatory assets and liabilities, net | (310) | | | (214) | | | (24) | | | (548) | |
| Deferred employee benefit costs | (59) | | | 7 | | | (59) | | | (111) | |
| | | | | | | |
| Tax carryforwards | (25) | | | (3) | | | (70) | | | (98) | |
| Other | (33) | | | 11 | | | 43 | | | 21 | |
| Total net accumulated deferred income tax liabilities (assets) | 1,573 | | | 1,224 | | | 83 | | | 2,880 | |
| Accumulated deferred investment tax credits | 39 | | | 0 | | | 0 | | | 39 | |
| Accumulated deferred income taxes and investment tax credits | $ | 1,612 | | | $ | 1,224 | | | $ | 83 | | | $ | 2,919 | |
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2018 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,010 |
| | $ | 1,345 |
| | $ | 179 |
| | $ | 3,534 |
|
| Regulatory assets and liabilities, net | (343 | ) | | (221 | ) | | (25 | ) | | (589 | ) |
| Deferred employee benefit costs | (58 | ) | | (4 | ) | | (64 | ) | | (126 | ) |
| Tax carryforwards | (35 | ) | | (26 | ) | | (166 | ) | | (227 | ) |
| Other | (40 | ) | | 25 |
| | 46 |
| | 31 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 1,534 |
| | $ | 1,119 |
| | $ | (30 | ) | | $ | 2,623 |
|
| 2017 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,064 |
| | $ | 1,264 |
| | $ | 146 |
| | $ | 3,474 |
|
| Regulatory assets and liabilities, net | (317 | ) | | (206 | ) | | (24 | ) | | (547 | ) |
| Deferred employee benefit costs | (53 | ) | | (17 | ) | | (61 | ) | | (131 | ) |
| Revenue requirement reconciliation adjustments | — |
| | 20 |
| | — |
| | 20 |
|
| Tax carryforwards | (31 | ) | | (43 | ) | | (287 | ) | | (361 | ) |
| Other | (13 | ) | | 3 |
| | 61 |
| | 51 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 1,650 |
| | $ | 1,021 |
| | $ | (165 | ) | | $ | 2,506 |
|
The following table presents the components of accumulated deferred income tax assets relating to net operating loss carryforwards, tax credit carryforwards, and charitable contribution carryforwards at December 31, 20182020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2020 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| | | | | | | |
State(a) | $ | 0 | | | $ | 3 | | | $ | 4 | | | $ | 7 | |
| Total net operating loss carryforwards | $ | 0 | | | $ | 3 | | | $ | 4 | | | $ | 7 | |
| Tax credit carryforwards: | | | | | | | |
Federal(b) | $ | 26 | | | $ | 3 | | | $ | 54 | | | $ | 83 | |
State(c) | 0 | | | 0 | | | 7 | | | 7 | |
| | | | | | | |
| Total tax credit carryforwards | $ | 26 | | | $ | 3 | | | $ | 61 | | | $ | 90 | |
Charitable contribution carryforwards(c) | $ | 0 | | | $ | 0 | | | $ | 3 | | | $ | 3 | |
Valuation allowance(d) | 0 | | | 0 | | | (3) | | | (3) | |
| Total charitable contribution carryforwards | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| 2019 | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Tax credit carryforwards: | | | | | | | |
| Federal | $ | 25 | | | $ | 3 | | | $ | 67 | | | $ | 95 | |
| State | 0 | | | 0 | | | 3 | | | 3 | |
| | | | | | | |
| Total tax credit carryforwards | $ | 25 | | | $ | 3 | | | $ | 70 | | | $ | 98 | |
| Charitable contribution carryforwards | $ | 0 | | | $ | 0 | | | $ | 3 | | | $ | 3 | |
| Valuation allowance | 0 | | | 0 | | | (3) | | | (3) | |
| Total charitable contribution carryforwards | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2018 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
Federal(a) | $ | — |
| | $ | 23 |
| | $ | 55 |
| | $ | 78 |
|
State(a) | — |
| | — |
| | 13 |
| | 13 |
|
| Total net operating loss carryforwards | $ | — |
| | $ | 23 |
| | $ | 68 |
| | $ | 91 |
|
| Tax credit carryforwards: | | | | | | | |
Federal(b) | $ | 35 |
| | $ | 3 |
| | $ | 79 |
| | $ | 117 |
|
State(c) | — |
| | — |
| | 10 |
| | 10 |
|
| Total tax credit carryforwards | $ | 35 |
| | $ | 3 |
| | $ | 89 |
| | $ | 127 |
|
Charitable contribution carryforwards(d) | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | 14 |
|
Valuation allowance(e) | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | 9 |
|
| 2017 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| Federal | $ | — |
| | $ | 41 |
| | $ | 162 |
| | $ | 203 |
|
| State | — |
| | — |
| | 32 |
| | 32 |
|
| Total net operating loss carryforwards | $ | — |
| | $ | 41 |
| | $ | 194 |
| | $ | 235 |
|
| Tax credit carryforwards: | | | | | | | |
| Federal | $ | 31 |
| | $ | 2 |
| | $ | 80 |
| | $ | 113 |
|
| State | — |
| | — |
| | 7 |
| | 7 |
|
| Total tax credit carryforwards | $ | 31 |
| | $ | 2 |
| | $ | 87 |
| | $ | 120 |
|
| Charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 11 |
|
| Valuation allowance | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
|
| |
(a) | Will expire between 2034 and 2037. Any net operating loss carryforward generated after January 1, 2018, will not have an expiration date as a result of the TCJA. |
| |
(b) | Will expire between 2029 and 2037. |
| |
(c) | Will expire between 2019 and 2022. |
| |
(d) | Will expire between 2019 and 2023. |
| |
(e) | See Schedule II under Part IV, Item 15, in this report for information on changes in the valuation allowance. |
(b)Will expire between 2030 and 2040.
(c)Will expire between 2021 and 2025.
(d)See Schedule II under Part IV, Item 15, in this report for information on changes in the valuation allowance.
Uncertain Tax Positions
As of December 31, 20182020 and 2017,2019, the Ameren Companies did not record any uncertain tax positions.
The Internal Revenue ServiceAmeren is currently examining Ameren’s 2018 and 2017a part of the IRS’s compliance assurance process program, which involves real-time review of compliance with federal income tax returns.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. TheAmeren’s federal tax returns for the 2015, 2017, 2018, and 2019 tax years are open, but, at the time of this filing, the Ameren Companies currently do not have material income tax issues under examination, administrative appeals, or litigation.
Ameren Missouri has an uncertain tax position tracker. Under Missouri’s regulatory framework, uncertain tax positions do not reduce Ameren Missouri’s electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value, usingwith a return at the weighted-average cost of capitalapplicable WACC included in each of the electric rate orders in effect before the tax position was resolved, of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will affect earnings in the year it is created. It will then be amortized over three years, beginning on the effective date of new rates established in the next electric service regulatory rate review.
NOTE 13 – RELATED-PARTY TRANSACTIONS
In the normal course of business, Ameren Missouri and Ameren Illinois have engaged in, and may in the future 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.statements, except as noted in Software Licensing Agreement discussion below. Below are the material related-party agreements.
Electric Power Supply Agreements
Ameren Illinois must acquire capacity and energy sufficient to meet its obligations to customers. Ameren Illinois uses periodic RFP processes, administered by the IPA and approved by the ICC, to contract capacity and energy on behalf of its customers. Ameren Missouri participates in the RFP process and has been a winning supplier for certain periods.
Capacity Supply Agreements
In a procurement eventevents in 2015,2020, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $15$3 million for the 12 months endingfrom June 2021 through May 31, 2017.2023.
Energy Swaps and Energy ProductsProduct 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 megawatthoursMWhs at a predetermined price over a specified period of time. The following table presents the specified performance period, price, and amount of megawatthoursMWhs included in the agreements:
|
| | | | |
| IPA Procurement Event | Performance Period | MWh | | Average Price per MWh |
| May 2014 | January 2015 – February 2017 | 168,400 | $ | 51 |
| April 2015 | June 2015 – June 2017 | 667,000 | | 36 |
| September 2015 | November 2015 – May 2018 | 339,000 | | 38 |
| April 2016 | June 2017 – September 2018 | 375,200 | | 35 |
| September 2016 | May 2017 – September 2018 | 82,800 | | 34 |
| April 2017 | March 2019 – May 2020 | 85,600 | | 34 |
| April 2018 | June 2019 – September 2020 | 110,000 | | 32 |
| | | | | | | | | | | | | | |
| IPA Procurement Event | Performance Period | MWh | | Average Price per MWh |
| April 2017 | March 2019 – May 2020 | 85,600 | | $ | 34 | |
| April 2018 | June 2019 – September 2020 | 110,000 | | 32 | |
| 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 | |
Collateral Postings
Under the terms of the Illinois energy product agreements entered into through RFP processes administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, which means that only the suppliers can be required to post collateral. Therefore, Ameren Missouri, as a winning supplier in the RFP process, may be required to post collateral. As of December 31, 20182020 and 2017,2019, there were no collateral postings required of Ameren Missouri related to the Illinois energy product agreements.
Interconnection and Transmission Agreements
Ameren Missouri and Ameren Illinois are parties to an interconnection agreement forthat governs the useconnection of their respective transmission lines and other facilities used for the distribution of power. These agreements have no contractual expiration date, but may be terminated by either party with three years’ notice.
Ameren Missouri and ATXI are parties to an interconnection agreement that governs the connection of the High Prairie Renewable Energy Center to an ATXI transmission line that allows Ameren Missouri to distribute power generated from the High Prairie Renewable Energy Center. See Note 2 – Rate and Regulatory Matters for further information on the acquisition of the High Prairie Renewable Energy Center.
Support Services Agreements
Ameren Services provides support services to its affiliates. The costs of support services including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The support services agreement can be terminated at any time by the mutual agreement of Ameren Services and that affiliate or by either party with 60 days’ notice before the end of a calendar year.
In addition, Ameren Missouri and Ameren Illinois provide affiliates with access to their facilities for administrative purposes and with use of other assets. The costs of the rent and facility services and other assets are based on, or are an allocation of, actual costs incurred.
Separately, Ameren Missouri and Ameren Illinois also provide storm-related and miscellaneous support services to each other on an as-needed basis.
Transmission Services
Ameren Illinois receives transmission services from ATXI for its retail load in the AMIL pricing zone.
load.
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. The Ameren Missouri and Ameren Illinois agreements are effective from August 2017 through June 2019 and from August 2018 through July 2019, respectively.
Money Pool
See Note 4 – Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.
Software Licensing Agreement
In September 2019, Ameren Missouri purchased a license for advanced metering infrastructure software from Ameren Illinois. The amount of the $24 million cost-based transaction price over the $5 million remaining carrying value of the software was recorded as revenue by Ameren Illinois, with $14 million of revenue recorded at Ameren Illinois Electric Distribution and $5 million recorded at Ameren Illinois Natural Gas. The revenue recorded at Ameren Illinois Electric Distribution was reflected in formula ratemaking, which resulted in no impact to net income. Per authoritative accounting guidance for sales to rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation by Ameren. Ameren Missouri’s $24 million software investment is included in “Property, Plant, and Equipment, Net.”
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreement. The following table presents the affiliate balances related to income taxes for Ameren Missouri and Ameren Illinois as of December 31, 20182020 and 2017:December 31, 2019:
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | | 2019 |
| Ameren Missouri | Ameren Illinois | | | Ameren Missouri | Ameren Illinois |
Income taxes payable to parent(a) | $ | 0 | | $ | 6 | | | | $ | 15 | | $ | 43 | |
Income taxes receivable from parent(b) | 9 | | 15 | | | | 15 | | 17 | |
|
| | | | | | | | | | | | | | |
| | 2018 | | | 2017 |
| | Ameren Missouri | Ameren Illinois | | | Ameren Missouri | Ameren Illinois |
Income taxes payable to parent(a) | $ | 16 |
| $ | 7 |
| | | $ | 11 |
| $ | 17 |
|
Income taxes receivable from parent(b) | — |
| 6 |
| | | — |
| — |
|
| |
(a) | Included in “Accounts payable – affiliates” on the balance sheet. |
| |
(b) | Included in “Accounts receivable – affiliates” on the balance sheet. |
(b)Included in “Accounts receivable – affiliates” on the balance sheet.
Capital Contributions
The following table presents cash capital contributions received from Ameren (parent) by Ameren Missouri and Ameren Illinois for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | |
Ameren Missouri(a) | $ | 491 | | | $ | 124 | | | $ | 45 | | |
| Ameren Illinois | 464 | | (a) | 15 | | (a) | 160 | | |
(a)Includes capital contributions made as a result of the tax allocation agreement.
|
| | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | |
Ameren Missouri(a) | $ | 45 |
| | $ | 30 |
| | $ | 44 |
| (b) |
| Ameren Illinois | 160 |
| | 8 |
| | — |
| |
| |
(a) | As a result of the tax allocation agreement. |
| |
(b) | Included a $38 million accrued capital contribution from 2015. |
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, 2018, 2017,2020, 2019, and 2016.2018. 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 | | 2020 | $ | 11 | | $ | (a) |
| with Ameren Illinois | | | 2019 | | 3 | | | (a) |
| | | | 2018 | | 11 | | | (a) |
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2020 | | 26 | | | 1 | |
| rent and facility services | | | 2019 | | 27 | | | 2 | |
| | | | 2018 | | 22 | | | 3 | |
| Ameren Missouri and Ameren Illinois miscellaneous | Operating Revenues | | 2020 | | 3 | | | 1 | |
| support services and services provided to ATXI | | | 2019 | | 1 | | | 2 | |
| | | 2018 | | 1 | | | 1 | |
| Ameren Missouri software licensing | Operating Revenues | | 2020 | | (a) | | (a) |
| with Ameren Illinois | | | 2019 | | (a) | | 19 | |
| | | 2018 | | (a) | | (a) |
| Total Operating Revenues | | | 2020 | $ | 40 | | $ | 2 | |
| | | 2019 | | 31 | | | 23 | |
| | | | 2018 | | 34 | | | 4 | |
| Ameren Illinois power supply | Purchased Power | | 2020 | $ | (a) | $ | 11 | |
| agreements with Ameren Missouri | | | 2019 | | (a) | | 3 | |
| | | | 2018 | | (a) | | 11 | |
| Ameren Missouri and Ameren Illinois | Purchased Power | | 2020 | | (a) | | 2 | |
| transmission services from ATXI | | | 2019 | | (a) | | 2 | |
| | | 2018 | | (a) | | 1 | |
| Total Purchased Power | | | 2020 | $ | (a) | $ | 13 | |
| | | 2019 | | (a) | | 5 | |
| | | 2018 | | (a) | | 12 | |
| Ameren Missouri and Ameren Illinois | Other Operations and | | 2020 | $ | (b) | $ | 4 | |
| rent and facility services | Maintenance | | 2019 | | 2 | | | 5 | |
| | | 2018 | | 3 | | | 6 | |
| Ameren Services support services | Other Operations and | | 2020 | | 140 | | | 133 | |
| agreement | Maintenance | | 2019 | | 135 | | | 127 | |
| | | | 2018 | | 136 | | | 126 | |
| Total Other Operations and | | | 2020 | $ | 140 | | $ | 137 | |
| Maintenance Expenses | | | 2019 | | 137 | | | 132 | |
| | | | 2018 | | 139 | | | 132 | |
| Money pool borrowings (advances) | (Interest Charges) | | 2020 | $ | (b) | $ | (b) |
| Other Income, Net | | 2019 | | (b) | | (b) |
| | | | 2018 | | 1 | | | (b) |
(a)Not applicable.
(b)Amount less than $1 million.
|
| | | | | | | | | |
| Agreement | Income Statement Line Item | | | | Ameren Missouri | | Ameren Illinois |
| Ameren Missouri power supply agreements | Operating Revenues | | 2018 | $ | 11 |
| $ | (a) |
|
| with Ameren Illinois | | | 2017 | | 23 |
| | (a) |
|
| | | | 2016 | | 28 |
| | (a) |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2018 | | 22 |
| | 3 |
|
| rent and facility services | | | 2017 | | 26 |
| | 4 |
|
| | | | 2016 | | 25 |
| | 5 |
|
| Ameren Missouri and Ameren Illinois miscellaneous | Operating Revenues | | 2018 | | 1 |
| | 1 |
|
| support services and services provided to ATXI | | | 2017 | | (b) |
| | 1 |
|
| | | | 2016 | | 1 |
| | (b) |
|
| Total Operating Revenues | | | 2018 | $ | 34 |
| $ | 4 |
|
| | | | 2017 | | 49 |
| | 5 |
|
| | | | 2016 | | 54 |
| | 5 |
|
| Ameren Illinois power supply | Purchased Power | | 2018 | $ | (a) |
| $ | 11 |
|
| agreements with Ameren Missouri | | | 2017 | | (a) |
| | 23 |
|
| | | | 2016 | | (a) |
| | 28 |
|
| Ameren Illinois transmission | Purchased Power | | 2018 | | (a) |
| | 1 |
|
| services from ATXI | | | 2017 | | (a) |
| | 2 |
|
| | | | 2016 | | (a) |
| | 2 |
|
| Total Purchased Power | | | 2018 | $ | (a) |
| $ | 12 |
|
| | | | 2017 | | (a) |
| | 25 |
|
| | | | 2016 | | (a) |
| | 30 |
|
| Ameren Missouri and Ameren Illinois | Other Operations and | | 2018 | $ | 3 |
| $ | 6 |
|
| rent and facility services | Maintenance | | 2017 | | (b) |
| | (b) |
|
| | | | 2016 | | (b) |
| | (b) |
|
| Ameren Services support services | Other Operations and | | 2018 | | 136 |
|
| 126 |
|
| agreement | Maintenance | | 2017 | | 149 |
| | 139 |
|
| | | | 2016 | | 129 |
| | 123 |
|
| Total Other Operations and | | | 2018 | $ | 139 |
| $ | 132 |
|
| Maintenance Expenses | | | 2017 | | 149 |
| | 139 |
|
| | | | 2016 | | 129 |
| | 123 |
|
| Money pool borrowings (advances) | (Interest Charges) | | 2018 | $ | 1 |
| $ | (b) |
|
| | Other Income, Net | | 2017 | | 1 |
| | (b) |
|
| | | | 2016 | | (b) |
| | (b) |
|
| |
(b) | Amount less than $1 million. |
NOTE 14 – COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in thesethe 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, and Note 13 – Related-party Transactions, and Note 15 – Supplemental Information in this report.
Leases
We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | After 5 Years | | Total |
| Ameren: | | | | | | | | | | | | | |
Minimum capital lease payments(a)(b) | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | — |
| | $ | 393 |
|
| Less amount representing interest | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | — |
| | 123 |
|
| Present value of minimum capital lease payments | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | — |
| | $ | 270 |
|
| Operating leases | 10 |
| | 8 |
| | 7 |
| | 6 |
| | 5 |
| | 9 |
| | 45 |
|
| Total lease obligations | $ | 17 |
| | $ | 15 |
| | $ | 15 |
| | $ | 14 |
| | $ | 245 |
| | $ | 9 |
| | $ | 315 |
|
| Ameren Missouri: | | | | | | | | | | | | | |
Minimum capital lease payments(b)(c) | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | — |
| | $ | 393 |
|
| Less amount representing interest | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | — |
| | 123 |
|
| Present value of minimum capital lease payments | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | — |
| | $ | 270 |
|
| Operating leases | 8 |
| | 7 |
| | 6 |
| | 5 |
| | 5 |
| | 9 |
| | 40 |
|
| Total lease obligations | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 13 |
| | $ | 245 |
| | $ | 9 |
| | $ | 310 |
|
| Ameren Illinois: | | | | | | | | | | | | | |
| Operating leases | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| |
(a) | See Note 3 – Property, Plant, and Equipment, Net for additional information. |
| |
(b) | See Note 5 – Long-term Debt and Equity Financings for additional information on Ameren’s and Ameren Missouri’s capital lease agreements. |
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Ameren | $ | 9 |
| | $ | 11 |
| | $ | 38 |
|
| Ameren Missouri | 8 |
| | 10 |
| | 34 |
|
| Ameren Illinois | 1 |
| | 1 |
| | 30 |
|
Other Obligations
To supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power, and other commitments at December 31, 2018.2020. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services, and service maintenance agreements related to Ameren Missouri’s High Prairie Renewable Energy Center, among other agreements, at December 31, 2018.2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Coal | | Natural Gas(a) | | Nuclear
Fuel | | Purchased Power(b)(c)(d) | | Methane
Gas | | Other(e) | | Total |
| Ameren: | | | | | | | | | | | | | |
| 2021 | $ | 321 | | | $ | 161 | | | $ | 56 | | | $ | 150 | | (f) | $ | 3 | | | $ | 97 | | | $ | 788 | |
| 2022 | 194 | | | 111 | | | 12 | | | 64 | | | 3 | | | 29 | | | 413 | |
| 2023 | 113 | | | 72 | | | 45 | | | 24 | | | 3 | | | 27 | | | 284 | |
| 2024 | 94 | | | 31 | | | 26 | | | 7 | | | 3 | | | 25 | | | 186 | |
| 2025 | 55 | | | 17 | | | 0 | | | 0 | | | 3 | | | 28 | | | 103 | |
| Thereafter | 0 | | | 64 | | | 21 | | | 0 | | | 18 | | | 92 | | | 195 | |
| Total | $ | 777 | | | $ | 456 | | | $ | 160 | | | $ | 245 | | | $ | 33 | | | $ | 298 | | | $ | 1,969 | |
| Ameren Missouri: | | | | | | | | | | | | | |
| 2021 | $ | 321 | | | $ | 44 | | | $ | 56 | | | $ | 0 | | | $ | 3 | | | $ | 79 | | | $ | 503 | |
| 2022 | 194 | | | 40 | | | 12 | | | 0 | | | 3 | | | 30 | | | 279 | |
| 2023 | 113 | | | 35 | | | 45 | | | 0 | | | 3 | | | 28 | | | 224 | |
| 2024 | 94 | | | 15 | | | 26 | | | 0 | | | 3 | | | 26 | | | 164 | |
| 2025 | 55 | | | 7 | | | 0 | | | 0 | | | 3 | | | 29 | | | 94 | |
| Thereafter | 0 | | | 17 | | | 21 | | | 0 | | | 18 | | | 70 | | | 126 | |
| Total | $ | 777 | | | $ | 158 | | | $ | 160 | | | $ | 0 | | | $ | 33 | | | $ | 262 | | | $ | 1,390 | |
| Ameren Illinois: | | | | | | | | | | | | | |
| 2021 | $ | 0 | | | $ | 117 | | | $ | 0 | | | $ | 160 | | (f) | $ | 0 | | | $ | 13 | | | $ | 290 | |
| 2022 | 0 | | | 71 | | | 0 | | | 67 | | | 0 | | | 0 | | | 138 | |
| 2023 | 0 | | | 37 | | | 0 | | | 25 | | | 0 | | | 0 | | | 62 | |
| 2024 | 0 | | | 16 | | | 0 | | | 7 | | | 0 | | | 0 | | | 23 | |
| 2025 | 0 | | | 10 | | | 0 | | | 0 | | | 0 | | | 0 | | | 10 | |
| Thereafter | 0 | | | 47 | | | 0 | | | 0 | | | 0 | | | 0 | | | 47 | |
| Total | $ | 0 | | | $ | 298 | | | $ | 0 | | | $ | 259 | | | $ | 0 | | | $ | 13 | | | $ | 570 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b)(c) | | Methane Gas | | Other | | Total |
| Ameren: | | | | | | | | | | | | | |
| 2019 | $ | 349 |
| | $ | 197 |
| | $ | 25 |
| | $ | 157 |
| | $ | 4 |
| | $ | 67 |
| | $ | 799 |
|
| 2020 | 160 |
| | 143 |
| | 43 |
| | 54 |
| | 4 |
| | 41 |
| | 445 |
|
| 2021 | 121 |
| | 77 |
| | 59 |
| | 10 |
| | 4 |
| | 30 |
| | 301 |
|
| 2022 | 72 |
| | 27 |
| | 14 |
| | — |
| | 3 |
| | 26 |
| | 142 |
|
| 2023 | — |
| | 7 |
| | 42 |
| | — |
| | 3 |
| | 27 |
| | 79 |
|
| Thereafter | — |
| | 34 |
| | 31 |
| | — |
| | 29 |
| | 72 |
| | 166 |
|
| Total | $ | 702 |
| | $ | 485 |
| | $ | 214 |
| | $ | 221 |
| | $ | 47 |
| | $ | 263 |
| | $ | 1,932 |
|
| Ameren Missouri: | | | | | | | | | | | | | |
| 2019 | $ | 349 |
| | $ | 40 |
| | $ | 25 |
| | $ | — |
| | $ | 4 |
| | $ | 49 |
| | $ | 467 |
|
| 2020 | 160 |
| | 31 |
| | 43 |
| | — |
| | 4 |
| | 26 |
| | 264 |
|
| 2021 | 121 |
| | 15 |
| | 59 |
| | — |
| | 4 |
| | 26 |
| | 225 |
|
| 2022 | 72 |
| | 5 |
| | 14 |
| | — |
| | 3 |
| | 26 |
| | 120 |
|
| 2023 | — |
| | 3 |
| | 42 |
| | — |
| | 3 |
| | 27 |
| | 75 |
|
| Thereafter | — |
| | 14 |
| | 31 |
| | — |
| | 29 |
| | 56 |
| | 130 |
|
| Total | $ | 702 |
| | $ | 108 |
| | $ | 214 |
| | $ | — |
| | $ | 47 |
| | $ | 210 |
| | $ | 1,281 |
|
| Ameren Illinois: | | | | | | | | | | | | | |
| 2019 | $ | — |
| | $ | 157 |
| | $ | — |
| | $ | 157 |
| | $ | — |
| | $ | 8 |
| | $ | 322 |
|
| 2020 | — |
| | 112 |
| | — |
| | 54 |
| | — |
| | 5 |
| | 171 |
|
| 2021 | — |
| | 62 |
| | — |
| | 10 |
| | — |
| | — |
| | 72 |
|
| 2022 | — |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | 22 |
|
| 2023 | — |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
| Thereafter | — |
| | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
|
| Total | $ | — |
| | $ | 377 |
| | $ | — |
| | $ | 221 |
| | $ | — |
| | $ | 13 |
| | $ | 611 |
|
| |
(a) | Includes amounts for generation and for distribution. |
| |
(b) | The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 2034 with various renewable energy suppliers due to the contingent nature of the payment amounts. |
| |
(c) | The purchased power amounts for Ameren and Ameren Missouri exclude a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts. |
(b)The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 2035 with various renewable energy suppliers due to the contingent nature of the payment amounts, with the exception of expected payments of $48 million through 2025.
(c)The purchased power amounts for Ameren and Ameren Missouri exclude a 102-MW power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts.
(d)The purchased power amounts for Ameren exclude obligations resulting from capacity supply and energy product agreements between Ameren Missouri and Ameren Illinois, as disclosed in Note 13 – Related-party Transactions.
(e)The other amounts for Ameren exclude obligations resulting from interconnection agreements between Ameren Missouri and ATXI, as disclosed in Note 13 – Related-party Transactions.
(f)In January 2018, as required by the FEJA, Ameren Illinois entered into 10-year agreements to acquire zero emission credits.credits, through 2026. Annual zero emission credit commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year.year, which begins each June. The amounts above reflect Ameren Illinois’ commitment to acquire approximately $26 million of zero emission credits through May 2019.2021.
Environmental Matters
We are subject to variousOur electric generation, transmission, and distribution operations and natural gas transmission, distribution, and storage operations must comply with a variety of environmental laws that are enforced through statutory and regulatory requirements including statutes and regulations, enforcedpermitting programs implemented by federal, state, and local authorities. The development and operationDepending upon the business activity of electric generation, transmission, and distributionspecific facilities, and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect to environmental laws. Thesesuch laws address emissions,emissions; discharges to water water intake, impacts to air, land,bodies; the storage, handling and water, and chemicaldisposal of hazardous substances and waste handling.materials; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. We employ dedicated personnel knowledgeable in environmental matters to ensure our business activities comply with regulatory requirements.
The EPA has promulgated environmental
Environmental regulations that have a significant impact on the electric utility industry. Over time,industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants.As of December 31, 2018, Ameren Missouri’s fossil fuel-fired energy centers represented 16% and 32% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations Clean Air Act regulations that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as
SO2, particulate matter, NOx,mercury, toxic metals, and acid gases, and CO2 emissions from new power plants. Clean Water Act regulations govern both water intake and discharges from power plants are regulated underand require evaluation of the Clean Water Act. Such regulationecological and biological impact of our operations and could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, eithercenters. Depending upon the scope of whichmodifications ultimately required by state regulators, these capital expenditures could result in significant capital expenditures.be significant. The management and disposal of coal ash is regulated as a solid waste under the Resource Conservation and Recovery Act and the CCR rule, which will require the closure of our surface impoundments and the installations of dry ash handling systems at several of Ameren Missouri’s coal-fired energy centers. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.
Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $300$175 million to $400$225 million from 20192021 through 20232025 in order to comply with existing environmental regulations. Additional environmental controls beyond 20232025 could be required. This estimate of capital expenditures includes expendituresash pond closure and corrective action measures required by the CCR regulations, by the Clean Water Act rule applicablepotential modifications to cooling water intake structures at existing power plants under Clean Water Act rules, and by effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. This estimate does not include capital expenditures that may be required as a result of the NSR and Clean Air Act litigation discussed below. Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning ultra-low-sulfurlow-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 estimateestimates because of uncertainty as to whetherfuture permitting requirements made by state regulators and the EPA, will substantially revisepotential revisions to regulatory obligations, exactly whichand the cost of potential compliance strategies, will be used and their ultimate cost, among other things.
The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of several regulations and proposed amendments to regulations and guidelines, including to the effluent limitation guidelines and the CCR Rule, which could ultimately result in the revision of all or part of such rules.
Clean Air Act
Federal and state laws, including CSAPR, regulate emissions of SO2 and NOx through emissionthe reduction of emissions at their source reductions and the use and retirement of emission allowances. The firstCSAPR is implemented through a series of phases, and the second phase of the CSAPR emission reduction requirements became effective in 2015. The second phase of emission reduction requirements, which were revised by the EPA in 2016, became effective in 2017; additional2017. Additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfurlow-sulfur coal, operates two2 scrubbers at its Sioux energy center,Energy Center, and optimizes other existing air pollution control equipment. Ameren Missouri expects to incur additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costs are expected to be recovered from customers through the FAC or higher base rates.
CO2 Emissions Standards
In 2015, the EPA issuedThe EPA’s Affordable Clean Energy Rule repealed the Clean Power Plan which would have established CO2 emissions standards applicable to existing power plants. The United States Supreme Court stayed the rule in February 2016, pending various legal challenges. In August 2018, the EPA proposed to repeal and replace the Clean Power Planreplaced it with a proposed new rule known as the Affordable Clean Energy Rule, which establishesthat had established emission guidelines for states to follow in developing plans to limit CO2 emissions from power plants. The EPA proposes to useand identified certain efficiency measures as the best system of emission reduction for coal-fired power plants. The EPA is expected to finalizeelectric generating units. In January 2021, the United States Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy rule inRule, and ruled that the first halfEPA had the discretion to consider emission reduction measures that include efficiency measures and generation shifting to lower carbon emissions. Additional litigation including reconsideration by the entire United States Court of 2019. WeAppeals for the District of Columbia Circuit or an appeal to the United States Supreme Court is possible. Regardless of the outcome of such potential legal challenges, the EPA is likely to develop new regulations to address carbon emissions from coal and natural gas electric generating units, which could take years to finalize. At this time, Ameren Missouri cannot predict the outcome of EPA’s rulemaking or the outcome of legal challenges related toor future rulemakings. As such, rulemaking.the impact on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri is uncertain.
NSR and Clean Air Act Litigation
In January 2011, the 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. The complaint, as amended in October 2013, allegedMissouri alleging that in performing projects at its coal-fired Rush Island coal-fired energy centerEnergy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In the first phase, in January 2017, the district court issued a liability ruling and, in September 2019, entered a final order that required Ameren Missouri to install a flue gas desulfurization system at the projects violated provisions ofRush Island Energy Center and a dry sorbent injection system at the Clean Air Act andLabadie Energy Center. There were no fines in the order. In October 2019, Ameren Missouri law. In the second phase,appealed the district court will determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. Hearings on remedy-related issues are scheduled for April 2019. At the conclusion of both phases of the litigation, Ameren Missouri intends to appeal the liabilitycourt’s ruling to the United States Court of Appeals for the Eighth Circuit. The district court has stayed implementation of
the majority of the requirements of its order while the case is under appeal. Ameren Missouri believes that the district court both misinterpreted and misapplied the law in its ruling. In December 2020, the court of appeals heard oral arguments presented by the parties. Ameren Missouri is unable to predict the ultimate resolution of this matter. The court is under no deadline to issue a ruling in this case; however, Ameren Missouri expects a ruling during 2021.
The ultimate resolution of this matter could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Among other things and subject to economic and regulatory considerations, resolution of this matter could result in increased capital expenditures for the installation of air pollution control equipment, as well as increased operations and maintenance expenses. WeBased upon engineering studies from October 2019, capital expenditures to comply with the district court’s order for installation of a flue gas desulfurization system at the Rush Island Energy Center are unableestimated at approximately $1 billion. Further, the flue gas desulfurization system would result in additional operation and maintenance expenses of $30 million to predict$50 million annually for the ultimate resolutionlife of this matterthe energy center. Engineering studies required to develop estimated capital expenditures and estimated additional operation and maintenance expenses for the Labadie Energy Center to comply with the district court’s order will not be undertaken while the case is under appeal. As a result of the district court’s stay, Ameren Missouri does not expect to make significant capital expenditures or incur operations and maintenance expenses related to the costs that might be incurred.
district court’s order while the case is under appeal.
Clean Water Act
In July 2018, the United States Court of Appeals for the Second Circuit upheld theThe EPA’s Section 316(b) Rule applicablerequires power plant operators to evaluate cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and planidentify measures for reducing the number of aquatic organisms impinged on a power plant’s cooling water intake screens or entrained through the plant’s cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. TheRequirements of the rule will beare being implemented by Ameren Missouri duringthrough the permit renewal process of each energy center’s water discharge permit, which is expected to be completed by 2023.
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, that are based on the effectiveness of available control technology. The EPA’s 2015 rule prohibits effluent discharges of certain waste streams, and imposes more stringent limitations on certain water discharges from power plants. In September 2017,To meet the EPA published a rule that postponedrequirements of the compliance dates by two years for the limitations applicable to two specific waste streams so that it could potentially revise those standards.guidelines, Ameren Missouri is in the processinstalled dry ash handling systems and completed construction of constructing wastewater treatment facilities that meet the limitations in these guidelines at three3 of its 4 coal-fired energy centers.centers in 2020. The Meramec Energy Center, which is the fourth coal-fired energy center and is scheduled to close permanently in 2022, will not have new wastewater and dry ash handling systems. Estimated capital expenditures to complete these projects are included in the CCR management compliance plan, discussed below.
CCR Management
In 2015, the EPA issued theThe EPA’s CCR rule which established regulations regardingestablishes requirements for the management and disposal of CCR from coal-fired energy centers. These regulations affect CCR disposalpower plants and handling costswill result in the closure of surface impoundments at Ameren Missouri’s energy centers. They require closureAmeren Missouri is in the process of closing surface impoundments if performance criteria relatingat 3 facilities, and is scheduled to groundwater impacts and location restrictions are not achieved. In July 2018,complete the last of such closures at all of its energy centers in 2023. While the EPA has issued a series of revisions to the CCR rule, that extended certain compliance deadlines and indicated that additionalnone of those revisions or proposals is expected to the CCR rule are likely.materially impact our closure schedule. Ameren and Ameren Missouri have AROs of $135$111 million recorded on their respective balance sheets as of December 31, 2018,2020, associated with CCR storage facilities that reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2019 and 2023. The recent EPA revisions do not affect Ameren Missouri’s closure schedule.facilities. Ameren Missouri estimates it will need to make total capital expenditures of $150$75 million to $200$100 million from 20192021 through 20232025 to implement its CCR management compliance plan, which includes installation of dry ash handling systems, waste waterwastewater treatment facilities, and groundwater monitoring equipment.
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. Ameren Missouri and Ameren Illinois have each been identified by federal or state governments as a potentially responsible party at several contaminated sites.
As of December 31, 2018,2020, Ameren Illinois had investigated andhas remediated the majority of the 44 former MGP sites in Illinois it owned or for which it was otherwise responsible. Ameren Illinois estimates it could substantially conclude remediation efforts at itsthe remaining sites by 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders. Costs are subject to annual prudence review by the ICC. As of December 31, 2018,2020, Ameren Illinois estimated the remaining obligation related to these former MGP sites at $150$94 million to $212$157 million. Ameren and Ameren Illinois recorded a liability of $150$94 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.
The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the ultimate 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.
Ameren Missouri participated in the investigation
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 practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.
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, 2020and2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | December 31, 2019 |
| Ameren | Ameren
Missouri | Ameren
Illinois | | | Ameren | Ameren
Missouri | Ameren
Illinois |
| Cash and cash equivalents | $ | 139 | | $ | 136 | | $ | 0 | | | | $ | 16 | | $ | 9 | | $ | 0 | |
| Restricted cash included in “Other current assets” | 17 | | 5 | | 6 | | | | 14 | | 4 | | 5 | |
| Restricted cash included in “Other assets” | 141 | | 0 | | 141 | | | | 120 | | 0 | | 120 | |
| Restricted cash included in “Nuclear decommissioning trust fund” | 4 | | 4 | | 0 | | | | 26 | | 26 | | 0 | |
| Total cash, cash equivalents, and restricted cash | $ | 301 | | $ | 145 | | $ | 147 | | | | $ | 176 | | $ | 39 | | $ | 125 | |
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 that are 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, 2020 and 2019, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $28 million and $32 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, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | December 31, 2019 |
| Ameren Missouri | Ameren Illinois(a) | Ameren | | | Ameren Missouri | Ameren Illinois(a) | Ameren |
| Beginning of period | $ | 7 | | $ | 10 | | $ | 17 | | | | $ | 7 | | $ | 11 | | $ | 18 | |
| Bad debt expense | 15 | | 33 | | 48 | | | | 9 | | 21 | | 30 | |
| | | | | | | | |
| Net write-offs | (6) | | (9) | | (15) | | | | (9) | | (22) | | (31) | |
| End of period | $ | 16 | | $ | 34 | | $ | 50 | | | | $ | 7 | | $ | 10 | | $ | 17 | |
(a)Ameren Illinois has riders 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. In 2020, the rider for electric distribution allows for recovery of bad debt expense recognized under GAAP. See Note 2 – Rate and Regulatory Matters for additional information.
Net write-offs decreased for the year ended December 31, 2020 due to the temporary suspension of disconnecting customers for nonpayment. See Note 2 – Rate and Regulatory Matters for additional information.
Inventories
The following table presents the components of inventories for each of the Ameren Companies at December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | December 31, 2019 |
| Ameren
Missouri | Ameren
Illinois | Ameren | | | Ameren
Missouri | Ameren
Illinois | Ameren |
Fuel(a) | $ | 115 | | $ | 0 | | $ | 115 | | | | $ | 126 | | $ | 0 | | $ | 126 | |
| Natural gas stored underground | 5 | | 52 | | 57 | | | | 6 | | 57 | | 63 | |
| Materials, supplies, and other | 266 | | 83 | | 349 | | | | 241 | | 64 | | 305 | |
| Total inventories | $ | 386 | | $ | 135 | | $ | 521 | | | | $ | 373 | | $ | 121 | | $ | 494 | |
(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, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | | December 31, 2019 |
| Ameren
Missouri | | Ameren
Illinois | | | | Ameren | | | | Ameren
Missouri | | Ameren
Illinois | | Ameren | |
| Beginning balance at January 1 | $ | 687 | |
| $ | 4 | | | | (a) | $ | 691 | | (b) | | | $ | 646 | | | $ | 4 | | | $ | 650 | | |
| Liabilities incurred | 36 | | (c) | 0 | | | | | 36 | | (c) | | | 0 | | | 0 | | | 0 | | |
| Liabilities settled | (58) | | | 0 | | | | | (58) | | | | | (20) | | | 0 | | | (20) | | |
Accretion(d) | 29 | | | 1 | | | | | 30 | | | | | 28 | | | 0 | | | 28 | | |
| Change in estimates | 57 | | (e) | 0 | | | | | 57 | | (e) | | | 33 | | (f) | 0 | | | 33 | | (f) |
| Ending balance at December 31 | $ | 751 | | (g) | $ | 5 | | | | (a) | $ | 756 | | (b), (g) | | | $ | 687 | |
| $ | 4 | | (a) | $ | 691 | | (b) |
(a)Included in “Other deferred credits and liabilities” on the balance sheet.
(b)Balance included $60 million and $53 million in “Other current liabilities” on the balance sheet as of both December 31, 2020 and 2019, respectively.
(c)In December 2020, Ameren Missouri recorded an ARO related to the decommissioning for the High Prairie Renewable Energy Center.
(d)Accretion expense attributable to Ameren Missouri and Ameren Illinois was recorded as a decrease to regulatory liabilities and an increase to regulatory assets, respectively.
(e)Ameren Missouri changed its fair value estimate primarily due to an update to the decommissioning of the Callaway Energy Center to reflect the cost study and funding analysis filed with the MoPSC in November 2020 and an increase in the cost estimate for closure of certain CCR storage facilities.
(f)Ameren Missouri changed its fair value estimate primarily due to an increase in the cost estimate for closure of certain CCR storage facilities.
(g)The balance as of December 31, 2020, includes an ARO related to the decommissioning of the Callaway Enter Center of $549 million.
Noncontrolling Interests
As of December 31, 2020 and 2019, Ameren’s noncontrolling interests included the preferred stock of Ameren Missouri and Ameren Illinois.
Deferred Compensation
As of December 31, 2020, and 2019, “Other current liabilities” and “Other deferred credits and liabilities” on Ameren’s balance sheet included deferred compensation obligations of $90 million and $86 million, respectively, recorded at the present value of future benefits to be paid.
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, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | |
| Ameren Missouri | $ | 139 | | | $ | 147 | | | $ | 164 | | |
| Ameren Illinois | 115 | | | 117 | | | 118 | | |
| Ameren | $ | 254 | | | $ | 264 | | | $ | 282 | | |
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 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | |
| Average rate: | | | | | | |
| Ameren Missouri | 5 | % | | 6 | % | | 7 | % | |
| Ameren Illinois | 5 | % | | 5 | % | | 5 | % | |
| Ameren: | | | | | | |
| Allowance for equity funds used during construction | $ | 32 | | | $ | 28 | | | $ | 36 | | |
| Allowance for borrowed funds used during construction | 16 | | | 20 | | | 21 | | |
| Total Ameren | $ | 48 | | | $ | 48 | | | $ | 57 | | |
| Ameren Missouri: | | | | | | |
| Allowance for equity funds used during construction | $ | 19 | | | $ | 19 | | | $ | 27 | | |
| Allowance for borrowed funds used during construction | 10 | | | 12 | | | 14 | | |
| Total Ameren Missouri | $ | 29 | | | $ | 31 | | | $ | 41 | | |
| Ameren Illinois: | | | | | | |
| Allowance for equity funds used during construction | $ | 13 | | | $ | 9 | | | $ | 9 | | |
| Allowance for borrowed funds used during construction | 6 | | | 8 | | | 7 | | |
| Total Ameren Illinois | $ | 19 | | | $ | 17 | | | $ | 16 | | |
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 the forward sale agreement 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 the forward sale agreement, 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, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| | | | | |
| | | | | |
| Weighted-average Common Shares Outstanding – Basic | 247.0 | | | 245.6 | | | 243.8 | |
| Assumed settlement of performance share units and restricted stock units | 1.2 | | | 1.4 | | | 2.0 | |
| Dilutive effect of forward sale agreement | 0.5 | | | 0.1 | | | 0 | |
Weighted-average Common Shares Outstanding – Diluted(a) | 248.7 | | | 247.1 | | | 245.8 | |
| | | | | |
| | | | | |
| | | | | |
(a)There were 0 potentially dilutive securities excluded from the earnings per diluted share calculations for the years ended December 31, 2020, 2019, and 2018.
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, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 | | December 31, 2018 |
| Ameren | Ameren
Missouri | | Ameren
Illinois | | Ameren | Ameren
Missouri | Ameren
Illinois | | Ameren | Ameren
Missouri | Ameren
Illinois |
| Investing | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Accrued capital expenditures | $ | 400 | | $ | 183 | | | $ | 218 | | | $ | 333 | | $ | 140 | | $ | 163 | | | $ | 272 | | $ | 121 | | $ | 138 | |
| Accrued nuclear fuel expenditures | 0 | | 0 | | | 0 | | | 19 | | 19 | | 0 | | | 20 | | 20 | | 0 | |
| Accrued wind generation expenditures | 46 | | 46 | | | 0 | | | 0 | | 0 | | 0 | | | 0 | | 0 | | 0 | |
Net realized and unrealized gain (loss) – nuclear decommissioning trust fund | 116 | | 116 | | | 0 | | | 143 | | 143 | | 0 | | | (38) | | (38) | | 0 | |
Exchange of bond investments for the extinguishment of senior unsecured notes(a) | 0 | | 0 | | | 0 | | | 17 | | 0 | | 17 | | | 0 | | 0 | | 0 | |
| Financing | | | | | | | | | | | | |
| Issuance of common stock for stock-based compensation | $ | 38 | | $ | 0 | | | $ | 0 | | | $ | 54 | | $ | 0 | | $ | 0 | | | $ | 35 | | $ | 0 | | $ | 0 | |
Exchange of bond investments for the extinguishment of senior unsecured notes(a) | 0 | | 0 | | | 0 | | | (17) | | 0 | | (17) | | | 0 | | 0 | | 0 | |
| | | | | | | | | | | | |
(a)See Note 5 – Long-term Debt and Equity Financings for additional information.
NOTE 15 16 – SEGMENT INFORMATION
Ameren has four4 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 one1 segment. Ameren Illinois has three3 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.
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, 2018, 2017,2020, 2019, and 2016.2018. 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 | | |
| 2020 | | | | | | | | | | | | | | | |
| External revenues | $ | 3,069 | | | $ | 1,496 | | | $ | 760 | | | $ | 469 | | | $ | 0 | | | $ | 0 | | | $ | 5,794 | | | |
| Intersegment revenues | 40 | | | 2 | | | 0 | | | 54 | | | 0 | | | (96) | | | 0 | | | |
| Depreciation and amortization | 604 | | | 288 | | | 81 | | | 98 | | | 4 | | | 0 | | | 1,075 | | | |
| Interest income | 26 | | | 2 | | | 0 | | | 1 | | | 4 | | | (4) | | | 29 | | | |
| Interest charges | 190 | | | 72 | | | 41 | | | 78 | | (a) | 42 | | | (4) | | | 419 | | | |
| Income taxes (benefit) | 34 | | | 42 | | | 36 | | | 78 | | | (35) | | | 0 | | | 155 | | | |
| Net income (loss) attributable to Ameren common shareholders | 436 | | | 143 | | | 99 | | | 216 | | | (23) | | | 0 | | | 871 | | | |
| Capital expenditures | 1,666 | | (b) | 543 | | | 301 | | | 716 | | | 5 | | | 2 | | | 3,233 | | (b) | |
| | | | | | | | | | | | | | | |
| 2019 | | | | | | | | | | | | | | | |
| External revenues | $ | 3,212 | | | $ | 1,487 | | | $ | 791 | | | $ | 401 | | | $ | 0 | | | $ | 0 | | | $ | 5,891 | | | |
| Intersegment revenues | 31 | | | 17 | | | 6 | | | 63 | | | 0 | | | (98) | | | 19 | | (c) | |
| Depreciation and amortization | 556 | | | 273 | | | 78 | | | 84 | | | 4 | | | 0 | | | 995 | | | |
| Interest income | 26 | | | 6 | | | 0 | | | 1 | | | 5 | | | (5) | | | 33 | | | |
| Interest charges | 178 | | | 71 | | | 38 | | | 74 | | (a) | 25 | | | (5) | | | 381 | | | |
| Income taxes (benefit) | 68 | | | 45 | | | 30 | | | 64 | | | (25) | | | 0 | | | 182 | | | |
| Net income (loss) attributable to Ameren common shareholders | 426 | | | 146 | | | 84 | | | 185 | | | (13) | | | 0 | | | 828 | | | |
| Capital expenditures | 1,076 | | | 518 | | | 318 | | | 528 | | | 3 | | | (32) | | (d) | 2,411 | | | |
| | | | | | | | | | | | | | | |
| 2018 | | | | | | | | | | | | | | | |
| External revenues | $ | 3,555 | | | $ | 1,544 | | | $ | 814 | | | $ | 378 | | | $ | 0 | | | $ | 0 | | | $ | 6,291 | | | |
| Intersegment revenues | 34 | | | 3 | | | 1 | | | 55 | | | 0 | | | (93) | | | 0 | | | |
| Depreciation and amortization | 550 | | | 259 | | | 65 | | | 77 | | | 4 | | | 0 | | | 955 | | | |
| Interest income | 28 | | | 6 | | | 0 | | | 0 | | | 4 | | | (5) | | | 33 | | | |
| Interest charges | 200 | | | 73 | | | 38 | | | 75 | | (a) | 19 | | | (4) | | | 401 | | | |
| Income taxes (benefit) | 124 | | | 41 | | | 25 | | | 56 | | | (9) | | | 0 | | | 237 | | | |
| Net income (loss) attributable to Ameren common shareholders | 478 | | | 136 | | | 70 | | | 164 | | | (33) | | | 0 | | | 815 | | | |
| Capital expenditures | 914 | | | 503 | | | 311 | | | 562 | | | 5 | | | (9) | | | 2,286 | | | |
| | | | | | | | | | | | | | | |
(a)Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent).
(b)Includes $564 million at Ameren and Ameren Missouri for the acquisition of the High Prairie Renewable Energy Center for the year ended December 31, 2020.
(c)Intersegment revenues at Ameren include $14 million and $5 million of revenue from Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. Under authoritative accounting guidance for rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation. See Note 13 – Related-party Transactions for additional information.
(d)Intersegment capital expenditure eliminations include $24 million of eliminations for the year ended December 31, 2019, for a software licensing agreement between Ameren Illinois and Ameren Missouri. See Note 13 – Related-party Transactions for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren |
| 2018 | | | | | | | | | | | | | |
| External revenues | $ | 3,555 |
| | $ | 1,544 |
| | $ | 814 |
| | $ | 378 |
| | $ | — |
| | $ | — |
| | $ | 6,291 |
|
| Intersegment revenues | 34 |
| | 3 |
| | 1 |
| | 55 |
| (a) | — |
| | (93 | ) | | — |
|
| Depreciation and amortization | 550 |
| | 259 |
| | 65 |
| | 77 |
| | 4 |
| | — |
| | 955 |
|
| Interest income | 28 |
| | 6 |
| | — |
| | — |
| | 4 |
| | (5 | ) | | 33 |
|
| Interest charges | 200 |
| | 73 |
| | 38 |
| | 75 |
| (b) | 19 |
| | (4 | ) | | 401 |
|
| Income taxes | 124 |
| | 41 |
| | 25 |
| | 56 |
| | (9 | ) | | — |
| | 237 |
|
| Net income (loss) attributable to Ameren common shareholders | 478 |
| | 136 |
| | 70 |
| | 164 |
| | (33 | ) | | — |
| | 815 |
|
| Capital expenditures | 914 |
| | 503 |
| | 311 |
| | 562 |
| | 5 |
| | (9 | ) | | 2,286 |
|
| 2017 | | | | | | | | | | | | | |
| External revenues | $ | 3,488 |
| | $ | 1,564 |
| | $ | 742 |
| | $ | 382 |
| | $ | (2 | ) | | $ | — |
| | $ | 6,174 |
|
| Intersegment revenues | 49 |
| | 4 |
| | 1 |
| | 44 |
| (a) | — |
| | (98 | ) | | — |
|
| Depreciation and amortization | 533 |
| | 239 |
| | 59 |
| | 60 |
| | 5 |
| | — |
| | 896 |
|
| Interest income | 27 |
| | 7 |
| | — |
| | — |
| | 11 |
| | (11 | ) | | 34 |
|
| Interest charges | 207 |
| | 73 |
| | 36 |
| | 67 |
| (b) | 19 |
| | (11 | ) | | 391 |
|
| Income taxes | 254 |
| | 83 |
| | 36 |
| | 90 |
| | 113 |
| | — |
| | 576 |
|
| Net income (loss) attributable to Ameren common shareholders | 323 |
| | 131 |
| | 60 |
| | 140 |
| | (131 | ) | | — |
| | 523 |
|
| Capital expenditures | 773 |
| | 476 |
| | 245 |
| | 644 |
| | 1 |
| | (7 | ) | | 2,132 |
|
| 2016 | | | | | | | | | | | | | |
| External revenues | $ | 3,470 |
| | $ | 1,544 |
| | $ | 753 |
| | $ | 309 |
| | $ | — |
| | $ | — |
| | $ | 6,076 |
|
| Intersegment revenues | 54 |
| | 4 |
| | 1 |
| | 46 |
| (a) | — |
| | (105 | ) | | — |
|
| Depreciation and amortization | 514 |
| | 226 |
| | 55 |
| | 43 |
| | 7 |
| | — |
| | 845 |
|
| Interest income | 28 |
| | 11 |
| | — |
| | 1 |
| | 11 |
| | (11 | ) | | 40 |
|
| Interest charges | 211 |
| | 72 |
| | 34 |
| | 58 |
| (b) | 18 |
| | (11 | ) | | 382 |
|
| Income taxes | 216 |
| | 78 |
| | 39 |
| | 74 |
| | (25 | ) | | — |
| | 382 |
|
| Net income (loss) attributable to Ameren common shareholders | 357 |
| | 126 |
| | 59 |
| | 117 |
| | (6 | ) | | — |
| | 653 |
|
| Capital expenditures | 738 |
| | 470 |
| | 181 |
| | 689 |
| | 4 |
| | (6 | ) | | 2,076 |
|
| |
(a) | Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
| |
(b) | Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent). |
Ameren Illinois
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| 2020 | | | | | | | | | | |
| External revenues | $ | 1,498 | | | $ | 760 | | | $ | 277 | | | $ | 0 | | | $ | 2,535 | | |
| Intersegment revenues | 0 | | | 0 | | | 52 | | | (52) | | | 0 | | |
| Depreciation and amortization | 288 | | | 81 | | | 65 | | | 0 | | | 434 | | |
| Interest income | 2 | | | 0 | | | 1 | | | 0 | | | 3 | | |
| Interest charges | 72 | | | 41 | | | 42 | | | 0 | | | 155 | | |
| Income taxes | 42 | | | 36 | | | 46 | | | 0 | | | 124 | | |
| Net income available to common shareholder | 143 | | | 99 | | | 137 | | | 0 | | | 379 | | |
| Capital expenditures | 543 | | | 301 | | | 603 | | | 0 | | | 1,447 | | |
| | | | | | | | | | |
| 2019 | | | | | | | | | | |
| External revenues | $ | 1,504 | | | $ | 797 | | | $ | 226 | | | $ | 0 | | | $ | 2,527 | | |
| Intersegment revenues | 0 | | | 0 | | | 62 | | | (62) | | | 0 | | |
| Depreciation and amortization | 273 | | | 78 | | | 55 | | | 0 | | | 406 | | |
| Interest income | 6 | | | 0 | | | 0 | | | 0 | | | 6 | | |
| Interest charges | 71 | | | 38 | | | 38 | | | 0 | | | 147 | | |
| Income taxes | 45 | | | 30 | | | 35 | | | 0 | | | 110 | | |
| Net income available to common shareholder | 146 | | | 84 | | | 113 | | | 0 | | | 343 | | |
| Capital expenditures | 518 | | | 318 | | | 372 | | | 0 | | | 1,208 | | |
| | | | | | | | | | |
| 2018 | | | | | | | | | | |
| External revenues | $ | 1,547 | | | $ | 815 | | | $ | 214 | | | $ | 0 | | | $ | 2,576 | | |
| Intersegment revenues | 0 | | | 0 | | | 53 | | | (53) | | | 0 | | |
| Depreciation and amortization | 259 | | | 65 | | | 50 | | | 0 | | | 374 | | |
| Interest income | 6 | | | 0 | | | 0 | | | 0 | | | 6 | | |
| Interest charges | 73 | | | 38 | | | 38 | | | 0 | | | 149 | | |
| Income taxes | 41 | | | 25 | | | 32 | | | 0 | | | 98 | | |
| Net income available to common shareholder | 136 | | | 70 | | | 98 | | | 0 | | | 304 | | |
| Capital expenditures | 503 | | | 311 | | | 444 | | | 0 | | | 1,258 | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois |
| 2018 | | | | | | | | | |
| External revenues | $ | 1,547 |
| | $ | 815 |
| | $ | 214 |
| | $ | — |
| | $ | 2,576 |
|
| Intersegment revenues | — |
| | — |
| | 53 |
| (a) | (53 | ) | | — |
|
| Depreciation and amortization | 259 |
| | 65 |
| | 50 |
| | — |
| | 374 |
|
| Interest income | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
| Interest charges | 73 |
| | 38 |
| | 38 |
| | — |
| | 149 |
|
| Income taxes | 41 |
| | 25 |
| | 32 |
| | — |
| | 98 |
|
| Net income available to common shareholder | 136 |
| | 70 |
| | 98 |
| | — |
| | 304 |
|
| Capital expenditures | 503 |
| | 311 |
| | 444 |
| | — |
| | 1,258 |
|
| 2017 | | | | | | | | | |
| External revenues | $ | 1,568 |
| | $ | 743 |
| | $ | 216 |
| | $ | — |
| | $ | 2,527 |
|
| Intersegment revenues | — |
| | — |
| | 42 |
| (a) | (42 | ) | | — |
|
| Depreciation and amortization | 239 |
| | 59 |
| | 43 |
| | — |
| | 341 |
|
| Interest income | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
| Interest charges | 73 |
| | 36 |
| | 35 |
| | — |
| | 144 |
|
| Income taxes | 83 |
| | 36 |
| | 47 |
| | — |
| | 166 |
|
| Net income available to common shareholder | 131 |
| | 60 |
| | 77 |
| | ��� |
| | 268 |
|
| Capital expenditures | 476 |
| | 245 |
| | 355 |
| | — |
| | 1,076 |
|
| 2016 | | | | | | | | | |
| External revenues | $ | 1,548 |
| | $ | 754 |
| | $ | 187 |
| | $ | — |
| | $ | 2,489 |
|
| Intersegment revenues | — |
| | — |
| | 45 |
| (a) | (45 | ) | | — |
|
| Depreciation and amortization | 226 |
| | 55 |
| | 38 |
| | — |
| | 319 |
|
| Interest income | 11 |
| | — |
| | 1 |
| | — |
| | 12 |
|
| Interest charges | 72 |
| | 34 |
| | 34 |
| | — |
| | 140 |
|
| Income taxes | 78 |
| | 39 |
| | 41 |
| | — |
| | 158 |
|
| Net income available to common shareholder | 126 |
| | 59 |
| | 67 |
| | — |
| | 252 |
|
| Capital expenditures | 470 |
| | 181 |
| | 273 |
| | — |
| | 924 |
|
| |
(a) | Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the years ended December 31, 2018, 2017,2020, 2019, and 2016.2018. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.
Ameren
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | | | Intersegment Eliminations | | Ameren | |
| 2020 | | | | | | | | | | | | | | |
| Residential | $ | 1,373 | | | $ | 867 | | | $ | 0 | | | $ | 0 | | | | | $ | 0 | | | $ | 2,240 | | |
| Commercial | 1,025 | | | 486 | | | 0 | | | 0 | | | | | 0 | | | 1,511 | | |
| Industrial | 261 | | | 124 | | | 0 | | | 0 | | | | | 0 | | | 385 | | |
| Other | 325 | | | 21 | | | 0 | | | 523 | | | | | (94) | | | 775 | | |
| Total electric revenues | $ | 2,984 | | | $ | 1,498 | | | $ | 0 | | | $ | 523 | | | | | $ | (94) | | | $ | 4,911 | | |
| Residential | $ | 76 | | | $ | 0 | | | $ | 541 | | | $ | 0 | | | | | $ | 0 | | | $ | 617 | | |
| Commercial | 29 | | | 0 | | | 136 | | | 0 | | | | | 0 | | | 165 | | |
| Industrial | 4 | | | 0 | | | 14 | | | 0 | | | | | 0 | | | 18 | | |
| Other | 16 | | | 0 | | | 69 | | | 0 | | | | | (2) | | | 83 | | |
| Total gas revenues | $ | 125 | | | $ | 0 | | | $ | 760 | | | $ | 0 | | | | | $ | (2) | | | $ | 883 | | |
Total revenues(a) | $ | 3,109 | | | $ | 1,498 | | | $ | 760 | | | $ | 523 | | | | | $ | (96) | | | $ | 5,794 | | |
| 2019 | | | | | | | | | | | | | | |
| Residential | $ | 1,403 | | | $ | 848 | | | $ | 0 | | | $ | 0 | | | | | $ | 0 | | | $ | 2,251 | | |
| Commercial | 1,157 | | | 497 | | | 0 | | | 0 | | | | | 0 | | | 1,654 | | |
| Industrial | 278 | | | 127 | | | 0 | | | 0 | | | | | 0 | | | 405 | | |
| Other | 271 | | | 32 | | (b) | 0 | | | 464 | | | | | (96) | | | 671 | | |
| Total electric revenues | $ | 3,109 | | | $ | 1,504 | | | $ | 0 | | | $ | 464 | | | | | $ | (96) | | | $ | 4,981 | | |
| Residential | $ | 81 | | | $ | 0 | | | $ | 570 | | | $ | 0 | | | | | $ | 0 | | | $ | 651 | | |
| Commercial | 34 | | | 0 | | | 154 | | | 0 | | | | | 0 | | | 188 | | |
| Industrial | 4 | | | 0 | | | 13 | | | 0 | | | | | 0 | | | 17 | | |
| Other | 15 | | | 0 | | | 60 | | (b) | 0 | | | | | (2) | | | 73 | | |
| Total gas revenues | $ | 134 | | | $ | 0 | | | $ | 797 | | | $ | 0 | | | | | $ | (2) | | | $ | 929 | | |
Total revenues(a) | $ | 3,243 | | | $ | 1,504 | | | $ | 797 | | | $ | 464 | | | | | $ | (98) | | | $ | 5,910 | | |
| 2018 | | | | | | | | | | | | | | |
| Residential | $ | 1,560 | | | $ | 867 | | | $ | 0 | | | $ | 0 | | | | | $ | 0 | | | $ | 2,427 | | |
| Commercial | 1,271 | | | 511 | | | 0 | | | 0 | | | | | 0 | | | 1,782 | | |
| Industrial | 312 | | | 130 | | | 0 | | | 0 | | | | | 0 | | | 442 | | |
| Other | 308 | | (c) | 39 | | | 0 | | | 433 | | | | | (92) | | | 688 | | (c) |
| Total electric revenues | $ | 3,451 | | | $ | 1,547 | | | $ | 0 | | | $ | 433 | | | | | $ | (92) | | | $ | 5,339 | | |
| Residential | $ | 90 | | | $ | 0 | | | $ | 581 | | | $ | 0 | | | | | $ | 0 | | | $ | 671 | | |
| Commercial | 37 | | | 0 | | | 159 | | | 0 | | | | | 0 | | | 196 | | |
| Industrial | 4 | | | 0 | | | 17 | | | 0 | | | | | 0 | | | 21 | | |
| Other | 7 | | | 0 | | | 58 | | | 0 | | | | | (1) | | | 64 | | |
| Total gas revenues | $ | 138 | | | $ | 0 | | | $ | 815 | | | $ | 0 | | | | | $ | (1) | | | $ | 952 | | |
Total revenues(a) | $ | 3,589 | | | $ | 1,547 | | | $ | 815 | | | $ | 433 | | | | | $ | (93) | | | $ | 6,291 | | |
(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, 2020, 2019, and 2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren | |
| 2018 | | | | | | | | | | | | | | |
| Residential | $ | 1,560 |
| | $ | 867 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,427 |
| |
| Commercial | 1,271 |
| | 511 |
| | — |
| | — |
| | — |
| | — |
| | 1,782 |
| |
| Industrial | 312 |
| | 130 |
| | — |
| | — |
| | — |
| | — |
| | 442 |
| |
| Other | 308 |
| (a) | 39 |
| | — |
| | 433 |
| | — |
| | (92 | ) | | 688 |
| (a) |
| Total electric revenues | $ | 3,451 |
| | $ | 1,547 |
| | $ | — |
| | $ | 433 |
| | $ | — |
| | $ | (92 | ) | | $ | 5,339 |
| |
| Residential | $ | 90 |
| | $ | — |
| | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 671 |
| |
| Commercial | 37 |
| | — |
| | 159 |
| | — |
| | — |
| | — |
| | 196 |
| |
| Industrial | 4 |
| | — |
| | 17 |
| | — |
| | — |
| | — |
| | 21 |
| |
| Other | 7 |
| | — |
| | 58 |
| | — |
| | — |
| | (1 | ) | | 64 |
| |
| Total gas revenues | $ | 138 |
| | $ | — |
| | $ | 815 |
| | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | 952 |
| |
Total revenues(b) | $ | 3,589 |
| | $ | 1,547 |
| | $ | 815 |
| | $ | 433 |
| | $ | — |
| | $ | (93 | ) | | $ | 6,291 |
| |
| 2017 | | | | | | | | | | | | | | |
| Residential | $ | 1,417 |
| | $ | 870 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,287 |
| |
| Commercial | 1,208 |
| | 527 |
| | — |
| | — |
| | — |
| | — |
| | 1,735 |
| |
| Industrial | 305 |
| | 113 |
| | — |
| | — |
| | — |
| | — |
| | 418 |
| |
| Other | 481 |
| | 58 |
| | — |
| | 426 |
| | (2 | ) | | (96 | ) | | 867 |
| |
| Total electric revenues | $ | 3,411 |
| | $ | 1,568 |
| | $ | — |
| | $ | 426 |
| | $ | (2 | ) | | $ | (96 | ) | | $ | 5,307 |
| |
| Residential | $ | 77 |
| | $ | — |
| | $ | 531 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 608 |
| |
| Commercial | 31 |
| | — |
| | 146 |
| | — |
| | — |
| | — |
| | 177 |
| |
| Industrial | 4 |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | 16 |
| |
| Other | 14 |
| | — |
| | 54 |
| | — |
| | — |
| | (2 | ) | | 66 |
| |
| Total gas revenues | $ | 126 |
| | $ | — |
| | $ | 743 |
| | $ | — |
| | $ | — |
| | $ | (2 | ) | | $ | 867 |
| |
Total revenues(b) | $ | 3,537 |
| | $ | 1,568 |
| | $ | 743 |
| | $ | 426 |
| | $ | (2 | ) | | $ | (98 | ) | | $ | 6,174 |
| |
| 2016 | | | | | | | | | | | | | | |
| Residential | $ | 1,422 |
| | $ | 895 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,317 |
| |
| Commercial | 1,224 |
| | 517 |
| | — |
| | — |
| | — |
| | — |
| | 1,741 |
| |
| Industrial | 315 |
| | 96 |
| | — |
| | — |
| | — |
| | — |
| | 411 |
| |
| Other | 435 |
| | 40 |
| | — |
| | 355 |
| | 1 |
| | (104 | ) | | 727 |
| |
| Total electric revenues | $ | 3,396 |
| | $ | 1,548 |
| | $ | — |
| | $ | 355 |
| | $ | 1 |
| | $ | (104 | ) | | $ | 5,196 |
| |
| Residential | $ | 77 |
| | $ | — |
| | $ | 530 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 607 |
| |
| Commercial | 30 |
| | — |
| | 153 |
| | — |
| | — |
| | — |
| | 183 |
| |
| Industrial | 4 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | 14 |
| |
| Other | 17 |
| | — |
| | 61 |
| | — |
| | — |
| | (2 | ) | | 76 |
| |
| Total gas revenues | $ | 128 |
| | $ | — |
| | $ | 754 |
| | $ | — |
| | $ | — |
| | $ | (2 | ) | | $ | 880 |
| |
Total revenues(b) | $ | 3,524 |
| | $ | 1,548 |
| | $ | 754 |
| | $ | 355 |
| | $ | 1 |
| | $ | (106 | ) | | $ | 6,076 |
| |
| |
(a) | Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information. |
| |
(b) | 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, 2018, 2017, and 2016: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Ameren |
| 2020 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (14) | | | $ | (20) | | | $ | 20 | | | $ | 50 | | | $ | 36 | |
| Other revenues not from contracts with customers | 25 | | | 8 | | | 2 | | | 1 | | | 36 | |
| 2019 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 35 | | | $ | (74) | | | $ | 0 | | | $ | (31) | | | $ | (70) | |
| Other revenues not from contracts with customers | 19 | | | 7 | | | 2 | | | 0 | | | 28 | |
| 2018 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (8) | | | $ | (3) | | | $ | (23) | | | $ | (25) | | | $ | (59) | |
| Other revenues not from contracts with customers | 24 | | | 16 | | | 2 | | | 0 | | | 42 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Ameren |
| 2018 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (8 | ) | | $ | (3 | ) | | $ | (23 | ) | | $ | (25 | ) | | $ | (59 | ) |
| Other revenues not from contracts with customers | 24 |
| | 16 |
| | 2 |
| | — |
| | 42 |
|
| 2017 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (28 | ) | | $ | (5 | ) | | $ | 5 |
| | $ | 13 |
| | $ | (15 | ) |
| Other revenues not from contracts with customers | 15 |
| | 6 |
| | 2 |
| | — |
| | 23 |
|
| 2016 | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 8 |
| | $ | (70 | ) | | $ | 11 |
| | $ | (1 | ) | | $ | (52 | ) |
| Other revenues not from contracts with customers | 16 |
| | 6 |
| | 2 |
| | — |
| | 24 |
|
(c)Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates to be refunded related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information.
Ameren Illinois
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| 2020 | | | | | | | | | | |
| Residential | $ | 867 | | | $ | 541 | | | $ | 0 | | | $ | 0 | | | $ | 1,408 | | |
| Commercial | 486 | | | 136 | | | 0 | | | 0 | | | 622 | | |
| Industrial | 124 | | | 14 | | | 0 | | | 0 | | | 138 | | |
| Other | 21 | | | 69 | | | 329 | | | (52) | | | 367 | | |
Total revenues(a) | $ | 1,498 | | | $ | 760 | | | $ | 329 | | | $ | (52) | | | $ | 2,535 | | |
| 2019 | | | | | | | | | | |
| Residential | $ | 848 | | | $ | 570 | | | $ | 0 | | | $ | 0 | | | $ | 1,418 | | |
| Commercial | 497 | | | 154 | | | 0 | | | 0 | | | 651 | | |
| Industrial | 127 | | | 13 | | | 0 | | | 0 | | | 140 | | |
| Other | 32 | | (b) | 60 | | (b) | 288 | | | (62) | | | 318 | | |
Total revenues(a) | $ | 1,504 | | | $ | 797 | | | $ | 288 | | | $ | (62) | | | $ | 2,527 | | |
| 2018 | | | | | | | | | | |
| Residential | $ | 867 | | | $ | 581 | | | $ | 0 | | | $ | 0 | | | $ | 1,448 | | |
| Commercial | 511 | | | 159 | | | 0 | | | 0 | | | 670 | | |
| Industrial | 130 | | | 17 | | | 0 | | | 0 | | | 147 | | |
| Other | 39 | | | 58 | | | 267 | | | (53) | | | 311 | | |
Total revenues(a) | $ | 1,547 | | | $ | 815 | | | $ | 267 | | | $ | (53) | | | $ | 2,576 | | |
(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, 2020, 2019, and 2018:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois |
| 2020 | | | | | | | |
| Revenues from alternative revenue programs | $ | (20) | | | $ | 20 | | | $ | 42 | | | $ | 42 | |
| Other revenues not from contracts with customers | 8 | | | 2 | | | 0 | | | 10 | |
| 2019 | | | | | | | |
| Revenues from alternative revenue programs | $ | (74) | | | $ | 0 | | | $ | (33) | | | $ | (107) | |
| Other revenues not from contracts with customers | 7 | | | 2 | | | 0 | | | 9 | |
| 2018 | | | | | | | |
| Revenues from alternative revenue programs | $ | (3) | | | $ | (23) | | | $ | (25) | | | $ | (51) | |
| Other revenues not from contracts with customers | 16 | | | 2 | | | 0 | | | 18 | |
(b)Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information.
|
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| 2018 | | | | | | | | | | |
| Residential | $ | 867 |
| | $ | 581 |
| | $ | — |
| | $ | — |
| | $ | 1,448 |
| |
| Commercial | 511 |
| | 159 |
| | — |
| | — |
| | 670 |
| |
| Industrial | 130 |
| | 17 |
| | — |
| | — |
| | 147 |
| |
| Other | 39 |
| | 58 |
| | 267 |
| | (53 | ) | | 311 |
| |
Total revenues(a) | $ | 1,547 |
| | $ | 815 |
| | $ | 267 |
| | $ | (53 | ) | | $ | 2,576 |
| |
| 2017 | | | | | | | | | | |
| Residential | $ | 870 |
| | $ | 531 |
| | $ | — |
| | $ | — |
| | $ | 1,401 |
| |
| Commercial | 527 |
| | 146 |
| | — |
| | — |
| | 673 |
| |
| Industrial | 113 |
| | 12 |
| | — |
| | — |
| | 125 |
| |
| Other | 58 |
| | 54 |
| | 258 |
| | (42 | ) | | 328 |
| |
Total revenues(a) | $ | 1,568 |
| | $ | 743 |
| | $ | 258 |
| | $ | (42 | ) | | $ | 2,527 |
| |
| 2016 | | | | | | | | | | |
| Residential | $ | 895 |
| | $ | 530 |
| | $ | — |
| | $ | — |
| | $ | 1,425 |
| |
| Commercial | 517 |
| | 153 |
| | — |
| | — |
| | 670 |
| |
| Industrial | 96 |
| | 10 |
| | — |
| | — |
| | 106 |
| |
| Other | 40 |
| | 61 |
| | 232 |
| | (45 | ) | | 288 |
| |
Total revenues(a) | $ | 1,548 |
| | $ | 754 |
| | $ | 232 |
| | $ | (45 | ) | | $ | 2,489 |
| |
| |
(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, 2018, 2017, and 2016: |
|
| | | | | | | | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois |
| 2018 | | | | | | | |
| Revenues from alternative revenue programs | $ | (3 | ) | | $ | (23 | ) | | $ | (25 | ) | | $ | (51 | ) |
| Other revenues not from contracts with customers | 16 |
| | 2 |
| | — |
| | 18 |
|
| 2017 | | | | | | | |
| Revenues from alternative revenue programs | $ | (5 | ) | | $ | 5 |
| | $ | 9 |
| | $ | 9 |
|
| Other revenues not from contracts with customers | 6 |
| | 2 |
| | — |
| | 8 |
|
| 2016 | | | | | | | |
| Revenues from alternative revenue programs | $ | (70 | ) | | $ | 11 |
| | $ | 2 |
| | $ | (57 | ) |
| Other revenues not from contracts with customers | 6 |
| | 2 |
| | — |
| | 8 |
|
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2018 | | | 2017 | |
| Quarter ended | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 |
| | June 30 |
| | September 30 | | December 31 | |
Operating revenues(a) | $ | 1,585 |
| | $ | 1,563 |
| | $ | 1,724 |
| | $ | 1,419 |
| | | $ | 1,515 |
| | $ | 1,537 |
| | $ | 1,723 |
| | $ | 1,399 |
| |
Operating income(a) | 273 |
| | 385 |
| | 533 |
| | 166 |
| | | 242 |
| | 387 |
| | 569 |
| | 212 |
| |
| Net income (loss) | 153 |
| | 240 |
| | 359 |
| | 69 |
| | | 104 |
| | 194 |
| | 290 |
| | (59 | ) | (b) |
| Net income (loss) attributable to Ameren common shareholders | $ | 151 |
| | $ | 239 |
| | $ | 357 |
| | $ | 68 |
| | | $ | 102 |
| | $ | 193 |
| | $ | 288 |
| | $ | (60 | ) | |
| Earnings (loss) per common share – basic | $ | 0.62 |
| | $ | 0.98 |
| | $ | 1.46 |
| | $ | 0.28 |
| | | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.19 |
| | $ | (0.24 | ) | |
Earnings (loss) per common share – diluted(c) | $ | 0.62 |
| | $ | 0.97 |
| | $ | 1.45 |
| | $ | 0.28 |
| | | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.18 |
| | $ | (0.24 | ) | |
| |
(a)
| 2017 amounts have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers and the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information. |
| |
(b) | Includes an increase to income tax expense of $154 million recorded in 2017 as a result of the TCJA. |
| |
(c) | The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is because of the effects of rounding and the changes in the number of weighted-average diluted shares outstanding each period. |
|
| | | | | | | | | | | | | | | | |
Ameren Missouri Quarter ended | | Operating Revenues(a) | | Operating Income(a) | | Net Income (Loss) | | Net Income (Loss) Available to Common Shareholder |
| March 31, 2018 | | $ | 792 |
| | $ | 90 |
| | $ | 39 |
| | $ | 38 |
|
| March 31, 2017 | | 791 |
| | 47 |
| | 6 |
| | 5 |
|
| June 30, 2018 | | 955 |
| | 258 |
| | 169 |
| | 168 |
|
| June 30, 2017 | | 934 |
| | 230 |
| | 121 |
| | 120 |
|
| September 30, 2018 | | 1,129 |
| | 394 |
| | 295 |
| | 294 |
|
| September 30, 2017 | | 1,116 |
| | 412 |
| | 235 |
| | 234 |
|
| December 31, 2018 | | 713 |
| | 7 |
| | (22 | ) | | (22 | ) |
| December 31, 2017 | | 696 |
| | 33 |
| | (36 | ) | (b) | (36 | ) |
| |
(a) | 2017 amounts have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers and the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information. |
| |
(b) | Includes an increase to income tax expense of $32 million recorded in 2017 as a result of the TCJA. |
|
| | | | | | | | | | | | | | | | |
Ameren Illinois Quarter ended | | Operating Revenues(a) | | Operating Income(a) | | Net Income | | Net Income Available to Common Shareholder |
| March 31, 2018 | | $ | 760 |
| | $ | 159 |
| | $ | 96 |
| | $ | 95 |
|
| March 31, 2017 | | 703 |
| | 169 |
| | 80 |
| | 79 |
|
| June 30, 2018 | | 578 |
| | 105 |
| | 63 |
| | 62 |
|
| June 30, 2017 | | 576 |
| | 128 |
| | 58 |
| | 57 |
|
| September 30, 2018 | | 564 |
| | 113 |
| | 63 |
| | 63 |
|
| September 30, 2017 | | 574 |
| | 124 |
| | 55 |
| | 55 |
|
| December 31, 2018 | | 674 |
| | 135 |
| | 85 |
| | 84 |
|
| December 31, 2017 | | 674 |
| | 148 |
| | 78 |
| | 77 |
|
| |
(a) | 2017 amounts have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers and the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information. |
| |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
| |
ITEM 9A. | CONTROLS AND PROCEDURES |
| |
(a) | Evaluation of Disclosure Controls and Procedures |
ITEM 9A.CONTROLS AND PROCEDURES
(a)Evaluation of Disclosure Controls and Procedures
As of December 31, 2018,2020, 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, 2018,2020, 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 |
(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, 2018.2020. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2018,2020, 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 |
(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 |
ITEM 9B.OTHER INFORMATION
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 20182020 that has not previously been reported onreported.
On February 19, 2021, the board of directors of Ameren Missouri amended and restated the bylaws of Ameren Missouri to delete a director residency requirement and to delete a requirement to provide notice to the Missouri Secretary of State upon a change in the number of directors. The bylaws were also amended to delete a provision that gave the board of directors the ability to require the treasurer or an SEC Form 8-K.assistant treasurer to post a bond for the discharge of his or her duties and to provide for certain other administrative clarifications.
On February 19, 2021, the board of directors of Ameren Illinois amended and restated the bylaws of Ameren Illinois to delete a provision that gave the board of directors the ability to require the treasurer, an assistant treasurer, or the controller to post a bond for the discharge of his or her duties and to provide for certain other administrative clarifications. PART III
| |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE |
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 20192021 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 20192021 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) Beneficial Ownership Reporting Compliance,” “Corporate Governance” and “Board Structure.”
Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Executive Officers of the Registrants”“Information about our Executive Officers” in Part I of this report.
Ameren Missouri and Ameren Illinois do not have separately designated standing audit committees, but instead use Ameren’s auditAudit and risk committeeRisk 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. Walter J. GalvinEdward Coleman serves as chairman of Ameren’s auditAudit and risk committeeRisk Committee and Catherine S. Brune, J. Edward Coleman, Ward H. Dickson, Noelle K. Eder, and Craig S. Ivey, and Leo S. Mackay, Jr. serve as members. The board of directors of Ameren has determined that Walter J. Galvin, J. Edward Coleman and Ward H. Dickson each qualify as an audit committee financial expert and that each is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of Ameren Missouri and Ameren Illinois use the nominatingNominating and corporate governance committeeCorporate Governance Committee of Ameren’s board of directors to perform such committee functions. This committeeCommittee is responsible for the nomination of directors and for corporate governance practices. Ameren’s nominatingNominating and corporate governance committeeCorporate Governance Committee will consider
director nominations from shareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s website: www.ameren.com.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 each of the Ameren Companies. Ameren has also adopted a code of business conduct that applies to the directors, officers, and employees of the Ameren Companies. It is referred to as the Principles of Business Conduct. The Ameren Companies make available free of charge through Ameren’s website (www.ameren.com)(www.amereninvestors.com) the Codecode of Ethicsethics and the Principlessupplemental code of Business Conduct.ethics. Any amendment to the Codecode of Ethicsethics or the Principlessupplemental code of Business Conductethics and any waiver from a provision of the Codecode of Ethicsethics or the Principlessupplemental code of Business Conductethics 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 |
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 20192021 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 20192021 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 |
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, 2018,2020, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans:
| | | | | | | | | | | | | | | | | | | | |
Plan
Category | | Column A Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights(a) | | Column B Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Column C Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in Column A) |
Equity compensation plans approved by security holders(b) | | 1,490,771 | | | (c) | | 2,348,521 | |
| Equity compensation plans not approved by security holders | | — | | | — | | | — | |
| Total | | 1,490,771 | | | (c) | | 2,348,521 | |
(a)Of the securities to be issued, 918,570 of the securities represent the target number of outstanding performance share units (PSUs) and 488,460 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
|
| | | | | | | | | |
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 Equity Compensation Plans (excluding securities reflected in Column A) |
Equity compensation plans approved by security holders(b) | | 1,650,565 |
| | (c) |
| | 3,772,209 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
|
| Total | | 1,650,565 |
| | (c) |
| | 3,772,209 |
|
| |
(a) | Pursuant to grants of performance share units (PSUs) and restricted stock units (RSUs) under the 2014 Incentive Plan, 1,393,223 of the securities represent the target number of PSUs granted but not vested and 187,314 of the securities represent the number of RSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 2018 (including outstanding awards under the 2014 Incentive Plan as of December 31, 2018). 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 total shareholder return objectives 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 2019 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. Also, 70,028 of the securities represent shares that may be issued as of December 31, 2018, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for members of the board of directors. |
| |
(b) | Consists of the 2014 Incentive Plan. |
| |
(c) | No consideration is received when shares are distributed for earned PSUs, RSUs, and director awards. Accordingly, there is no weighted-average exercise price. |
(b)Consists of the 2014 Omnibus Incentive Compensation Plan.
(c)No cash consideration is received when shares are distributed for earned PSUs, RSUs, and director awards. Accordingly, there is no weighted-average exercise price.
Ameren Missouri and Ameren Illinois do not have separate equity compensation plans.
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 20192021 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 20192021 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Security Ownership.”
| |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
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 20192021 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 20192021 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 TransactionTransactions Policy” and “Director Independence.”
| |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
ITEM 14.PRINCIPAL ACCOUNTING 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 20192021 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Selection of Independent Registered Public Accounting Firm.”
PART IV
ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
| |
ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| |
| |
| Page No. |
| Page No. |
| (a)(1) Financial Statements | |
| Ameren | |
| Report of Independent Registered Public Accounting Firm | |
Consolidated Statement of Income and Comprehensive Income – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| |
Consolidated Balance Sheet – December 31, 20182020 and 20172019 | |
Consolidated Statement of Cash Flows – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| Ameren Missouri | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Balance Sheet – December 31, 20182020 and 20172019 | |
Statement of Cash Flows – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| Ameren Illinois | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Balance Sheet – December 31, 20182020 and 20172019 | |
Statement of Cash Flows – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| |
| (a)(2) Financial Statement Schedules | |
| Schedule I | |
| Condensed Financial Information of Parent – Ameren: | |
Condensed Statement of Income and Comprehensive Income – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Condensed Balance Sheet – December 31, 20182020 and 20172019 | |
Condensed Statement of Cash Flows – Years Ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| Schedule II | |
| Ameren | |
Valuation and Qualifying Accounts for the years ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| Ameren Missouri | |
Valuation and Qualifying Accounts for the years ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
| Ameren Illinois | |
Valuation and Qualifying Accounts for the years ended December 31, 2018, 2017,2020, 2019, and 20162018 | |
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
|
| | | | | | | | | | |
| (a)(3) | | | |
(a)(3) | | Exhibits – reference is made to the Exhibit Index | |
| (b) | | Exhibit Index | |
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2018, 2017, and 2016 |
| (In millions) | 2018 | | 2017 | | 2016 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
|
| Operating expenses | 11 |
| | 15 |
| | 19 |
|
| Operating loss | (11 | ) | | (15 | ) | | (19 | ) |
| Equity in earnings of subsidiaries | 857 |
| | 659 |
| | 663 |
|
| Interest income from affiliates | 3 |
| | 9 |
| | 10 |
|
| Total other income (expense), net | (12 | ) | | 2 |
| | — |
|
| Interest charges | 34 |
| | 31 |
| | 28 |
|
| Income tax (benefit) | (12 | ) | | 101 |
| | (27 | ) |
| Net Income Attributable to Ameren Common Shareholders | $ | 815 |
| | $ | 523 |
| | $ | 653 |
|
| | | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 815 |
| | $ | 523 |
| | $ | 653 |
|
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $3, and $(7), respectively | (4 | ) | | 5 |
| | (20 | ) |
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 811 |
| | $ | 528 |
| | $ | 633 |
|
| | | | | | | | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME For the Years Ended December 31, 2020, 2019, and 2018 |
| (In millions) | 2020 | | 2019 | | 2018 |
| Operating revenues | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Operating expenses | 12 | | | 15 | | | 11 | |
| Operating loss | (12) | | | (15) | | | (11) | |
| Equity in earnings of subsidiaries | 908 | | | 850 | | | 857 | |
| Interest income from affiliates | 4 | | | 5 | | | 3 | |
| Total other expense, net | (8) | | | (2) | | | (12) | |
| Interest charges | (57) | | | (39) | | | (34) | |
| Income tax benefit | 36 | | | 29 | | | 12 | |
| | | | | |
| | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 871 | | | $ | 828 | | | $ | 815 | |
| | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 871 | | | $ | 828 | | | $ | 815 | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $5, $1, and $(1), respectively | 16 | | | 5 | | | (4) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 887 | | | $ | 833 | | | $ | 811 | |
|
| | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions) | December 31, 2018 | | December 31, 2017 |
| Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Advances to money pool | 76 |
| | 13 |
|
| Accounts receivable – affiliates | 43 |
| | 46 |
|
| Other current assets | 4 |
| | 8 |
|
| Total current assets | 123 |
| | 67 |
|
| Investments in subsidiaries | 8,559 |
| | 7,944 |
|
| Note receivable – ATXI | 75 |
| | 75 |
|
| Accumulated deferred income taxes, net | 108 |
| | 222 |
|
| Other assets | 126 |
| | 140 |
|
| Total assets | $ | 8,991 |
| | $ | 8,448 |
|
| Liabilities and Shareholders’ Equity: | | | |
| Short-term debt | $ | 470 |
| | $ | 383 |
|
| Borrowings from money pool | 46 |
| | 28 |
|
| Accounts payable – affiliates | 10 |
| | 6 |
|
| Other current liabilities | 12 |
| | 27 |
|
| Total current liabilities | 538 |
| | 444 |
|
| Long-term debt | 697 |
| | 696 |
|
| Pension and other postretirement benefits | 43 |
| | 37 |
|
| Other deferred credits and liabilities | 82 |
| | 87 |
|
| Total liabilities | 1,360 |
| | 1,264 |
|
| Commitments and Contingencies (Note 5) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 244.5 and 242.6, respectively | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,627 |
| | 5,540 |
|
| Retained earnings | 2,024 |
| | 1,660 |
|
| Accumulated other comprehensive loss | (22 | ) | | (18 | ) |
| Total shareholders’ equity | 7,631 |
| | 7,184 |
|
| Total liabilities and shareholders’ equity | $ | 8,991 |
| | $ | 8,448 |
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions, except per share amounts) | December 31, 2020 | | December 31, 2019 |
| Assets: | | | |
| Cash and cash equivalents | $ | 0 | | | $ | 0 | |
| Advances to money pool | 16 | | | 102 | |
| Accounts receivable – affiliates | 12 | | | 73 | |
| | | |
| Miscellaneous accounts and notes receivable | 15 | | | 4 | |
| | | |
| Other current assets | 4 | | | 3 | |
| Total current assets | 47 | | | 182 | |
| Investments in subsidiaries | 10,872 | | | 9,108 | |
| | | |
| Note receivable – ATXI | 75 | | | 75 | |
| Accumulated deferred income taxes, net | 42 | | | 49 | |
| Other assets | 167 | | | 145 | |
| Total assets | $ | 11,203 | | | $ | 9,559 | |
| Liabilities and Shareholders’ Equity: | | | |
| Current maturities of long-term debt | $ | 0 | | | $ | 350 | |
| Short-term debt | 490 | | | 153 | |
| Borrowings from money pool | 0 | | | 24 | |
| | | |
| | | |
| Accounts payable – affiliates | 41 | | | 39 | |
| Other current liabilities | 34 | | | 23 | |
| Total current liabilities | 565 | | | 589 | |
| Long-term debt | 1,588 | | | 794 | |
| Pension and other postretirement benefits | 27 | | | 37 | |
| Other deferred credits and liabilities | 85 | | | 80 | |
| Total liabilities | 2,265 | | | 1,500 | |
| Commitments and Contingencies (Note 5) | 0 | | 0 |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 253.3 and 246.2, respectively | 3 | | | 2 | |
| Other paid-in capital, principally premium on common stock | 6,179 | | | 5,694 | |
| Retained earnings | 2,757 | | | 2,380 | |
| Accumulated other comprehensive loss | (1) | | | (17) | |
| Total shareholders’ equity | 8,938 | | | 8,059 | |
| Total liabilities and shareholders’ equity | $ | 11,203 | | | $ | 9,559 | |
|
| | | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2018, 2017, and 2016 |
| (In millions) | | 2018 | | 2017 | | 2016 |
| Net cash flows provided by operating activities | | $ | 550 |
| | $ | 454 |
| | $ | 483 |
|
| Cash flows from investing activities: | | | | | | |
| Money pool advances, net | | (63 | ) | | 14 |
| | (27 | ) |
| Notes receivable – ATXI, net | | — |
| | 275 |
| | (60 | ) |
| Investments in subsidiaries | | (208 | ) | | (151 | ) | | (123 | ) |
| Other | | 5 |
| | 6 |
| | 2 |
|
| Net cash flows provided by (used in) investing activities | | (266 | ) | | 144 |
| | (208 | ) |
| Cash flows from financing activities: | | | | | | |
| Dividends on common stock | | (451 | ) | | (431 | ) | | (416 | ) |
| Short-term debt, net | | 87 |
| | (124 | ) | | 206 |
|
| Money pool borrowings, net | | 18 |
| | (5 | ) | | 19 |
|
| Issuances of common stock | | 74 |
| | — |
| | — |
|
| Repurchases of common stock for stock-based compensation | | — |
| | (24 | ) | | (51 | ) |
| Employee payroll taxes related to stock-based compensation | | (19 | ) | | (15 | ) | | (32 | ) |
| Net cash flows used in financing activities | | (291 | ) | | (599 | ) | | (274 | ) |
| Net change in cash, cash equivalents, and restricted cash | | $ | (7 | ) | | $ | (1 | ) | | $ | 1 |
|
| Cash, cash equivalents, and restricted cash at beginning of year | | 8 |
| | 9 |
| | 8 |
|
| Cash, cash equivalents, and restricted cash at end of year | | $ | 1 |
| | $ | 8 |
| | $ | 9 |
|
| | | | | | | |
| Cash dividends received from consolidated subsidiaries | | $ | 450 |
| | $ | 362 |
| | $ | 465 |
|
| | | | | | | |
| Noncash financing activity – Issuance of common stock for stock-based compensation | | $ | 35 |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2020, 2019, and 2018 |
| (In millions) | | 2020 | | 2019 | | 2018 |
| Net cash flows provided by operating activities | | $ | 147 | | | $ | 491 | | | $ | 550 | |
| Cash flows from investing activities: | | | | | | |
| Money pool advances, net | | 86 | | | (26) | | | (63) | |
| | | | | | |
| Investments in subsidiaries | | (956) | | | (142) | | | (208) | |
| | | | | | |
| | | | | | |
| | | | | | |
| Other | | 8 | | | 5 | | | 5 | |
| Net cash flows used in investing activities | | (862) | | | (163) | | | (266) | |
| Cash flows from financing activities: | | | | | | |
| Dividends on common stock | | (494) | | | (472) | | | (451) | |
| Short-term debt, net | | 337 | | | (317) | | | 87 | |
| Money pool borrowings, net | | (24) | | | (22) | | | 18 | |
| Maturities of long-term debt | | (350) | | | 0 | | | 0 | |
| Issuances of long-term debt | | 798 | | | 450 | | | 0 | |
| Issuances of common stock | | 476 | | | 68 | | | 74 | |
| | | | | | |
| Employee payroll taxes related to stock-based compensation | | (20) | | | (29) | | | (19) | |
| Debt issuance costs | | (7) | | | (4) | | | 0 | |
| | | | | | |
| Net cash flows provided by (used in) financing activities | | 716 | | | (326) | | | (291) | |
| Net change in cash, cash equivalents, and restricted cash | | $ | 1 | | | $ | 2 | | | $ | (7) | |
| Cash, cash equivalents, and restricted cash at beginning of year | | 3 | | | 1 | | | 8 | |
| Cash, cash equivalents, and restricted cash at end of year | | $ | 4 | | | $ | 3 | | | $ | 1 | |
| Supplemental information: | | | | | | |
| Cash dividends received from consolidated subsidiaries | | $ | 105 | | | $ | 445 | | | $ | 450 | |
| | | | | | |
| | | | | | |
| Noncash financing activity – Issuance of common stock for stock-based compensation | | 38 | | | 54 | | | 35 | |
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 20182020
NOTE 1 – BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. Ameren Corporation (parent company only) has accounted for its subsidiaries using the equity method. These financial statements are presented on a condensed basis.
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. See Note 13 – Related-party Transactions under Part II, Item 8, of this report for information on the tax allocation agreement between Ameren Corporation (parent company only) and its subsidiaries.
NOTE 2 – CASH AND CASH EQUIVALENTS
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheet and the statement of cash flows as of December 31, 20182020and2017:2019:
| | | | 2018 | | 2017 | |
| (In millions) | | (In millions) | 2020 | | 2019 | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| Cash and cash equivalents | $ | 0 | | | $ | 0 | | |
| Restricted cash included in “Other current assets” | 1 |
| | 8 |
| Restricted cash included in “Other current assets” | 4 | | | 3 | | |
| Total cash, cash equivalents, and restricted cash | $ | 1 |
| | $ | 8 |
| Total cash, cash equivalents, and restricted cash | $ | 4 | | | $ | 3 | | |
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
NOTE 3 – SHORT-TERM DEBT AND LIQUIDITY
Ameren, Ameren Services, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. All participants may borrow from or lend to the non-state-regulated money
pool. The total amount available to pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulatednon-state-
regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. Interest revenues and interest charges related to non-state-regulated money pool advances and borrowings were immaterial in 2016, 2017,2018, 2019, and 2018.2020.
Ameren Corporation (parent company only) had a total of $11$3 million in guarantees outstanding, primarily for ATXI, that were not recorded on its December 31, 20182020 balance sheet. The ATXI guarantees were issued to local governments as assurance for potential remediation of damage caused by ATXI construction.
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).
NOTE 4 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on Ameren Corporation’s (parent company only) long-term debt, indenture provisions, and restricted cash balance.forward sale agreement related to common stock.
NOTE 5 – COMMITMENTS AND CONTINGENCIES
See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies of Ameren Corporation (parent company only).
NOTE 6 – OTHER INCOME (EXPENSE),EXPENSE, NET
The following table presents the components of “Other Income (Expense),Expense, Net” in the Condensed Statement of Income and Comprehensive Income for the years ended December 31, 2018, 2017,2020, 2019, and 2016:2018:
| | | | | | | | | | | | | | | | | |
| (In millions) | 2020 | | 2019 | | 2018 |
| Other Expense, Net | | | | | |
| Non-service cost components of net periodic benefit income | $ | 1 | | | $ | 2 | | | $ | 2 | |
| Donations | (8) | | | (3) | | | (13) | |
| Other expense, net | (1) | | | (1) | | | (1) | |
| Total Other Expense, Net | $ | (8) | | | $ | (2) | | | $ | (12) | |
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Other Income (Expense), Net | | | | | |
| Non-service cost components of net periodic benefit income | $ | 2 |
| | $ | 2 |
| | $ | 5 |
|
| Donations | (13 | ) | | — |
| | (5 | ) |
| Other expense, net | (1 | ) | | — |
| | — |
|
| Total Other Income (Expense), Net | $ | (12 | ) | | $ | 2 |
| | $ | — |
|
Based on authoritative accounting guidance described in Note 10 - Retirement Benefits under Part II, Item 8, of this report, Ameren Corporation (parent company only) has retrospectively reclassified $2 million and $5 million of net benefit income from “Operating Expenses” to “Other Income (Expense), Net” in | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2020, 2019, AND 2018 |
| (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: | | | | | | | | | | |
| 2020 | | $ | 17 | | | $ | 42 | | | $ | 6 | | | $ | 15 | | | $ | 50 | |
| 2019 | | 18 | | | 26 | | | 4 | | | 31 | | | 17 | |
| 2018 | | 19 | | | 27 | | | 4 | | | 32 | | | 18 | |
| Deferred tax valuation allowance: | | | | | | | | | | |
| 2020 | | $ | 3 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 3 | |
| 2019 | | 5 | | | (2) | | | 0 | | | 0 | | | 3 | |
| 2018 | | 11 | | | (6) | | | 0 | | | 0 | | | 5 | |
| Ameren Missouri: | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | |
| 2020 | | $ | 7 | | | $ | 15 | | | $ | 0 | | | $ | 6 | | | $ | 16 | |
| 2019 | | 7 | | | 9 | | | 0 | | | 9 | | | 7 | |
| 2018 | | 7 | | | 9 | | | 0 | | | 9 | | | 7 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Ameren Illinois: | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | |
| 2020 | | $ | 10 | | | $ | 27 | | | $ | 6 | | | $ | 9 | | | $ | 34 | |
| 2019 | | 11 | | | 17 | | | 4 | | | 22 | | | 10 | |
| 2018 | | 12 | | | 18 | | | 4 | | | 23 | | | 11 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
(a)Amounts associated with the Condensed Statement of Income and Comprehensive Incomeallowance for the years ended December 31, 2017, and December 31, 2016, respectively.
NOTE 7 – INCOME TAXES
During the year ended December 31, 2017, Ameren (parent) recorded $110 million in income tax expense and reduction in accumulated deferred income taxes as a result of the TCJA. During the year ended December 31, 2018, Ameren (parent) updated its provisional estimate and recorded $5 million of income tax expense and reduction in accumulated deferred income taxes, primarily duedoubtful accounts relate to the application of proposed IRS regulations on depreciation transition rules.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.
|
| | | | | | | | | | | | | | | | | | | |
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2018, 2017, AND 2016 |
| (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: | | | | | | | | | |
| 2018 | $ | 19 |
| | $ | 27 |
| | $ | 4 |
| | $ | 32 |
| | $ | 18 |
|
| 2017 | 19 |
| | 26 |
| | 7 |
| | 33 |
| | 19 |
|
| 2016 | 19 |
| | 32 |
| | 3 |
| | 35 |
| | 19 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2018 | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| 2017 | 11 |
| | (6 | ) | (c) | — |
| | — |
| | 5 |
|
| 2016 | 6 |
| | 7 |
| | (2 | ) | | — |
| | 11 |
|
| Ameren Missouri: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2018 | $ | 7 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 7 |
|
| 2017 | 7 |
| | 9 |
| | — |
| | 9 |
| | 7 |
|
| 2016 | 7 |
| | 10 |
| | — |
| | 10 |
| | 7 |
|
| Ameren Illinois: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2018 | $ | 12 |
| | $ | 18 |
| | $ | 4 |
| | $ | 23 |
| | $ | 11 |
|
| 2017 | 12 |
| | 17 |
| | 7 |
| | 24 |
| | 12 |
|
| 2016 | 12 |
| | 22 |
| | 3 |
| | 25 |
| | 12 |
|
| |
(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. The amounts relating to the deferred tax valuation allowance are for items that have expired and were removed from both the underlying accumulated deferred income tax account as well as the offsetting valuation account. |
| |
(b) | Uncollectible accounts charged off, less recoveries. |
| |
(c) | Includes an adjustment of $3 million to Ameren (parent)’s valuation allowance for certain deferred tax assets existing at December 31, 2017, for the reduction in the income tax rate. |
| |
ITEM 16. | FORM 10-K SUMMARY |
ITEM 16.FORM 10-K SUMMARY
The Ameren Companies elected not to provide a summary of the Form 10-K.
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 | | February 14, 2017 Form 8-K, Exhibit 3, File No. 1-14756 |
| 3.8(ii) | Ameren Missouri | | December 18, 2014 Form 8-K,
Exhibit 3.1, File No. 1-2967
|
| 3.9(ii) | Ameren Illinois | | December 18, 2014 Form 8-K,
Exhibit 3.2, 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 4.4 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 | | June 26, 2017 Form 8-K, Exhibit 4.1, File No. 1-14756 |
| 4.7 | 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 |
4.54.8 | Ameren
Ameren Missouri | Ameren
Ameren Missouri
| | Exhibit 4.22, File No. 333-222108 |
4.64.9 | Ameren Ameren Missouri | | Exhibit 4.23, File No. 333-222108 |
4.74.10 | Ameren Ameren Missouri | | Exhibit 4.24, File No. 333-222108 |
4.84.11 | Ameren Ameren Missouri | | Exhibit 4.25, File No. 333-222108 |
4.94.12 | Ameren Ameren Missouri | | 1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
|
4.104.13 | Ameren Ameren Missouri | | 2000 Form 10-K, Exhibit 4.1,
File No. 1-2967
|
4.114.14 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967
|
| | | | | | | | | | | |
4.124.15 | Ameren Ameren Missouri | | March 11, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.134.16 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.1,
File No. 1-2967
|
4.144.17 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.2,
File No. 1-2967
|
|
| | | |
4.154.18 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.3,
File No. 1-2967
|
4.164.19 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.8,
File No. 1-2967
|
4.174.20 | Ameren Ameren Missouri | | September 23, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.184.21 | Ameren Ameren Missouri | | January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.194.22 | Ameren Ameren Missouri | | July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.204.23 | Ameren Ameren Missouri | | June 19, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.214.24 | Ameren Ameren Missouri | | March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.224.25 | Ameren Ameren Missouri | | Exhibit 4.45, File No. 333-182258 |
4.234.26 | Ameren Ameren Missouri | | September 11, 2012 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.244.27 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.254.28 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967 |
4.264.29 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967 |
4.274.30 | Ameren Ameren Missouri | | April 6, 2018 Form 8-K, Exhibit 4.2, File No. 1-2967 |
4.284.31 | Ameren Ameren Missouri | | March 6, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.32 | Ameren Ameren Missouri | | October 1, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.33 | Ameren Ameren Missouri | | March 20, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.34 | Ameren Ameren Missouri | | October 9, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.35 | 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
|
4.294.36 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.10,
File No. 1-2967
|
4.304.37 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
|
4.314.38 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.11,
File No. 1-2967
|
4.324.39 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
|
| | | | | | | | | | | |
4.334.40 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.12,
File No. 1-2967
|
4.344.41 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967
|
4.354.42 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.13,
File No. 1-2967
|
4.364.43 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-2967
|
4.374.44 | Ameren Ameren Missouri | | Exhibit 4.48, File No. 333-182258 |
4.384.45 | Ameren Ameren Missouri | | March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
|
| | | |
4.394.46 | Ameren Ameren Missouri | | September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.40 | Ameren
Ameren Missouri
| | January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.41 | Ameren
Ameren Missouri
| | July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.424.47 | Ameren Ameren Missouri | | June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.43 | Ameren
Ameren Missouri
| | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.444.48 | 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 |
4.454.49 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.464.50 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.474.51 | Ameren
Ameren Missouri | Ameren
Ameren Missouri
| | June 23, 2016 Form 8-K, Exhibits 4.3, and 4.4, File No. 1-2967 |
4.484.52 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.494.53 | Ameren Ameren Illinois | | Exhibit 4.4, File No. 333-59438 |
4.504.54 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.514.55 | Ameren Ameren Illinois | | Exhibit 4.17, File No. 333-166095 |
4.524.56 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
4.534.57 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
4.544.58 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
4.55 | Ameren
Ameren Illinois
| Indenture of Mortgage and Deed of Trust between Ameren Illinois (successor in interest to Central Illinois Light Company and Illinois Power Company) and Deutsche Bank Trust Company Americas (formerly Bankers Trust Company), as trustee, dated as of April 1, 1933 (CILCO Mortgage), Supplemental Indenture between the same parties dated as of June 30, 1933, Supplemental Indenture between CILCO (predecessor in interest to Ameren Illinois) and the trustee, dated as of July 1, 1933, Supplemental Indenture between the same parties dated as of January 1, 1935, and Supplemental Indenture between the same parties dated as of April 1, 1940 | Exhibit B-1, Registration No. 2-1937; Exhibit B-1(a), Registration No. 2-2093; and Exhibit A, April 1940 Form 8-K, File No. 1-2732 |
4.564.59 | Ameren Ameren Illinois | | 2017 Form 10-K, Exhibit 4.59, File No. 1-3672 |
4.57 | Ameren
Ameren Illinois
| | 2017 Form 10-K, Exhibit 4.60, File No. 1-3672 |
4.58 | Ameren
Ameren Illinois
| | 2017 Form 10-K, Exhibit 4.61, File No. 1-3672 |
4.59 | Ameren
Ameren Illinois
| | 2017 Form 10-K, Exhibit 4.62, File No. 1-3672 |
4.60 | Ameren
Ameren Illinois
| | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
|
| | | |
4.61 | Ameren
Ameren Illinois
| | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
4.62 | Ameren
Ameren Illinois
| | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-27321-14756 |
4.634.60 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K,8-K, Exhibit 4.1, File No. 1-3672 |
4.644.61 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.1,
File No. 1-3672
|
4.654.62 | Ameren Ameren Illinois | | September 30, 2019 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
| 4.63 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-27321-14756 |
| | | | | | | | | | | |
4.664.64 | 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 |
4.674.65 | Ameren Ameren Illinois | | June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004 |
4.68 | Ameren
Ameren Illinois
| | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 |
4.694.66 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K,8-K, Exhibit 4.9, File No. 1-3672 |
4.704.67 | Ameren Ameren Illinois | | Exhibit 4.78, File No. 333-182258 |
4.714.68 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.724.69 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.734.70 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.744.71 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.754.72 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.764.73 | Ameren Ameren Illinois | | September 30, 2017 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
4.774.74 | Ameren Ameren Illinois | | November 28, 2017 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.784.75 | Ameren Ameren Illinois | | May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.794.76 | Ameren Ameren Illinois | | November 15, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.804.77 | Ameren Ameren Illinois | | September 30, 2019 Form 10-Q, Exhibit 4.3, File No. 1-3672 |
| 4.78 | Ameren
Ameren Illinois | | November 26, 2019 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.79 | Ameren
Ameren Illinois | | 2019 Form 10-K, Exhibit 4.79, File No. 1-3672 |
| 4.80 | Ameren
Ameren Illinois | | November 23, 2020 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.81 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-30041-14756 |
4.814.82 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K,8-K, Exhibit 4.5, File No. 1-14756 |
4.824.83 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
4.834.84 | Ameren Ameren Illinois | | Exhibit 4.83, File No. 333-182258 |
4.844.85 | Ameren Ameren Illinois | | September 30, 2019 Form 10-Q, Exhibit 4.4, File No. 1-3672 |
| 4.86 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.854.87 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
|
| 4.88 | | | |
4.86Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| | | | | | | | | | | |
4.874.89 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.884.90 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.894.91 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.904.92 | Ameren
Ameren Illinois | Ameren
| | April 6, 2018,September 30, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
4.91 | Ameren
Ameren Illinois
| | May 22, 2018 Form 8-K, Exhibit 4.2,10-Q, Exhibits 4.5 and 4.6, File No. 1-3672 |
4.924.93 | Ameren | Ameren
| | November 15, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
Material Contracts4.94 | Ameren Missouri | | |
10.14.95 | Ameren Illinois | | |
| Material Contracts |
| 10.1 | Ameren Companies | | June 30, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
| 10.2 | Ameren
Ameren Missouri | Ameren
Ameren Missouri
| | December 8, 201611, 2019 Form 8-K, Exhibit 10.1, File No. 1-2967 |
| 10.3 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 8, 201611, 2019 Form 8-K, Exhibit 10.2, File No. 1-3672 |
| 10.4 | Ameren | | 2019 Form 10-K, Exhibit 10.6, File No. 1-14756 |
| 10.5 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
| 10.6 | Ameren | | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 |
| 10.7 | Ameren | | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
| 10.8 | Ameren | | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756 |
| 10.9 | Ameren | | 2010 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.10 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.11 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.12 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.13 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.13, File No. 1-14756 |
| 10.14 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.14, File No. 1-14756 |
| 10.15 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.17, File No. 1-14756 |
| 10.16 | Ameren Companies | | |
| 10.17 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1610.18 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1710.19 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1810.20 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1910.21 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.19, File No. 1-14756 |
10.2010.22 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.23, File No. 1-14756 |
| 10.23 | Ameren Companies | | |
| 10.24 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 |
10.2110.25 | Ameren Companies | | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
| | | | | | | | | | | |
10.2210.26 | Ameren Companies | | |
|
| | | |
10.2310.27 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2410.28 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2510.29 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2610.30 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2710.31 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.27, File No. 1-14756 |
10.2810.32 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.32, File No. 1-14756 |
| 10.33 | Ameren Companies | | |
| 10.34 | Ameren Companies | | Exhibit 99, File No. 333-196515 |
10.2910.35 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.3010.36 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.3110.37 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.3210.38 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.3310.39 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.3410.40 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.34, File No. 1-14756 |
10.3510.41 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.35, File No. 1-14756 |
10.3610.42 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.41, File No. 1-14756 |
| 10.43 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.42, File No. 1-14756 |
| 10.44 | Ameren Companies | | |
| 10.45 | Ameren Companies | | |
| 10.46 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.36, File No. 1-14756 |
10.3710.47 | Ameren Companies | | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.3810.48 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 |
| 10.49 | Ameren Companies | | February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756 |
| Subsidiaries of the Registrant |
| 21.1 | Ameren Companies | | |
| | | | | | | | | | | |
| Consent of Experts and Counsel |
| 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 | | | |
31.5 | Ameren Illinois | | |
| 31.6 | Ameren Illinois | | |
| Section 1350 Certifications |
| 32.1 | Ameren | | |
| 32.2 | Ameren Missouri | | |
| 32.3 | Ameren Illinois | | |
| Additional Exhibits |
| 99.1 | Ameren Companies | | 2013 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.INS101.SCH | Ameren Companies | XBRL Instance 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.
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.
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| | | | |
| | AMEREN CORPORATION (registrant)
|
| | | |
Date: | February 26, 2019 | By | | /s/ Warner L. Baxter |
| | | | Warner L. Baxter
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. |
| | | | | |
| | AMEREN CORPORATION (registrant) |
| | | |
| Date: | February 22, 2021 | By | | /s/ Warner L. Baxter |
| | | | Warner L. Baxter
Chairman, President and Chief Executive Officer and Director (Principal Executive Officer) | | February 26, 2019 |
Warner L. Baxter | | | | |
| | | |
/s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
| | February 26, 2019 |
Martin J. Lyons, Jr. | | | | |
| | | | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 26, 2019 |
Bruce A. Steinke | | | | |
| | | | | |
* | | Director | | February 26, 2019 |
Catherine S. Brune | | | | |
| | | | | |
* | | Director | | February 26, 2019 |
J. Edward Coleman | | | | |
| | | |
* | | Director | | February 26, 2019 |
Ward H. Dickson | | | | |
| | | |
* | | Director | | February 26, 2019 |
Noelle K. Eder | | | | |
| | | | | |
* | | Director | | February 26, 2019 |
Ellen M. Fitzsimmons | | | | |
| | | |
* | | Director | | February 26, 2019 |
Rafael Flores | | | | |
| | | | | |
* | | Director | | February 26, 2019 |
Walter J. Galvin | | | | |
| | | |
* | | Director | | February 26, 2019 |
Richard J. Harshman | | | | |
| | | | | |
* | | Director | | February 26, 2019 |
Craig S. Ivey | | | | |
| | | | | |
* | | Director | | February 26, 2019 |
Gayle P. W. Jackson | | | | |
| | | |
* | | Director | | February 26, 2019 |
James C. Johnson | | | | |
| | | |
* | | Director | | February 26, 2019 |
Steven H. Lipstein | | | | |
| | | |
| | | | | |
| | | | | |
|
| | | | | |
* | | Director | | February 26, 2019 |
Stephen R. Wilson | | | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 26, 2019 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
|
| | | | |
| | UNION ELECTRIC COMPANY (registrant)
|
| | | |
Date: | February 26, 2019 | By | | /s/ Michael L. Moehn |
| | | | Michael L. Moehn
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/ Warner L. Baxter | | Chairman, President and Chief Executive Officer, and Director (Principal Executive Officer) | | February 22, 2021 |
| Warner L. Baxter | | | | |
| | | |
| /s/ Michael L. Moehn | | Executive Vice President and Chief Financial Officer
(Principal Financial Officer) | | February 22, 2021 |
| Michael L. Moehn | | | | |
| | | | | |
/s/ Michael L. Moehn | | Chairman and President, and Director (Principal Executive Officer) | | February 26, 2019 |
Michael L. Moehn | | | | |
| | | |
/s/ Martin J. Lyons, Jr.
| | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 26, 2019 |
Martin J. Lyons, Jr. | | | | |
| | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 26, 201922, 2021 |
| Bruce A. Steinke | | | | |
| | | | | |
| * | | Director | | February 26, 201922, 2021 |
| Cynthia J. Brinkley | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| Catherine S. Brune | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| J. Edward Coleman | | | | |
| | | |
| * | | Director | | February 22, 2021 |
| Ward H. Dickson | | | | |
| | | |
| * | | Director | | February 22, 2021 |
| Noelle K. Eder | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| Ellen M. Fitzsimmons | | | | |
| | | |
| * | | Director | | February 22, 2021 |
| Rafael Flores | | | | |
| | | |
| * | | Director | | February 22, 2021 |
| Richard J. Harshman | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| Craig S. Ivey | | | | |
| | | |
| * | | Director | | February 22, 2021 |
| James C. Johnson | | | | |
| | | |
| * | | Director | | February 22, 2021 |
| Steven H. Lipstein | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| Leo S. Mackay, Jr. | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| Stephen R. Wilson | | | | |
| | | |
| *By | /s/ Michael L. Moehn | | | | February 22, 2021 |
| Michael L. Moehn | | | | |
| Attorney-in-Fact | | | | |
| | | | | | | | | | | | | | |
| | UNION ELECTRIC COMPANY (registrant) |
| | | |
| Date: | February 22, 2021 | By | | /s/ Martin J. Lyons, Jr. |
| | | | Martin J. Lyons, Jr.
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/ Martin J. Lyons, Jr. | | Chairman and President, and Director
(Principal Executive Officer) | | February 22, 2021 |
| Martin J. Lyons, Jr. | | | | |
| | | |
/s/ Michael L. Moehn | | Executive Vice President and Chief Financial Officer, and Director
(Principal Financial Officer) | | February 22, 2021 |
| Michael L. Moehn | | | | |
| | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer
(Principal Accounting Officer) | | February 22, 2021 |
| Bruce A. Steinke | | | | |
| | | | | |
| * | | Director | | February 22, 2021 |
| Mark C. Birk | | | | |
| | | |
| * | | Director | | February 26, 201922, 2021 |
| Fadi M. Diya | | | | |
| | | |
| * | | Director | | February 26, 201922, 2021 |
Gregory L. NelsonChonda J. Nwamu | | | | |
| | | |
| *By | /s/ Michael L. Moehn | Director | | | February 26, 201922, 2021 |
David N. Wakeman | Michael L. Moehn | | | | |
| Attorney-in-Fact | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 26, 2019 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
| | | | | | | | | | | | | | |
| | AMEREN ILLINOIS COMPANY (registrant) |
| | | | |
| Date: | February 22, 2021 | AMEREN ILLINOIS COMPANY (registrant)
|
| By | | | | |
Date: | February 26, 2019 | By | | /s/ Richard J. Mark |
| | | | Richard J. Mark
Chairman and President
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
|
| | | | | | | | | | | | | | | | |
| /s/ Richard J. Mark | | Chairman and President, and Director (Principal
(Principal Executive Officer) | | February 26, 201922, 2021 |
| Richard J. Mark | | | | |
| | | |
/s/ Martin J. Lyons, Jr.Michael L. Moehn | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 26, 201922, 2021 |
Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal
(Principal Accounting Officer) | | February 26, 201922, 2021 |
| Bruce A. Steinke | | | | |
| | | | | |
| * | | Director | | February 26, 201922, 2021 |
Craig D. NelsonChonda J. Nwamu | | | | |
| | | |
| * | | Director | | February 26, 201922, 2021 |
Gregory L. NelsonTheresa A. Shaw | | | | |
| | | | | |
| * | | Director | | February 26, 201922, 2021 |
| David N. Wakeman | | | | |
| | | |
| *By | /s/ Martin J. Lyons, Jr.Michael L. Moehn | | | | February 26, 201922, 2021 |
| Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| Attorney-in-Fact | | | | |
