UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| | | | | |
| | |
(X) | ☒ | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2017.2023 |
OR
| | | | | |
| ☐ | | OR |
| |
( ) | | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the transition period from to . |
| | | | | | | | |
| | | | |
Commission
File Number
| | Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number
| | IRS Employer
Identification No.
|
| | |
| 1-14756 | | Ameren Corporation | 43-1723446 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
| 43-1723446 | | | | | | | |
| 1-2967 | | (Missouri Corporation) | | |
| | 1901 Chouteau Avenue | | |
| | St. Louis, Missouri 63103 | | |
| | (314) 621-3222 | | |
| | |
1-2967 | | Union Electric Company | 43-0559760 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
| 43-0559760 | | | | | | | |
| 1-3672 | | (Missouri Corporation) | | |
| | 1901 Chouteau Avenue | | |
| | St. Louis, Missouri 63103 | | |
| | (314) 621-3222 | | |
| | |
1-3672 | | Ameren Illinois Company | | 37-0211380 |
| | (Illinois Corporation) | | |
| | 6 Executive Drive | | |
| | Collinsville, Illinois 62234 | | |
| | |
(Illinois Corporation)
10 Richard Mark Way
Collinsville, Illinois 62234
(618) 343-8150
| | Securities Registered Pursuant to Section 12(b) of the Act:
The following security is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:
| | | | | | | | |
| | | |
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:
| | | | | | | | |
| Registrant | | | |
Registrant | Title of each class |
| Union Electric Company | | Preferred Stock, cumulative, no par value, stated value $100 per share
|
| Ameren Illinois Company | | Preferred Stock, cumulative, $100 par value per shareDepositary Shares, each representing one-fourth of a share of 6.625% Preferred Stock, cumulative, $100 par value per share
|
Indicate by checkmarkcheck mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
| | | | | | | | | | | | | | |
| Ameren Corporation | Yes | ☒ | No | ☐ |
| | | | |
Ameren Corporation | Yes | ý
| No | ¨
|
| Union Electric Company | Yes | ¨
☒ | No | ý
☐ |
| Ameren Illinois Company | Yes | ¨
☒ | No | ý
☐ |
Indicate by checkmarkcheck mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| | | | | | | | | | | | | | |
| Ameren Corporation | Yes | ☐ | No | ☒ |
| | | | |
Ameren Corporation | Yes | ¨
| No | ý
|
| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
Indicate by checkmarkcheck mark whether the registrants:each registrant: (1) havehas 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) havehas been subject to such filing requirements for the past 90 days.
| | | | | | | | | | | | | | |
| Ameren Corporation | Yes | ☒ | No | ☐ |
| | | | |
Ameren Corporation | Yes | ý
| No | ¨
|
| Union Electric Company | Yes | ý
☒ | No | ¨
☐ |
| Ameren Illinois Company | Yes | ý
☒ | No | ¨
☐ |
Indicate by checkmarkcheck mark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
| | | | | | | | | | | | | | |
| Ameren Corporation | Yes | ☒ | No | ☐ |
| | | | |
Ameren Corporation | Yes | ý
| No | ¨
|
| Union Electric Company | Yes | ý
☒ | No | ¨
☐ |
| Ameren Illinois Company | Yes | ý
☒ | No | ¨
☐ |
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.
|
| | |
Ameren Corporation | | ý
|
Union Electric Company | | ý
|
Ameren Illinois Company | | ý
|
Indicate by checkmarkcheck mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| | | | | | | | | | | | | | | | | | | | |
| Ameren Corporation | Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ |
| | | Smaller reporting company | ☐ | Emerging growth company | | | | | | | | ☐ |
| | Large
Accelerated
Filer
| | Accelerated
Filer
| | Non-accelerated
Filer
| | Smaller
Reporting
Company
| | Emerging Growth Company |
Ameren Corporation | | ý | | ¨ | | ¨
| | ¨
| | ¨ |
| Union Electric Company | Large accelerated filer | ¨
☐ | Accelerated filer | ¨
☐ | Non-accelerated filer | ý
| | ¨ | | ¨☒ |
| | | Smaller reporting company | ☐ | Emerging growth company | ☐ |
| Ameren Illinois Company | Large accelerated filer | ¨
☐ | Accelerated filer | ¨
☐ | Non-accelerated filer | ý
☒ |
| | | Smaller reporting company | ☐ | ¨Emerging growth company | | ¨☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
| | | | | | | | | | | | | | |
| Ameren Corporation | | | | ☐ |
| |
Ameren Corporation | ¨ |
| Union Electric Company | | ¨ | | ☐ |
| Ameren Illinois Company | | ¨ | | ☐ |
Indicate by checkmarkcheck mark whether each registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
| | | | | | | | | | | | | | |
| Ameren Corporation | | | | ☒ |
| Union Electric Company | | | | ☐ |
| Ameren Illinois Company | | | | ☐ |
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
| | | | | | | | | | | | | | |
| Ameren Corporation | | | | ☐ |
| Union Electric Company | | | | ☐ |
| Ameren Illinois Company | | | | ☐ |
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
| | | | | | | | | | | | | | |
| Ameren Corporation | | | | ☐ |
| Union Electric Company | | | | ☐ |
| Ameren Illinois Company | | | | ☐ |
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
| | | | | | | | | | | | | | |
| Ameren Corporation | Yes | ☐ | No | ☒ |
| | | | |
Ameren Corporation | Yes | ¨
| No | ý
|
| Union Electric Company | Yes | ¨
☐ | No | ý
☒ |
| Ameren Illinois Company | Yes | ¨
☐ | No | ý
☒ |
As of June 30, 2017,2023, the aggregate market value of Ameren Corporation’s common stock, $0.01 par value, (based upon the closing price of the common stock on the New York Stock Exchange on June 30, 2017)2023) held by nonaffiliates was $13,230,607,078.$21,380,504,079. All of the shares of common stock of the other registrants were held by Ameren Corporation as of June 30, 2017.2023.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2018,2024, were as follows:
| | | | | | | | |
| Registrant | Title of each class of common stock | Shares |
| |
| Ameren Corporation | Common stock, $0.01 par value per share: 242,634,798share | 266,288,867 | |
| |
| Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): | 102,123,834 | |
| |
| 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 20182024 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
| | | | | | | | | | | |
| | |
| | Page |
| |
| |
| | | |
| Item 1. | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Item 1A. | | |
| Item 1B. | | |
Item 2.1C. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
| |
| | | |
| | | |
| Item 5. | | |
| Item 6. | | |
| Item 7. | | |
| | |
| | |
| | |
| | |
| | |
| | |
| Item 7A. | | |
Item 7A. | | |
| Item 8. | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| Item 9. | | |
| Item 9A. | | |
| Item 9B. | | |
| Item 9C. | | |
| | | |
| | | |
| Item 10. | | |
| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
| | | |
| | | |
| Item 15. | | |
| Item 16. | | |
| |
| |
This report contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “targets,” and similar expressions.
GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed.
2014 Incentive2023 IRP – Integrated Resource Plan, – The 2014 Omnibus Incentive Compensation Plan, which provides a long-term nonbinding plan that Ameren Missouri filed with the MoPSC in September 2023 that includes Ameren Missouri’s preferred plan for compensatory stock-based awards to eligible employees and directors.meeting customers’ projected long-term energy needs.
AER – Ameren Energy Resources Company, LLC, a former Ameren Corporation subsidiary that consisted of non-rate-regulated operations. In December 2013, AER contributed substantially all of its assets and liabilities, including its ownership interests in Ameren Energy Generating Company, Ameren Energy Resources Generating Company, and Ameren Energy Marketing Company, to New AER.
Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies – Ameren Corporation, Ameren Missouri, and Ameren Illinois, collectively, which are individual registrants within the Ameren consolidated group.
Ameren Illinois – Ameren Illinois Company, an Ameren Corporation subsidiary that operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois, doing business as Ameren Illinois.
Ameren Illinois Electric Distribution – An Ameren Corporation and Ameren Illinois financial reporting segment consisting of the rate-regulated electric distribution business of Ameren Illinois.
Ameren Illinois 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 Transmission– An Ameren Illinois Company, an Ameren Corporation subsidiary that operatesfinancial reporting segment consisting of the rate-regulated electric and natural gas transmission and distribution businesses in Illinois, doing business asof 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 Corporation.
Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services, such as accounting, legal, treasury, and asset management services, to Ameren (parent) and its subsidiaries.
Ameren Transmission – An Ameren Corporation financial reporting segment primarily consisting of the aggregated electric transmission businesses of Ameren Illinois and ATXI.
AMIL – The MISO balancing authority area operated by Ameren, which includes the load of Ameren Illinois and ATXI.
AMMO – The MISO balancing authority area operated by Ameren, which includes the load and energy centers of Ameren Missouri.
ARO – Asset retirement obligations.obligation.
ATM program – At-the-market equity distribution program.
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.
Base rate – The service rate charged to customers, which varies by segmentation within customer classes, excludes rates applicable to riders, and is determined by the ratemaking process used to establish the annual revenue requirement applicable to such service.
Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
CCN – Certificate of convenience and necessity.
CCR – Coal combustion residuals, which include fly ash, bottom ash, boiler slag, and flue gas desulfurization materials generated from burning coal to generate electricity.
CILCOCCR Rule – 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,”Coal Combustion Residuals Rule, an EPA rule that established requirements for the disposal of CCR in landfills and surface impoundments, and the operation and closure of such landfills and surface impoundments.
CDP – A not-for-profit entity that administers a global disclosure system related to environmental matters, among other things.
CEJA – Climate and Equitable Jobs Act, Illinois legislation enacted in September 2021 that, among other things, gives Ameren Illinois the option to establish new electric distribution rates through either a traditional regulatory rate review, which would have established emission guidelinesmay be based on a future test year, or an MYRP for statesa four-year period. Formerly referred to followas the Illinois Energy Transition Legislation or IETL in developing plans to reduce CO2 emissions from existing fossil-fuel-fired electric generating units. In October 2017, the EPA announced a proposal to repeal the Clean Power Plan.previous filings.
CO2 – Carbon dioxide.
COLCOLI – Nuclear energy center combined construction and operating license.Company-owned life insurance.
Customer demand charges – Revenues from nonresidential customers based on their peak demand during a specified time interval.
Cooling degree-daysdegree days – The summation of positive differences between the average daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of electricity demand by residential and commercial customers for summer cooling.
Credit Agreements – The Illinois Credit Agreement and the Missouri Credit Agreement, collectively.
CSAPR – Cross-State Air Pollution Rule, an EPA rule that requires states that contribute to air pollution in downwind states to limit air emissions from fossil-fuel-fired electric generating units.
CT – Combustion turbine, used primarily for peaking electric generation capacity.
Deferred payment arrangement – A payment option that allows certain Ameren Missouri and Ameren Illinois retail customers to pay a utility bill balance over an extended period of time, generally up to 12 months.
Dekatherm – A standard unit of energy equivalent to approximately one million Btus.
DOE – Department of Energy, a United States government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Electric margins – Electric revenues less fuel and purchased power costs.
EMANI – European Mutual Association for Nuclear Insurance.
EPA – Environmental Protection Agency, a United States government agency.
ERISA – Employee Retirement Income Security Act of 1974, as amended.
ESG – Environmental, social, and governance.
Excess deferred income taxes – The amountAmounts resulting from the revaluation of deferred income taxes previously collected from customers thatsubject to regulatory ratemaking, which will be returnedrefunded to customers over periodscustomers. Deferred income taxes are revalued when federal or state income tax rates decrease, and the offset to the revaluation of time determined by our regulators.deferred income taxes subject to regulatory ratemaking is recorded to a regulatory liability.
Exchange Act – Securities Exchange Act of 1934, as amended.
FAC – Fuel adjustment clause, a fuel and purchased power 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 2016 an 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 (parent), Ameren Missouri, Ameren Illinois, ATXI, and Ameren Services.
FTRs – Financial transmission rights, financial instruments that specify 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.
Grid Plan – Multi-year integrated grid plan, a plan required to be filed with the ICC every four years under the CEJA, which outlines how Ameren Illinois expects to invest in electric distribution infrastructure in order to support grid modernization, clean energy, energy efficiency, and the state of Illinois’ renewable energy, equity, climate, electrification, and environmental goals over a five-year period.
Heating degree-daysdegree 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. By its election to participate in this regulatory framework, Ameren Illinois is required to make incremental capital expenditures to modernize itsestablished electric distribution system, to meet performance standards,rates through 2023 and to create jobs in Illinois, among other requirements.will reconcile related revenue requirements under this process.
Illinois Credit Agreement –Ameren’s and Ameren Illinois’ $1.1$1.2 billion senior unsecured credit agreement, which expires in December 2021,2027, 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.
IPHIRA – Illinois Power Holdings, LLC,The Inflation Reduction Act of 2022, federal legislation enacted in August 2022, which includes various provisions, such as expanded production and investment tax credits for clean energy investments, transferability of certain tax credits to an indirect wholly owned subsidiary of Dynegy Inc.unrelated party for cash, and a corporate alternative minimum tax on certain entities, among other things.
IRS – Internal Revenue Service, a United States government agency.
ISRS – Infrastructure system replacement surcharge, a cost recovery mechanism that allows Ameren Missouri to recover natural gas infrastructure replacement costs from customers without a traditional rate proceeding.
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.
Medina ValleyMEEIA – AmerenEnergy Medina Valley Cogen, LLC, an Ameren Corporation subsidiary.
MEEIA –A rate-adjustment mechanism allowed under the Missouri Energy Efficiency Investment Act, a Missouri law that allows electric utilities to recover costs and performance incentives, if any, related to MoPSC-approved customer energy-efficiency programs.programs without a traditional regulatory rate review, subject to MoPSC prudence reviews.
MEEIA 2013 2019 –Ameren Missouri’s portfolio of customer energy-efficiency programs, net shared benefits,recovery of lost electric margins, and performance incentiveincentives for 2013March 2019 through 2015,December 2024, pursuant to the MEEIA,Missouri law, as approved by the MoPSC in August 2012.December 2018.
MEEIA 2016 –Ameren Missouri’s portfolio of customer energy-efficiency programs, throughput disincentive, and performance incentive for March 2016 through February 2019, pursuant to the MEEIA, as approved by the MoPSC in February 2016.
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$1.4 billion senior unsecured credit agreement, which expires in December 2021,2027, unless extended.
Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.
Mmbtu – One million Btus.
Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.
Moody’s – Moody’s Investors Service, Inc., a credit rating agency.
MoOPC–Missouri Office of Public Counsel.
MoPSC – Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including Ameren Missouri.
MRO– Midwest Reliability Organization, one of the regional electric reliability councils organized for coordinating the planning and operation of the United States’ bulk power supply.
MTM – Mark-to-market.
MW – Megawatt.
MWh – Megawatthour, one thousand kilowatthours.
MW-day – Megawatt-day, a measure of electric generation equivalent to one MW of power generated over one day.
MYRP – Multi-year rate plan, a four-year electric distribution service rate plan allowed to be filed with the ICC under the CEJA. Under a multi-year rate plan, the ICC will approve base rates for electric distribution service charged to customers for each calendar year of a four-year period. Ameren Illinois will reconcile its actual revenue requirement to the ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap with exclusions for certain costs and riders, and adjustments to the ICC-determined ROE for performance incentives and penalties.
Native load – End-use retail customers whom we areAmeren Missouri or Ameren Illinois is obligated to serve by statute, franchise, contract, or other regulatory requirement.
Natural gas margins – Natural gas revenues less natural gas purchased for resale.
NAV – Net asset value per share.
NEIL – Nuclear Electric Insurance Limited, which includes all of its affiliated companies.
NERC – North American Electric Reliability Corporation.
Net energy costs – Net energy costs, as defined in the FAC, which include fuel, fuel transportation, certain fuel additives, ash disposal costs and revenues, emission allowances, and purchased power costs, including transportation, net of off-system sales.sales and capacity revenues. Substantially all transmission revenues and charges are excluded from net energy costs. Effective February 28, 2022, all off-system sales from the High Prairie Renewable and Atchison Renewable energy centers are excluded as those sales are included in the RESRAM. Prior to this change, 95% of these sales were included in the FAC and 5% were included in the RESRAM.
Net shared benefits metering – Ameren Missouri’s share ofNet 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 present value of lifetimegrid. Customers receive a credit for the energy savings, net of program costs, designedthey add to offset sales volume reductions resulting from MEEIA 2013 customer energy-efficiency programs.the grid.
New AER – New Ameren Energy Resources Company, LLC, a limited liability company formed as a direct wholly owned subsidiary of AER. New AER, acquired by IPH in December 2013, included substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren.
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.
OATT – Open Access Transmission Tariff.
OCI – Other comprehensive income (loss) as defined by GAAP.
Off-system sales revenues– Revenues from other than native load sales, including wholesale sales.
OTC – Over-the-counter.
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.
PUHCA 2005PHMSA – Pipeline and Hazardous Materials Safety Administration, a United States government agency.
PISA – Plant-in-service accounting regulatory mechanism, a mechanism under Missouri law that permits electric utilities to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on rate base for certain property, plant, and equipment placed in service, and not included in base rates, subject to MoPSC prudence reviews. The Public Utility Holding Company Actrate base on which the return is calculated incorporates qualifying capital expenditures not included in base rates, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes. The regulatory asset for accumulated PISA deferrals earns a return at the applicable WACC. The PISA is effective through 2028, unless Ameren Missouri requests and receives MoPSC approval of 2005.an extension through 2033.
QIP – Qualifying infrastructure plant. Costsplant, a rate-adjustment mechanism that provided Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure natural gas plant are includedinvestments that were placed in an Ameren Illinois recovery mechanism.service between regulatory rate reviews, subject to ICC prudence reviews. The QIP expired in December 2023.
Rate base –The basis on which a publicrate-regulated 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-adjustment mechanism, a regulatory mechanism allowed under Missouri law that enables Ameren Missouri to recover costs relating to compliance with Missouri’s renewable energy standard, including recovery of investments in wind generation and other renewables, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism by adjusting customer rates on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. RESRAM regulatory assets earn carrying costs at short-term interest rates.
Revenue requirement – The cost of providing utility service to customers, which is calculated as the sum of a utility’s recoverable operating expenses, and an alloweda return at the weighted-average cost of capital on rate base, including 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, through customer rates of amounts specified by the mechanism without a traditional regulatory rate review.
ROE– Return on common equity.
RTO– Regional transmission organization.
S&P&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’sUnited States’ bulk power supply.
Smart Energy Plan – Ameren Missouri’s plan to upgrade Missouri’s electric grid through at least 2028. Planned upgrades include investments to improve reliability and accommodate more renewable energy.
SO2– Sulfur dioxide.
STEM – Science, technology, engineering, and math.
TCJA – The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities; itentities. 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, are effective for taxable years beginning after December 31, 2017.
Test yearyear– 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.
Throughput disincentive Tracker–Ameren Missouri’s reduced margin caused by a regulatory recovery mechanism that allows for the current period’s lower sales volume resultingdeferral 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, MEEIA 2016 customer energy-efficiency programs. Recoveryor refunded to, customers over a period of this disincentive is designed to make Ameren Missouri earnings neutral eachtime 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 from the lost margins caused by its MEEIA 2016 customer energy-efficiency programs.of time assuming all dividends are reinvested.
WestinghouseVBA– Westinghouse Electric Company, LLC.
VBA – A volumeVolume balancing adjustment, a rate-adjustment mechanism for Ameren Illinois’ natural gas operations. 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 adjustmentallows Ameren Illinois to adjust customer rates without a traditional regulatory rate review, subject to ICC prudence reviews. The rider ensures that
Ameren Illinois’ natural gas revenues are not affected by changes in sales volumes, including those resulting from deviations from normal weather conditions, do not result in an over- or under-collectionfor residential and small nonresidential customers.
WACC – Weighted-average cost of capital, which is the weighted-average cost of debt and equity, as allowed by the applicable regulator.
WNAR – Weather normalization adjustment rider, a rate-adjustment mechanism that allows Ameren Missouri to adjust natural gas delivery service rates charged to residential customers without a traditional regulatory rate review, subject to MoPSC prudence reviews, when deviations from normal weather conditions cause natural gas revenues for theseto vary from the related revenue requirement approved by the MoPSC in the previous regulatory rate classes.review.
Zero-emissionZero emission credit – A credit that represents the environmental attributes of one MWh of energy produced from certain zero-emissionszero emissions nuclear-powered generation facilities, which certain Illinois utilities are required to purchase pursuant to the FEJA.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, projections, strategies, targets, estimates, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed within Risk Factors under Part I, Item 1A, of this report, and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
•regulatory, judicial, or legislative actions, and any changes in regulatory policies and ratemaking determinations, that may change regulatory recovery mechanisms, such as those that may result from Ameren Missouri’s petition to the complaint case filed in February 2015 withMoPSC for a financing order to authorize the FERC seeking a reduction inissuance of securitized utility tariff bonds to finance the allowed base return on common equitycost of the planned retirement of the Rush Island Energy Center, Ameren Missouri’s proposed customer energy-efficiency plan under the MISO tariff, Ameren Missouri’s proceedingMEEIA filed with the MoPSC in January 2024, Ameren Illinois’ December 2023 ICC order for the MYRP electric distribution service regulatory rate review that directed Ameren Illinois to passfile a revised Grid Plan for 2023 through 2027 along with Ameren Illinois’ January 2024 rehearing request of the order and appeal of the order to customerthe Illinois Appellate Court for the Fifth Judicial District, Ameren Illinois’ appeal of the November 2023 ICC natural gas delivery service rate order to the Illinois Appellate Court for the Fifth Judicial District, and the August 2022 United States Court of Appeals for the District of Columbia Circuit ruling that vacated FERC’s MISO ROE-determining orders and remanded the proceedings to the FERC;
•our ability to control costs and make substantial investments in our businesses, including our ability to recover costs and investments, and to earn our allowed ROEs, within frameworks established by our regulators, while maintaining affordability of services for our customers;
•the effect and duration of Ameren Illinois’ election to utilize MYRPs for electric distribution service ratemaking effective for rates beginning in 2024, including the effect of the reduction inreconciliation cap on the federal statutory corporate income tax rate enacted under the TCJA, Ameren Illinois’ natural gas regulatory rate review filed with the ICC in January 2018, Ameren Illinois’ proceeding filed with the ICC to pass through to its natural gas customer rates the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA, the request filed by MISO participants, including Ameren Illinois and ATXI, with the FERC to allow revisions to 2018 electric transmission rates to reflect the impacts of the reduction in the federal statutory corporate income tax rate enacted under the TCJA, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;distribution revenue requirement;
•the effect of Ameren Illinois’ participation inuse of the performance-based formula ratemaking frameworks under the IEIMAframework for its participation in electric energy-efficiency programs, and the FEJA, includingrelated impact of the direct relationship between Ameren Illinois’ return on common equityROE and the 30-year United States Treasury bond yields,yields;
•the effect on Ameren Missouri of any customer rate caps or limitations on increasing the electric service revenue requirement pursuant to Ameren Missouri’s election to use the PISA;
•Ameren Missouri’s ability to construct and/or acquire wind, solar, and other renewable energy generation facilities and battery storage, as well as natural gas-fired energy centers, extend the operating license for the Callaway Energy Center, retire fossil fuel-fired energy centers, and implement new or existing customer energy-efficiency programs, including any such construction, acquisition, retirement, or implementation in connection with its Smart Energy Plan, integrated resource plan, or emissions reduction goals, and to recover its cost of investment, a related return, and, in the case of customer energy-efficiency programs, any lost margins in a timely manner, each of which is affected by the ability to obtain all necessary regulatory and project approvals, including CCNs from the MoPSC or any other required approvals for the addition of renewable resources and natural gas-fired energy centers;
•Ameren Missouri’s ability to use or transfer federal production and investment tax credits related to renewable energy projects; the cost of wind, solar, and other renewable generation and storage technologies; and our ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost for each facility;
•the outcome of competitive bids related to requests for proposals associated with the MISO’s long-range transmission planning;
•the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments, including as they relate to the construction and acquisition of electric and natural gas utility infrastructure and the related financial commitments;ability of counterparties to complete projects, which is dependent upon the availability of necessary materials and equipment, including those obligations that are affected by supply chain disruptions;
•advancements in energy technologies, including carbon capture, utilization, and sequestration, hydrogen fuel for electric production and energy storage, next generation nuclear, and large-scale long-cycle battery energy storage, and the impact of federal and state energy and economic policies with respect to those technologies;
•the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, foreign trade, and energy policies;
•the effects of changes in federal, state, or local tax laws or rates, including the effects of the IRA and the 15% minimum tax on adjusted financial statement income, as well as additional regulations, interpretations, amendments, or technical corrections to, or in connection with the TCJA,IRA, and any challenges to the tax positions taken by the Ameren Companies;Companies, if any, as well as resulting effects on customer rates and the recoverability of the minimum tax imposed under the IRA;
•the effects on energy prices and demand for our services resulting from technological advances, including advances in customer energy-efficiencyenergy 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 plans;
Ameren Illinois’ ability to achieve the FEJA electric energy-efficiency goals and the resulting impact on its allowed return on program investments;
our ability to align overall spending, both operating and capital, with frameworks established by our regulators and to recover these costs in a timely manner in our attempt to earn our allowed returns on equity;
•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 natural gas for distribution and purchased power, zero-emissionincluding capacity, zero emission credits, renewable energy credits, and natural gas for distribution;emission allowances; and the level and volatility of future market prices for such commodities including our ability to recover the costs for such commodities 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 Westinghouse, Callaway energy center’s onlyprimarily one NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;
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 Callaway energy center, or, in the absence of insurance, the ability to recover uninsured losses from our customers;
business and economic conditions, including their impact on interest rates, collection of our receivable balances, and demand for our products;
the effects of the TCJA on us and the resulting treatment by regulators will have on our results of operations, financial position, and liquidity;
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;
the impact of adopting new accounting guidance and the application of appropriate accounting rules and guidance;
the impact of weather conditions and other natural phenomena on us and our customers, including the impact of system outages;
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 our increasing investment in electric transmission projects, as well as potential wind and solar generation projects, our ability to obtain all of the necessary approvals to complete the projects, and the uncertainty as to whether we will achieve our expected returns in a timely manner;
operation of Ameren Missouri’s Callaway energy center, including planned and unplanned outages, and decommissioning costs;Energy Center assemblies;
the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
| |
• | the impact of current environmental regulations and new, more stringent, or changing requirements, including those related to CO2, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our 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 negative opinions of us or our utility services that our customers, 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 protect sensitive customer information, increases in rates, or negative media coverage;
the impact of complying with renewable energy portfolio requirements in Missouri and Illinois;
labor disputes, work force reductions, future wage and employee benefits costs, including changes in discount rates, mortality tables, and returns on benefit plan assets;
the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments;
•the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy Ameren Missouri’sour energy sales;
legal•the effectiveness of our risk management strategies and administrative proceedings;our use of financial and derivative instruments;
•the ability to obtain sufficient insurance or, in the absence of insurance, the ability to timely recover uninsured losses from our customers;
•the impact of cyber attacks,cyberattacks and data security risks on us, our suppliers, or other entities on the grid, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information; and
•acts of sabotage, which have increased in frequency and severity within the utility industry, war, terrorism, or other intentionally disruptive acts.acts;
•business, economic, and capital market conditions, including the impact of such conditions on interest rates, inflation, and investments;
•the impact of inflation or a recession on our customers and the related impact on our results of operations, financial position, and liquidity;
•disruptions of the capital and credit markets, deterioration in credit metrics of the Ameren Companies, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity, and our ability to access the capital and credit markets on reasonable terms when needed;
•the actions of credit rating agencies and the effects of such actions;
•the impact of weather conditions and other natural phenomena on us and our customers, including the impact of system outages and the level of wind and solar resources;
•the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;
•the ability to maintain system reliability during the transition to clean energy generation by Ameren Missouri and the electric utility industry as well as Ameren Missouri’s ability to meet generation capacity obligations;
•the effects of failures of electric generation, electric and natural gas transmission or distribution, or natural gas storage facilities systems and equipment, which could result in unanticipated liabilities or unplanned outages;
•the operation of Ameren Missouri’s Callaway Energy Center, including planned and unplanned outages, as well as the ability to recover costs associated with such outages and the impact of such outages on off-system sales and purchased power, among other things;
•Ameren Missouri’s ability to recover the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs;
•the impact of current environmental laws and new, more stringent, or changing requirements, including those related to NSR, CO2, NOx, and other emissions and discharges, Illinois emission standards, cooling water intake structures, CCR, energy efficiency, and wildlife protection, that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our operating costs or investment requirements, result in an impairment of our assets, cause us to sell our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;
•the impact of complying with renewable energy standards in Missouri and Illinois and with the zero emission standard in Illinois;
•the effectiveness of Ameren Missouri’s customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA programs;
•Ameren Illinois’ ability to achieve the performance standards applicable to its electric distribution business and electric customer energy-efficiency goals and the resulting impact on its allowed ROE;
•labor disputes, work force reductions, changes in future wage and employee benefits costs, including those resulting from changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;
•the impact of negative opinions of us or our utility services that our customers, investors, legislators, regulators, creditors, or other stakeholders may have or develop, which could result from a variety of factors, including failures in system reliability, failure to implement our investment plans or to protect sensitive customer information, increases in rates, negative media coverage, or concerns about ESG practices;
•the impact of adopting new accounting and reporting guidance;
•the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
•legal and administrative proceedings;
•pandemics or other significant global health events, and their impacts on our results of operations, financial position, and liquidity; and
•the impacts of the Russian invasion of Ukraine and the Israel-Hamas war, related sanctions imposed by the U.S. and other governments, and any broadening of these or other global conflicts, including potential impacts on the cost and availability of fuel, natural gas, enriched uranium, and other commodities, materials, and services, the inability of our counterparties to perform their obligations, disruptions in the capital and credit markets, and other impacts on business, economic, and geopolitical conditions, including inflation.
New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.
PART I
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 including– Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as the provision ofproviding shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise. 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 developing MISO-approved electric transmission projects, includingbusiness in the Illinois Rivers and Mark Twain projects, and placed the Spoon River project in service in February 2018.
The following table presents our total employees at December 31, 2017:
|
| | |
Ameren Missouri | 3,639 |
|
Ameren Illinois | 3,423 |
|
Ameren Services | 1,553 |
|
Ameren | 8,615 |
|
Labor unions at 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, 2017, these labor unions collectively represented about 52% of Ameren’s total employees. They represented 62% and 57% of the employees at Ameren Missouri and Ameren Illinois, respectively. The collective bargaining agreements expire between 2018 and 2020.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 is primarily composedconsists 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 and Ameren Illinois’Companies’ reporting structures is provided below. For additional information on financial reporting segments, see Note 1 – Summary of Significant Accounting Policies and Note 15 – Segment Information under Part II, Item 8, of this report.below:
| |
(a) | Ameren Transmission segment includes associated 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 businessesbusiness experiencing the least amount of regulatory lag. Depending on the
jurisdiction, the effects of regulatory lag are mitigated by various means, including annual revenue requirement reconciliations, the usedecoupling of revenues from sales volumes to ensure revenues approved in a future test year,regulatory rate review are not affected by changes in sales volumes, the implementationrecovery of trackers and riders,certain capital investments between traditional regulatory rate reviews, the level and timing of expenditures, the use of future test years to establish customer rates, and regulatory frameworks that include annual revenue requirement reconciliationsthe use of trackers and decoupling of revenues from sales volumes.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, 2018:2024, except as noted: | | | | Rate Regulator | Allowed
Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren’s 2017 Operating Revenues(a) |
| Rate Regulator | | | Rate Regulator | Effective
Rate Order
Issued In | Rates Effective | Allowed
ROE | Percent of
Common Equity | Rate Base
(in billions) | Portion of Ameren’s 2023 Operating Revenues(a) |
| Ameren Missouri | |
Electric service(b) | |
Electric service(b) | |
Electric service(b) | MoPSC | 9.2% - 9.7%(c) | (c) | 54% | MoPSC | June 2023 | July 2023 | (c) | 49% |
| Natural gas delivery service | MoPSC | (d) | 2% | Natural gas delivery service | MoPSC | December 2021 | February 2022 | (d) | $0.3 | 2% |
| Ameren Illinois | |
Electric distribution delivery service(e) | |
Electric distribution delivery service(e) | |
Electric distribution delivery service(e) | ICC | 8.40% | 50.0% | $2.7 | 25% | ICC | December 2023 | January 2024 | 8.72% | 50.00% | $3.9 | 29% |
Natural gas delivery service(f) | ICC | 9.60% | 50.0% | $1.2 | 12% | Natural gas delivery service(f) | ICC | November 2023 | 9.44% | 50.00% | $2.8 | 12% |
Electric transmission service(g) | FERC | 10.82% | 51.6% | $1.6 | 4% | Electric transmission service(g) | FERC | (g) | January 2024 | 10.52% | 54.90% | $3.9 | 5% |
| ATXI | |
Electric transmission service(g) | FERC | 10.82% | 56.2% | $1.3 | 3% |
Electric transmission service(g) | |
Electric transmission service(g) | | FERC | (g) | January 2024 | 10.52% | 60.16% | $1.5 | 3% |
| |
(a) | Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and natural gas purchased for resale for natural gas delivery service, and intercompany eliminations. |
| |
(b) | Ameren Missouri’s electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate. |
| |
(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%. |
| |
(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. It includes the impacts on rate base and operating revenues relating to the ISRS for investments after the January 2011 rate order. |
| |
(e) | Based on the ICC’s December 2017 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The December 2017 rate order was based on 2016 recoverable costs, expected net plant additions for 2017, and the monthly yields during 2016 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ 2018 electric distribution delivery service revenues will be based on its 2018 actual recoverable costs, rate base, common equity percentage, and return on common equity, as calculated under the IEIMA’s performance-based formula ratemaking framework. |
| |
(f) | Based on the ICC’s December 2015 rate order. The rate order was based on a 2016 future test year. |
| |
(g) | (a)Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and natural gas purchased for resale for natural gas delivery service, and intercompany eliminations. (b)Ameren Missouri’s electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate. Because the bundled rates charged to MoPSC retail customers include the revenue requirement associated with Ameren Missouri's FERC-regulated transmission services, the table above does not separately reflect a FERC-authorized rate base or allowed ROE. (c)This rate order did not specify an ROE, capital structure, or rate base. (d)This rate order did not specify an ROE or a capital structure. (e)In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027. This rate order was based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ 2022 year-end rate base approved by the 2022 electric distribution service revenue requirement reconciliation adjustment order. The December 2023 ICC order rejected Ameren Illinois’ Grid Plan, which was addressed as part of the MYRP proceeding. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The ICC will be under no deadline to act on the revised Grid Plan when filed. This rate base will remain in effect through 2027, unless the rehearing of the MYRP order or approval of a revised Grid Plan by the ICC results in an update of each year’s revenue requirement. Under an MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. (f)This rate order was based on a 2024 future test year. (g)Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking based on each year’s forecasted information. The 10.82% return, which includes the 50 basis points incentive adder for participation in an RTO, could be lowered by 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. |
Ameren Missouri
Ameren Missouri’s electric operating revenues are subject to regulation by the MoPSC. If certain criteria are met, Ameren Missouri’s electric rates may be adjusted without a traditional rate proceeding. For example, Ameren Missouri’s MEEIA customer energy-efficiency program costs, net shared benefits or throughput disincentive, 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 FAC and the MEEIA recovery mechanisms, Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, 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 is a member of MISO, and its transmission rate is calculated in accordance with the MISO OATT. 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 subject to regulation by the MoPSC. If certain 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 more timely basis between regulatory rate reviews. Ameren Missouri is not currently recovering any infrastructure replacement costs under the ISRS.
Ameren Illinois
Ameren Illinois Electric Distribution
Ameren Illinois’ electric distribution delivery service operating revenues are regulated by the ICC. In 2017, 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 and the FEJA. The IEIMA 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. The return on equity component of the formula rate is equal to the calendar year average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement included in customer rates for that year, including an allowed return on equity. This annual revenue requirement reconciliation adjustment will be collected from, or refunded to, customers within two years.
The FEJA revised certain portions of the IEIMA, extending the IEIMA formula ratemaking framework through 2022, and clarifying that a common equity ratio up to and including 50% is prudent. 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 the FEJA, 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 the IEIMA in 2022. Through 2022, revenue differences will be included in the annual IEIMA revenue requirement reconciliation. Additionally, this law implemented a customer surcharge 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, will be passed through to electric distribution customers with no effect on Ameren Illinois’ earnings.
Pursuant to the FEJA, and consistent with the energy-efficiency plan for 2018 through 2021 approved by the ICC, Ameren Illinois plans to invest up to $99 million in electric energy-efficiency programs per year. Ameren Illinois plans to make additional investments of a similar level in electric energy-efficiency programs per year that will earn a return through 2030. The electric energy-efficiency program investments and the 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 regulatory framework applicable to electric
distribution service provides for return on equity penalties up to 34 basis points in 2018, and up to 38 basis points in each year from 2019 through 2022, if these performance standards are not met. Beginning in 2018, the regulatory framework applicable to 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.
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. From 2012 through 2017, Ameren Illinois invested $508 million in IEIMA capital projects toward its $625 million requirement.
Ameren Illinois employs cost recovery mechanisms for power procurement, customer energy-efficiency program costs incurred before June 2017, 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 December 2015, the ICC issued a rate order that approved an increase in revenues for Ameren Illinois’ natural gas delivery service, based on a 2016 future test year. The rate order also approved the VBA for residential and small nonresidential customers. In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49 million, which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider, as explained in more detail below. The request was based on a 10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. If certain 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. 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. Recovery begins two months after the natural gas investments are placed in service and continues until the investments are included in base rates in a future natural gas 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 the natural gas rate order, QIP recoveries will be included in base rates and the QIP rider will be 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 2017, Ameren Illinois’ transmission service 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 is primarily composed 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 OATT. 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 updatedbased on each January withyear’s forecasted information. A reconciliation at the end of the year,The 10.52% return, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates inincludes a subsequent year. Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution 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 of 12.38% was challenged by customer groups in two complaint cases filed in November 2013 and in February 2015. As a result of a FERC order issued in the November 2013 complaint case, a 10.82% total allowed return on common equity has been reflected in rates since September 2016, inclusive of the 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 point50-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 establishRTO, is based on 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 September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. The FERC is under no deadline to issue a final order in the February 2015 complaint case.
ATXI has three MISO-approved multi-value projects, the Illinois Rivers, Spoon River, and Mark Twain projects. As of December 31, 2017, ATXI’s expected remaining investment in all three projects was approximately $300 million, with the total investment expected to be more than $1.6 billion. The Illinois Rivers project involves the construction of a 345-kilovolt line from eastern Missouri across Illinois to western Indiana. ATXI has obtained a certificate of public convenience and necessity and project approvals from the ICC and the MoPSC for each state’s portion of the Illinois Rivers project. The last line segment of this project is expected to be completed by the end of 2019; however, delays associated with property acquisition could delay the completion date. As of December 31, 2017, all 10 substations and seven of the nine line segments for Illinois Rivers were complete and in-service. The Spoon River project is located in northwest Illinois. ATXI placed the Spoon River project in service in February 2018. The Mark Twain project is located in northeast Missouri and connects Iowa to the Illinois Rivers project. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to complete the Mark Twain project by the end of 2019.
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.FERC’s May 2020 order.
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.
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.consolidations. In addition, Ameren Missouri, Ameren Illinois, and ATXI must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities (with maturities of more than 12 months) and to conduct mergers, affiliate transactions, and various other activities.
Ameren Missouri, Ameren Illinois, and ATXI are also subject to mandatory reliability standards, including cybersecurity standards adopted by the FERC, to ensure the reliability of the bulk electric power system. These standards are developed and enforced by the NERC, pursuant to authority delegated to it by the FERC. Ameren Missouri, Ameren Illinois, and ATXI are members of the SERC. The SERC is one of six regional entities and represents all or portions of 16 central and southeastern states under authority from the NERC for the purpose of
implementing and enforcing reliability standards approved by the FERC. Ameren Missouri is also a member of the MRO, which is also one of the six regional entities and represents all or portions of 16 central, southern, and midwestern states, as well as two Canadian provinces, under authority from the NERC. The regional entities of the NERC work to safeguard the reliability of the bulk power systems throughout North America. If any of Ameren Missouri, Ameren Illinois, or ATXI is found not to be in compliance with these mandatory reliability standards, it could incur substantial monetary penalties and other sanctions.
Under PUHCAthe 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. PUHCA 2005The act also permits the MoPSC and the ICC to request that the FERC review cost allocations by Ameren Services to other Ameren companies.subsidiaries.
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 inon 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 electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of our operations are subject to federal, state, and local environmental statutes and regulations relating to the protection of the safetyenvironment and human health of our personnel, the public, and the environment.safety. These environmental statutes and regulations are comprehensive and include requirements relating to identification, generation,the storage, handling, transportation, disposal, recordkeeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials; safety and health standards; and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants and the management of waste and byproduct materials. Failure to comply with these statutes or regulations could have material adverse effects 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 statutes and regulations 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, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% 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 revised 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 underwaste materials and hazardous substances, emergency planning and response requirements, limitations and standards applicable to discharges from our facilities into the CCR rule, which will require the closure of surface impoundmentsair or water that are enforced through permitting requirements, 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.Amerenwildlife protection laws, including those related to endangered species. Federal 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 and adopt new regulations, which adds uncertainty tomay impact our planning process and to the ultimate implementation of these or other new or revised regulations. Local and state land use requirements can also potentially impact our planning activities.
For 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 2017,The AMMO balancing authority area includes the load and most energy centers of Ameren Missouri, and had a peak demand was 7,814 megawattsof 7,836 MWs in AMMO2023. The AMIL balancing authority area includes the load of Ameren Illinois and 8,877 megawattscertain natural gas-fired energy centers of Ameren Missouri, and had a peak demand of 8,859 MWs in AMIL.2023. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
Ameren Missouri, Ameren Illinois, and ATXI are transmission-owning members of the MISO. Ameren Missouri is authorized by the MoPSC to participate in the MISO through May 2020. The previously requiredfor an indefinite term, subject to the MoPSC’s authority to require future proceedings if an event or circumstance occurs that significantly affects Ameren Missouri’s position in the MISO. Ameren Illinois’ election to participate in the MISO is subject to the ICC’s oversight. In July 2022, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study related to Ameren Missouri’sof continued participation in the MISO as required periodically by the MoPSC and originally expectedcompared to beparticipation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed in 2017, was deferred upon approval of the MoPSC. Ameren Missouri expects to file the periodicits cost-benefit study with the ICC. The study concluded that continued participation in 2020, based on the deferral granted byMISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. In January 2024, the MoPSC.ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study. For additional information regarding the RTO cost-benefit study, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
Ameren Missouri, Ameren Illinois, and ATXI are members
SUPPLY OF ELECTRIC POWER
Capacity
Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. In the April 2023 MISO capacity auction, Ameren Missouri’s generation resources exceeded its native load capacity requirements for the June 2023 through May 2024 period. Ameren Illinois purchases capacity from the MISO and through bilateral contracts resulting from IPA procurement events. In 2022, the FERC issued an order approving changes to the annual MISO capacity auction. Historically, the auctions were designed to cover annual peak demand plus a target reserve margin. Beginning with the April 2023 auction for the June 2023 to May 2024 planning year, auctions include four seasonal load forecasts and available capacity levels and are designed to cover each season’s peak demand plus a target reserve margin. The seasonal auction structure was established to help to address variability in resources as the MISO begins to rely more heavily on renewable generation.
Ameren Missouri
Ameren Missouri’s electric supply is primarily generated from its energy centers. Factors that could cause Ameren Missouri to purchase power include, among other things, energy center outages, the fulfillment of renewable energy portfolio 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 absencethe lack of sufficient owned generation.generation availability.
Ameren Missouri files a long-term nonbinding 20-year integrated resource plan with the MoPSC every three years. The most recent integrated resource plan was filed in September 2017,2023 and includes Ameren Missouri’s preferred approachplan for meeting customers’ projected long-term energy needs in a cost-effective manner that maintains system reliability and customer affordability while maintaining system reliability. The plan targets cleaner and more diverse sources oftransitioning to clean energy generation including solar, wind,in an environmentally responsible manner. The preferred plan includes, among other things, the following:
•adding an 800-MW natural gas, hydro,gas-fired simple-cycle energy center by 2027 and nuclear power. It also includes expandingan additional 1,200-MW natural gas-fired combined-cycle energy center by 2033, representing investment opportunities of $0.8 billion and $1.7 billion, respectively;
•adding 2,800 MWs of renewable generation by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, adding 100 megawatts2030, which includes the 900 MWs of solar generation over the next 10 years, projects discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and an additional 1,900 MWs by 2036, representing investment opportunities of $5.3 billion and $4.1 billion, respectively;
•adding 400 MWs of battery storage by 2030 and an additional 400 MWs by 2035, representing investment opportunities of $0.6 billion and $0.7 billion, respectively;
•adding 1,200 MWs of other clean dispatchable generation resources by 2040 and an additional 1,200 MWs by 2043;
•retiring all of Ameren Missouri’s coal-fired energy centers as they reachby 2042;
•accelerating the endretirement date of their usefulthe Rush Island coal-fired energy center from 2025 to 2024;
•extending the retirement date of the Sioux coal-fired energy center from 2030 to 2032 to ensure reliability during the transition to clean energy generation, which is subject to the approval of a change in depreciable lives expandingof the energy center’s assets by the MoPSC;
•retiring 1,800 MWs of Ameren Missouri’s natural gas-fired energy centers by 2040 to comply with Illinois law;
•the continued implementation of customer energy-efficiency programs, and adding cost-effective demand response programs.programs; and
•the expectation that Ameren Missouri will seek and receive NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date.
The addition of renewable or natural gas-fired generation facilities is subject to obtaining necessary project approvals, including FERC approval and the issuance of a CCN by the MoPSC, as applicable. Ameren Missouri would be adversely affected if the MoPSC does not allow recovery of the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs. In connection with the accelerated retirement of the Rush Island Energy Center, Ameren Missouri is seeking approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute. The next integrated resource plan is expected to be filed in September 2026.
Ameren Missouri continues to evaluate its longer-term needs for new generating capacity. The need for ainvestment in new sources of energy center is dependent on several key factors, including continuation of and customer participation in energy-efficiency programs, andthe amount of distributed generation from customers, load growth, technological advancements, costs of generation alternatives, environmental regulation of coal-fired and natural gas-fired power plants, and state renewable portfolio standards,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, natural gas-fired generation, including the potential to switch to hydrogen fuel and/or blend hydrogen fuel with natural gas and install carbon capture technology, extending the operating license for the Callaway Energy Center, additional customer energy-efficiency and demand response programs, distributed energy resources, and energy storage.
See also OutlookMissouri law required Ameren Missouri to offer solar rebates through December 2023 and currently requires Ameren Missouri to offer net metering to certain customers that install renewable generation at their premises. The difference between the cost of the solar rebates and the amount set in Management’s Discussionbase rates was deferred as a regulatory asset or liability under the RESRAM, 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.earn carrying costs at short-term interest rates. Customers that elect to enroll in net metering are allowed to net their generation against their distribution usage within each billing month.
Ameren Illinois
In Illinois, while electric transmission and distribution service rates are regulated, power supply prices are not. Although electric customers are allowed to purchase power from an alternative retail electric supplier, Ameren Illinois is required to be the provider of last resort for its electric distribution customers. In 2017, 2016,2023, 2022, and 2015,2021, Ameren Illinois procured power on behalf of its customers for 23%28%, 23%28%, and 26%23%, respectively, of its total kilowatthour sales. Power purchased by Ameren Illinois for its electric distribution customers who do not elect to purchase their power from an alternative retail electric supplier comes either through procurement processes conducted by the IPA or through markets operated by the MISO. The IPA administers an RFP process through which Ameren Illinois procures its expected supply. The purchased power and related procurement costs incurred by Ameren Illinois are passed directly to its electric distribution customers through a cost recovery mechanism. Transmission costs are charged to customers who purchase electricity from Ameren Illinois through a cost recovery mechanism. The purchased power, power procurement, and transmission costs are reflected in Ameren Illinois Electric Distribution’s results of operations, but do not affect Ameren Illinois Electric Distribution’s earnings because these costs are offset by corresponding revenues. Ameren Illinois charges transmission and distribution service rates to electric distribution customers who purchase electricity, from alternative retail electric suppliers,regardless of supplier, which does affect Ameren Illinois Electric Distribution’s earnings.
SeePursuant to the CEJA, Ameren Illinois is required to file a Grid Plan with the ICC every four years. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024 after its initial Grid Plan for the years 2023 to 2027 was rejected by the ICC’s December 2023 order in Ameren Illinois’ MYRP proceeding. For additional information regarding Ameren Illinois’ MYRP proceeding, see Note 132 – Related-party TransactionsRate and Note 14 – Commitments and ContingenciesRegulatory Matters under Part II, Item 8, of this report for additional information onreport. The Grid Plan outlines how Ameren Illinois expects to invest in electric distribution infrastructure in order to support grid modernization, clean energy, energy efficiency, and the state of Illinois’ renewable energy, equity, climate, electrification, and environmental goals. Ameren Illinois’ next Grid Plan is required to be filed by mid-January 2026.
Illinois law requires Ameren Illinois to offer rebates and net metering to certain customers who install renewable generation or paired energy storage systems at their premises. The cost of the customer generation rebate program is deferred as a regulatory asset, which earns a return at the applicable WACC. Customers that elect to receive a generation rebate and are enrolled in net metering are allowed to net their power procurementsupply service charges, but not their distribution service charges. Customers that elect to receive energy storage rebates and have not received generation rebates are allowed to net their power supply and distribution service charges. By law, Ameren Illinois’ electric distribution revenues are decoupled from sales volumes, which ensures that the electric distribution revenues authorized in Illinois.a regulatory rate review are not affected by changes in sales volumes.
POWER GENERATION
Ameren Missouri owns energy centers that rely on a diverse fuel portfolio, including coal, (Ameren Missouri’s primary fuel source), nuclear, and natural gas, as well as renewable sources of generation, which include hydroelectric, wind, methane gas, and solar. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978. As of December 31, 2023, Ameren Missouri’s coal-fired energy centers represented 8% and 16% of Ameren’s and Ameren Missouri’s rate base, respectively. The Callaway nuclear energy centerEnergy Center began operation in 1984 and is licensed to operate until 2044. AsAmeren Illinois operates a solar generation facility, which is one of December 31, 2017,two pilot solar projects Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33%Illinois is allowed to invest in under the CEJA. The second solar generation facility is planned be placed in service before the end of Ameren’s and Ameren Missouri’s rate base, respectively.2025. See Item 2 – Properties under Part I of this report for information regarding Ameren Missouri’s electric generationour 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, 2017, Ameren Missouri had price-hedged 88% of its expected coal supply and 99% of its coal transportation requirements for generation in 2018.While Ameren Missouri has additional coal supply under contract through 2021. The coal transportminimum purchase obligations associated with these agreements, that Ameren Missouri hasthe majority of these agreements are not associated with Union Pacific Railroad and Burlington Northern Santa Fe Railway are currently set to expire at the end of 2019.any specific coal-fired energy center. Ameren Missouri burned approximately 18.611.5 million tons of coal in 2017.2023. For information regarding the percentages of Ameren Missouri’s projected required supply of coal and coal transportation that are price-hedged through 2028, see Commodity Price Risk under Part II, Item 7A, of this report.
About 97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming.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, staffing and equipment issues, infrastructure maintenance, derailments, weather, and weather. As of December 31, 2017, coal inventories for Ameren Missouri were near targeted levels. Disruptionssupplier financial hardship. Delays and disruptions in coal deliveries could cause Ameren Missouri to pursue a strategy that could include reducing off-system sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.
Nuclear
The production of nuclear fuel involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, the enrichment of that gas, the conversion of the enriched uranium hexafluoride gas into uranium dioxide fuel pellets, and the fabrication into fuel assemblies. Ameren Missouri has entered into uranium, uranium conversion, uranium enrichment, and fabrication contracts to procure the fuel supply for its Callaway energy center.Energy Center.
The Callaway energy centerEnergy Center requires refueling at 18-month intervals. The last refueling was completed in December 2017.November 2023. The next refueling is scheduled for the spring of 2019. As of December 31, 2017, Ameren Missouri had agreements or inventories to price-hedge all of Callaway’s spring 2019 refueling requirements.2025. Ameren Missouri has inventories and supply contracts sufficient to meet all of its uranium (concentrate and hexafluoride), conversion, enrichment, and enrichmentfabrication requirements at least through the 2022spring 2028 refueling. Ameren Missouri has fuel fabrication service contracts through at least 2022.
Natural Gas Supply for Generation
To maintain deliveries to its natural-gas-fired energy centers throughout the year, especially during the summer peak demand, Ameren Missouri’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. Ameren Missouri primarily uses the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to energy centers. In addition to physical transactions, Ameren Missouri uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
Ameren Missouri’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to its energy centers. This strategy is accomplished by optimizing transportation and storage options and by minimizing cost and price risk through various supply and price-hedging agreements that allow access to multiple natural gas pools, supply basins, and storage services. As of December 31, 2017, Ameren Missouri had price-hedged about 73% of its expected natural gas supply requirements for generation in 2018.
Renewable EnergyRENEWABLE ENERGY AND ZERO EMISSION STANDARDS
Missouri and Illinois laws require electric utilities to include renewable energy resources in their portfolios. Ameren Missouri and Ameren Illinois satisfied their renewable energy portfolio requirements in 2023, pending regulatory review by the MoPSC for Ameren Missouri.
Ameren Missouri
In Missouri, utilities are required to purchase or generate electricity equal to at least 5%15% of native load sales from renewable energy sources, beginning in 2017. That percentage will increase towith at least 15% by 2021,2% of the requirement derived from solar energy. The requirement is subject to an average 1% annual increaselimit on increases to customer rates over any 10-year period. At least 2%For renewable generation facilities located in Missouri, 125% of each renewable energy portfolio requirement must be derived from solar energy. In 2017, Ameren Missouri met its renewable energy requirements.the electricity generated counts towards meeting the requirement. Ameren Missouri expects to satisfy the nonsolarnon-solar requirement in 20182024 with its High Prairie Renewable, Atchison Renewable, Keokuk, energy center and its Maryland Heights energy center, and throughcenters, a 102-megawatt102-MW power purchase agreement with a wind farm operator.operator, which expires in August 2024, and previously purchased renewable energy credits. The High Prairie Renewable and Atchison Renewable energy centers are wind generation facilities. The Keokuk Energy Center generates electricity using a hydroelectric dam located on the Mississippi River. The Maryland Heights energy 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 its own solar energy at the O’Fallon energy center and at its headquarters building. See Supply of Electric Power above for renewable energy plans incorporated in Ameren Missouri’s integrated resource plan, filed with the MoPSC in September 2017.solar facilities.
State law required renewable energy resources to equal or exceed 13% of the total electricity that Ameren Illinois supplied to its eligible retail customers for the twelve months ended June 1, 2017. For the 2017 plan year, Ameren
In accordance with Illinois met the renewable energy requirement. Starting June 1, 2017,law, Ameren Illinois is required to collect funds from all electric distribution customers to fund IPA procurement events for renewable energy credits. The amount set by law and required to be collected from customers by Ameren Illinois is capped at $4.58 per MWh. The IPA establishes its long-term renewable resources procurement plans in a filing made every two years. In February 2024, the ICC approved the IPA’s latest long-term renewable resources procurement plan, which established the 2024 and 2025 renewable energy credit procurement targets. Based on IPA procurement events that align with the IPA’s plan, Ameren Illinois has contractual commitments to purchase approximately 1.0 million wind renewable energy credits per year and approximately 3.1 million solar renewable energy credits per year. Ameren Illinois has also entered into contracts, ending in 2032, to purchase approximately 0.6 million wind renewable energy credits per year. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy resources for allcredits, they would be refunded to customers pursuant to a reconciliation proceeding, the first of its electric distributionwhich was initiated in August 2023. Based on amounts collected from customers even if an alternative retail electric supplier provides powerand renewable energy credit purchases under contract, the August 2023 reconciliation proceeding did not result in refunds to the customer. The FEJA requirescustomers.
Illinois law also required Ameren Illinois to procure zero-emissionenter into contracts to purchase zero emission credits in an amount equal to approximately 16% of the actual amount of electricity delivered to retail customers during calendar year 2014, pursuant to Illinois’ zero emission standard. As a result of a 2018 IPA procurement event, which was approved by the ICC, Ameren Illinois entered into agreements to acquire zero emission credits through May 2027. Annual zero emission credit commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Both renewable energy credits and zero emission credits have cost recovery mechanisms, which allow Ameren Illinois to retailcollect from, or refund to, customers in Illinois during calendar year 2014. The zero-emission credit cost recovery mechanism, effective June 1, 2017, fully recovers or refunds, through customer rates,differences between actual costs incurred from the variance in actual zero-emission credit costs incurredpurchase of the credits and the amounts collected from customers. Ameren Illinois defers the variance as a regulatory asset or liability, respectively. These requirements were, and will continue to be, satisfied through ongoing IPA procurement events.
State law requires Ameren Illinois to offer rebates for certain net metering customers. The cost of the rebates are deferred as a regulatory asset. It will be included in rate base and earn a return based on the utility’s weighted-average cost of capital. Customers that receive these rebates will be allowed to net their supply service charges, but not their distribution service charges. Beginning in 2017, the FEJA decoupled the electric distribution revenues established in a rate proceeding from the actual sales volumes, which ensures that Ameren Illinois’ electric distribution earnings will not be affected by any reduction in sales volumes.
Energy EfficiencyCUSTOMER ENERGY-EFFICIENCY PROGRAMS
Ameren Missouri and Ameren Illinois have implemented energy-efficiency programs to educate their customers and to help their customersthem become more efficient usersenergy consumers. These programs provide incentives to customers for installing newer, more efficient technology, and for using energy in a more conservation-minded manner. As a component of the energy-efficiency programs, Ameren Missouri and Ameren Illinois have invested in electric smart meters to provide customers more visibility to their energy consumption and facilitate more efficient use of energy. As of December 31, 2023, smart meters have been installed for 88% of Ameren Missouri’s electric customers. Ameren Illinois has completed its transition to smart meters, which have been installed for nearly all its electric and natural gas customers.
Ameren Missouri
In Missouri, the MEEIAMissouri Energy Efficiency Investment Act established a regulatory frameworkrider 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 standards.programs.
In February 2016,2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 20162019 plan. ThatThe plan includedincludes a portfolio of customer energy-efficiency and demand response programs along with a riderthrough December 2024. Ameren Missouri intends to collectinvest approximately $420 million over the program costs,life of the throughput disincentive, andplan, including $76 million in 2024. In addition, the plan includes a performance incentive from customers. The throughput disincentive recovery replacedthat provides Ameren Missouri an opportunity to earn revenues by achieving certain customer energy-efficiency goals. If the net shared benefits that were collected undertarget program spending goal is achieved for 2024, the performance incentive would result in revenues of $12 million in 2024. Through 2023, Ameren Missouri has invested approximately $343 million in MEEIA 2013 plan. 2019 customer energy-efficiency programs. Additionally, as part of its Smart Energy Plan, Ameren Missouri has invested $336 million in smart meters since 2019.
The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any difference between actual program costs, lost electric margins, and any performance incentive and the throughput disincentiveamounts collected from customers, without a traditional regulatory rate proceedingreview, subject to MoPSC prudence reviews, until lower volumes resulting from the MEEIA programs are reflected in base rates. Customer rates, based upon both forecasted program costs and throughput disincentive,lost electric margins and collected via the MEEIA rider, are reconciled annually to actual results.
Ameren Missouri intends to invest $158 million in MEEIA 2016 customer energy-efficiency programs. In addition, similar to the MEEIA 2013 plan, 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.Illinois
StateIllinois law requires Ameren Illinois to offer customer energy-efficiency programs, and imposes electric energy-efficiency savings goals and a maximum annual amount of investment in electric energy-efficiency programs, which is approximately $120 million annually through 2029 and may increase by up to approximately $30 million from 2026 to 2029 depending on the election of certain customers to participate in the programs. Every four years, Ameren Illinois is required to file a four-year electric energy-efficiency plan with the ICC. In September 2017,June 2022, the ICC issued an order approving Ameren Illinois’ electric and natural gas energy-efficiency plans for 2022 through 2025, as well as mechanisms by which program costs can be recovered from customers.regulatory recovery mechanisms. The order authorized electric and natural gas energy-efficiency program expenditures of $394$476 million and $62$66 million, respectively, forover the period 2018 through 2021. Additionally, as part of its IEIMA capital project investments, Ameren four-year period.
Illinois expects to invest $439 million in smart-grid infrastructure from 2012 to 2021, including smart meters that enable customers to improve their energy efficiency.
Historically, Ameren Illinois has recovered the cost of its energy-efficiency programs as they were incurred. Since June 2017, the FEJA has allowedlaw allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and such investments will 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 average yieldyields 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. The FEJA also increasedWhile the level ofICC approves Ameren Illinois’ four-year electric energy-efficiency saving targets through 2030. Ameren Illinois plans, the ICC has the ability to invest up to $99 million per year inreduce the amount of approved electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs from 2018 through 2021. Ameren Illinois plans to make similar yearlyavailable, which could reduce the investments in electric energy-efficiency programs through 2030. The ICC can lower the electric energy-efficiency saving goals if sufficient cost-effective measures are not available. programs.The electric energy-efficiency program investments and the return on those investments will beare collected from customers through a rider and are not included in the electric distribution service MYRP framework. Ameren Illinois’ natural gas energy-efficiency program costs are recovered through a rider; they will not be included in the IEIMA formula rate process.rider.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their customers. Ameren Missouri and Ameren Illinois each develop and manage a portfolio of natural gas supply resources. These resources include firm natural gas supply through agreements with producers, firm interstate and intrastate firm transportation capacity, firm no-notice storage capacity leased from interstate pipelines, and on-system storage facilities to maintain natural gas deliveries to customers throughout the year and especially during peak demand periods. Ameren Missouri and Ameren Illinois primarily use Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, Mississippi River Transmission Corporation, Northern Border Pipeline Company, MoGas Pipeline, and Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to transactions requiring physical delivery, certain financial instruments, including those entered into in the NYMEXNew York Mercantile Exchange futures market and in the OTCover-the-counter financial markets, are used to hedge the price paid for natural gas. Natural gas purchasesupply 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. AsFor information regarding the percentage of December 31, 2017, Ameren MissouriMissouri’s and Ameren Illinois had price-hedged 66% and 75%, respectively, of their expected 2018Illinois’ projected remaining natural gas supply requirements.requirements that are price-hedged through 2028, see Commodity Price Risk under Part II, Item 7A, of this report.
For additional information on our fuel, and purchased power, and natural gas for distribution supply, see Results of Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Commodity Price Risk under Part II, Item 7A, of this report. Also see Note 1 – Summary of Significant Accounting Policies, Note 7 – Derivative Financial Instruments, Note 13 – Related-party Transactions, 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 rate-regulated energy infrastructure, enhance regulatory frameworks and advocate for responsible policies, and optimize operating performance to capitalize on opportunities to benefit our customers, communities, shareholders, and the environment is driven by the capabilities and engagement of our workforce. Ameren’s workforce strategy is designed to promote a skilled and diverse workforce that is prepared to deliver on Ameren’s mission (To Power the Quality of Life) and vision (Leading the Way to a Sustainable Energy Future), both today and in the future. Our workforce strategy is anchored in four key pillars: Culture, Leadership, Talent, and Rewards, which are discussed further below. Foundational to our workforce strategy are our core competencies of:
| | | | | |
•Be Strategic •Continuously Improve •Deliver Results | •Engage Respectfully •Foster Collaboration •Think Customer |
Ameren’s chief executive officer and chief human resources officer, with the support of other leaders of the Ameren Companies, are responsible for developing and executing our workforce strategy. In addition to reviewing and determining the Ameren Companies’ compensation practices and policies for the chief executive officer and other executive officers, the Human Resources Committee of Ameren’s board of directors is responsible for oversight of Ameren’s human capital management practices and policies, including those related to diversity, equity, and inclusion. The Human Resources Committee and Ameren’s board of directors are updated regularly on human capital matters.
Culture
We strive to cultivate a mission-driven, values-based culture that enables the sustainable execution of our core strategy.
We design our human capital management practices and policies to reinforce our core values, shape our culture, and drive employee engagement. In doing so, we strive to align our employees to our mission and vision, improve safety, continuously improve operating performance, attract and retain top talent, and recognize employee contributions, among other things. We assess employee engagement through a variety of channels. As a part of our assessment, we conduct confidential employee engagement surveys twice each year to identify areas of strength and opportunities for improvement in our employees’ experience, and take actions aimed at increasing employee engagement. We also offer flexible work arrangements, such as permitting certain employees to work from alternate locations or to make adjustments to an employee’s daily work hours, among other things, complemented by our work to advance the digital enablement of our workforce, and have enhanced our facilities and workforce policies and practices to increase collaboration and productivity.
As a part of our culture, every employee is expected to challenge any unsafe act, complete each workday safely, and provide feedback on safety and security matters. In addition to comprehensive safety and security standards, and mandatory health, safety, and security training programs for applicable employees, we promote programs designed to encourage employees to provide feedback on practices or actions that could harm employees, customers, or the Ameren Companies, including perceived issues related to safety, security (both physical and cyber), ethics and compliance violations, or acts of discrimination.
We seek to foster diversity, equity, and inclusion across our organization. Our efforts extend to the community through philanthropic contributions and volunteerism, including to support non-profit organizations in leading community-building efforts, providing education and support to our community and company leaders through our diversity leadership summit, providing various training programs, and organizing and promoting opportunities for employee volunteerism. We also have employee resource groups, which bring together groups of employees who share common interests or backgrounds. Within these groups, employees collaborate to address concerns and provide training and development opportunities, among other things.
Leadership
Ameren’s leaders play a critical role in setting and executing Ameren’s strategic initiatives, modeling our values and culture, and engaging and enabling the workforce. As such, we seek to develop a strong, diverse leadership team. Management engages in an extensive succession planning process annually, which includes the involvement of Ameren’s board of directors. We develop our leaders both individually, through job rotations, work experiences, and leadership development programs, and as a team, through collaborative learning and mentoring relationships. Throughout the year, we offer a variety of forums intended to connect our leaders to our mission, values, strategy and culture, build leadership skills and capabilities, and to promote connection and inclusion. In addition, we evaluate our organizational structure and make adjustments and expand roles to facilitate execution of our strategy and organizational efficiency.
Talent
In order to attract and retain a skilled and diverse workforce, we promote an inclusive work environment, provide opportunities for employees to expand their knowledge and skill sets, and support career development. Our talent management initiatives include a wide range of recruiting partnerships and programs, including those programs discussed below. Our onboarding efforts are designed to ensure early engagement, including the opportunity to participate in mentoring programs. Additionally, employees are encouraged to participate in technical, professional, and leadership development opportunities, and outreach initiatives to engage with the communities that we serve, among other things. As our business needs change, we remain focused on ensuring that our workforce has the tools and skills necessary to deliver on our strategic initiatives.
We have established programs to recruit early and mid-career talent to further enhance the diversity of our workforce pipelines. These programs include skilled craft education and training for individuals interested in skilled craft roles, an intern/co-op program that serves as a pipeline for STEM-related careers, a career reentry program for experienced professionals transitioning from voluntary career breaks, a program for individuals transitioning from military service, and an early career rotation program. Additionally, each year management and the Human Resources Committee of Ameren’s board of directors review the diversity of our workforce, leadership team, and leadership pipeline.
Workforce
The majority of our workforce is comprised of skilled-craft and STEM-related professional and technical employees. Our workforce has been stable, with a total attrition rate of 7% in 2023. The majority of employee attrition is attributable to employee retirements, generally allowing for thoughtful workforce and succession planning in advance of these planned transitions. The following table presents our employee count and their average tenure at December 31, 2023, and the attrition rate in 2023:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Employee
Count | | Average Tenure
(in years) | | Attrition
Rate | |
| Ameren | | 9,372 | | 13 | | 7% | |
| Ameren Missouri | | 4,011 | | 14 | | 8% | |
| Ameren Illinois | | 3,280 | | 13 | | 7% | |
| Ameren Services | | 2,081 | | 10 | | 7% | |
Ameren’s workforce is diverse in many ways. At the officer level, which represented 50 individuals as of December 31, 2023, 26% were female, and 26% were racially and/or ethnically diverse. The following table presents our total employee population that is represented by a collective bargaining unit, is a female, or is racially and/or ethnically diverse at December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Collective Bargaining Unit | | Female(a) | | Racially and/or Ethnically Diverse(a) | | |
| Ameren | | 46% | | 24% | | 16% | | |
| Ameren Missouri | | 58% | | 17% | | 14% | | |
| Ameren Illinois | | 54% | | 23% | | 14% | | |
| Ameren Services | | 10% | | 41% | | 23% | | |
(a)Gender, race, and ethnicity were self-reported by our employees.
The following table presents Ameren’s employees by generation at December 31, 2023:
| | | | | | | | | | | | | | |
| Generation Description | Ameren | Ameren Missouri | Ameren Illinois | Ameren Services |
| Baby Boomer (birth years between 1946 and 1964) | 13% | 13% | 13% | 13% |
| Generation X (birth years between 1965 and 1980) | 40% | 40% | 39% | 42% |
| Millennials (birth years between 1981 and 1996) | 41% | 40% | 42% | 39% |
| Generation Z/Post Millennial (birth years after 1997) | 6% | 7% | 6% | 6% |
| | | | |
Collective bargaining units at Ameren’s subsidiaries consist of the International Brotherhood of Electrical Workers, the International Union of Operating Engineers, the Laborer’s International Union of North America, the United Association of Plumbers and Pipefitters, and the United Government Security Officers of America. The Ameren Companies expect continued constructive relationships with their respective labor unions. The Ameren Missouri collective bargaining unit contracts expire in 2025 and 2026, and cover 4% and 96% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2026 and 2027, and cover 92% and 8% of represented employees, respectively.
Rewards
The primary objective of our rewards program is to provide a total rewards package that attracts and retains a talented workforce and reinforces strong performance in a financially sustainable manner. Management continuously evaluates our core benefits in an effort to create a market-competitive, performance-based, shareholder-aligned total rewards package with a view towards balancing employee value and financial sustainability. We recognize that the rewards package required to attract and retain talent over the long term is about more than pay and benefits; it is about the total employee experience and support of their overall well-being. In addition to base salary, medical benefits, and retirement benefits, including pension for substantially all employees and 401(k) savings, our total rewards package includes short-term incentives and long-term stock-based compensation for certain employees. Further, we offer our employees various programs that encourage overall well-being, including wellness and employee assistance programs. We strive to provide a competitive and sustainable rewards package that supports our ability to attract, engage, and retain a talented and diverse workforce, while at the same time reinforcing and rewarding strong performance.
INDUSTRY ISSUES
We are facing issues common to the electric and natural gas utility industry. These issues include:
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;
changes to •corporate income tax law as a result ofchanges, including the enactment of the TCJA,IRA, as well as additional interpretations, regulations, amendments, or technical corrections related tothat affect the federalamount and timing of income tax code,payments, reduce or limit the ability to claim certain deductions and any state incomeuse carryforward tax reform;benefits and/or credits, or result in rate base reductions;
•cybersecurity risks, cyber attacks, including ransomware and other ransom-based attacks and those attacks arising from or generated by artificial intelligence, hacking, social engineering, and other forms of malicious cybersecurity and/or privacy events, which could result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the theft or inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information;
•acts of sabotage, which have increased in frequency and severity within the utility industry, terrorism, and other intentionally disruptive acts;
•political, regulatory, and customer resistance to higher rates;
•the potential for more intense competition in generation, supply, and distribution, including new technologies and their declining costs;
•the impact and effectiveness of vegetation management programs;
•the potential for reliability issues due to inadequate resources resulting from the retirement of fossil-fuel-fired and nuclear generation facilities as they are replaced with renewable energy generation sources, market inefficiencies related to prices for purchased power, capacity, and ancillary services, and other factors;
•the need to place new transmission and generation facilities in service, which is dependent upon timely regulatory approvals and the availability of necessary labor and materials, among other things, to maintain grid reliability;
•the modernization of the electric grid to accommodate a two-way flow of electricity and increase capacity for distributed generation interconnection;
•net metering rules and other changes in existing regulatory frameworks and recovery mechanisms to address the allocation of costs to customers who own generation resources that enable them both to sell power to us and to purchase power from us through the use of our transmission and distribution assets;
•legislation or programs to encourage or mandate energy efficiency, energy conservation, and renewable sources of power, such as solar, 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 economic conditionsconditions;
•distributed generation, energy storage, technological advances, and energy-efficiency or conservation initiatives;
•changes in the structure of the industry as a result of changes in federal and state laws, including the formation and growth of independent transmission entities;
a further reduction•changes in the allowed return on common equityROE, including ROE incentive adders, on FERC-regulated electric transmission assets;
•the availability of fuel and fluctuations in fuel prices;
•the availability of materials and equipment, and the potential disruptions in supply chains;
•the availability of a skilled work force, including retainingtransferring the specialized skillsknowledge of those who are nearing retirement;retirement to employees succeeding them;
•inflationary pressures on the prices of commodities, labor, services, materials, and supplies, high interest rates, and impacts associated with extended recovery periods from customers;
•maintaining affordability of electric and natural gas utility services for customers;
•the potential for reduced efficiency and productivity due to challenges of hybrid remote working arrangements for non-field employees;
•regulatory lag;
•the influence of macroeconomic factors on yields of United States Treasury securities and on the allowed 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, regulations, and requirements, including 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;
|
•complex new and proposed environmental laws including statutes, regulations, and requirements, such as air and water quality standards, mercury emissions standards, limitations on the use of natural gas in generation, CCR management requirements, and potential CO2 limitations, which may limit, or result in the cessation of, the operation of electric generating units;
•public concerns about the potential environmental impacts from the combustion of fossil fuelsfuels;
•pressure from public interest groups regarding limiting the use of natural gas, as well as proposed restrictions on the use of natural gas by state and somelocal authorities;
•certain investors’ concerns about investing in, energyas well as certain insurers’ concerns about providing coverage to, utility companies that have fossil fuel-firedcoal-fired generation assets;
•increasing scrutiny by investors and other stakeholders of ESG practices;
•aging infrastructure and the need to construct new power generation, transmission, and distribution facilities, which have long time frames for completion, with limited long-term ability to predict power and commodity prices and regulatory requirements;
•public concerns about nuclear generation, decommissioning, and the disposal of nuclear waste;
•industry reputational challenges resulting from alleged or actual legal, regulatory or compliance failures, including in connection with lobbying and political activities or liabilities arising out of wildfires or other catastrophic events; and
•consolidation of electric and natural gas utility companies.
We are monitoring all these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
| | | | | | | | | | | | | | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2023 | | 2022 | | 2021 | |
| Electric Sales – kilowatthours (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 12,839 | | | 13,915 | | | 13,366 | | |
| Commercial | 13,466 | | | 13,826 | | | 13,556 | | |
| Industrial | 3,977 | | | 4,090 | | | 4,151 | | |
| Street lighting and public authority | 71 | | | 76 | | | 81 | | |
| Ameren Missouri retail load subtotal | 30,353 | | | 31,907 | | | 31,154 | | |
| Off-system sales | 4,145 | | | 7,645 | | | 7,425 | | |
| Ameren Missouri total | 34,498 | | | 39,552 | | | 38,579 | | |
Ameren Illinois Electric Distribution(a): | | | | | | |
| Residential | 10,774 | | | 11,708 | | | 11,620 | | |
| Commercial | 11,602 | | | 11,867 | | | 11,795 | | |
| Industrial | 10,740 | | | 10,981 | | | 11,076 | | |
| Street lighting and public authority | 385 | | | 410 | | | 430 | | |
| Ameren Illinois Electric Distribution total | 33,501 | | | 34,966 | | | 34,921 | | |
| Eliminate affiliate sales | (30) | | | (190) | | | (412) | | |
| Ameren total | 67,969 | | | 74,328 | | | 73,088 | | |
| Electric Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 1,577 | | | $ | 1,578 | | | $ | 1,445 | | |
| Commercial | 1,280 | | | 1,219 | | | 1,126 | | |
| Industrial | 306 | | | 290 | | | 280 | | |
| Other, including street lighting and public authority | 124 | | | 171 | | | 170 | |
|
| Ameren Missouri retail load subtotal | $ | 3,287 | | | $ | 3,258 | | | $ | 3,021 | | |
| Off-system sales and capacity | 407 | | | 591 | | | 191 | | |
| Ameren Missouri total | $ | 3,694 | | | $ | 3,849 | | | $ | 3,212 | | |
| Ameren Illinois Electric Distribution: | | | | | | |
| Residential | $ | 1,344 | | | $ | 1,325 | | | $ | 933 | | |
| Commercial | 747 | | | 768 | | | 545 | | |
| Industrial | 186 | | | 199 | | | 135 | | |
| Other, including street lighting and public authority | (59) | | | (36) | | | 26 | | |
| Ameren Illinois Electric Distribution total | $ | 2,218 | | | $ | 2,256 | | | $ | 1,639 | | |
| Ameren Transmission: | | | | | | |
Ameren Illinois Transmission(b) | $ | 480 | | | $ | 424 | | | $ | 365 | | |
| ATXI | 198 | | | 192 | | | 199 | | |
| Eliminate affiliate revenues | (1) | | | (1) | | | (2) | | |
| Ameren Transmission total | $ | 677 | | | $ | 615 | | | $ | 562 | | |
| Other and intersegment eliminations | (150) | | | (139) | | | (116) | | |
| Ameren total | $ | 6,439 | | | $ | 6,581 | | | $ | 5,297 | | |
(a)Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2023, 2022, and 2021, Ameren Illinois procured power on behalf of its customers for 28%, 28%, and 23%, respectively, of its total kilowatthour sales.
(b)Includes $113 million, $104 million, and $66 million in 2023, 2022, and 2021, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution.
|
| | | | | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2017 | | 2016 | | 2015 |
| Electric Sales – kilowatthours (in millions): | | | | | |
| Ameren Missouri: | | | | | |
| Residential | 12,653 |
| | 13,245 |
| | 12,903 |
|
| Commercial | 14,384 |
| | 14,712 |
| | 14,574 |
|
| Industrial | 4,469 |
| | 4,790 |
| | 8,273 |
|
| Street lighting and public authority | 117 |
| | 125 |
| | 126 |
|
| Ameren Missouri retail load subtotal | 31,623 |
| | 32,872 |
| | 35,876 |
|
| Off-system | 10,640 |
| | 7,125 |
| | 7,380 |
|
| Ameren Missouri total | 42,263 |
| | 39,997 |
| | 43,256 |
|
Ameren Illinois Electric Distribution(a): | | | | | |
| Residential | 10,985 |
| | 11,512 |
| | 11,554 |
|
| Commercial | 12,382 |
| | 12,583 |
| | 12,280 |
|
| Industrial | 11,359 |
| | 11,738 |
| | 11,863 |
|
| Street lighting and public authority | 515 |
| | 521 |
| | 524 |
|
| Ameren Illinois Electric Distribution total | 35,241 |
| | 36,354 |
| | 36,221 |
|
| Eliminate affiliate sales | (440 | ) | | (520 | ) | | (385 | ) |
| Ameren total | 77,064 |
| | 75,831 |
| | 79,092 |
|
| Electric Operating Revenues (in millions): | | | | | |
| Ameren Missouri: | | | | | |
| Residential | $ | 1,416 |
| | $ | 1,421 |
| | $ | 1,464 |
|
| Commercial | 1,207 |
| | 1,223 |
| | 1,258 |
|
| Industrial | 305 |
| | 315 |
| | 469 |
|
| Other, including street lighting and public authority | 115 |
| | 102 |
| | 84 |
|
| Ameren Missouri retail load subtotal | $ | 3,043 |
| | $ | 3,061 |
| | $ | 3,275 |
|
| Off-system | 370 |
| | 333 |
| | 195 |
|
| Ameren Missouri total | $ | 3,413 |
| | $ | 3,394 |
| | $ | 3,470 |
|
| Ameren Illinois Electric Distribution: | | | | | |
| Residential | $ | 870 |
| | $ | 894 |
| | $ | 858 |
|
| Commercial | 527 |
| | 518 |
| | 474 |
|
| Industrial | 113 |
| | 96 |
| | 124 |
|
| Other, including street lighting and public authority | 58 |
| | 41 |
| | 76 |
|
| Ameren Illinois Electric Distribution total | $ | 1,568 |
| | $ | 1,549 |
| | $ | 1,532 |
|
| Ameren Transmission: | | | | | |
Ameren Illinois Transmission(b) | $ | 258 |
| | $ | 232 |
| | $ | 189 |
|
| ATXI | 168 |
| | 123 |
| | 70 |
|
| Ameren Transmission total | $ | 426 |
| | $ | 355 |
| | $ | 259 |
|
| Other and intersegment eliminations | (97 | ) | | (102 | ) | | (81 | ) |
| Ameren total | $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
|
| | | | | | | | | | | | | | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2023 | | 2022 | | 2021 | |
Ameren Missouri fuel costs (cents per kilowatthour generated)(a) | 1.29 | ¢ | | 1.41 | ¢ | | 1.46 | ¢ | |
| Source of Ameren Missouri energy supply: | | | | | | |
| Coal | 54.6 | % | | 61.6 | % | | 73.0 | % | |
| Nuclear | 25.6 | | | 21.6 | | | 10.5 | | |
| Hydroelectric | 2.4 | | | 3.2 | | | 4.2 | | |
| Wind | 4.9 | | | 4.7 | | | 3.7 | | |
| Natural gas | 1.1 | | | 1.1 | | | 1.0 | | |
| Methane gas and solar | 0.2 | | | 0.2 | | | 0.2 | | |
| Purchased power – wind | 0.6 | | | 0.8 | | | 0.6 | | |
| Purchased power – other | 10.6 | | | 6.8 | | | 6.8 | | |
| Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % | |
| |
(a) | Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2017, 2016, and 2015, Ameren Illinois procured power on behalf of its customers for 23%, 23%, and 26%, respectively, of its total kilowatthour sales. |
| |
(b) | Includes $42 million, $45 million, and $38 million in 2017, 2016, and 2015, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution. |
(a) Ameren Missouri fuel costs exclude $72 million, $(98) million, and $1 million in 2023, 2022, and 2021, respectively, for changes in FAC recoveries.
| | | | | | | | | | | | | | | | | | | | |
Natural Gas Operating Statistics – Year Ended December 31, | 2023 | | 2022 | | 2021 | |
| Natural Gas Sales – dekatherms (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | 6 | | | 8 | | | 7 | | |
| Commercial | 3 | | | 4 | | | 4 | | |
| Industrial | 1 | | | 1 | | | 1 | | |
| Transport | 9 | | | 9 | | | 9 | | |
| Ameren Missouri total | 19 | | | 22 | | | 21 | | |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | 47 | | | 59 | | | 54 | | |
| Commercial | 14 | | | 18 | | | 16 | | |
| Industrial | 3 | | | 6 | | | 4 | | |
| Transport | 99 | | | 99 | | | 100 | | |
| Ameren Illinois Natural Gas total | 163 | | | 182 | | | 174 | | |
| Ameren total | 182 | | | 204 | | | 195 | | |
| Natural Gas Operating Revenues (in millions): | | | | | | |
| Ameren Missouri: | | | | | | |
| Residential | $ | 100 | | | $ | 119 | | | $ | 79 | | |
| Commercial | 46 | | | 56 | | | 34 | | |
| Industrial | 5 | | | 7 | | | 4 | | |
| Transport and other | 14 | | | 15 | | | 24 | | |
| Ameren Missouri total | $ | 165 | | | $ | 197 | | | $ | 141 | | |
| Ameren Illinois Natural Gas: | | | | | | |
| Residential | $ | 657 | | | $ | 846 | | | $ | 657 | | |
| Commercial | 164 | | | 221 | | | 172 | | |
| Industrial | 14 | | | 41 | | | 35 | | |
| Transport and other | 62 | | | 72 | | | 93 | | |
| Ameren Illinois Natural Gas total | $ | 897 | | | $ | 1,180 | | | $ | 957 | | |
| Other and intercompany eliminations | (1) | | | (1) | | | (1) | | |
| Ameren total | $ | 1,061 | | | $ | 1,376 | | | $ | 1,097 | | |
|
Rate Base Statistics – At December 31, | 2023 | | 2022 | | 2021 | |
| Rate Base (in billions): | | | | | | |
| Electric transmission and distribution | $ | 17.5 | | | $ | 15.4 | | | $ | 13.5 | | |
| Natural gas transmission and distribution | 3.2 | | | 2.9 | | | 2.7 | | |
| Coal generation: | | | | | | |
| Labadie Energy Center | 0.9 | | | 0.9 | | | 0.9 | | |
| Sioux Energy Center | 0.6 | | | 0.7 | | | 0.7 | | |
| Rush Island Energy Center (scheduled to be retired in October 2024) | 0.4 | | | 0.4 | | | 0.4 | | |
Meramec Energy Center (retired in December 2022) | — | | | — | | | 0.1 | | |
| Coal generation total | 1.9 | | | 2.0 | | | 2.1 | | |
| Nuclear generation | 1.5 | | | 1.5 | | | 1.5 | | |
| Renewable generation (hydroelectric, wind, solar, methane gas) | 1.4 | | | 1.5 | | | 1.5 | | |
| Natural gas generation | 0.3 | | | 0.3 | | | 0.3 | | |
| Rate base total | $ | 25.8 | | | $ | 23.6 | | | $ | 21.6 | | |
|
| | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2017 | | 2016 | | 2015 |
| Source of Ameren Missouri energy supply: | | | | | |
| Coal | 70.9 | % | | 66.2 | % | | 67.1 | % |
| Nuclear | 19.0 |
| | 22.8 |
| | 23.3 |
|
| Hydroelectric | 3.4 |
| | 3.3 |
| | 3.6 |
|
| Natural gas | 0.7 |
| | 0.7 |
| | 0.3 |
|
| Methane gas and solar | 0.1 |
| | 0.1 |
| | 0.2 |
|
| Purchased – Wind | 0.7 |
| | 0.8 |
| | 0.7 |
|
| Purchased – Other | 5.2 |
| | 6.1 |
| | 4.8 |
|
| Ameren Missouri total | 100.0 | % | | 100.0 | % | | 100.0 | % |
|
| | | | | | | | | | | |
Natural Gas Operating Statistics – Year Ended December 31, | 2017 | | 2016 | | 2015 |
| Natural Gas Sales – dekatherms (in millions): | | | | | |
| Ameren Missouri: | | | | | |
| Residential | 6 |
| | 6 |
| | 7 |
|
| Commercial | 3 |
| | 3 |
| | 3 |
|
| Industrial | 1 |
| | 1 |
| | 1 |
|
| Transport | 8 |
| | 8 |
| | 7 |
|
| Ameren Missouri total | 18 |
| | 18 |
| | 18 |
|
| Ameren Illinois Natural Gas: | | | | | |
| Residential | 50 |
| | 52 |
| | 55 |
|
| Commercial | 15 |
| | 17 |
| | 18 |
|
| Industrial | 3 |
| | 3 |
| | 3 |
|
| Transport | 98 |
| | 94 |
| | 89 |
|
| Ameren Illinois Natural Gas total | 166 |
| | 166 |
| | 165 |
|
| Ameren total | 184 |
| | 184 |
| | 183 |
|
| Natural Gas Operating Revenues (in millions): | | | | | |
| Ameren Missouri: | | | | | |
| Residential | $ | 77 |
| | $ | 77 |
| | $ | 84 |
|
| Commercial | 31 |
| | 30 |
| | 34 |
|
| Industrial | 4 |
| | 4 |
| | 5 |
|
| Transport and other | 14 |
| | 17 |
| | 14 |
|
| Ameren Missouri total | $ | 126 |
| | $ | 128 |
| | $ | 137 |
|
| Ameren Illinois Natural Gas: | | | | | |
| Residential | $ | 532 |
| | $ | 531 |
| | $ | 550 |
|
| Commercial | 146 |
| | 153 |
| | 163 |
|
| Industrial | 14 |
| | 12 |
| | 13 |
|
| Transport and other | 51 |
| | 58 |
| | 57 |
|
| Ameren Illinois Natural Gas total | $ | 743 |
| | $ | 754 |
| | $ | 783 |
|
| Other and intercompany eliminations | (2 | ) | | (2 | ) | | (2 | ) |
| Ameren total | $ | 867 |
| | $ | 880 |
| | $ | 918 |
|
| | | | | | |
Rate Base Statistics – At December 31, | 2017 | | 2016 | | 2015 |
| Rate Base (in billions): | | | | | |
| Coal generation | $ | 2.0 |
| | $ | 2.0 |
| | $ | 2.0 |
|
| Natural gas generation | 0.4 |
| | 0.4 |
| | 0.5 |
|
| Nuclear and renewables generation | 1.9 |
| | 1.8 |
| | 1.7 |
|
| Electric and natural gas transmission and distribution | 10.1 |
| | 9.4 |
| | 8.2 |
|
| Rate base total | $ | 14.4 |
| | $ | 13.6 |
| | $ | 12.4 |
|
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, eXtensible Business Reporting Language (XBRL) documents, and any amendments to those reports filed with or furnished to the SEC pursuant to Sections 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through athe SEC’s website maintained by the SEC (www.sec.gov). Ameren’s own website is oura 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, Cybersecurity and corporate governance committee, finance committee,Digital Technology Committee, Finance Committee, Human Resources Committee, Nominating and nuclearCorporate Governance Committee, and operations committee;Nuclear, Operations and Environmental Sustainability Committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures document with respect to related-person transactions; a code of ethics applicable to all directors, officers and employees; a supplemental code of ethics for principal executive and senior financial officers; 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. ThisThe extensive regulatory framework,frameworks, some of which isare more specifically identified in the following risk factors, regulates,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 theour regulatory framework,frameworks, including initiatives by federal and state legislatures, RTOs, utility regulators, and taxing authorities.authorities, and actions by local jurisdictions that may affect the constructing or siting of facilities. Significant changes in the nature of the regulation of our businesses, including expiration or discontinuation of, or significant changes to, existing regulatory mechanisms, could require changes to our business planning and management of our businesses and could adversely affect our results of operations, financial position, and liquidity. Failure to obtain adequate rates or regulatory approvals in a timely manner; failure to obtain necessary licenses or permits from regulatory authorities; the impact of new or modified laws, regulations, standards, interpretations, or other legal requirements; or increased compliance costs could adversely affect our results of operations, financial position, and liquidity.
The electric and natural gas rates that we are allowed to charge are determined through regulatory proceedings, which are subject to intervention and appeal. Rates are also subject to legislative actions, which are largely outside of our control. AnyCertain events thatcould prevent us from recovering our costs in a timely manner or at all, 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, including the impact of inflationary pressures, and cost disallowances to varying degrees by jurisdiction, which, if unmitigated, could adversely affect our results of operations, financial position, and liquidity. Rate orders are also subject to appeal, which creates additional uncertainty as to the rates that we will ultimately be allowed to charge for our services. From time to time, our regulators may approve trackers, riders, or other recovery mechanisms that allow electric or natural gas rates to be adjusted without a traditional regulatory rate 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 electric and natural gas utility rates established in those proceedings
are primarily based on
historical costs, revenues, and revenues.sales volumes. Ameren Illinois’ natural gas rates established in those proceedings are based on estimated future costs, revenues, and revenues.sales volumes. Effective for rates beginning in 2024 through at least 2027, Ameren Illinois’ electric distribution rates will be established through an MYRP as discussed in the following risk factor. An MYRP includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap. Thus, the rates that we are allowed to charge for utility services may not match our actual costs at any given time.
Rates include an allowed 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.
With respect to Ameren Missouri’s electricMissouri and natural gasAmeren Illinois, and the utility rates, in years whenindustry 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 operations costs rise or customer usage declines below those levels reflected in rates, we may not be able to earn the alloweda return established by the regulator. Thison investments could result in the deferral or cancellation of planned capital investments, which could reduce themore frequent regulatory rate base investments on which Ameren Missouri earns a rate of return.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 participationBeginning in the performance-based formula ratemaking framework established pursuant to the IEIMA and the FEJA, Ameren Illinois’ return on equity for its2024 through at least 2027, electric distribution servicerates for Ameren Illinois are established through an MYRP, which are subject to ongoing regulatory and its electric energy-efficiency investments is directly correlatedjudicial proceedings and associated risks, and are subject to yields on United States Treasury bonds.a reconciliation cap. Additionally, Ameren Illinois is requiredsubject to achieve certain performance standardsmetrics that if not achieved would result in a reduction to the company’s allowed ROE.
The CEJA resulted in changes to the regulatory framework applicable to Ameren Illinois’ electric distribution business by giving Ameren Illinois the option to file an MYRP with the ICC or establish future rates through a traditional regulatory rate review, among other things. An MYRP establishes rates for a four-year period, and Ameren Illinois has the option to file for an MYRP every four years. Ameren Illinois elected to file an MYRP for rates effective in 2024 through 2027. Under the MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs are excluded from the reconciliation cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and amortization of certain assets. The reconciliation cap also excludes costs recovered outside of base rates through riders. Ameren Illinois’ existing riders remain effective and electric distribution service revenues continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year incorporates Ameren Illinois’ year-end rate base and actual capital spending levels.structure for such year, provided that the resulting revenue requirement does not exceed the 105% reconciliation cap and the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. In addition, the ICC determines the ROE applicable to each year of the four-year period. Economic conditions could result in the annual predetermined ROE becoming inadequate over the four-year period. In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,162 million, $1,210 million, $1,242 million, and $1,255 million, respectively. These revenue requirements were established under an alternative methodology which used Ameren Illinois’ previously approved 2022 year-end rate base since the order rejected the Grid Plan that was filed by Ameren Illinois as a part of the MYRP proceeding. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The 2022 year-end rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement. In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements of $1,214 million, $1,300 million, $1,371 million, and $1,420 million, for 2024, 2025, 2026, and 2027, respectively. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District. Failure to meet theselimit capital expenditures and operation and maintenance expenses to amounts
to which maintain revenue requirements couldunder the reconciliation cap limit would adversely affect Ameren’s and Ameren Illinois’ results of operations, financial position, and liquidity.
Ameren Illinois participates in a performance-based formula ratemaking framework established pursuant to the IEIMA for its electric distribution service. Beginning in 2017, the FEJA allowed Ameren Illinois to recover its electric distribution revenue requirement for a given year, independent of actual sales volumes. Since June 2017, the FEJA has also allowed Ameren Illinois to earn a return on its electric energy-efficiency program investments, which 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 return on equity component under the IEIMA and the FEJA is equal to the calendar year average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworks for both its electric distribution service and its electric energy-efficiency investments 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 average monthly yields of the 30-year United States Treasury bonds would result in an estimated $8 million change in Ameren’s and Ameren Illinois’ net income, based on its 2018 projected rate base.
Ameren Illinoisbusiness is also subject to performance standards.metrics. Failure to achieve the standardsmetrics would result in a reduction in the company’s allowed return on equityROE calculated under the ratemaking formulas. TheMYRP. In 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points under the MYRP, allocated among seven performance standards applicable to electric distribution servicemetrics. These performance metrics include improvements in service reliability to reducein both the frequency and duration of outages, a reduction in the numberpeak loads, an increased percentage of estimated bills, a reduction of consumption from inactive meters, andspend with diverse suppliers, a reduction in bad debt expense. The regulatory framework applicabledisconnections for certain customers, and improved timeliness in response to electric distribution service providescustomer requests for returninterconnection of distributed energy resources. These performance metrics apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, the allowed ROE on equity penalties up to 34 basis points in 2018, and up to 38 basis points in each year from 2019 through 2022, if these performance standards are not met. Beginning in 2018, the regulatory framework applicable to electric 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.
Between 2012Ameren Illinois’ QIP expired in December 2023, which will subject Ameren Illinois to increased regulatory lag with respect to certain natural gas infrastructure investments. In addition, reconciliation hearings to determine the accuracy and 2021,prudence of natural gas capital investments recovered under the QIP are still ongoing.
The QIP expired in December 2023. Previously, it provided Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that were placed in service between regulatory rate reviews. Infrastructure investments under the QIP earned a return at the applicable WACC. As a result of the expiration of the QIP, Ameren Illinois is requiredsubject to invest a minimumincreased regulatory lag on its natural gas infrastructure investments that are placed in service between regulatory rate reviews, which could adversely affect Ameren’s and Ameren Illinois’ investment plans and results of $625operations, financial position, and liquidity. In addition, reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP from 2020 to 2023 are still ongoing. In October 2023, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow approximately $53 million in natural gas capital projectsinvestments as improper and imprudent, providing a potential over-recovery of approximately $3 million in 2020. In October 2023, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2020. Ameren Illinois’ 2020 QIP rate recovery request under review by the ICC was within the rate increase limitations allowed by law. The ICC is under no deadline to modernize its distribution system incremental to its average annual electric distribution service capital projects of $228 million for calendar years 2008 through 2010. Through 2017,issue an order in this proceeding. Ameren Illinois has invested $508 million in IEIMA capital projects toward its $625 million minimum requirement. If Ameren Illinois does not meet its investment commitments under IEIMA, Ameren Illinois would no longer be eligible to annually update its performance-based formula rates under IEIMA.cannot predict the ultimate outcome of this regulatory proceeding.
Without the extension of formula ratemaking, the IEIMA performance-based formula ratemaking framework expires at the end of 2022. Ameren Illinois would then be required to establish future rates throughAs a traditional rate proceeding with the ICC, which might not result in rates that produce a full or timely recovery of costs or provide for an adequate return on investments. The decoupling provisions of the FEJA do not expire atelection to use the endPISA, effective in 2024, Ameren Missouri’s electric service business is subject to a limitation on increasing the annual revenue requirement due to the inclusion of 2022.incremental PISA deferrals in the revenue requirement.
Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through December 2028 and an additional extension through December 2033 is allowed if requested by Ameren Missouri and approved by the FEJA,MoPSC, among other things. This law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates, compared to the revenue requirement established in the immediately preceding rate order, due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024. Increased capital expenditures could cause incremental PISA deferrals to exceed the 2.5% limitation, and such amounts exceeding the 2.5% limitation would be excluded from recovery under future revenue requirements. Failure to limit capital investments to an amount which maintains PISA deferrals under the 2.5% limitation could adversely affect Ameren’s and Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021 that will earn a return. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. 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.
Missouri’s results of operations, financial position, and liquidity.
We are subject to various environmental laws and regulations.permitting laws. Significant capital expenditures aremay be required to achieve and to maintain compliance with these laws and regulations.environmental laws. Failure to comply with these laws and regulations could result in the closing of facilities, alterations to the manner in which these facilities operate, increased operating costs, ordelays and increased costs of building new facilities, and exposure to fines and liabilities, allliabilities.
Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of which could adversely affect our results of operations, financial position, and liquidity.
We are subject to various environmental lawsstatutes and regulations enforcedrelating to the protection of the environment and human health and safety, including permitting programs implemented by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect toSuch environmental laws and regulations. These laws and regulations address emissions,air emissions; discharges to water water usage, 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 energy-related facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. Further, we are subject to risks from changing or conflicting interpretations of existing laws, modifications to existing laws, new laws, new or modified permit terms, and enforcement of environmental laws and permits by federal, state, and local authorities.
We are also subject to liability under environmental laws that address the remediation of environmental contamination on property currently or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such properties include MGP sites, substations, and third-party sites, such as landfills. Additionally, private individuals and non-governmental organizations may seek to enforce environmental laws and regulations against us. They couldus, allege injury from exposure to hazardous materials, allege a failure to comply with environmental laws, and regulations, seek to compel remediation of environmental contamination, or seek to recover damages resulting from thatpurported 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, 2017,2023, Ameren Missouri’s fossil fuel-firedcoal-fired energy centers represented 17%8% and 33%16% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations under the Clean Air Act that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the revised 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. emissions. Regulations implementing the Clean Water Act govern both intake and discharges from power plants are regulated underof water, as well as evaluation of the Clean Water Act. Such regulationecological and biological impact of those operations, and could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, eitherdischarges. Depending upon the scope of whichmodifications ultimately required by state regulators, capital expenditures associated with these modifications could result in significant capital expenditures.be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR rule,Rule, which will require the closure of 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 compliance with existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers.
Ameren is also subject to risks from changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the power plants implemented modifications. In January 2011, the United States Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The complaint, as amended in October 2013, allegedMissouri alleging that in performing projects at its Rush Island coal-fired energy centerperformed in 2007 and 2010 Ameren Missouriat the coal-fired Rush Island Energy Center violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling against Ameren Missouri and, in September 2019, entered a remedy order that required Ameren Missouri to install a flue gas desulfurization system at the Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. Following an appeal from Ameren Missouri, in August 2021, the United States Court of Appeals for the Eighth Circuit affirmed the liability ruling and the district court’s remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In September 2023, the district court granted Ameren Missouri’s request to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri to operate the energy center as directed by the MISO. The United States Department of Justice is seeking an order from the district court providing for additional mitigation relief. Ameren Missouri could be required to implement mitigation relief measures, the costs of which could be material and which Ameren Missouri would not expect to recover. Ameren Missouri is challenging such mitigation claims, noting that the projects violated provisionsscope of any such potential additional mitigation relief should be limited by the August 2021 court of appeals decision and offset by emission reductions resulting from the accelerated retirement of the Clean Air ActRush Island Energy Center. The MISO designated the energy center as a system support resource in 2022 and concluded that certain reliability mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation through August 2024, and in September 2023, an agreement between Ameren Missouri law.and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies. The case then proceededsystem support resource designation and the related agreement are subject to annual renewal and revision. Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the upgrades expected to be completed in the fall of 2024. Ameren Missouri expects to complete the last of the upgrades by mid-2025. Related to this matter, in November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the second phaseplanned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to determinecollect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed that Ameren Missouri’s prior actions required to remedy the violations foundthat resulted in the liability phase. The EPA previously withdrew all claimsadverse ruling discussed above were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If the remaining unrecovered net plant balance for penaltiesthe Rush Island Energy Center and fines. The ultimate resolutionan associated return are not recoverable through base rates or other regulatory mechanisms, Ameren Missouri would recognize an abandonment loss equal to the difference between the remaining net book value of this matterthe asset and the present value of the expected future cash flows. As of December 31, 2023, the Rush Island Energy Center had a net plant balance of $530 million included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net”. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling discussed above, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Among other things and subject to economic and regulatory considerations, resolution
In June 2022, the installation of pollution control equipment, as well as increased operations and maintenance expenses.
In 2015, the EPA issued the Clean Power Plan, which would have established CO2 emissions standards applicable to existing power plants. The United States Supreme Court stayed the ruleissued its decision in February 2016, pending various legal challenges. In October 2017,West Virginia v. EPA, clarifying that there are limits on how the EPA announced a proposalmay regulate greenhouse gases absent further direction from the United States Congress. The court concluded that the EPA’s proposed rules were designed to repeal the Clean Power Plan.shift generation from fossil-fuel-fired power plants to renewable energy facilities, which was improper absent specific congressional authorization. In December 2017,May 2023, the EPA issued an advanced notice ofa new proposed rulemaking to solicit input from stakeholders as to how the EPA should regulaterule that would set CO2 emissions from emission standards for new and existing fossil-fuel-fired power plants underbased on the Clean Air Act. Accordingly, we no longer expectadoption of carbon capture technology, natural gas co-firing, and co-firing hydrogen fuel to reduce emissions. If the Clean Power Planproposed rule were adopted, the affected fossil-fuel-fired power plants would be required to take effect. However,comply with the rule through a phased-in approach or retire. Capacity restrictions for coal-fired units could apply as early as 2030. Larger natural gas-fired power plants would be required to co-fire with hydrogen by 2032, with additional requirements by 2038. The EPA mayexpects to issue new requirements that would regulate CO2 emissions from existing power plants. Wea final rule in 2024. Legal challenges to the final rule, if adopted as proposed, are expected. Ameren and Ameren Missouri cannot predict the outcome of the EPA’s future rulemaking or the outcomeresults of any legalsuch challenges relating toor potential impacts of any such future rulemakings, any of which could have an adverse effectregulations on ourtheir results of operations, financial position, and liquidity.liquidity until final regulations are adopted and the merits of such legal challenges are determined.
The CEJA established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the CEJA, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service.
Ameren and Ameren Missouri have incurred, and expect to incur, significant costs with respect to environmental compliance and site remediation. New or revised environmental regulations, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties or fines, or reduced operations or closure of some of Ameren Missouri’s coal-firedcoal-and natural gas-fired energy centers, which, in turn, could lead to increased liquidity and financing needs, and higher financing costs. Actions required to ensure that Ameren Missouri’s facilities and operations are in compliance with environmental laws and regulations could be
prohibitively expensive for Ameren Missouri if the costs are not fully recovered through rates. Environmental laws could require Ameren Missouri to close or to alter significantly the operations of its energy centers. If Ameren Missouri requests recovery of capital expenditures and costs for environmental compliance through rates, the MoPSC could deny recovery of all or a portion of these costs, prevent timely recovery, or make changes to the regulatory framework in an effort to minimize rate volatility and customer rate increases. Capital expenditures and costs to comply with future legislation or regulations might result in Ameren Missouri closing coal-fired energy centers earlier than planned. If these costs are not recoverable through base rates or other regulatory mechanisms, it could lead to an impairment of assets and reduced revenues. Any of the foregoing could have an adverse effect on our results of operations, financial positions, and liquidity.
We are subject to business and financial risks related to the impact of climate change legislation, regulation, and emission reduction goals.
There is increasing concern and activism among various external stakeholders, both nationally and internationally, about climate change, including public concerns about the potential environmental impacts from the combustion of fossil fuels, as well as pressure from public interest groups regarding limiting the use of natural gas. Also, state and local authorities have proposed restrictions on the use of natural gas, and the ICC has initiated a future of gas proceeding to explore issues involved with decarbonization of the natural gas distribution system in the state of Illinois. Further, federal, state, and local authorities, including the United States Congress, have considered initiatives to further restrict greenhouse gases to address global climate change. Additionally, international agreements could lead to future federal or state legislation or regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius. The TCJA is complex and significantly affectsBiden administration made a policy commitment regarding a reduction in greenhouse gas emissions for the Ameren Companies. United States, but rulemaking to achieve such reductions has not yet been implemented. Actions taken to implement the Paris Agreement could result in future additional greenhouse gas reduction requirements in the United States. In addition, the EPA has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions from the utility industry.
As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2 emissions. Future federal and state legislation or regulations that mandate limits on the TCJA, theemission of, or impose taxation on, greenhouse gases could result in a significant increase in capital expenditures and operating costs, decreased revenues, penalties or fines, or reduced operations of some of Ameren Companies expect lower operating cash flows, driven by lower customer rates,Missouri’s coal- and natural gas-fired energy centers, which, may needin turn, could lead to be funded through debt and/or equity issuances. Further, additional interpretations, regulations, amendments,increased liquidity and technical correctionsfinancing needs, and higher financing costs. Moreover, to the federal income tax code, as well as the associated treatment by ourextent Ameren Missouri requests recovery of these costs through rates, its regulators may adversely affect ourmight deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations related to climate change might force Ameren Missouri to close some coal-fired energy centers earlier than planned, which could lead to possible loss on abandonment and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity.
The TCJA, among other things, reduced the federal statutory corporate income tax rate from 35% to 21%, effective January 1, 2018. Additionally, the TCJA eliminated 50% accelerated depreciation tax benefits for nearly all regulated utility capital investments made after September 27, 2017. As
Ameren recorded a noncash charge to earnings of $154 millionis targeting net-zero carbon emissions by 2045, as well as a result of the revaluation of deferred taxes, largely attributable to Ameren (parent). Ameren also reclassified deferred income tax liabilities of $2.4 billion to regulatory liabilities. This reclassification is due to the60% reduction of the federal statutory corporate income tax rate, which reduced such income tax obligations,by 2030 and the expected return of funds previously collected from customers. Our rate-regulated businesses recover income taxes in customer ratesan 85% reduction by 2040 based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds2005 levels. Ameren’s goals include both direct emissions from our customers for income taxes and when we pay such taxes. Excess deferred taxes were created as the deferred income tax obligation decreased due to a reduction in the federal statutory corporate income tax rate.
The elimination of 50% accelerated tax depreciation on nearly all capital investments has caused an increase in Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. 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 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion). Over the next five years, Ameren may be required to issue incremental debt and/or equity to fund this reduction in operating cash flows, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%operations (scope 1), as calculated in accordance with ratemaking frameworks.well as electricity usage at Ameren Missouribuildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and Ameren Illinois expect to fund cash flows needs through debt issuances, adjustmentssulfur hexafluoride. Achievement of dividends to Ameren (parent), and/or capital contributions from Ameren (parent), with the intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. As a result of the TCJA, financial metrics used by credit rating agencies may be negatively affected, primarily due to expected decreases in operating cash flows discussed above.
Most of the effects of the TCJA will be reflected in adjusted customer electric and gas rates over time. The regulatory treatment of the effects of the TCJA will be subject to the discretion of the FERC, the MoPSC and the ICC. The period over which the return of excess deferred taxes will occur will ultimately be determined by our regulators.
Certain aspects of the TCJA are unclear. These aspects will require interpretations and regulations from the IRS and state taxing authorities, and the TCJA could be subject to potential amendments and technical corrections, any of which could adversely affect our results of operations, financial position, and liquidity. The revaluation of deferred taxes recorded as of December 31, 2017, may be subject to further adjustment in accordance with additional interpretations or as a result of the IRS audit of the 2017 income tax return, either of which could adversely affect our results of operations, financial position, and liquidity. There may be other material adverse effects resulting from the TCJA that we have not yet identified, each of which could be material in any particular quarterly period.
Customers’, legislators’, and regulators’ opinions of us are affected bythese goals is dependent on many factors, including the pace and extent of development and deployment of low- to zero-carbon energy technologies and carbon capture technologies, and the cost of those technologies; natural gas prices; new transmission infrastructure; the ability to maintain system reliability implementationduring the transition to clean energy generation; and constructive energy and economic policies, including those that address investment in energy infrastructure, global climate change, incentives for clean energy technologies, and environmental regulations. Additional factors associated with operational risks for the construction and acquisition of 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, such as those being undertaken for Ameren Illinois’ electric and natural gas delivery systems, our abilityinfrastructure may also affect the achievement of these goals, as further discussed below. The strategy to safeguard sensitive customer informationachieve these goals also relies on continuing to pursue a diverse portfolio including low-carbon and protect our systems from cyber attacks,carbon-free resources and energy-efficiency resources; continuing to participate in efforts to help advance the development of technologies such as carbon capture, utilization, and sequestration; the use of hydrogen fuel for electric production and energy storage, next generation nuclear, and large-scale long-cycle battery energy storage; and constructively engaging with legislators, regulators, investors, customers, and other 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 developstakeholders to support outcomes leading to 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.net-zero future.
We are subject to federal regulatory compliance and proceedings, which exposes us to the potential forcould result in increasing costs, regulatory penalties, andand/or other sanctions.
TheWe are subject to FERC can impose civil penalties of approximately $1.2 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 $1.5 million per violation per day for violation of its regulations, rules, and orders, including mandatory NERC reliability standards. The FERC also conducts audits and reviews of Ameren Missouri’s, Ameren Illinois’, and ATXI’s accounting records to assess the accuracy of itstheir respective formula ratemaking process, and it can require refunds to be issued to customers for previously billed amounts, with interest.
Additionally, pursuant to the CEJA, Illinois utilities are subject to requirements and provisions related to ethical conduct, including submitting an annual ethics and compliance report to the ICC. The law authorizes the ICC to initiate an investigation into how customer funds were used if a violation of the law is determined to have occurred at an Illinois utility, potentially requiring the utility to issue refunds and imposing a penalty of up to $0.5 million per violation.
OPERATIONAL RISKS
The construction and acquisition of, and capital improvements to, our electric and natural gas utility infrastructure, along with Ameren Missouri’s ability to implement its Smart Energy Plan, which is aligned with its 2023 IRP, involve substantial risks. 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 incurmake 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 $11.4$22.8 billion (Ameren Missouri – up to $4.5$13.5 billion; Ameren Illinois – up to $6.6$7.6 billion; ATXI – up to $0.3$1.7 billion) of capital expenditures from 20182024 through 2022. These2028. For additional information on these estimates, do not reflect the potential additional investments identifiedsee Liquidity and Capital Resources – Capital Expenditures in Ameren Missouri’s integrated resource plan, which could represent incremental investmentsManagement’s Discussion and Analysis of approximately $1 billion through 2020Financial Condition and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made. These estimates include allowance for equity funds used during construction.Results of Operations under Part II, Item 7, of this report. Investments in Ameren’s rate-regulated operations are expected to be recoverable from customers, but they are subject to prudence reviews and are exposed to regulatory lag of varying degrees by jurisdiction.
Our ability to complete construction projects successfully within projected estimates, including schedule, performance, and/or cost, and to implement Ameren Missouri’s Smart Energy Plan, which may include acquisition of generation facilities after they are constructed, is contingent upon many variablesfactors and subject to substantial risks. These variablesfactors include, but are not limited to, the following: project management expertise,expertise; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment; escalating costs, forincluding but not limited to changes to tariffs on materials and labor, the ability to obtain required project approvals, and the ability to obtain necessary rights-of-way and easements. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors who do not perform as required under their contracts,or government actions; changes in the scope and timing of projects; the ability to obtain required regulatory, project, and permit approvals; the ability to obtain necessary rights-of-way, easements, and transmission connection agreements at an acceptable cost in a timely fashion; unsatisfactory performance by the projects when completed; the inability to earn an adequate return on invested capital; the ability to raise capital on reasonable terms, orterms; geopolitical conflict 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 carbon emission reduction targets outlined in the 2023 IRP, factors also include Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources or natural gas-fired generation, retirement of energy centers, and new or continued customer energy-efficiency
programs; the ability to enter into agreements for renewable or natural gas-fired generation and acquire or construct that generation at a reasonable cost; the ability to obtain NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date; the ability to qualify for, and use or transfer, federal production or investment tax credits; the cost of wind, solar, and performanceother renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to maintain system reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; energy prices and demand.
Any of these 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.
Ameren and Ameren Illinois may not be able to execute their electric transmission investment plans or to realize the expected return on those investments.
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 changes, including changes as a result of third-party complaints and challenges at the FERC. The regulatory framework may be less favorable or the rate of return may be lower in the future. 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 $8 million and $4 million, respectively, based on each company’s 2018 projected rate base.
A significant portion of Ameren’s electric transmission investments consists of three separate ATXI projects, which have been approved by MISO as multi-value projects. As of December 31, 2017, ATXI’s expected remaining investment in all three projects was approximately $300 million, with the total investment expected to be more than $1.6 billion The last of these projects is expected to be completed in 2019. A failure by ATXI to complete these three projects on time and within projected cost estimates could adversely affect Ameren’s results of operations, financial position, and liquidity.
Within MISO, certain new transmission projects which are eligible for regional cost sharing may be subject to competition. Therefore, Ameren may need to compete to build certain future electric transmission projects in its subsidiaries’ service territories. Such competition could limit Ameren’s future transmission investment.
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;
•aging infrastructure that may require significant expenditures to operate and maintain;
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 ultra-low-sulfur coal used by Ameren Missouri to comply with environmental regulations;
•lack of adequate water required for cooling plant operations;operations and to operate hydroelectric energy centers;
•labor disputes;
•disruptions in the delivery of electricity to our customers;
•inability to maintain reliability of our electric utility services as coal-fired energy centers are retired and renewable energy generation is placed in service;
•disruptions to the global supply chain as a result of shortages for labor, materials, or equipment, international trade relations, geopolitical conflict, delivery delays, economic pressures, including increased interest rates and inflation, among other things;
•suppliers and contractors who do not perform as required under their contracts;contracts, including those obligations that are affected by supply chain disruptions;
•failure of other operators’ facilities and the effect of that failure on our electric system and customers;
•inability to comply with regulatory requirements or permit requirements,obtain permits, including those relating to environmental laws;
disruptions in the delivery of electricity to our customers;
•handling, storage, and disposition of CCR;
•unusual or adverse weather conditions or other natural disasters, including those that may result from climate change, such as severe storms, droughts, floods, tornadoes, earthquakes, icing, sustained high or low temperatures, solar flares, and electromagnetic pulses;
•the level of wind and solar resources;
•inability to operate wind generation facilities at full capacity resulting from requirements to protect natural resources, including wildlife;
•the occurrence of catastrophic events such as fires, explosions, acts of sabotage, which have increased in frequency and severity within the utility industry, acts of terrorism, civil unrest, pandemic health events, or other similar events;
•accidents that might result in injury or loss of life, extensive property damage, or environmental damage;
•ineffective vegetation management programs;
•cybersecurity risks, including loss of operational control of Ameren Missouri’s energy centers and our transmission and distribution systems and loss of data, including sensitive customer, employee, financial, and operating system information, through insider or outsider actions;
failure of other operators’ facilities and the effect of that failure on our electric system and customers;
the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, pandemic health events, or other similar events;
•limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities;
•inability to implement or maintain information systems;
•failure to keep pace with and the ability to adapt to rapid technological change; and
•other unanticipated operations and maintenance expenses and liabilities.
The foregoing risks could affect the controls and operations of our facilities or impede our ability to meet regulatory requirements, which could increase operating costs, increase our capital requirements and costs, reduce our revenues, or have an adverse effect on our liquidity.
Ameren Missouri’s ability to obtain an adequate supply of coal could limit operation of its coal-fired energy centers.
Ameren Missouri owns and operates coal-fired energy centers. About 97% of Ameren Missouri’s coal is purchased from the Powder River Basin in Wyoming, which has a limited number of suppliers. Deliveries from the Powder River Basin have occasionally been restricted because of rail congestion, staffing and equipment issues, infrastructure maintenance, derailments, weather, and supplier financial hardship. As of December 31, 2023, coal inventory at the Labadie Energy Center was below targeted levels and coal inventory at the Sioux Energy Center was at targeted levels. Additional delays or disruptions in the delivery of coal, failure of our coal suppliers to provide adequate quantities or quality of coal, or lack of adequate inventories of coal, including low-sulfur coal used to comply with environmental regulations,
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, including losses due to market performance and other economic factors that adversely affect the value of the securities in the nuclear decommissioning trust fund;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 primarily one NRC-licensed supplier of Callaway Energy Center’s assemblies;
•costly and extended outages for scheduled or unscheduled maintenance and refueling;
•uncertainties about the technological and financial aspects of decommissioning nuclear facilities at the end of their licensed lives;
limited availability of fuel supply•the ability to continue to attract and our reliance on licensed fuel assemblies that are fabricated by Westinghouse,maintain qualified labor to operate the Callaway energy center’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;Energy Center;
costly and extended outages for scheduled or unscheduled maintenance and refueling;
•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 release of nuclear contamination.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. While the Callaway Energy Center is in compliance with the current NRC standards relating to seismic design and risk, these standards also require Ameren Missouri to further evaluateaddress periodic changes to seismic hazard data and evaluation methods for the impact of an earthquake on its Callaway energy centerEnergy Center due to its proximity to a fault line, which could require theseismic risk evaluation updates and installation of additional capital equipment.
Our natural gas distribution and storage activitiesservice businesses involve numerous risks that may result in accidents and increased operating costs that could adversely affect our results of operations, financial position, and liquidity.costs.
Inherent in our natural gas distribution businesses, which includes transmission, distribution, and storage activitiesfacilities, 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 transmission and distribution mains and storage facilities near populated areas, including residential areas, business centers, industrial sites, and other public gathering places, could increase the level of damages resulting from these risks. A major domestic incident involving natural gas systemsfacilities 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 replacementreplacement. Ameren Missouri could be adversely affected if it is unable to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that could adversely affect our results of operations, financial position,remaining investment and liquidity.those decommissioning costs.
Our aging infrastructure may pose risks to system reliability and expose us to expedited or unplanned significant capital expenditures and operating costs. All of Ameren Missouri’s coal-fired energy centers were constructed prior to 1978, and the Callaway energy center Energy Center
began operating in 1984. The age of these energy centers increases the risks of unplanned outages, reduced generation output, and higher maintenance expense. If, at the end of its life, an energy center’s cost has not been fully recovered,Also, as discussed above, Ameren Missouri mayexpects to retire the Rush Island Energy Center by October 15, 2024. Further, Ameren Missouri would 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. 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 ifwhen 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 IEIMACEJA 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, compounded by high interest rates and inflationary pressures, could cause additional rate volatility for our customers, resistance by our regulators to allow customer rate increases, and/or regulatory lag in some of our jurisdictions, any of which could adversely affect our results of operations, financial position, and liquidity.
Energy conservation, energy efficiency, distributed generation, energy storage, technological advances, and other factors thatcould reduce energy demand could adversely affect Ameren and Ameren Missouri’s results of operations, financial position, and liquidity.from our customers.
Without a regulatory mechanism to ensure recovery, declines in energy usage willcould result in an under-recovery of Ameren Missouri’sour revenue requirement. Such declines could occur due to a number of factors:
Conservation and energy-efficiency programs. Missouri allows for conservation and energy-efficiency programs that are designed to reduce energy demand.
Distributed generation and other energy-efficiency efforts. Ameren Missouri is exposed to declining usage from energy-efficiency efforts not related to its energy-efficiency programs, as well as from 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 have become more cost-competitive, with decreasing costs expected in the future. The costs 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 to reduce the demand for our electric utility services. Increased adoption 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 incur stranded costs, which ultimately might not be recovered through rates.
Macroeconomic factors. Macroeconomic factors resulting in low economic growthrequirement or contraction within Ameren Missouri’s service territories could reduce energy demand.
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. A significant portion of our work force is nearing retirement, including many employees with specialized skills, such as maintaining and servicing our electric and natural gas infrastructure and operating our energy centers. We are also party to collective bargaining agreements that collectively represent about 52% of Ameren’s total employees. 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. 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 impact 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 our customer rates, as 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 couldrevenue requirement would 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 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 long-term debt. By the end of 2019, $951 million and $457 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these
senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. 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 a recession 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,spread over less sales volumes, which could adversely affect our results of operations, financial position, and liquidity. Such declines could occur due to a number of factors, including:
•customer energy-efficiency programs that are designed to reduce energy demand;
•energy-efficiency efforts by customers not related to our energy-efficiency programs;
•increased customer use of distributed generation sources, such as solar panels and other technologies, which have become more cost-competitive, with decreasing costs expected in the future, as well as the use of energy storage technologies; and
•macroeconomic factors resulting in low economic growth or contraction within our service territories, which could reduce energy demand.
Decreased use of our generation, transmission, and distribution services might result in stranded costs, which ultimately might not be recovered through rates, and therefore could lead to an impairment or abandonment of assets.
FINANCIAL, ECONOMIC, AND MARKET RISKS
Ameren’s holding company structure could limit its ability to pay common stock dividends and to service its debt obligations.
Ameren is a holding company; therefore, its primary assets are its investments in the common stock of its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. As a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s ability to service its debt obligations is dependent upon the earnings of its operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under affiliate indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations, and other items affecting retained earnings, and available cash. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of affiliate borrowing arrangements and cash payments under the tax allocation agreement) to Ameren. Under the IRA, a 15% minimum tax on adjusted financial statement income, as defined in the law, is assessed against corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. As Ameren files a consolidated income tax return, it is reliant on its subsidiaries to pay the minimum tax once the threshold is exceeded. The payments related to the minimum tax by Ameren Missouri, Ameren Illinois, and ATXI are expected to be recovered, subject to approval by their respective regulators. Certain financing agreements, corporate organizational documents, and certain statutory and regulatory requirements may impose restrictions on the ability of Ameren Missouri, Ameren Illinois, and ATXI to transfer funds to Ameren in the form of cash dividends, loans, or advances.
IncreasingSignificant increases in prices of labor, services, materials and supplies and other costs, including costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits, could adversely affect our results of operations, financial position, or liquidity.
A part of our core strategy focuses on disciplined cost management, including prudently monitoring all of our expenses. However, we have observed inflationary pressures related to prices of labor, services, materials and supplies, and other costs. We are uncertain whether these inflationary pressures will continue and at what rate. These inflationary pressures, as well as high interest rates, could impact our ability to control costs, to make substantial investments in our businesses, to recover costs and investments, to earn our allowed ROEs within
frameworks established by our regulators, and/or to maintain affordability of our services for our customers. In addition, these inflationary pressures and high interest rates could adversely affect our customers’ usage of, or payment for, our services. Additionally, volatility in the commodities market could increase collateral postings and prepayments. Also, market volatility could significantly affect the investment performance of Ameren’s COLI. Significant increases in our costs could increase our financing needs and otherwise adversely affect our results of operations, financial position, and liquidity. For additional information on purchased power costs, see Outlook under Part II, Item 7, of this report.
Related to benefits, Ameren 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 waswere overfunded by $551 million as of December 31, 2017.2023. Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on Ameren’sits assumptions at December 31, 2017,2023, its investment performance in 2017,2023, and its pension funding policy, Ameren does not expect to make material contributions in 2024 and 2025, and expects to make annual contributions of less than $1 million to $60 million in each of the next five years, with aggregate estimated contributions of $120 million. We expectmillion in 2026 through 2028. Ameren Missouri’sMissouri and Ameren Illinois’ portionsIllinois estimate that their portion of the future funding requirements towill be 35%40% and 55%50%, respectively. These amounts are estimates. Theyestimated contributions may change withbased on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions.
In addition to the costs of our retirementpension plans, the costs of providing health care benefits to our employees and retirees have increased in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. Future legislative changes related to health care could also significantly change our benefit programs and costs.
GENERAL RISKS
Customers’, investors’, legislators’, regulators’, and creditors’ opinions of us are affected by many factors, including system reliability, implementation of our strategic plan, protection of customer information, rates, media coverage, and ESG practices, as well as actions by other utility companies. Negative opinions developed by customers, investors, legislators, regulators, and creditors could harm our reputation.
Our results are influenced by the expectations of our customers, investors, legislators, regulators, and creditors. Those expectations are based, in part, on the reliability and affordability of our utility services. Service interruptions and facility shutdowns can occur due to failures of equipment as a result of severe or destructive weather or other causes. The ability of Ameren Missouri and Ameren Illinois to respond promptly to such failures can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, our ability to safeguard sensitive customer information and protect our systems from physical or cyber attacks, and other actions can affect customer satisfaction. The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect regulator and customer satisfaction.
Our ability to successfully execute our strategic plan, including the transition of Ameren Missouri’s generation fleet and achievement of the carbon emission reduction targets outlined in the 2023 IRP, may affect customers’, investors’, legislators’, regulators’, and creditors’ opinions and actions. Additionally, negative perceptions or publicity resulting from increasing costsscrutiny of ESG practices could negatively impact our reputation, investment in our common stock, or our access to capital and funding requirementscredit markets. Customers’, investors’, legislators’, regulators’, and creditors’ opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation.
If customers, investors, legislators, regulators, or creditors have or develop a negative opinion of us and our utility services, this could result in increased costs associated with regulatory oversight and could affect the ROEs we are allowed to earn, as well as the access to, and the cost of, capital. Additionally, negative opinions about us or other utility companies could make it more difficult for our defined benefit retirement plans, health care plans, and other employee benefitsbusinesses to achieve favorable legislative or regulatory outcomes. Negative opinions could increasealso result in sales volume reductions or increased use of distributed generation by our financing needs and otherwisecustomers. Any of these consequences could adversely affect our results of operations, financial position, and liquidity.
We are subject to employee workforce factors that could adversely affect our operations.
Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. Certain specialized knowledge that focuses on skilled-craft and STEM-related disciplines is required to construct and operate generation, transmission, and distribution assets. Further, a significant portion of our work force is nearing retirement. As of December 31, 2023, approximately 23% of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ total employees were 55 years old or older. We are also party to collective bargaining agreements that collectively represent about 46%, 58%, and 54% of Ameren’s, Ameren Missouri’s and Ameren Illinois’ total employees, respectively. The Ameren Missouri collective bargaining unit contracts expire in 2025 and 2026, and cover 4% and 96% of represented employees, respectively. The Ameren Illinois collective bargaining unit contracts expire in 2026 and 2027, and cover 92% and 8% of represented employees, respectively. Remote working arrangements could increase our data security risks, including loss of data
related to sensitive customer, employee, financial, and operating system information, through insider or outsider actions. Certain events, such as significant delays in finding appropriate replacement talent, inadequately trained replacement employees, a mismatch of skill sets to future needs, any work stoppage experienced in connection with negotiations of collective bargaining agreements, or challenges with remote working arrangements, could adversely affect our operations.
Our operations are subject to acts of sabotage, terrorism, cyber attacks, and other intentionally disruptive acts.
Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and enterprise information systems may be affected by malicious acts, terrorist activities and other intentionally disruptive acts, including physical and cyber attacks, which could disrupt our ability to produce or distribute our energy products. In the industry, there continues to be attacks on energy infrastructure, such as substations and related assets. The threat landscape continues to expand, which may result in more attacks in the future. Any such incident could limit our ability to generate, purchase, or transmit power or natural gas and could have significant regional economic consequences. Any such disruption could result in a significant decrease in revenues, a significant increase in costs including those for repair, or adversely affect economic activity in our service territory which, in turn, could adversely affect our results of operations, financial position, and liquidity.
There has been an increase in the number and sophistication of physical and cyber attacks across all industries worldwide. Physical attacks could include sabotaging, vandalizing, or burglarizing transmission and distribution facilities, which are unmanned, widely dispersed, and often in isolated areas, or the theft of physical data and information. Cyber attacks could include viruses, malicious or destructive code, phishing attacks, denial of service attacks, supply chain attacks, ransomware and other extortion-based attacks, improper access by third parties, attacks on email systems, and attacks leading to data loss, operational control, or exploitation of vulnerabilities specific to internally developed systems or to those provided and/or maintained by our suppliers, including those attacks arising from or generated by artificial intelligence, among various other security breaches. A security breach of our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm resulting from theft or the inappropriate release or destruction of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, availability of our services could be impacted, and/or we could be subject to increased costs associated with regulatory oversight, fines or legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected grid. Therefore, a disruption caused by a physical or cyber incident at another utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. Insurance might not be adequate to cover losses that arise in connection with these events. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.
Our businesses are dependent on our ability to access the capital and credit markets successfully. We might not have access to sufficient capital in the amounts and at the times needed, as well as on reasonable terms.
We rely on the issuance of short-term and long-term debt and equity as significant sources of liquidity and funding for capital requirements not satisfied by our operating cash flow, as well as to refinance existing long-term debt. The inability to raise debt or equity capital on reasonable terms, or at all, could negatively affect our ability to maintain or to expand our businesses. General economic factors beyond our control might create uncertainty that could increase our cost of capital or impair or eliminate our ability to access the debt, equity, or credit markets, including our ability to draw on bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Any adverse change in our credit ratings could reduce access to capital and trigger collateral postings and prepayments. Such changes could also increase the cost of borrowing and the costs of fuel, power, and natural gas supply, among other things, which could adversely affect our results of operations, financial position, and liquidity.
| |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C.CYBERSECURITY
The Ameren Companies have identified cybersecurity as an enterprise risk, which is managed through Ameren's integrated enterprise risk management program. The program is designed to continuously assess risk and evaluate the likelihood and probability of impact in order to determine the appropriate risk tolerance and risk management strategies that inform our cybersecurity policies, investments, practices, controls, and countermeasures. The program is a comprehensive, consistently applied management framework that is designed to ensure all forms of material risk and opportunity are identified, reported and managed in an effective manner overseen by the risk management steering
committee. The risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors’ oversight, oversees Ameren's enterprise risk management processes, which include the identification, assessment, mitigation, and monitoring of risks including strategic, operational, and cybersecurity risks.
Ameren's board of directors maintains a standing committee, the Cybersecurity and Digital Technology Committee, that is dedicated to the oversight of Ameren's cybersecurity and digital technology risks. The committee has primary responsibility for oversight of cybersecurity and digital technology risk management, including the programs, policies, practices, controls and safeguards for digital technology, information security, prevention and detection of cybersecurity incidents and information or data breaches, and cybersecurity and digital technology matters as they relate to crisis preparedness, incident response plans, and disaster recovery and business continuity capabilities. The committee receives regular updates from the Chief Customer and Technology Officer, the Chief Information Officer, the Chief Information Security Officer, and other members of senior management regarding Ameren’s cybersecurity program and key initiatives. The Cybersecurity and Digital Technology Committee regularly reports on its activities to Ameren’s board of directors, including reviewing and advising Ameren’s board of directors of any developments it believes should be considered.
Ameren's cybersecurity program and team are led by the Chief Information Security Officer, who possesses 25 years of critical infrastructure experience both managing and protecting information systems in concert with extensive cybersecurity operations and leadership roles. The Chief Information Security Officer regularly engages with senior-level Ameren officers, reports to the risk management steering committee, and has recurring meetings with the Cybersecurity and Digital Technology Committee as part of ongoing risk management and oversight of the cybersecurity program. Ameren’s board of directors is also regularly updated on its cybersecurity program. In addition, the board of directors participate in periodic cybersecurity drills to prepare for potential crisis scenarios.
To manage against existing conduct and new cybersecurity threats, we maintain enterprise-wide cybersecurity, crisis management, and information security policies and regular training and tests that reinforce the acceptable use of Ameren's information assets, protection of customer and employee data, and the role each employee plays in protecting Ameren against cybersecurity threats. Incident response plans and procedures are tested through recurring companywide cybersecurity exercises to promote readiness across the organization. The procedures are also designed to escalate incidents to appropriate members of management to guide the detection, response, and recovery from a material cybersecurity incident. To address cybersecurity threats, cybersecurity intelligence, as well as responding to cyber-related incidents, we work closely with law enforcement, cybersecurity consulting firms, and industry associations to enhance information sharing and guard against cybersecurity attacks.
We measure our cybersecurity effectiveness through formal cybersecurity scorecards and metrics reported to senior-level Ameren officers, the risk management steering committee, and the Cybersecurity and Digital Technology Committee. These metrics include but are not limited to measures around the effectiveness of our cybersecurity controls, our ability to manage cybersecurity events and incidents, cybersecurity incident response exercises, and results of our recurring internal assessments, external assessments, and audits that Ameren regularly undergoes. Ameren regularly engages external cybersecurity experts to assist with evaluating our cybersecurity program. These engagements provide insights into control performance, prioritized recommendations for enhancements to our cybersecurity strategy, and an overview of the cybersecurity threat landscape that collectively inform our investments and technical controls to protect Ameren's most critical assets. The results of these engagements are reviewed with senior-level Ameren officers and the Cybersecurity and Digital Technology Committee.
Ameren also deploys a third-party cybersecurity risk management program, which extends the governance elements described above to our third-party providers and suppliers. The supply chain and third-party risks introduced to Ameren are evaluated prior to the commencement of any new engagement or relationship, monitored closely throughout the lifecycle of the supplier and managed through privacy and cybersecurity provisions within the respective commercial contracts. Procedures have been established to address supplier incidents as well as supplier off-boarding at the expiration of the relationship.
We are not aware of any cybersecurity events that have materially affected or are reasonably likely to materially affect Ameren, including our business strategy, results of operations, financial position, or liquidity.
ITEM 2.PROPERTIES
For information on our principal properties, see the energy center tableand in-service utility-related properties tables below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of planned additions, replacements or transfers.additions. See also Note 5 – Long-term Debt and Equity Financings and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
The following table shows the anticipated capability of Ameren Missouri’sour energy centers at the time of Ameren Missouri’sthe expected 20182024 peak summer electrical demand:
demand for all energy centers owned as of December 31, 2023: | | | | | | | | | | | |
| | | | |
| Primary Fuel Source | Energy Center | Location | Net Kilowatt Capability(a) |
CoalAmeren Missouri: | | Labadie | |
| Coal | Labadie(b) | Franklin County, Missouri | 2,372,000 | |
| Rush Island(c) | Jefferson County, Missouri | 1,178,000 | |
| Sioux(d) | Sioux | St. Charles County, Missouri | 972,000 | |
| Total coal | | | 4,522,000 | |
| Nuclear | Meramec(b)Callaway(e)
| Callaway County, Missouri | 1,194,000 | |
| Hydroelectric | Osage(e) | Lakeside, Missouri | 235,000 | |
| Keokuk | Keokuk, Iowa | 148,000 | |
| Total hydroelectric | | | 383,000 | |
| Pumped-storage | Taum Sauk(e) | Reynolds County, Missouri | 440,000 | |
| Wind | High Prairie Renewable | Adair and Schuyler Counties, Missouri | 400,000 | |
| Atchison Renewable | Atchison County, Missouri | 298,800 | |
| Total wind | | | 698,800 | |
| Natural gas (CTs) | Audrain | Audrain County, Missouri | 608,000 | |
| Venice(f) | Venice, Illinois | 487,000 | |
| Goose Creek(f) | Piatt County, Illinois | 438,000 | |
| Pinckneyville(f) | Pinckneyville, Illinois | 316,000 | |
| Raccoon Creek(f) | Clay County, Illinois | 304,000 | |
| Kinmundy(f) | Kinmundy, Illinois | 210,000 | |
| Peno Creek | Bowling Green, Missouri | 172,000 | |
| Total natural gas | | | 2,535,000 | |
| Oil (CTs) | Fairgrounds(g) | Jefferson City, Missouri | 55,000 | |
| Mexico(g) | Mexico, Missouri | 54,000 | |
| Moberly(g) | Moberly, Missouri | 54,000 | |
| Moreau(g) | Jefferson City, Missouri | 54,000 | |
| Total oil | | | 217,000 | |
| Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 9,000 | |
| Solar | Montgomery County | Montgomery County, Missouri | 5,700 | |
| O’Fallon | O’Fallon, Missouri | 4,500 | |
| BJC | St. Louis, Missouri | 1,600 | |
| Cape Girardeau | Cape Girardeau, Missouri | 1,200 | |
| Lambert | St. Louis County, Missouri | 591,000900 | |
| Total coalOther Solar(h) | Various | 1,400 | | 5,113,000
|
NuclearTotal solar | | Callaway | 15,300 | | Callaway County, Missouri1,194,000 |
|
HydroelectricTotal Ameren Missouri | Osage | Lakeside, Missouri | 240,00010,014,100 | |
| Ameren Illinois: | | Keokuk | Keokuk, Iowa | 144,000
|
Total hydroelectricSolar | East St. Louis | | 384,000 |
|
Pumped-storage | Taum Sauk | Reynolds County, Missouri | 440,000 |
|
Oil (CTs) | Fairgrounds | Jefferson City, Missouri | 55,000 |
|
| Meramec | East St. Louis, County, MissouriIllinois | 55,0002,500 | |
| Mexico | Mexico, Missouri | 54,000 |
|
| Moberly | Moberly, Missouri | 54,000 |
|
| Moreau | Jefferson City, Missouri | 54,000 |
|
Total oil | | | 272,000 |
|
Natural gas (CTs) | Audrain(c)
| Audrain County, Missouri | 608,000 |
|
| Venice(d)
| Venice, Illinois | 491,000 |
|
| Goose Creek | Piatt County, Illinois | 438,000 |
|
| Pinckneyville | Pinckneyville, Illinois | 316,000 |
|
| Raccoon Creek | Clay County, Illinois | 304,000 |
|
| Meramec(b)(d)(e)
| St. Louis County, Missouri | 281,000 |
|
| Kinmundy(d)
| Kinmundy, Illinois | 208,000 |
|
| Peno Creek(c)(d)
| Bowling Green, Missouri | 192,000 |
|
Total natural gas | | | 2,838,000 |
|
Methane gas (CT) | Maryland Heights | Maryland Heights, Missouri | 8,000 |
|
Solar | O’Fallon | O’Fallon, Missouri | 3,000 |
|
Total Ameren and Ameren Missouri | | | 10,016,600 | | 10,252,000 |
|
| |
(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 lease 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 generating facilities represents nameplate capacity. This capacity is only attainable when wind/solar conditions are sufficiently available. The on-demand capability for wind and solar units is zero.
(b)The Labadie Energy Center is scheduled to retire 1,186,000 kilowatts by 2036 and 1,186,000 kilowatts by 2042.
(c)The Rush Island Energy Center is scheduled to retire by October 15, 2024 per the remedy order of the United States District Court for the Eastern District of Missouri. For additional information, see NSR and Clean Air Act Litigation in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
(d)As noted in the 2023 IRP, Ameren Missouri plans to extend the retirement date of the Sioux Energy Center from 2030 to 2032, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC.
(e)The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively.
(f)The Venice Energy Center is scheduled to retire by the end of 2029 and the Goose Creek, Pinckneyville, Raccoon Creek, and Kinmundy energy centers are scheduled to retire by the end of 2039 as noted in the 2023 IRP. See Illinois Emissions Standards in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.
(g)The Fairgrounds, Mexico, Moberly, and Moreau energy centers are scheduled to be retired by the end of 2029 as noted in the 2023 IRP.
(h)Includes five solar energy centers that each have a nameplate capacity of 500 kilowatts or less.
The following table presents in-service electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 2017:2023:
| | | | | | | | | | | |
| Ameren
Missouri | | Ameren
Illinois |
Circuit miles of electric transmission lines(a) | 3,140 | | | 4,761 | |
| Circuit miles of electric distribution lines | 33,927 | | | 45,984 | |
| Percentage of circuit miles of electric distribution lines underground | 24 | % | | 16 | % |
| Miles of natural gas transmission and distribution mains | 3,532 | | | 18,713 | |
| Underground natural gas storage fields | — | | | 12 | |
| Total working capacity of underground natural gas storage fields in billion cubic feet | — | | | 24 | |
|
| | | | | |
| | Ameren Missouri | | Ameren Illinois |
Circuit miles of electric transmission lines(a) | 2,970 |
| | 4,638 |
|
| Circuit miles of electric distribution lines | 33,414 |
| | 45,899 |
|
| Percentage of circuit miles of electric distribution lines underground | 23 | % | | 15 | % |
| Miles of natural gas transmission and distribution mains | 3,379 |
| | 18,393 |
|
| Underground natural gas storage fields | — |
| | 12 |
|
| Total working capacity of underground natural gas storage fields in billion cubic feet | — |
| | 24 |
|
| |
(a) | ATXI owns 303 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 as of December 31, 2023 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 and Atchison Renewable energy centers; Ameren Missouri’s BJC, Cape Girardeau, Lambert, and Maryland Heights energy centers; certain substations; and most transmission and distribution lines and natural gas mains. The United States or the state of Missouri may own or may have paramount rights with respect to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which certain of Ameren Missouri’s energy centers and other properties are located.
•The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of Ameren Missouri’s Keokuk energy 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 respective mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek CT energy center to the city of Bowling Green, Missouri, and leased the energy center back from the city through 2022. Under the terms of this capital lease, 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 lease, at which time the property, plant, and equipment will become subject to the lien of any Ameren Missouri first mortgage bond indenture then in effect.
Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as lessee of the CT energy center under a long-term lease with Audrain County. The lease will expire in December 2023. Under the terms of this capital lease, 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 lease, at which time the property, plant, and equipment will become subject to the lien of any Ameren Missouri first mortgage bond indenture then in effect.
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. Ameren Missouri’s proceeding with the MoPSC to investigate how the effect of the reduction in the federal statutory corporate income tax rate enacted under TCJA should be reflected in rates paid by electric and natural gas customers;
Ameren Illinois’ proceeding with the ICC to pass through to its natural gas customers the effect of the reduction in the federal statutory corporate income tax rate enacted under the TCJA;
Ameren Illinois’ natural gas regulatory rate review filed with the ICC in January 2018;
the request filed by MISO participants, including Ameren Illinois and ATXI, with the FERC to allow revisions to 2018 electric transmission rates to reflect the impacts of the reduction in the federal statutory corporate income tax rate enacted under the TCJA;
the February 2015 complaint case filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff;
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, 2017,2023, all their positions and offices held with the Ameren Companies as of February 15, 2018,29, 2024, and their tenures as officers, and their business backgroundstitles 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 | Period |
| | | | |
NameMartin J. Lyons, Jr. | Age57 | | Positions and Offices Held |
| | | |
Warner L. Baxter | 56 |
| | Chairman, President, and Chief Executive Officer, and DirectorOfficer; Ameren | January 2022(a) – Present |
| Baxter joined | Chairman and President; 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. | December 2019 – January 2022 |
| | Chairman and President; Ameren Services | | | March 2016 – December 2019 |
| Martin J. Lyons, Jr. | 51
| | Executive Vice President and Chief Financial OfficerOfficer; Ameren | January 2013 – December 2019 |
Lyons joinedMichael L. Moehn | 54 | Senior Executive Vice President and Chief Financial Officer; Ameren | March 2023 – Present |
| | Chairman and President; Ameren Services in 2001. In 2008, he was elected senior vice president and chief accounting officer of the Ameren Companies. In 2009, he was also elected chief financial officer of the Ameren Companies. In 2013, 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. | December 2019 – Present |
| | Executive Vice President and Chief Financial Officer; Ameren | | | December 2019 – February 2023 |
| Gregory L. Nelson | Chairman and President; Ameren Missouri | 60April 2014 – December 2019 |
| Chonda J. Nwamu |
52 | Executive Vice President, General Counsel, and Secretary; Ameren | March 2023 – Present |
| | Senior Vice President, General Counsel, and SecretarySecretary; Ameren | August 2019 – February 2023 |
| Nelson joined | Senior Vice President and Deputy General Counsel; Ameren Missouri in 1995. He was elected vice president and tax counsel of Ameren Services in 1999 and 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, he was elected senior vice president, general counsel and secretary of the Ameren Companies. | January 2019 – August 2019 |
| Theresa A. Shaw | 51 | | |
Bruce A. Steinke | 56 |
| | Senior Vice President, Finance, and Chief Accounting OfficerOfficer; Ameren | August 2021 – Present |
Steinke joined
| | Senior Vice President, Regulatory Affairs and Financial Services; Ameren Services in 2002. In 2008, he was elected vice presidentIllinois | September 2019 – August 2021 |
| | Vice President, Regulatory Affairs and controller ofFinancial Services; 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. | July 2018 – August 2019 |
(a)Elected President and Chief Executive Officer of Ameren in January 2022, and Chairman of Ameren in November 2023.
SUBSIDIARIES:
| | | | | | | | | | | |
| Name | Age | Positions | Period |
| | | |
| Bhavani Amirthalingam | 48 | Executive Vice President and Chief Customer and Technology Officer; Ameren Services | | March 2023 – Present |
| Name | Senior Vice President and Chief Digital Information Officer; Ameren Services | Age | | Positions and Offices HeldMarch 2018 – February 2023 |
| Mark C. Birk | 5359 |
Chairman and President; Ameren Missouri | January 2022 – Present |
| | Senior Vice President, Customer and Power Operations (Ameren Missouri)Operations; Ameren Missouri | October 2017 – January 2022 |
Birk joined Ameren Missouri in 1986. In 2005, 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 | 5561 |
| | Senior Vice President and Chief Nuclear Officer (Ameren Missouri)Officer; Ameren Missouri | January 2014 – Present |
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 | 61 |
| | Senior Vice President and Chief Information Officer (Ameren Services) |
Heger joined Ameren Missouri in 1976. In 2009, she was elected vice president, information technology, of Ameren Services, and in 2012, she was also elected chief information officer of Ameren Services. In 2015, she was elected senior vice president and chief information officer of Ameren Services. |
| | | |
| Mark C. Lindgren | 5056 |
Executive Vice President, Corporate Communications, and Chief Human Resources Officer; Ameren Services | March 2023 – Present |
| | Senior Vice President, Corporate Communications, and Chief Human Resources Officer (Ameren Services)Officer; Ameren Services | September 2015 – February 2023 |
Lindgren joinedGwendolyn G. Mizell | 62 | Senior Vice President and Chief Sustainability, Diversity, & Philanthropy Officer; Ameren Services in 1998. In 2009, he was elected vice president, human resources, of | March 2023 – Present |
| | Vice President, Chief Sustainability, Diversity, & Philanthropy Officer; Ameren Services and in 2012, he was also elected chief human resources officer of Ameren Services. In 2015, he was elected senior vice president, corporate communications, and chief human resources officer of Ameren Services. | March 2022 – February 2023 |
| | Vice President, Innovation, and Chief Sustainability Officer; Ameren Services | | | January 2021 – March 2022 |
| Richard J. Mark | Vice President, Sustainability and Electrification; Ameren Services | 62 |
| | Chairman and President (Ameren Illinois)June 2019 – January 2021 |
| Mark joined | Senior Director, Corporate Social Responsibility; 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. | March 2018 – June 2019 |
| | | |
Michael L. Moehn | 48 |
| | Chairman and President (Ameren Missouri) |
Moehn joined Ameren Services in 2000. In 2004, he was elected vice president, corporate planning, of Ameren Services. In 2008, he was elected senior vice president, corporate planning and business risk management, of Ameren Services. In 2012, he was elected senior vice president, customer operations, of Ameren Missouri, and relinquished his position at Ameren Services. In 2014, he was elected chairman and president of Ameren Missouri. |
| | | |
| Shawn E. Schukar | 5662 |
| | Chairman and President (ATXI)President; ATXI | May 2017 – Present |
Schukar joined a predecessor company ofLeonard P. Singh | 54 | Chairman and President; 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. | August 2022(a) – Present |
(a)Leonard P. Singh served as Senior Vice President of Consolidated Edison Company of New York from December 2020 to June 2022 and as Vice President, Manhattan Electric Operations of Consolidated Edison Company of New York from June 2015 to December 2020.
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No 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 andofficer or any directorsdirector of the Ameren Companies. All ofExcept 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 PURCHASES OF EQUITY SECURITIES
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 47,74835,157 on January 31, 2018. The following table presents the price ranges, closing prices, and dividends declared per Ameren common share for each quarter during 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| | High | | Low | | Close | | Dividends Declared |
| 2017 Quarter Ended: | | | | | | | |
| March 31 | $ | 56.57 |
| | $ | 51.35 |
| | $ | 54.59 |
| | $ | 0.44 |
|
| June 30 | 57.21 |
| | 53.72 |
| | 54.67 |
| | 0.44 |
|
| September 30 | 60.91 |
| | 53.54 |
| | 57.84 |
| | 0.44 |
|
| December 31 | 64.89 |
| | 57.67 |
| | 58.99 |
| | 0.4575 |
|
| 2016 Quarter Ended: | | | | | | | |
| March 31 | $ | 50.16 |
| | $ | 41.50 |
| | $ | 50.10 |
| | $ | 0.425 |
|
| June 30 | 53.59 |
| | 46.29 |
| | 53.58 |
| | 0.425 |
|
| September 30 | 54.08 |
| | 47.79 |
| | 49.18 |
| | 0.425 |
|
| December 31 | 52.88 |
| | 46.84 |
| | 52.46 |
| | 0.44 |
|
2024. There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding common stock of Ameren Missouri and Ameren Illinois.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its registrant subsidiaries during 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 | | | 2016 |
| (In millions) | Quarter Ended | | | Quarter Ended |
| Registrant | December 31 | | September 30 | | June 30 | | March 31 | | | December 31 | | September 30 | | June 30 | | March 31 |
| Ameren Missouri | $ | 30 |
| | $ | 160 |
| | $ | 112 |
| | $ | 60 |
| | | $ | 70 |
| | $ | 75 |
| | $ | 70 |
| | $ | 140 |
|
| Ameren Illinois | — |
| | — |
| | — |
| | — |
| | | 15 |
| | 35 |
| | 30 |
| | 30 |
|
| Ameren | 111 |
| | 106 |
| | 107 |
| | 107 |
| | | 107 |
| | 103 |
| | 103 |
| | 103 |
|
On February 9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 45.75 cents per share. The common share dividend is payable March 29, 2018, to shareholders of record on March 14, 2018.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see 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.
Purchases of Equity Securities
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
|
| | | | | | | | | | | | |
| Period | (a) Total Number of Shares (or Units) Purchased | | (b) Average Price Paid per Share (or Unit) | | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
October 1 – October 31, 2017 | — |
| | $ | — |
| | — |
| | — |
|
November 1 – November 30, 2017(a) | 5,232 |
| | 62.35 |
| | — |
| | — |
|
December 1 – December 31, 2017 | — |
| | — |
| | — |
| | — |
|
| Total | 5,232 |
| | $ | 62.35 |
| | — |
| | — |
|
| |
(a) | The shares of Ameren common stock were purchased in open-market transactions in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards issued under its stock-based compensation plans. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
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, 2017,2023, to December 31, 2017.
2023.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder returnTSR during the five years ended December 31, 2017.2023. 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, 2012,2018, in Ameren common stock and in each of the indices shown and it assumes that all of the dividends were reinvested.
Comparison of Five-Year Cumulative Return
| | | December 31, | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | December 31, | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 |
| Ameren (AEE) | $ | 100.00 |
| | $ | 123.31 |
| | $ | 163.67 |
| | $ | 159.79 |
| | $ | 200.79 |
| | $ | 232.84 |
|
| S&P 500 Index | 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
| EEI Index | 100.00 |
| | 113.01 |
| | 145.68 |
| | 140.00 |
| | 164.42 |
| | 183.69 |
|
| S&P 500 Utility Index | |
| Philadelphia Utility Index | |
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.(RESERVED)
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Ameren(a): | | | | | | | | | |
| Operating revenues | $ | 6,177 |
| | $ | 6,076 |
| | $ | 6,098 |
| | $ | 6,053 |
| | $ | 5,838 |
|
Operating income(b) | 1,458 |
| | 1,381 |
| | 1,259 |
| | 1,254 |
| | 1,184 |
|
Income from continuing operations(c) | 529 |
| | 659 |
| | 585 |
| | 593 |
| | 518 |
|
Income (loss) from discontinued operations, net of taxes(d) | — |
| | — |
| | 51 |
| | (1 | ) | | (223 | ) |
| Net income attributable to Ameren common shareholders | 523 |
| | 653 |
| | 630 |
| | 586 |
| | 289 |
|
| Common stock dividends | 431 |
| | 416 |
| | 402 |
| | 390 |
| | 388 |
|
| Continuing operations earnings per share – basic | 2.16 |
| | 2.69 |
| | 2.39 |
| | 2.42 |
| | 2.11 |
|
| Continuing operations earnings per share – diluted | 2.14 |
| | 2.68 |
| | 2.38 |
| | 2.40 |
| | 2.10 |
|
| Common stock dividends per share | 1.778 |
| | 1.715 |
| | 1.655 |
| | 1.61 |
| | 1.60 |
|
| As of December 31: | | | | | | | | | |
Total assets(e) | $ | 25,945 |
| | $ | 24,699 |
| | $ | 23,640 |
| | $ | 22,289 |
| | $ | 20,907 |
|
| Long-term debt, excluding current maturities | 7,094 |
| | 6,595 |
| | 6,880 |
| | 6,085 |
| | 5,475 |
|
| Total Ameren Corporation shareholders’ equity | 7,184 |
| | 7,103 |
| | 6,946 |
| | 6,713 |
| | 6,544 |
|
| Ameren Missouri: | | | | | | | | | |
| Operating revenues | $ | 3,539 |
| | $ | 3,523 |
| | $ | 3,609 |
| | $ | 3,553 |
| | $ | 3,541 |
|
Operating income(b) | 747 |
| | 745 |
| | 742 |
| | 785 |
| | 803 |
|
Net income available to common shareholder(c) | 323 |
| | 357 |
| | 352 |
| | 390 |
| | 395 |
|
| Dividends to parent | 362 |
| | 355 |
| | 575 |
| | 340 |
| | 460 |
|
| As of December 31: | | | | | | | | | |
| Total assets | $ | 14,043 |
| | $ | 14,035 |
| | $ | 13,851 |
| | $ | 13,474 |
| | $ | 12,867 |
|
| Long-term debt, excluding current maturities | 3,577 |
| | 3,563 |
| | 3,844 |
| | 3,861 |
| | 3,631 |
|
| Total shareholders’ equity | 4,081 |
| | 4,090 |
| | 4,082 |
| | 4,052 |
| | 3,993 |
|
| Ameren Illinois: | | | | | | | | | |
| Operating revenues | $ | 2,528 |
| | $ | 2,490 |
| | $ | 2,466 |
| | $ | 2,498 |
| | $ | 2,311 |
|
| Operating income | 580 |
| | 544 |
| | 466 |
| | 450 |
| | 415 |
|
| Net income available to common shareholder | 268 |
| | 252 |
| | 214 |
| | 201 |
| | 160 |
|
| Dividends to parent | — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| As of December 31: | | | | | | | | | |
| Total assets | $ | 10,345 |
| | $ | 9,474 |
| | $ | 8,903 |
| | $ | 8,204 |
| | $ | 7,397 |
|
| Long-term debt, excluding current maturities | 2,373 |
| | 2,338 |
| | 2,342 |
| | 2,224 |
| | 1,844 |
|
| Total shareholders’ equity | 3,310 |
| | 3,034 |
| | 2,897 |
| | 2,661 |
| | 2,448 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | Includes a $69 million provision recorded in 2015 for all of the previously capitalized COL costs relating to the cancelled second nuclear unit at its Callaway energy center.
|
| |
(c) | Includes an increase to income tax expense of $154 million and $32 million recorded in 2017 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. |
| |
(d) | See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. |
| |
(e) | Includes total assets from discontinued operations of $165 million at December 31, 2013, and immaterial balances at December 31, 2017, 2016, 2015, and 2014. Total assets from discontinued operations are included in “Other current assets” on Ameren’s balance sheet. |
| |
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 including– Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as the provision ofproviding shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise. 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 developing MISO-approved electric transmission projects, includingbusiness in the Illinois Rivers and Mark Twain projects, and placed the Spoon River project in service in February 2018.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 is primarily composedconsists 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.
Unless otherwise stated, the following sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations exclude discontinued operations for all periods presented. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information regarding that presentation.segments.
Ameren’s and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of itstheir majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri andMissouri’s subsidiaries were created for the ownership of renewable generation projects. Ameren Illinois havehas no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
The following discussion should be read in conjunction with the financial statements contained in this Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Discussion regarding our financial condition and results of operations for the year ended December 31, 2021, including comparisons with the year ended December 31, 2022, is included in Item 7 of our Form 10-K for the year ended December 31, 2022.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding for the relevant period.share.
OVERVIEW
Ameren’s strategic plan includes investing in,Our core strategy is driven by the following three pillars, which allow us to capitalize on opportunities to benefit our customers, communities, shareholders, and operating its utilities in, a manner consistent with existingthe environment:
| | | | | | | | | | | | | | | | | | | | |
| Investing in rate-regulated energy infrastructure | | Enhancing regulatory frameworks, enhancing those frameworks and advocating for responsible policies | | Optimizing operating performance |
| To capitalize on opportunities to benefit our customers, communities, shareholders, and the environment |
| We invest in rate-regulated energy infrastructure and seek to earn competitive returns on our investments. We seek to make prudent investments that benefit our customers. The goal of these investments is to maintain and enhance the reliability of our services, develop and deliver cleaner sources of energy, create economic development opportunities in our region, and provide customers with more options and greater control over their energy usage, among other things. By prudently investing in our businesses, we believe that we deliver superior value to both customers and shareholders. | | We seek to partner with our stakeholders, including our customers, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers and shareholders. We believe enhancing our regulatory frameworks is important to drive investment in our business segments, earn competitive returns on those investments, and realize timely recovery of our costs with the benefits accruing to both customers and shareholders. | | Utilizing a continuous improvement mindset, we seek to optimize operating performance for the benefit of our customers. We remain focused on disciplined cost management and strategic capital allocation. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators. We focus on minimizing the gap between allowed and earned ROEs and allocating capital resources to business opportunities that we expect will provide the most benefit to our customers and offer the most attractive risk-adjusted return potential. |
| |
| |
Rate Base ($ in billions)(a) | | Regulatory Frameworks(c) | | Improved Reliability(f) |
| | Segment | Regulatory Framework | | |
| Ameren
Transmission | Formula ratemaking
Allowed ROE of 10.52% | |
| Ameren Illinois
Electric
Distribution | Future test year ratemaking under an MYRP(d) Allowed ROE of 8.72%(e) | |
| Ameren Illinois
Natural Gas | Future test year ratemaking and PGA and VBA
Allowed ROE of 9.44% | |
| |
| Ameren
Missouri | Historical test year ratemaking and
PISA, RESRAM, FAC, MEEIA, PGA
Allowed ROE is not specified | |
| |
| | | |
(a)Reflects year-end rate base except for Ameren Transmission, which is average rate base. Ameren Illinois Electric Distribution excludes electric energy-efficiency rate base. (b)Compound annual growth rate. (c)As of January 2024. (d)In January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order in its MYRP proceeding. For more information on the MYRP proceeding, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. (e)Ameren Illinois’ formula ratemaking framework related to energy-efficiency investments uses an allowed ROE of the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points, subject to performance standards discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. (f)As measured by Ameren Missouri’s and Ameren Illinois’ System Average Interruption Frequency Index. |
Key announcements, updates, and regulatory outcomes
In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The approved revenue requirement was based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to 2030. The order did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard compliance costs that the MoPSC previously authorized in earlier electric rate orders, as well as creating and capitalizing on opportunities for investmentthe use of an electric property tax tracker. It also includes a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of its customersincome. The new rates became effective on July 9, 2023.
In June 2023, Ameren Missouri filed for CCNs with the MoPSC for four solar generation facilities, including the Split Rail Solar Project (300-MW facility, build-transfer agreement), the Cass County Solar Project (150-MW facility, development-transfer agreement), the Vandalia Solar Project (50-MW facility, self-build), and shareholders.the Bowling Green Solar Project (50-MW facility, self-build). In February 2024, Ameren remains focused on disciplined cost managementMissouri, the MoPSC staff, and strategic capital allocation. In 2017,the MoOPC filed a nonunanimous stipulation and agreement requesting the MoPSC approve Ameren continued to allocate significant amountsMissouri’s requests for CCNs for the Split Rail, Vandalia, and Bowling Green solar projects. The stipulation and agreement also requests MoPSC approval of capital to those businesses that arethe CCN request for the Cass County Solar Project conditioned upon the facility supporting the Renewable Solutions Program and full subscription of the portion of the program supported by constructive regulatory frameworks. It invested $1.4 billion of capital expendituresthis facility, subject to certain other terms and conditions. The remaining intervenors did not object to the agreement. Ameren Missouri expects a decision by the MoPSC in its FERC rate-regulated electric transmissionMarch 2024. Each project is expected to support Ameren Missouri’s transition to renewable generation and, Illinois electricin addition, the Cass County Solar Project is expected to support Ameren Missouri’s Renewable Solutions Program. In February and natural gas distribution businesses.April 2023, the MoPSC issued orders approving requested CCNs for the Huck Finn and Boomtown solar projects, respectively.
In March 2017,August 2023, the MoPSC issued an order approving a unanimousnonunanimous stipulation and agreement into extend Ameren Missouri’s July 2016 regulatory rate review. The electric rateMEEIA 2019 program for an additional year through 2024. For 2024, the order resulted inapproved the establishment of a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in the base levelportfolio of net energy costs, and a $26 million reduction in the base level of certain tracked expenses, compared with the amounts in the MoPSC’s April 2015 rate order. The new rates and base level of expenses became effective on April 1, 2017. In September 2017, Ameren Missouri filed its nonbinding 20-year integrated resource plan with the MoPSC. This plan includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable sources by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, and adding 100 megawatts of solar generation over the next 10 years. These new renewable energy sources would 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. The plan also provides for expanding renewable generation, retiring coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs and adding cost-effective demandperformance incentives that will provide Ameren Missouri an opportunity to earn revenues, including $12 million of performance incentive revenues if Ameren Missouri achieves certain program spending goals. In 2024, Ameren Missouri expects to invest $76 million in energy-efficiency programs. In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA for 2025 through 2027. The proposed plan includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.
In November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response programs. The new renewable energy sources identified into Ameren Missouri’s plan could represent incremental investmentspetition that stated Ameren Missouri’s decision to accelerate the retirement of approximately $1 billion through 2020. In connection with the integrated resource plan filing,Rush Island Energy Center was prudent and largely supported Ameren Missouri established a goalMissouri’s securitization request. However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of reducing CO2 emissions 80% by
2050 from a 2005 base level. To meet this goal,report, were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is targetingnot allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a 35% CO2 emission reductionmaterial adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri expects a decision by 2030 and a 50% reductionthe MoPSC by 2040 from the 2005 level by retiring coal-fired generation at the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.
In February 2024, Ameren Missouri filed an update to its useful life.Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2024. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $12.4 billion over the five-year period from 2024 through 2028, with expenditures largely recoverable under the PISA. Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.
In January 2017,December 2023, the ICC issued an order in Ameren Illinois implemented provisionsIllinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the FEJAMYRP proceeding. Rate changes consistent with the order became effective in January 2024. The ICC concluded that improved the constructive regulatory framework of its electric distribution business. The FEJA decoupled electric distribution revenues established in a rate proceeding from actual sales volumes. It provided that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes that are reflected in that year’s rates be collected from, or refunded to, customers within two years. Also, since June 2017, the FEJA has allowedproposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to defer the costs of its electric energy-efficiency program asfile a regulatory asset and earnrevised Grid Plan within three months. Ameren Illinois expects to file a return on those investments. The regulatory asset earns a return at the company’s weighted-average cost of capital,revised Grid Plan with the equity return based onICC in March 2024, and also expects to file a request to update the monthly average yieldassociated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the 30-year United States Treasury bonds plus 580 basis points. The equity portionyears 2024 through 2027, using the 2022 year-end rate base approved by the ICC in its 2022 electric distribution service revenue requirement reconciliation adjustment order discussed below. This rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of Ameren Illinois’ return on electric energy-efficiency program investments can also be increased or decreased by up to 200 basis points, depending on the achievementa revised Grid Plan results in an update of annual energy savings goals. each year’s revenue requirement.
In January 2018,2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include
a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements and annual rate base amounts to reflect a base level of investments to maintain grid reliability for 2024 through 2027. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District.
The following table presents the approved revenue requirements, ROE, capital structure common equity percentage, and annual rate base in the ICC’s December 2023 order, as well as the proposed revenue requirements and annual rate base amounts in Ameren Illinois’ February 2024 rehearing request filing:
| | | | | | | | | | | | | | |
| Year | Revenue Requirement (in millions) | ROE | Capital Structure Common Equity Percentage | Annual Rate Base (in billions) |
| ICC’s December 2023 MYRP Order: | | | | |
| 2024 | $1,162 | 8.72% | 50% | $3.9 |
| 2025 | $1,210 | 8.72% | 50% | $3.9 |
| 2026 | $1,242 | 8.72% | 50% | $3.9 |
| 2027 | $1,255 | 8.72% | 50% | $3.9 |
| Ameren Illinois’ February 2024 Rehearing Request Filing: | | | | |
| 2024 | $1,214 | (a) | 50% | $4.2 |
| 2025 | $1,300 | (a) | 50% | $4.5 |
| 2026 | $1,371 | (a) | 50% | $4.7 |
| 2027 | $1,420 | (a) | 50% | $4.9 |
(a)The ROE is under appeal as discussed above.
The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase.
In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $110 million, which reflected Ameren Illinois’ actual 2022 recoverable costs, year-end rate base of $3.9 billion, and a capital structure composed of 50% common equity. The approved reconciliation adjustment will be collected from customers in 2024. In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC seeking approvalby May 2024, which will reflect its 2023 year-end rate base. The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.
In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to increase its annual revenues for natural gas delivery service by $49of $112 million which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider. The request was based on a 10.3% return on common equity,9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of $1.6approximately $2.85 billion.
The order reflected a reduction of approximately $93 million of planned distribution and transmission capital investments included in Ameren Illinois’ requested revenue increase, which used a 2024 future test year. The new rates became effective on November 28, 2023. In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements withDecember 2023, Ameren Missouri and an electric cooperative in northeast Missouri to locate almost allIllinois filed a request for rehearing of the Mark Twain project on existing line corridors. It also received assents for road crossings fromICC's November 2023 order. The filing requested the five affected countiesICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and transmission capital investments included in northeast Missouri.the order, among other things. In January 2018,2024, the MoPSC granted ATXI a certificateICC denied Ameren Illinois’ rehearing request. Subsequently, in January 2024, Ameren Illinois filed an appeal of conveniencethe November 2023 ICC order and necessitythe January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Mark Twain project. ATXI plansFifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal.
In November 2023, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $100 million beginning in January 2024, which represents an increase of $24 million from 2023 rates. The order was based on a projected 2024 year-end rate base of $394 million.
In 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in the second quarter of 2018 and to complete the project by2026, with forecasted completion dates near the end of 2019.this decade. In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects. In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion. The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024. In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed above that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025.
In October 2017,February 2023, Ameren’s board of directors increased the quarterly common stock dividend to 45.7563 cents per share, resulting in an annualized equivalent dividend rate of $1.83$2.52 per share. In February 2024, Ameren’s board of directors increased the quarterly common stock dividend to 67 cents per share, resulting in an annualized equivalent dividend rate of $2.68 per share.
For further information on the matters discussed above, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and the Outlook section below.
Earnings
Net income attributable to Ameren common shareholders from continuing operations was $523$1,152 million, or $2.14$4.38 per diluted share, for 2017,2023, and $653$1,074 million, or $2.68$4.14 per diluted share, for 2016.2022. Net income was favorably affected in 2023, compared with 2022, by increased infrastructure investments across all business segments and a higher recognized ROE at Ameren Illinois Electric Distribution as well as increased base rate revenues at Ameren Missouri pursuant to the June 2023 MoPSC electric rate order. Earnings were also favorably affected by decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase in the cash surrender value of COLI, at Ameren Missouri and Ameren Illinois Natural Gas. Net income was unfavorably affected in 2017,2023, compared with 2016,2022, by increased income tax expensedecreased retail sales at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to a noncash charge to earnings formilder winter and summer temperatures. In addition, lower retail sales volumes, excluding the revaluationestimated effects of deferred taxes primarilyweather, decreased net income at Ameren (parent) as a result of the TCJA and the increaseMissouri in the Illinois income tax rate.2023, compared with 2022. Earnings in 2023, compared to 2022, were also unfavorably affected in 2017, compared with 2016, by decreased demand,increased financing costs at Ameren (parent), Ameren Missouri, and Ameren Illinois Natural Gas, primarily due to higher interest rates on increased levels of short-term borrowings at Ameren (parent), and higher long-term debt balances and higher interest rates on short-term borrowings and long-term debt, partially offset by higher levels of allowance for funds used during construction, at Ameren Missouri due to milder temperatures in 2017, by the absence in 2017 of the MEEIA 2013 performance incentive, and by increased depreciation and amortization expenses at Ameren Missouri. Net income was favorably affected in 2017, compared with 2016, by an increase in base rates, and lower base level of expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order, and by increased investments in infrastructure at the Ameren Illinois Electric Distribution and Ameren Transmission segments, which reflect Ameren’s strategy to allocate incremental capital to those businesses.
After the application of jurisdictional regulatory recovery mechanisms, the effect of the revaluation of deferred taxes as a result of the TCJA was a decrease to Ameren’s and Ameren Missouri’s net income of $154 million and $36 million, respectively, while the effect on Ameren Illinois’ net income was immaterial.Natural Gas.
Liquidity
At December 31, 2017,2023, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.6$2.1 billion.
Capital ExpendituresAmeren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. As of December 31, 2023, Ameren had approximately $770 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2023. For information regarding long-term debt issuances and maturities, common stock issuances, and outstanding forward sale agreements entered into under the ATM program through the date of this report, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.
Ameren continued to make significant investment in its utility businesses by makingremains focused on strategic capital allocation. The following chart presents 2023 capital expenditures by segment and the midpoint of $0.8 billion, $0.5 billion, $0.2 billion, and $0.6 billion in Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. projected cumulative capital expenditures for 2024 through 2028 by segment:
| | | | | | | | |
2023 Capital Expenditures by Segment (Total Ameren – $3.6 billion) (in billions) | | Midpoint of 2024 – 2028 Projected Capital Expenditures by Segment (Total Ameren – $21.9 billion) (in billions) |
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri(a) | | | Ameren Illinois Natural Gas | |
| | | | | | |
| | Ameren Illinois Electric Distribution | | | Ameren Transmission | |
For 20182024 through 2022,2028, Ameren’s cumulative capital expenditures are projected to range from $10.5$21.0 billion to $11.4$22.8 billion. The following table presents the range of projected spending by segment includes up to $4.5segment:
| | | | | | | | | | | | | | |
| | Range (in billions) |
Ameren Missouri(a) | | $ | 12.5 | | – | $ | 13.5 | |
Ameren Illinois Electric Distribution(b) | | 2.8 | | – | 3.1 | |
Ameren Illinois Natural Gas(b) | | 1.8 | | – | 1.9 | |
| Ameren Transmission | | 3.9 | | – | 4.3 | |
Ameren(a)(b) | | $ | 21.0 | | – | $ | 22.8 | |
(a)Amounts include $3.3 billion $2.5 billion, $1.7 billion,of renewable generation investments and $2.7 billion forof dispatchable generation investments, which includes $0.9 billion related to coal-fired generation, through 2028, consistent with Ameren Missouri,Missouri’s 2023 IRP.
(b)Amounts include investments necessary to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained. Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively.Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Economic conditions, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands and by weather conditions, such as storms, as well as by 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.costs, the cash surrender value of COLI, and the asset value of Ameren Missouri’s nuclear decommissioning trust fund. Almost all of Ameren’s revenues are subject to state or federal regulation.
This regulation has a material impact on the 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. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory frameworks.
We are observing inflationary pressures on the prices of labor, services, materials, and supplies, as well as high interest rates. Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for fuel, purchased power, and natural gas supply. Additionally, for certain non-commodity cost changes, the use of trackers, riders, formula ratemaking, and future test years, as applicable, mitigates our exposure.
Ameren Missouri principally uses coal nuclear fuel, and natural gasenriched uranium for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, inflation, and many other factors. As described below, weWe have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution service businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution service business, and a FAC for Ameren Missouri’s electric utility business.
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 rate proceeding, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. 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 to reduce the previously recognized FAC regulatory asset. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional rate proceeding. 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 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.
Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers. The FEJA also provides Ameren Illinois with cost recovery of renewable energy credit compliance, zero-emission credits, and energy-efficiency investments as well as a return on those electric energy-efficiency investments. 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 expense and costs of certain asbestos-related claims not recovered in base rates. Ameren Illinois’ natural gas business also has the QIP rider, which provides for recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews.
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. The regulatory balance is then collected from, or refunded to, customers within two years.
Ameren Illinois’ electric distribution service revenue requirement is 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 under the IEIMA and the FEJA is equal to the calendar year average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworks for both its electric distribution service and its electric energy-efficiency investments is directly correlated to the yields on such bonds. Beginning in 2017, the FEJA also provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes.
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’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, 2017, 2016,2023 and 2015:2022: |
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Net income attributable to Ameren common shareholders | $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| Earnings per common share – diluted | 2.14 |
| | 2.68 |
| | 2.59 |
|
| Net income attributable to Ameren common shareholders – continuing operations | 523 |
| | 653 |
| | 579 |
|
| Earnings per common share – diluted – continuing operations | 2.14 |
| | 2.68 |
| | 2.38 |
|
2017 versus 2016 | | | | | | | | | | | |
| 2023 | | 2022 |
| Net income attributable to Ameren common shareholders | $ | 1,152 | | | $ | 1,074 | |
| Earnings per common share – diluted | 4.38 | | | 4.14 | |
| | | |
| | | |
| | | |
Net income attributable to Ameren common shareholders from continuing operations in 2017 decreased $1302023 increased $78 million, or $0.54$0.24 per diluted share, from 2016.2022. The decreaseincrease was due to net income increases of $56 million, $33 million, and $11 million at Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively. The increases in net income were partially offset by a net income decrease of $17 million at Ameren Missouri and an increase in the net loss of $125 million for activity not reported as part of a segment, primarily at Ameren (parent), and a net income decrease of $34 million$5 million.
Earnings per share in 2023, compared with 2022, were favorably affected by:
•increased rate base investments 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.and a higher recognized ROE due to a higher annual average of the monthly yields of the 30-year United States Treasury bonds at Ameren Illinois Electric Distribution, which increased revenues at these segments (25 cents per share);
Compared•increased base rate revenues at Ameren Missouri effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, partially offset by the amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a lower base level of expenses included in trackers, and the net recovery for amounts associated with 2016, 2017the reduction in sales volumes resulting from MEEIA programs (12 cents per share);
•decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase in the cash surrender value of COLI, primarily at Ameren Missouri and Ameren Illinois Natural Gas (11 cents per share);
•decreased income tax expense not subject to formula rates or riders due, in part, to decreased income tax expense recognized at Ameren (parent) because of changes in the state income taxes apportioned to Missouri and Illinois, reflecting changes in revenues, as well as the effect of favorable market returns on COLI, compared with unfavorable returns in the year-ago period (6 cents per share);
•increased base rate revenues at Ameren Missouri for the inclusion of previously deferred PISA and RESRAM interest charges pursuant to the December 2021 and June 2023 MoPSC electric rate orders effective February 28, 2022, and July 9, 2023, respectively, partially offset by increased interest charges resulting from lower deferrals related to infrastructure investments associated with the PISA and RESRAM (6 cents per share);
•decreased taxes other than income taxes, primarily at Ameren Missouri, largely resulting from employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act in 2023 (3 cents per share);
•increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP (3 cents per share);
•increased other income, net, largely due to increased non-service cost components of net periodic benefit income not subject to formula rates or trackers (3 cents per share); and
•recovery of previously incurred expenses at Ameren Illinois Electric Distribution (2 cents per share).
Earnings per share from continuing operationsin 2023, compared with 2022, were unfavorably affected by:
an increase in income tax expense, primarily•decreased retail sales at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decrease in the federal statutory corporate income tax rate resulting from enactment of the TCJA (63 cents per share),Missouri and an increase in theAmeren Illinois corporate income tax rate (6 cents per share), as discussed in Note 12 – Income Taxes under Part II, Item 8, of this report;
decreased demandNatural Gas, primarily at Ameren Missouri due to milder winter and summer temperatures as well as lower sales volumes, excluding the estimated effects of weather, in 20172023 (estimated at 1525 cents per share);
•increased financing costs at Ameren (parent), Ameren Missouri, and Ameren Illinois Natural Gas, primarily due to higher interest rates on increased levels of short-term borrowings at Ameren (parent), and higher long-term debt balances and higher interest rates on short-term borrowings and long-term debt, partially offset by higher levels of allowance for funds used during construction, at Ameren Missouri recognized in 2016 (7and Ameren Illinois Natural Gas (13 cents per share);
•increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouriweighted-average basic common shares outstanding 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 participantsissuances of additional MISO-approved electric transmission investments made by other entities (2 cents per share).
Compared with 2016, 2017 earnings per share from continuing operations 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 lower base level of expenses at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate ordercommon shares as discusseddetailed in Note 25 – RateLong-term Debt and Regulatory MattersEquity Financings under Part II, Item 8, of this report (32(7 cents per share);
•increased depreciation and amortization expenses not recoverable under riders or trackers at Ameren Transmission earnings under formula ratemaking,Missouri and Ameren Illinois Natural Gas, primarily due to additional rate base, 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 rate base investment as well as a higher recognized return on equityproperty, plant, and equipment investments (4 cents per share); and
decreased income tax expense, excluding the effect of corporate income tax rate changes discussed above, primarily•lower MEEIA 2019 performance incentives recognized 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 share-based compensation compared with 2016 (1 centMissouri (3 cents per share).
The cents per share informationvariances above are presented above is based on the diluted averageweighted-average basic shares outstanding in 2016. Pretax2022 and do not reflect the impact of dilution on earnings per share, unless otherwise noted. The amounts above other than variances related to income taxes have been presented net of income taxes using Ameren’s 20162023 blended federal and state statutory tax rate of 39%.
2016 versus 2015
Net income attributable to Ameren common shareholders from continuing operations in 2016 increased $74 million, or $0.30 per diluted share, from 2015. The increase was due to net income increases of $34 million, $22 million, $5 million, and $3 million at Ameren Transmission, Ameren Illinois Natural Gas, Ameren Missouri, and Ameren Illinois Electric Distribution, respectively. Additionally, the net loss from other businesses, primarily Ameren (parent), and intersegment eliminations decreased $10 million.
In 2015, net income attributable to Ameren common shareholders from discontinued operations was favorably affected by the recognition of a tax benefit resulting from the removal of a reserve for unrecognized tax benefits of $53 million recorded in 2013 related to the divestiture of New AER, based on the completion of the IRS audit of Ameren’s 2013 tax year.
Compared with 2015, 2016 earnings per share from continuing operations were favorably affected by:
increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment. Ameren Transmission earnings also benefited from a temporarily higher allowed return on common equity, recognizing an 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 complaint case (19 cents per share);
the absence of a provision recognized in 2015, as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its Callaway energy center site (18 cents per share);
increased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures (estimated at 15 cents per share);
higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order (11 cents per share);
an income tax benefit recorded at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation (9 cents per share);
decreased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri (7 cents per share)26%. This was due, in part, to a reduction in energy center maintenance costs, excluding the cost of the Callaway energy center’s scheduled refueling and maintenance outage (discussed below), and reduced electric distribution maintenance expenditures; and
increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment, partially offset by a lower return on equity resulting from a reduction in the 30-year United States Treasury bond yields (2 cents per share).
Compared with 2015, 2016 earnings per share from continuing operations were unfavorably affected by:
the absence in 2016 of MEEIA net shared benefits due to the expiration of MEEIA 2013, partially offset by the recognition of a MEEIA 2013 performance incentive (15 cents per share);
decreased Ameren Missouri sales to the New Madrid Smelter resulting from a reduction in operations at the smelter (15 cents per share);
the cost of the Callaway energy center’s scheduled refueling and maintenance outage in 2016. There was no Callaway refueling and maintenance outage in 2015 (7 cents per share);
increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri, primarily resulting from additional electric property, plant, and equipment (4 cents per share);
decreased Ameren Illinois Electric Distribution earnings resulting from the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share);
decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues (3 cents per share); and
increased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Illinois Natural Gas, primarily due to increased repairs and compliance expenditures (2 cents per share).
The cents per share information presented above is based on the diluted average shares outstanding in 2015. Pretax amounts have been presented net of income taxes, using Ameren’s 2015 statutory tax rate of 39%.
For additional details regarding the Ameren Companies’ segment results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Provision for Callaway Construction and Operating License, Depreciation and Amortization Expenses, Taxes Other Than Income Taxes, Other Income, and Expenses,Net, Interest Charges, Income Taxes, and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.
Below is Ameren’s table of income statement components by segment for the years ended December 31, 2017, 2016,2023 and 2015:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | Ameren
Missouri | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren
Transmission | | Other /
Intersegment
Eliminations | | Ameren |
| Electric revenues | $ | 3,694 | | | $ | 2,218 | | | $ | — | | | $ | 677 | | | $ | (150) | | | $ | 6,439 | |
| Fuel | (514) | | | — | | | — | | | — | | | — | | | (514) | |
| Purchased power | (483) | | | (933) | | | — | | | — | | | 118 | | | (1,298) | |
| Electric margins | 2,697 | | | 1,285 | | | — | | | 677 | | | (32) | | | 4,627 | |
| Natural gas revenues | 165 | | | — | | | 897 | | | — | | | (1) | | | 1,061 | |
| Natural gas purchased for resale | (79) | | | — | | | (276) | | | — | | | — | | | (355) | |
| Natural gas margins | 86 | | | — | | | 621 | | | — | | | (1) | | | 706 | |
| Other operations and maintenance expenses | (1,003) | | | (532) | | | (237) | | | (60) | | | (34) | | | (1,866) | |
| | | | | | | | | | | |
| Depreciation and amortization | (783) | | | (351) | | | (108) | | | (138) | | | (7) | | | (1,387) | |
| Taxes other than income taxes | (360) | | | (75) | | | (67) | | | (8) | | | (12) | | | (522) | |
| Operating income (loss) | 637 | | | 327 | | | 209 | | | 471 | | | (86) | | | 1,558 | |
| Other income, net | 130 | | | 103 | | | 30 | | | 28 | | | 57 | | | 348 | |
| Interest charges | (227) | | | (89) | | | (55) | | | (96) | | | (99) | | | (566) | |
| Income (taxes) benefit | 8 | | | (82) | | | (50) | | | (106) | | | 47 | | | (183) | |
| Net income (loss) | 548 | | | 259 | | | 134 | | | 297 | | | (81) | | | 1,157 | |
| Noncontrolling interests – preferred stock dividends | (3) | | | (1) | | | — | | | (1) | | | — | | | (5) | |
| Net income (loss) attributable to Ameren common shareholders | $ | 545 | | | $ | 258 | | | $ | 134 | | | $ | 296 | | | $ | (81) | | | $ | 1,152 | |
| 2022 | | | | | | | | | | | |
| Electric revenues | $ | 3,849 | | | $ | 2,256 | | | $ | — | | | $ | 615 | | | $ | (139) | | | $ | 6,581 | |
| Fuel | (473) | | | — | | | — | | | — | | | — | | | (473) | |
| Purchased power | (677) | | | (984) | | | — | | | — | | | 114 | | | (1,547) | |
| Electric margins | 2,699 | | | 1,272 | | | — | | | 615 | | | (25) | | | 4,561 | |
| Natural gas revenues | 197 | | | — | | | 1,180 | | | — | | | (1) | | | 1,376 | |
| Natural gas purchased for resale | (104) | | | — | | | (553) | | | — | | | — | | | (657) | |
| Natural gas margins | 93 | | | — | | | 627 | | | — | | | (1) | | | 719 | |
| Other operations and maintenance expenses | (1,028) | | | (580) | | | (253) | | | (60) | | | (16) | | | (1,937) | |
| | | | | | | | | | | |
| Depreciation and amortization | (732) | | | (332) | | | (98) | | | (123) | | | (4) | | | (1,289) | |
| Taxes other than income taxes | (363) | | | (75) | | | (82) | | | (9) | | | (10) | | | (539) | |
| Operating income (loss) | 669 | | | 285 | | | 194 | | | 423 | | | (56) | | | 1,515 | |
| Other income, net | 99 | | | 60 | | | 19 | | | 17 | | | 31 | | | 226 | |
| Interest charges | (213) | | | (74) | | | (44) | | | (84) | | | (71) | | | (486) | |
| Income (taxes) benefit | 10 | | | (68) | | | (46) | | | (92) | | | 20 | | | (176) | |
| Net income (loss) | 565 | | | 203 | | | 123 | | | 264 | | | (76) | | | 1,079 | |
| Noncontrolling interests – preferred stock dividends | (3) | | | (1) | | | — | | | (1) | | | — | | | (5) | |
| Net income (loss) attributable to Ameren common shareholders | $ | 562 | | | $ | 202 | | | $ | 123 | | | $ | 263 | | | $ | (76) | | | $ | 1,074 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other / Intersegment Eliminations | | Total |
| Electric margins | $ | 2,431 |
| | $ | 1,109 |
| | $ | — |
| | $ | 426 |
| | $ | (31 | ) | | $ | 3,935 |
|
| Natural gas margins | 79 |
| | — |
| | 479 |
| | — |
| | (2 | ) | | 556 |
|
| Other revenues | — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | — |
|
| Other operations and maintenance | (902 | ) | | (512 | ) | | (224 | ) | | (63 | ) | | 41 |
| | (1,660 | ) |
| Depreciation and amortization | (533 | ) | | (239 | ) | | (59 | ) | | (60 | ) | | (5 | ) | | (896 | ) |
| Taxes other than income taxes | (328 | ) | | (74 | ) | | (60 | ) | | (6 | ) | | (9 | ) | | (477 | ) |
| Other income and (expenses) | 40 |
| | 3 |
| | (3 | ) | | 1 |
| | (3 | ) | | 38 |
|
| 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 |
| | $ | 1,105 |
| | $ | — |
| | $ | 355 |
| | $ | (27 | ) | | $ | 3,830 |
|
| Natural gas margins | 79 |
| | — |
| | 462 |
| | — |
| | (2 | ) | | 539 |
|
| Other revenues | 1 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
|
| Other operations and maintenance | (893 | ) | | (538 | ) | | (215 | ) | | (60 | ) | | 30 |
| | (1,676 | ) |
| Depreciation and amortization | (514 | ) | | (226 | ) | | (55 | ) | | (43 | ) | | (7 | ) | | (845 | ) |
| Taxes other than income taxes | (325 | ) | | (72 | ) | | (58 | ) | | (4 | ) | | (8 | ) | | (467 | ) |
| Other income and (expenses) | 42 |
| | 8 |
| | (1 | ) | | 2 |
| | (9 | ) | | 42 |
|
| 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 |
|
| 2015 | | | | | | | | | | | |
| Electric margins | $ | 2,481 |
| | $ | 1,074 |
| | $ | — |
| | $ | 259 |
| | $ | (26 | ) | | $ | 3,788 |
|
| Natural gas margins | 80 |
| | — |
| | 425 |
| | — |
| | (2 | ) | | 503 |
|
| Other revenues | 2 |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
|
| Other operations and maintenance | (925 | ) | | (532 | ) | | (219 | ) | | (56 | ) | | 38 |
| | (1,694 | ) |
| Provision for Callaway construction and operating license | (69 | ) | | — |
| | — |
| | — |
| | — |
| | (69 | ) |
| Depreciation and amortization | (492 | ) | | (212 | ) | | (52 | ) | | (33 | ) | | (7 | ) | | (796 | ) |
| Taxes other than income taxes | (335 | ) | | (72 | ) | | (56 | ) | | (2 | ) | | (8 | ) | | (473 | ) |
| Other income and (expenses) | 41 |
| | 8 |
| | (1 | ) | | 2 |
| | (6 | ) | | 44 |
|
| Interest charges | (219 | ) | | (71 | ) | | (35 | ) | | (35 | ) | | 5 |
| | (355 | ) |
| Income taxes | (209 | ) | | (71 | ) | | (24 | ) | | (51 | ) | | (8 | ) | | (363 | ) |
| Income (loss) from continuing operations | 355 |
| | 124 |
| | 38 |
| | 84 |
| | (16 | ) |
| 585 |
|
| Income from discontinued operations, net of taxes | — |
| | — |
| | — |
| | — |
| | 51 |
| | 51 |
|
| Net income | 355 |
| | 124 |
| | 38 |
| | 84 |
| | 35 |
| | 636 |
|
| Noncontrolling interests – preferred stock dividends | (3 | ) | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net income attributable to Ameren common shareholders | $ | 352 |
| | $ | 123 |
| | $ | 37 |
| | $ | 83 |
| | $ | 35 |
|
| $ | 630 |
|
Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2017, 2016,2023 and 2015:2022: | | | 2017 | Electric Distribution | | Natural Gas | | Transmission | | Total |
| 2023 | | 2023 | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren
Illinois
Transmission | | Other /
Intersegment
Eliminations | | Ameren Illinois |
| Electric revenues | |
| Purchased power | |
| Electric margins | $ | 1,109 |
| | $ | — |
| | $ | 258 |
| | $ | 1,367 |
|
| Natural gas revenues | |
| Natural gas purchased for resale | |
| Natural gas margins | — |
| | 479 |
| | — | | 479 |
|
| Other revenues | 1 |
| | — |
| | — | | 1 |
|
| Other operations and maintenance | (512 | ) | | (224 | ) | | (53 | ) | | (789 | ) |
| Other operations and maintenance expenses | |
| Depreciation and amortization | (239 | ) | | (59 | ) | | (43 | ) | | (341 | ) |
| Taxes other than income taxes | (74 | ) | | (60 | ) | | (3 | ) | | (137 | ) |
| Other income and (expenses) | 3 |
| | (3 | ) | | 1 |
| | 1 |
|
| Operating income | |
| Other income, net | |
| Interest charges | (73 | ) | | (36 | ) | | (35 | ) | | (144 | ) |
| Income taxes | (83 | ) | | (36 | ) | | (47 | ) | | (166 | ) |
| Net income | 132 |
| | 61 |
| | 78 |
| | 271 |
|
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | $ | 131 |
| | $ | 60 |
| | $ | 77 |
| | $ | 268 |
|
| 2016 | | | | | | | |
| 2022 | |
| Electric revenues | |
| Electric revenues | |
| Electric revenues | |
| Purchased power | |
| Electric margins | $ | 1,105 |
| | $ | — |
| | $ | 232 |
| | $ | 1,337 |
|
| Natural gas revenues | |
| Natural gas purchased for resale | |
| Natural gas margins | — | | 462 |
| | — | | 462 |
|
| Other operations and maintenance | (538 | ) | | (215 | ) | | (51 | ) | | (804 | ) |
| Other operations and maintenance expenses | |
| Depreciation and amortization | (226 | ) | | (55 | ) | | (38 | ) | | (319 | ) |
| Taxes other than income taxes | (72 | ) | | (58 | ) | | (2 | ) | | (132 | ) |
| Other income and (expenses) | 8 |
| | (1 | ) | | 2 |
| | 9 |
|
| Operating income | |
| Other income, net | |
| 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 |
|
| 2015 | | | | | | | |
| Electric margins | $ | 1,074 |
| | $ | — |
| | $ | 189 |
| | $ | 1,263 |
|
| Natural gas margins | — |
| | 425 |
| | — |
| | 425 |
|
| Other operations and maintenance | (532 | ) | | (219 | ) | | (46 | ) | | (797 | ) |
| Depreciation and amortization | (212 | ) | | (52 | ) | | (31 | ) | | (295 | ) |
| Taxes other than income taxes | (72 | ) | | (56 | ) | | (2 | ) | | (130 | ) |
| Other income and (expenses) | 8 |
| | (1 | ) | | 2 |
| | 9 |
|
| Interest charges | (71 | ) | | (35 | ) | | (25 | ) | | (131 | ) |
| Income taxes | (71 | ) | | (24 | ) | | (32 | ) | | (127 | ) |
| Net income | 124 |
| | 38 |
| | 55 |
| | 217 |
|
| Preferred stock dividends | (1 | ) | | (1 | ) | | (1 | ) | | (3 | ) |
| Net income attributable to common shareholder | $ | 123 |
| | $ | 37 |
| | $ | 54 |
| | $ | 214 |
|
|
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 2017 compared with 2016, as well as 2016 compared with 2015.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 |
| 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) | 61 |
| | 42 |
| | — |
| | 71 |
| | — |
| | 174 |
|
| Recovery of power restoration efforts provided to other utilities | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | 8 |
|
| Sales volume (excluding the New Madrid Smelter and estimated effect of weather) | (6 | ) | | — |
| | — |
| | — |
| | — |
| | (6 | ) |
| Off-system sales and capacity revenues | 22 |
| | — |
| | — |
| | — |
| | — |
| | 22 |
|
| MEEIA 2013 performance incentive | (28 | ) | | — |
| | — |
| | — |
| | — |
| | (28 | ) |
| Transmission services revenues | 11 |
| | — |
| | — |
| | — |
| | — |
| | 11 |
|
| Other | 4 |
| | (1 | ) | | — |
| | — |
| | 5 |
| | 8 |
|
Cost recovery mechanisms – offset in fuel and purchased power(c) | (11 | ) | | 18 |
| | — |
| | — |
| | — |
| | 7 |
|
Other cost recovery mechanisms(d) | 24 |
| | (36 | ) | | — |
| | — |
| | — |
| | (12 | ) |
| Total electric revenue change | $ | 19 |
| | $ | 19 |
| | $ | — |
| | $ | 71 |
| | $ | 5 |
| | $ | 114 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the New Madrid Smelter and 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 | (10 | ) | | 4 |
| | — |
| | — |
| | (9 | ) | | (15 | ) |
Cost recovery mechanisms – offset in electric revenue(c) | 11 |
| | (18 | ) | | — |
| | — |
| | — |
| | (7 | ) |
| Total fuel and purchased power change | $ | 15 |
| | $ | (15 | ) | | $ | — |
| | $ | — |
| | $ | (9 | ) | | $ | (9 | ) |
| Net change in electric margins | $ | 34 |
| | $ | 4 |
| | $ | — |
| | $ | 71 |
| | $ | (4 | ) | | $ | 105 |
|
| 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(c) | 2 |
| | — |
| | (28 | ) | | — |
| | — |
| | (26 | ) |
Other cost recovery mechanisms(d) | — |
| | — |
| | 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(c) | (2 | ) | | — |
| | 28 |
| | — |
| | — |
| | 26 |
|
| Total natural gas purchased for resale change | $ | 2 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 30 |
|
| Net change in natural gas margins | $ | — |
| | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2016 versus 2015 | 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) | $ | 57 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 72 |
|
| Base rates (estimate) | 48 |
| | 38 |
| | — |
| | 102 |
| | — |
| | 188 |
|
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)
| 7 |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
| New Madrid Smelter revenues | (129 | ) | | — |
| | — |
| | — |
| | — |
| | (129 | ) |
| Off-system sales and capacity revenues | 153 |
| | — |
| | — |
| | — |
| | — |
| | 153 |
|
| MEEIA 2013 net shared benefits | (85 | ) | | — |
| | — |
| | — |
| | — |
| | (85 | ) |
| MEEIA 2013 performance incentive | 28 |
| | — |
| | — |
| | — |
| | — |
| | 28 |
|
| Transmission services revenues | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Purchased power rider order in 2015 | — |
| | (15 | ) | | — |
| | — |
| | — |
| | (15 | ) |
| Other | (1 | ) | | (1 | ) | | — |
| | (6 | ) | | (21 | ) | | (29 | ) |
Cost recovery mechanisms – offset in fuel and purchased power(c) | (118 | ) | | (22 | ) | | — |
| | — |
| | — |
| | (140 | ) |
Other cost recovery mechanisms(d) | (39 | ) | | 2 |
| | — |
| | — |
| | — |
| | (37 | ) |
| Total electric revenue change | $ | (76 | ) | | $ | 17 |
| | $ | — |
| | $ | 96 |
| | $ | (21 | ) | | $ | 16 |
|
| Fuel and purchased power change: | | | | | | | | | | | |
| Energy costs (excluding the New Madrid Smelter and estimated effect of weather) | $ | (145 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (145 | ) |
| New Madrid Smelter energy costs | 72 |
| | — |
| | — |
| | — |
| | — |
| | 72 |
|
Effect of weather (estimate)(b) | (9 | ) | | (8 | ) | | — |
| | — |
| | — |
| | (17 | ) |
| Effect of higher net energy costs included in base rates | (34 | ) | | — |
| | — |
| | — |
| | — |
| | (34 | ) |
| Transmission services charges | (16 | ) | | — |
| | — |
| | — |
| | — |
| | (16 | ) |
| Other | 6 |
| | — |
| | — |
| | — |
| | 20 |
| | 26 |
|
Cost recovery mechanisms – offset in electric revenue(c) | 118 |
| | 22 |
| | — |
| | — |
| | — |
| | 140 |
|
| Total fuel and purchased power change | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | 26 |
|
| Net change in electric margins | $ | (84 | ) | | $ | 31 |
| | $ | — |
| | $ | 96 |
| | $ | (1 | ) | | $ | 42 |
|
| Natural gas revenue change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (7 | ) | | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
| Base rates (estimate) | — |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
|
| Other | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Cost recovery mechanisms – offset in natural gas purchased for resale(c) | (2 | ) | | — |
| | (76 | ) | | — |
| | — |
| | (78 | ) |
Other cost recovery mechanisms(d) | — |
| | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Total natural gas revenue change | $ | (9 | ) | | $ | — |
| | $ | (29 | ) | | $ | — |
| | $ | — |
| | $ | (38 | ) |
| Natural gas purchased for resale change: | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 6 |
| | $ | — |
| | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | (4 | ) |
Cost recovery mechanisms – offset in natural gas revenue(c) | 2 |
| | — |
| | 76 |
| | — |
| | — |
| | 78 |
|
| Total natural gas purchased for resale change | $ | 8 |
| | $ | — |
| | $ | 66 |
| | $ | — |
| | $ | — |
| | $ | 74 |
|
| Net change in natural gas margins | $ | (1 | ) | | $ | — |
| | $ | 37 |
| | $ | — |
| | $ | — |
| | $ | 36 |
|
| | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | Overall Ameren Increase of $66 Million | |
(a)Includes other/intersegment eliminations of $(32) million and $(25) million in 2023and 2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Electric Distribution | | Ameren Transmission | | | Other/Intersegment Eliminations | |
Natural Gas Margins
| | | | | | | | | | | | | | |
| Total by Segment(a) | | Decrease by Segment | |
| | Overall Ameren Decrease of $13 Million | |
(a)Includes other/intersegment eliminations of $(1) million and $(1) million in 2023and 2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| (a) | Includes an increase in transmission margins of $26 million and $43 million in 2017 and 2016, respectively, at Ameren Illinois. The 2017 increase in transmission margins at Ameren Illinois is the change in base rates (estimate) of $26 million. The 2016 increase in transmission margins at Ameren Illinois is the sum of the change in base rates (estimate) of $49 million and the change in Other of -$6 million. | | | | | | | |
| |
(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) | Includes amounts for power supply, renewable energy adjustment, zero-emission credits, transmission services, and purchased natural gas cost recovery mechanisms, as well as FAC recoveries. Electric and natural gas revenue changes are offset by corresponding changes in fuel, purchased power, and natural gas purchased for resale, resulting in no change to electric and natural gas margins. |
| |
(d) | Includes amounts for bad debt, energy-efficiency programs, and environmental remediation cost recovery mechanisms, as well as gross receipts tax revenues. See Other Operations and Maintenance Expenses or Taxes Other Than Income Taxes in this section for the related offsetting increase or decrease to expense. 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 2023, compared with 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins | | | | | |
| 2023 versus 2022 | Ameren
Missouri | | Ameren Illinois
Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /
Intersegment
Eliminations | | Ameren | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | |
Base rates (estimate)(b) | $ | 115 | | | $ | 30 | | | $ | — | | | $ | 62 | | | $ | — | | | $ | 207 | | | | | | |
Effect of weather (estimate)(c) | (71) | | | — | | | — | | | — | | | — | | | (71) | | | | | | |
| Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | (27) | | | — | | | — | | | — | | | — | | | (27) | | | | | | |
| MEEIA 2019 performance incentives | (10) | | | — | | | — | | | — | | | — | | | (10) | | | | | | |
| Off-system sales, capacity, and FAC revenues, net | (226) | | | — | | | — | | | — | | | — | | | (226) | | | | | | |
| Transmission service charges | (9) | | | — | | | — | | | — | | | — | | | (9) | | | | | | |
| Ameren Illinois customer energy-efficiency program investment revenues | — | | | 18 | | | — | | | — | | | — | | | 18 | | | | | | |
| Other | 1 | | | (2) | | | — | | | — | | | (7) | | | (8) | | | | | | |
Cost recovery mechanisms – offset in fuel and purchased power(d) | 82 | | | (51) | | | — | | | — | | | (4) | | | 27 | | | | | | |
Other cost recovery mechanisms(e) | (10) | | | (33) | | | — | | | — | | | — | | | (43) | | | | | | |
| Total electric revenue change | $ | (155) | | | $ | (38) | | | $ | — | | | $ | 62 | | | $ | (11) | | | $ | (142) | | | | | | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | 238 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 238 | | | | | | |
| | | | | | | | | | | | | | | | |
Effect of weather (estimate)(c) | 14 | | | — | | | — | | | — | | | — | | | 14 | | | | | | |
| Effect of higher net energy costs included in base rates | (21) | | | — | | | — | | | — | | | — | | | (21) | | | | | | |
| Transmission service charges | 4 | | | — | | | — | | | — | | | — | | | 4 | | | | | | |
| | | | | | | | | | | | | | | | |
Cost recovery mechanisms – offset in electric revenue(d) | (82) | | | 51 | | | — | | | — | | | 4 | | | (27) | | | | | | |
| Total fuel and purchased power change | $ | 153 | | | $ | 51 | | | $ | — | | | $ | — | | | $ | 4 | | | $ | 208 | | | | | | |
| Net change in electric margins | $ | (2) | | | $ | 13 | | | $ | — | | | $ | 62 | | | $ | (7) | | | $ | 66 | | | | | | |
| Natural gas revenue change: | | | | | | | | | | | | | | | | |
| Base rates (estimate) | $ | — | | | $ | — | | | $ | 6 | | | $ | — | | | $ | — | | | $ | 6 | | | | | | |
Effect of weather (estimate)(c) | (17) | | | — | | | — | | | — | | | — | | | (17) | | | | | | |
| Sales volume (excluding the estimated effect of weather) | — | | | — | | | (4) | | | — | | | — | | | (4) | | | | | | |
| | | | | | | | | | | | | | | | |
| QIP rider | — | | | — | | | 14 | | | — | | | — | | | 14 | | | | | | |
| Other | (2) | | | — | | | (4) | | | — | | | — | | | (6) | | | | | | |
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | (12) | | | — | | | (277) | | | — | | | — | | | (289) | | | | | | |
Other cost recovery mechanisms(e) | (1) | | | — | | | (18) | | | — | | | — | | | (19) | | | | | | |
| Total natural gas revenue change | $ | (32) | | | $ | — | | | $ | (283) | | | $ | — | | | $ | — | | | $ | (315) | | | | | | |
| Natural gas purchased for resale change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(c) | $ | 13 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 13 | | | | | | |
Cost recovery mechanisms – offset in natural gas revenue(d) | 12 | | | — | | | 277 | | | — | | | — | | | 289 | | | | | | |
| Total natural gas purchased for resale change | $ | 25 | | | $ | — | | | $ | 277 | | | $ | — | | | $ | — | | | $ | 302 | | | | | | |
| Net change in natural gas margins | $ | (7) | | | $ | — | | | $ | (6) | | | $ | — | | | $ | — | | | $ | (13) | | | | | | |
(a)Includes an increase in transmission electric margins of $56 million in 2023, compared with 2022, at Ameren Illinois.
(b)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates. For Ameren Missouri, base rates exclude an increase for the recovery of lost electric margins resulting from the MEEIA customer energy-efficiency programs and a decrease in base rates for RESRAM. These changes in Ameren Missouri base rates are included in the “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” and “Cost recovery mechanisms - offset in fuel and purchased power” line items, respectively.
(c)Represents the estimated variation resulting primarily from changes in cooling and heating degree days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.
(d)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of income, resulting in no change to electric and natural gas margins. Activity in Other/Intersegment Eliminations represents the elimination of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI, as well as Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution. See Note 13 – Related-party Transactions and Note 16 – Segment Information under Part II, Item 8, of this report for additional information on intersegment eliminations.
(e)Offsetting expense increases or decreases are reflected in “Other operations and maintenance,” “Depreciation and amortization,” or in “Taxes other than income taxes” within the “Operating Expenses” section of the statement of income. These items have no overall impact on earnings.
Ameren
Ameren’s electric margins increased $105$66 million, or 3%1%, in 20172023, compared with 2016, primarily2022, because of increased margins at Ameren Transmission and Ameren Missouri.Illinois Electric Distribution, as discussed below. Ameren’s natural gas margins increased $17decreased $13 million, or 3%2%, between years because of decreased margins at Ameren Missouri and Ameren Illinois Natural Gas, as discussed below.
Ameren Transmission
Ameren Transmission’s margins increased $62 million, or 10%, in 20172023, compared with 2016, because2022. Base rate revenues were favorably affected by higher recoverable expenses (+$38 million) and increased capital investment (+$24 million), as evidenced by a 10% increase in rate base used to calculate the revenue requirement.
Ameren Missouri
Ameren Missouri’s electric margins were comparable between years. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $82 million in 2023, compared with 2022, due to increased revenue related to the amortization of costs previously deferred under the FAC that were reflected in customer rates. The changes to “Cost recovery mechanisms - offset in fuel and purchased power” are fully offset by “Cost recovery mechanisms - offset in electric revenue,” in the table above, and result in no impact to margins. Ameren Missouri’s 5% exposure to net energy cost variances under the FAC is reflected within “Off-system sales, capacity, and FAC revenues, net” and “Energy costs (excluding the estimated effect of weather)”.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2023, compared with 2022:
•Winter temperatures were warmer as heating degree days decreased 22% while spring and summer temperatures were milder as cooling degree days decreased 3%. The aggregate effect of weather decreased margins by an estimated $57 million. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (-$71 million) and the “Effect of weather (estimate)” on fuel and purchased power (+$14 million) in the table above.
•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues decreased an estimated $27 million resulting from a decrease in retail sales volumes, due, in part, to customer outages resulting from major storms experienced throughout the service territory in July and August 2023, partially offset by an increase in customer demand charge revenues and an increase in the average retail price per kilowatthour related to changes in customer usage patterns.
•MEEIA 2019 performance incentives decreased revenues $10 million as performance incentives for program years 2021 and 2022 were recognized in 2022, whereas the performance incentive for program year 2023 was recognized in 2023.
•Revenues associated with other cost recovery mechanisms decreased $10 million, primarily due to a decrease in RESRAM revenues, partially offset by an increase in excise taxes and recoverable MEEIA program costs.
•Transmission service charge revenues decreased $9 million, primarily due to lower revenues related to reactive power.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2023, compared with 2022:
•Higher electric base rates, excluding the change in base rates for the MEEIA customer energy-efficiency programs and the RESRAM, resulting from the June 2023 MoPSC electric rate order effective July 9, 2023, partially offset by higher net energy costs included in base rates, increased margins an estimated $57 million. A similar effect resulting from the December 2021 MoPSC electric rate order effective February 28, 2022, increased margins an estimated $37 million. The change in electric base rates is the sum of the change in “Base rates (estimate)” (+$115 million) and the “Effect of higher net energy costs included in base rates” (-$21 million) in the table above.
•Ameren Missouri’s electric margins increased $12 million due to its 5% exposure to net energy cost variances under the FAC. The change in net energy costs is the sum of “Off-system sales, capacity and FAC revenues, net” (-$226 million) and “Energy costs (excluding the estimated effect of weather)” (+$238 million) in the table above. Revenues decreased primarily due to lower off-system sales volumes (-$108 million) related to reduced generation at the Rush Island Energy Center, lower capacity prices (-$101 million) set by the annual MISO auction in April 2023, and lower market prices for energy (-$11 million). Energy costs decreased primarily due to lower fuel costs (+$130 million), lower purchased power costs (+$98 million), and lower capacity costs (+$95 million), partially offset by decreased deferral of expenses under the FAC (-$90 million).
•Transmission service charge expenses decreased $4 million, primarily due to a decrease in charges related to transmission network upgrades.
Ameren Missouri’s natural gas margins decreased $7 million, or 8%, in 2023, compared with 2022.Purchased gas costs decreased $12 million in 2023, compared with 2022, due to lower commodity prices and decreased amortization of deferred natural gas costs related to the extremely cold weather in mid-February 2021.The decreased purchased gas costs are fully offset by a decrease in natural gas revenues under the PGA, resulting in no impact to margin. The decrease in purchased gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above. Margins decreased $4 million due to warmer winter temperatures as heating degree days decreased 22%. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on natural gas revenues (-$17 million) and the “Effect of weather (estimate)” on natural gas purchased for resale (+$13 million) in the table above.
Ameren Illinois
Ameren Illinois’ electric margins increased $69 million, or 4%, in 2023, compared with 2022, driven by increased margins at Ameren Illinois Transmission and Ameren Illinois Electric Distribution. Ameren Illinois Natural Gas.
Gas’ margins decreased $6 million, or 1%, between years.
Ameren TransmissionIllinois Electric Distribution
Ameren Transmission’sIllinois Electric Distribution’s margins increased $71$13 million, or 20%1%, in 20172023, compared with 2016. Margins were favorably affected2022. Purchased power costs decreased $51 million in 2023, compared with 2022, primarily due to decreased energy prices (-$54 million), which largely reflect the results of IPA procurement events, and lower volumes due to decreased sales (-$39 million), partially offset by increased capital investment,revenues related to the amortization of costs previously deferred under riders (+$28 million) and higher costs due to higher capacity prices (+$9 million). The decreased purchased power costs are fully offset by a decrease in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin. The decrease in purchased power cost is reflected in “Cost recovery mechanisms – offset in electric revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in fuel and purchased power” in the table above.
The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in 2023, compared with 2022:
•The impact from base rates (+$30 million) increased due to a higher recognized ROE (+$21 million), as evidenced by an increase of 98 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, and increased capital investment (+$15 million), as evidenced by a 9% increase in year-end rate base, partially offset by lower recoverable non-purchased power expenses (-$4 million), and the results from 2021 and 2022 revenue requirement reconciliation adjustment true-ups recognized in the subsequent year (-$2 million).
•Revenues associated with customer energy-efficiency program investments increased $18 million due to the recovery of 23%program expenses (+$12 million), increased investment (+$2 million), higher recognized ROE under formula ratemaking (+$2 million), and the results from the 2022 revenue requirement reconciliation adjustment true-up recognized in 20172023 (+$2 million).
Revenues associated with other cost recovery mechanisms decreased $33 million in 2023, compared with 2016, as well as higher recoverable2022, primarily due to a lower amount of bad debt costs included in 2017customer rates pursuant to the associated rider.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins decreased $6 million, or 1%, in 2023, compared with 20162022. Purchased gas costs decreased $277 million in 2023, compared with 2022, primarily due to lower amortization of natural gas costs that were previously deferred under forward-looking formula ratemaking. Marginsthe PGA and lower natural gas prices in 2023. Deferred natural gas costs related to the extremely cold weather in mid-February 2021 were unfavorably affectedfully recovered from customers by the absenceend of 2022. The decreased purchased natural gas costs are fully offset by a decrease in 2017natural gas revenues under the PGA, resulting in no impact to margin. The decrease in purchased gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above.
The following items had an unfavorable effect on Ameren Illinois Natural Gas’ margins in 2023, compared with 2022:
•Revenues associated with other cost recovery mechanisms decreased $18 million, primarily due to decreased revenues for excise taxes.
•Revenues decreased $4 million primarily due to lower sales volumes related to large commercial, industrial, and transportation customers, and lower capacity revenues. Revenues from sales to large commercial, industrial, and transportation customers are excluded from the VBA. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the VBA.
•Other miscellaneous revenues decreased $4 million primarily related to the refund of over-recovered costs associated with the COVID-19 pandemic, beginning in April 2023.
The following items had a temporarilyfavorable effect on Ameren Illinois Natural Gas’ margins in 2023, compared with 2022:
•Revenues increased $14 million due to additional investment in natural gas infrastructure under the QIP.
•Revenues increased $6 million due to higher allowed return on common equity of 12.38% for nearly four months in 2016natural gas base rates as a result of the expiration of the refund period in the February 2015 FERC complaint case. natural gas rate order effective November 28, 2023.
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the allowed return on common equity for FERC-regulated transmission rate base.
Ameren Missouri
Ameren Missouri’s electric margins increased $34 million, or 1%, in 2017 compared with 2016. 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)QIP and the effect of lower net energy costs included in base rates (+$39 million) in the Electric and2023 Natural Gas Margins table above. Higher electric base rates incorporated the effect of the suspension of operations at the New Madrid Smelter.
Increased transmission services revenues due to additional rate base investment, which increased margins by $11 million.
The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts primarily caused by hurricane damage, which increased revenues by $7 million.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2017 compared with 2016:
Summer temperatures were milder in 2017 compared with 2016, as cooling degree-days decreased 10%. The effect of weather decreased margins by an estimated $52 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$65 million) and the effect of weather (estimate) on fuel and purchased power (+$13 million) in the Electric and Natural Gas Margins table above.
The absence of the MEEIA 2013 performance incentive, which decreased margins by $28 million. See Note 2 –Delivery Service Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 performance incentive.
Increased transmission services charges resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, which decreased margins by $16 million.
Excluding the effect of reduced sales to the New Madrid Smelter, the estimated effect of weather, and the estimated effects of MEEIA 2016 customer energy-efficiency programs, total retail sales volumes decreased by less than 1%, which decreased revenues by $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 throughput disincentive recovery ensured that electric margins were not affected.
Ameren Illinois
Ameren Illinois’ electric margins increased $30 million, or 2%, in 2017 compared with 2016, driven by increases in Ameren Illinois Electric Distribution ($4 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 by $12 million.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $4 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 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 by $42 million. Ameren Illinois Electric Distribution’s margins were unfavorably affected by the absence of the impact of warmer-than-normal summer temperatures experienced in 2016, which decreased margins by an estimated $6 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 of weather (estimate) on electric revenues (-$5 million) and the effect of weather (estimate) on fuel and purchased power (-$1 million) in the Electric and Natural Gas Margins table above.Order.
Ameren Illinois Transmission
Ameren Illinois Transmission’s electric margins increased $26$56 million, or 11%13%, in 20172023, compared with 2016. Margins2022. Base rate revenues were favorably affected by increased capital investment as evidenced by an increase in rate base of 16% 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.
2016 versus 2015
Ameren
Ameren’s electric margins increased $42 million, or 1%(+$25 million), in 2016 compared with 2015, primarily because of increased margins at Ameren Transmission and Ameren Illinois Electric Distribution, partially offset by decreased margins at Ameren Missouri. Ameren’s natural gas margins increased $36 million, or 7%, in 2016 compared with 2015, primarily because of increased margins at Ameren Illinois Natural Gas.
Ameren Transmission
Ameren Transmission’s margins increased $96 million, or 37%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a 42%15% increase in rate base used to calculate the revenue requirement, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from 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.
Ameren Missouri
Ameren Missouri’s electric margins decreased $84 million, or 3%, in 2016 compared with 2015. Ameren Missouri’s natural gas margins were comparable between years.
The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2016 compared with 2015:
The suspension of the New Madrid Smelter operations in the first quarter of 2016, which decreased margins by $57 million. The change in margins due to lower sales to the New Madrid Smelter is the sum of New Madrid Smelter revenues (-$129 million) and New Madrid Smelter energy costs (+$72 million) in the Electric and Natural Gas Margins table above. New Madrid Smelter energy costs included the impact of a provision in the FAC tariff that, under certain circumstances, allowed Ameren Missouri to retain a portion of the revenues from any off-system sales it made as a result of reduced sales to the New Madrid Smelter.
The expiration of MEEIA 2013, which decreased margins by $57 million. The change in margins due to the expiration of MEEIA 2013 is the sum of MEEIA 2013 net shared benefits (-$85 million) and MEEIA 2013 performance incentive (+$28 million) in the Electric and Natural Gas Marginstable above. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency-related volume reductions in current and future periods. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 performance incentive.
Increased transmission services charges resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, which decreased margins by $16 million.
The following items had a favorable effect on Ameren Missouri’s electric margins in 2016 compared with 2015:
Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 16%, while heating degree-days decreased 6%. The net effect of weather increased margins by an estimated $48 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$57 million) and the effect of weather (estimate) on fuel and purchased power (-$9 million) in the Electric and Natural Gas Margins table above.
Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $14 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$48 million) and the change in effect of higher net energy costs included in base rates (-$34 million) in the Electric and Natural Gas Margins table above.
Lower net energy costs as a result of the 5% of changes retained by Ameren Missouri through the FAC, primarily due to higher MISO capacity revenues, which increased margins by $8 million. The change in net energy costs is the sum of the change in off-system sales and capacity revenues (+$153 million) and the change in energy costs (excluding the New Madrid Smelter and estimated effect of weather) (-$145 million) in the Electric and Natural Gas Margins table above.
Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effect of weather, total retail sales volumes increased by less than 1%, which increased revenues by $7 million, due to an additional day as a result of the leap year and growth, partially offset by the carryover effect of MEEIA 2013 on sales volumes and the effect of MEEIA 2016 customer energy-efficiency programs. MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes but the throughput disincentive recovery ensured that electric margins were not affected.
Ameren Illinois
Ameren Illinois’ electric margins increased $74 million, or 6%, in 2016 compared with 2015, driven by increases in Ameren Illinois Electric Distribution ($31 million) and Ameren Illinois Transmission ($43 million) margins. Ameren Illinois Natural Gas’ margins increased $37 million, or 9%, in 2016 compared with 2015.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $31 million, or 3%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Electric Distribution’s electric margins:
Revenues increased by $38 million, primarily because of an increase in rate base of 8% and higher recoverable costs in 2016 compared with 2015, under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity due to a reduction in 30-year United States Treasury bond yields, which decreased 24 basis points in 2016 compared with 2015.expenses (+$31 million).
Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 13%, while heating degree-days decreased 5%. The net effect of weather increased margins by an estimated $7 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$15 million) and the effect of weather (estimate) on fuel and purchased power (-$8 million) in the Electric and Natural Gas Margins table above.
Ameren Illinois Electric Distribution’s margins were unfavorably affected by the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism, which increased margins by $15 million in 2015.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $37 million, or 9%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins:
Higher natural gas base rates in 2016, which increased margins by an estimated $42 million.
The absence of warmer-than-normal 2015 winter temperatures and the application of the VBA in 2016, which increased margins by $3 million. The VBA, which was approved by the ICC in December 2015, eliminated the impact of weather on natural gas margins for residential and small nonresidential customers in 2016. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (+$13 million) and the effect of weather (estimate) on natural gas purchased for resale (-$10 million) in the Electric and Natural Gas Margins table above.
Ameren Illinois Transmission
Ameren Illinois Transmission’s margins increased $43 million, or 23%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a 27% increase in rate base used to calculate the revenue requirement, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from 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.
Other Operations and Maintenance Expenses
2017 versus 2016 | | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | Overall Ameren Decrease of $71 Million | |
(a)Includes $60 million and $60 million at Ameren Transmission in 2023 and 2022, respectively, and other/intersegment eliminations of $34 million and $16 million in 2023and 2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Ameren
Other operations and maintenance expenses at Ameren decreased $16$71 million in 20172023, compared with 2016, because of items2022. In addition to changes by segment as discussed below, and an increase in intersegment eliminations of $14 million.
Ameren Transmission
Otherother operations and maintenance expenses increased $3$18 million in 2017 compared with 2016,2023 for activity not reported as part of a
segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of an increase in labor costs duethe elimination of the non-service cost component of net periodic benefit income at Ameren Services. The non-service cost component of net periodic benefit cost or income at Ameren Services is allocated to increased wagesthe segments and staffing additions.
Ameren Missouri
primarily included in the segments’ other operations and maintenance expenses. Other operations and maintenance expenses were comparable at Ameren Transmission between periods.
Ameren Missouri
The $25 million decrease in Ameren Missouri’s other operations and maintenance expenses in 2023, compared with 2022, was primarily due to the following items:
•The cash surrender value of COLI increased $21 million. The effect of changes in the cash surrender value of COLI resulted in gains of $7 million in 2023, compared with losses of $14 million in 2022.
•The recognition of regulatory assets for previously expensed costs approved for recovery pursuant to the June 2023 MoPSC rate order decreased other operations and maintenance expenses $14 million.
•Renewable development costs decreased $9 million, higheras the MoPSC order approving CCNs for the Boomtown and Huck Finn solar projects in 2017 compared with 2016. the first half of 2023 led to increased capitalization of renewable development costs pursuant to anticipated recovery from customers.
•Energy center operating and maintenance costs decreased $3 million, primarily because of the retirement of the Meramec Energy Center in December 2022, partially offset by increased costs related to maintenance outages at other energy centers.
The following items increasedpartially offset the above decreases in other operations and maintenance expenses between years:
•Transmission and distribution storm-related costs increased $7 million because of the major storms experienced throughout the service territory in July and August 2023.
•Transmission and distribution expenditures, excluding storm costs, increased $7 million, primarily because of increased inspection and vegetation management expenditures.
•MEEIA customer energy-efficiency program costsspend increased by $22 million.
Labor and benefit costs increased by $11 million due to increased wages, as well as assistance provided to other utilities to aid in storm recovery efforts, primarily caused by hurricane damage.
Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, increased by $3 million, primarily due to higher coal handling charges.
The following items decreased other operations and maintenance expenses between years:
Employee benefit costs decreasedas approved by $21 million, primarily due to a reduction in the base level of pension and postretirement expenses allowed in rates as a result of the March 2017 MoPSC electric rate order, as well as changes in the market value of company-owned life insurance.
Solar rebate costs decreased by $8 million, primarily as a result of the March 2017 MoPSC electric rate order.MoPSC.
Ameren Illinois
Other operations and maintenance expenses decreased $15$64 million at Ameren Illinois in 20172023, compared with 2016,2022, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission in 2017 compared with 2016.between 2023 and 2022.
Ameren Illinois Electric Distribution
OtherThe $48 million decrease in Ameren Illinois Electric Distribution’s other operations and maintenance expenses were $26 million lower in 20172023, compared with 2016,2022, was primarily due to the following items:
•Bad debt costs decreased $43 million primarily because of a $47lower amount of costs recovered from customers pursuant to the associated rider.
•The cash surrender value of COLI increased $10 million decrease in 2023, primarily because of favorable market returns, compared with unfavorable market returns in 2022.
•Pension and benefit costs decreased $8 million, primarily related to decreased pension service costs due to changes in actuarial assumptions.
The following items partially offset the above decreases in other operations and maintenance expenses between years:
•Amortization of regulatory assets associated with customer energy-efficiency costs, which was partially offset by an $11 million increase in environmental remediationinvestments under formula ratemaking increased $9 million.
•Amortization of previously deferred storm-related costs and a $3 million increasecosts related to major storm activity in labor costs resulting from2023, increased wages.$6 million.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $9costs decreased $16 million higher in 20172023, compared with 2016, primarily2022, in part, because of increased bad debt, customer energy-efficiency, and environmental remediation costs.
2016 versus 2015
Ameren
a $5 million increase in the cash surrender value of COLI. In 2023, the effect of changes in the cash surrender value of COLI resulted in a gain of $2 million, compared with a loss of $3 million in 2022. Other operations and maintenance expenses also decreased $18$5 million in 2016 compared with 2015, as discussed below.
Ameren Transmission
Other operations and maintenance expenses increased $4 million in 2016 compared with 2015, primarily2023 because of an increasea decline in system operations and labor costs.
Ameren Missouri
Other operations and maintenance expenses were $32 million lower in 2016 compared with 2015. The following items decreasedrequired environmental remediation work. Additionally, other operations and maintenance expenses between years:
MEEIA customer energy-efficiency program costs decreased by $34 million in 2016, primarily because of the expiration of MEEIA 2013, partially offset by costs incurred for MEEIA 2016.
Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center discussed below, decreased by $18 million, primarily because of reduced staffing costs and decreased routine maintenance costs, partially offset by higher coal handling charges.
Electric distribution maintenance expenditures decreased by $16$4 million, primarily related to reduced system repair and vegetation management work.
Employee benefit costs decreased by $15 million, primarily because of a $6 million reduction in the base level of pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order, and lower medical benefit costs, as well as a $4 million decrease due to changes in the market value of company-owned life insurance.
The following items increased other operations and maintenance expenses between years:
Refueling and maintenance outage costs at the Callaway energy center increased by $26 million, primarily because of costs for the 2016 scheduled refueling and maintenance outage. There was no Callaway refueling and maintenance outage in 2015.
Litigation costs increased by $11 million, primarily related to increases in estimated obligations for pending legal claims.
Solar rebate costs increased by $9 million, as a result of the April 2015 MoPSC electric rate order.
Storm-related repair costs increased by $7 million.
Ameren Illinois
Other operations and maintenance expenses increased $7 million in 2016 compared with 2015, as discussed below.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses were $6 million higher in 2016 compared with 2015. The following items increased other operations and maintenance expenses between years:
Labor costs increased by $6 million, primarily because of staffing additions to meet enhanced standards and goals related to the IEIMA.
Storm-related repair costs increased by $3 million.
Bad debt, customer energy efficiency, and environmental remediation costs increased by $2 million.
Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.
The following items decreased other operations and maintenance expenses between years:
Employee benefit costs decreased by $6 million, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
Electric distribution operations and maintenance expenditures decreased by $3 million, primarily related to reduced circuit maintenance work, partially offset by increased vegetation management work.
Ameren Illinois Natural Gas
Other operations and maintenance expenses were $4 million lower in 2016 compared with 2015. The following items decreased other operations and maintenance expenses between years:
Bad debt, customer energy-efficiency, and environmental remediation costs decreased by $10 million.
Employee benefit costs decreased by $5 million, primarily because of lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
The following items increased other operations and maintenance expenses between years:
Repairs and compliance expenditures increased by $8 million, primarily related to increased pipeline integrity and storage field maintenance.
Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.
Ameren Illinois Transmission
Other operations and maintenance expenses were $5 million higher in 2016 compared with 2015, primarily because of an increase in system operations and labor overhead costs.
Provision for Callaway Construction and Operating License
Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site in 2015, primarily becauseDepreciation and Amortization
2017 versus 2016 | | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase by Segment | |
| | Overall Ameren Increase of $98 Million | |
Depreciation
(a)Includes other/intersegment eliminations of $7 million and $4 million in 2023 and 2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
The $98 million, $51 million, and $42 million increases in depreciation and amortization expenses increased $51 million, $19 million, and $22 million in 20172023, compared with 20162022, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, were primarily because ofdue to additional property, plant, and equipment across their respective segments.
2016 versus 2015In addition, Ameren’s and Ameren Missouri’s depreciation and amortization expenses were affected by the following, which include the effect of the additional investments in property, plant, and equipment:
•Increased depreciation and amortization of $51 million, due to the inclusion in base rates of amounts previously deferred under the PISA and RESRAM effective February 28, 2022, and July 9, 2023, pursuant to the December 2021 and June 2023 MoPSC electric rate orders, respectively.
•Depreciation and amortization rate changes pursuant to the electric rate orders noted above, which increased depreciation and amortization expenses by $17 million.
•Increased depreciation and amortization of $6 million, primarily because of electric system capital additions not eligible for deferral under PISA and RESRAM.
•The higher deferral, net of amortization of prior-period deferrals, pursuant to a tracker related to certain excess deferred income taxes, which decreased depreciation and amortization by $17 million.
•Depreciation and amortization expenses increased $49 million, $22reflected a deferral to a regulatory asset of depreciation and amortization expenses pursuant to PISA and RESRAM. The amount of depreciation and amortization expenses included in base rates for PISA and RESRAM deferrals was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021; and when new customer rates became effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, which incorporated deferrals through December 31, 2022. The effect of higher deferrals, net of amortization of prior-period deferrals, decreased depreciation and amortization expenses by $5 million.
•The higher net under-recovery of RESRAM eligible expenses decreased depreciation and amortization expenses by $3 million.
Taxes Other Than Income Taxes
| | | | | | | | | | | | | | |
| Total by Segment(a) | | Increase (Decrease) by Segment | |
| | Overall Ameren Decrease of $17 Million | |
(a)Includes $8 million and $24$9 million at Ameren Transmission in 2023 and 2022, respectively, and other/intersegment eliminations of $12 million and $10 million in 20162023and2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Taxes other than income taxes decreased $17 million in 2023, compared with 20152022, largely because of a $14 million decrease in excise taxes at Ameren Illinois Natural Gas, primarily resulting from decreased sales revenues. Taxes other than income taxes also decreased $6 million and $2 million in 2023, at Ameren Missouri and Ameren Illinois, respectively, primarily because of additional property, plant,employee retention tax credits received under the Coronavirus Aid, Relief, and equipment across their respective segments. Additionally,Economic Security Act. The decreases in taxes other than income taxes at Ameren Missouri’s depreciationMissouri were partially offset by a $4 million increase in excise taxes, primarily related to increased retail electric rates increased as a result ofpursuant to the April 2015June 2023 MoPSC electric rate order.
Taxes Other Than Income Taxes
2017 versus 2016
Ameren
Taxes other than income taxes increased $10 million in 2017 compared with 2016, as discussed below. Taxes other than income taxes were comparable at Ameren Transmission. 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 $3 million, primarily becauseAmeren Illinois
Taxes other than income taxes increased $5 million, primarily because of increased property taxes at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas. Taxes other than income taxes were comparable at Ameren Illinois Transmission.
2016 versus 2015
Ameren
Taxes other than income taxes decreased $6 million in 2016 compared with 2015, primarily at Ameren Missouri, as discussed below. Taxes other than income taxes were comparable at Ameren Transmission, as well as at Ameren Illinois and its respective segments.
Ameren Missouri
Taxes other than income taxes decreased $10 million, primarily because of decreased gross receipts taxes resulting from lower residential and commercial electric revenues and because of decreased property taxes.
Other Income, and ExpensesNet
2017 versus 2016 | | | | | | | | | | | | | | |
| Total by Segment | | Increase by Segment | |
| | Overall Ameren Increase of $122 Million | |
Ameren
Other income, net of expenses, decreased $4 million in 2017 compared with 2016, primarily due to decreased income at Ameren Illinois Electric Distribution, as discussed below, along with a decrease in the allowance for equity funds used during construction, partially offset by decreased donations in 2017. Other income, net of expenses, was comparable at the remaining Ameren segments. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
See Note 6 – Other Income, and ExpensesNet under Part II, Item 8, of this report for additional information. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for more information on the non-service cost components of net periodic benefit income.
Ameren
Other income, net, increased $122 million in 2023, compared with 2022. In addition to changes discussed below, other income, net, increased $26 million, primarily because of a $30 million increase in the non-service cost component of net periodic benefit income for activity not reported as part of a segment, partially offset by a $3 million increase in charitable contributions.
Ameren Transmission
Other income, net, increased $11 million in 2023, compared with 2022, largely because of a $5 million increase in the allowance for equity funds used during construction, primarily resulting from a higher average monthly equity-to-debt ratio at ATXI, and higher average construction work in progress balances. Other income, net, also increased $3 million because of an increase in the non-service cost component of net periodic benefit income.
Ameren Missouri
Other income, net, increased $31 million in 2023, compared with 2022, primarily because of a $42 million increase in the non-service cost component of net periodic benefit income pursuant to the June 2023 MoPSC electric rate order, which reflected the effect of such increase in electric service rates effective July 9, 2023. Other income, net, also increased $6 million because of higher allowance for equity funds used during construction, resulting from higher average construction work in progress balances. Additionally, other income, net increased $6 million because of higher interest income on under-recovered asset balances associated with regulatory recovery mechanisms. These increases in other income, net, were partially offset by a decrease of $23 million in interest income on industrial development revenue bonds, as these bonds were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements related to the investments in industrial development revenue bonds.
Ameren Illinois
Other income, net, of expenses, decreased $8increased $60 million in 2023, compared with 2022, primarily because of lower interestincreases in the non-service cost component of net periodic benefit income associated with a lower IEIMA revenue requirement reconciliation regulatory asset balanceof $26 million, $11 million, and $3 million at Ameren Illinois Electric Distribution.Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, respectively. Other income, net, of expenses, was comparablealso increased $13 million at the remaining Ameren Illinois segments.
2016 versus 2015
OtherElectric Distribution because of higher interest income net of expenses, was comparable between years at Ameren, Ameren Missouri, Ameren Illinois, and their respective segments.on under-recovered balances associated with regulatory recovery mechanisms.
Interest Charges
2017 versus 2016 | | | | | | | | | | | | | | |
| Total by Segment | | Increase by Segment | |
| | Overall Ameren Increase of $80 Million | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Interest charges increased $80 million in 2023, compared with 2022, primarily because of the following items:
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report and the Long-term Debt and Equity section below for additional information on short-term borrowings and long-term debt, respectively, discussed below. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreement discussed below.
Ameren
Interest charges increased $9$80 million in 20172023, compared with 2016,2022. In addition to changes by segments discussed below, interest charges increased $28 million for activity not reported as discussed below.
part of a segment, primarily because of a $23 million increase related to higher interest rates on increased levels of short-term borrowings at Ameren (parent). Interest charges for activity not reported as part of a segment also increased $5 million because of issuances of long-term debt at Ameren (parent) in November and December 2023.
Ameren Transmission
Interest charges increased $9$12 million in 2023, compared with 2022, primarily because of issuances of long-term debt in August and November 2022 and May 2023, which collectively increased interest charges by $17 million. The increases in 2023 were partially offset by a $8 million reduction to interest charges because of an increase in average outstanding debt at Ameren Illinois and ATXI.
Ameren Missouri
Interest charges decreased $4 million, primarily becausethe borrowed funds capitalized as part of a decrease in the average interest rate of debt.
Ameren Illinois
Interest charges increased $4 million, primarily because of an increase in average outstanding debt, partially offset by a decrease in the average interest rate of debt. Interest charges were comparable between years at each of the Ameren Illinois segments.
2016 versus 2015
Ameren
Interest charges increased $27 million in 2016 compared with 2015, because of an approximately $475 million increase in average outstanding debt and an increase in the average interest rate of debt at Ameren (parent). Ameren (parent) issued senior unsecured notes in November 2015 to repay lower-cost short-term debt incurred primarily in connection with the funding of increasing ATXI investments. An increase in the average interest rate of debt at Ameren Transmission was partially offset by a decrease in the average interest rate of debt at Ameren Missouri, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.
Ameren Transmission
Interest charges increased $23 million, because of an increase in ATXI’s and Ameren Illinois’ average outstanding debt and an increase in the average interest rate of debt.
Ameren Missouri
Interest charges decreased $8 million, primarily because of a decrease in average outstanding debt.
Ameren Illinois
Interest charges increased $9 million, primarily at Ameren Illinois Transmission, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.
Ameren Illinois Transmission
Interest charges increased $9 million, primarily because of an increase in Ameren Illinois’ average outstanding debt and a decrease in the allowance for funds used during construction, because of a reduction inprimarily due to increased average construction work in progress balances and a higher applicable borrowing rate.
Ameren Missouri
Interest charges increased $14 million in 2023, compared with 2022. The following items increased interest charges between years:
•Issuances of long-term debt in April 2022 and March 2023 collectively increased interest charges by $27 million.
•Interest charges increased $11 million because of higher interest rates on increased levels of short-term borrowings.
•Interest charges reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM. The amount of PISA and RESRAM deferrals included in base rates was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021, and when new customer rates became effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, which incorporated deferrals through December 31, 2022. Lower deferrals in 2023, due to the inclusion in base rates of interest associated with certain property, plant, and equipment previously deferred under the PISA and RESRAM, increased interest charges by $9 million.
The following items partially offset the above increases in interest charges between years:
•Interest charges decreased $23 million, primarily due to the termination of a financing obligation agreement related to the CT energy center in Audrain County. The decreases in interest charges associated with this agreement are offset by decreases in interest income on related industrial development revenue bonds, as more projectsdiscussed above.
•Interest charges decreased $14 million because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to higher average construction work in progress balances and a higher applicable borrowing rate.
Ameren Illinois
Interest charges increased $36 million in 2023, compared with 2022, primarily because of the issuances of long-term debt in 2022 and 2023. Issuances of long-term debt at Ameren Illinois in August and November 2022 and May 2023 collectively increased interest charges by $19 million at Ameren Illinois Electric Distribution, by $15 million at Ameren Illinois Transmission, and $12 million at Ameren Illinois Natural Gas. The increases in 2023 were placedpartially offset by a $4 million reduction to interest charges at Ameren Illinois Transmission because of an increase in servicethe borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to higher average construction work in 2016.progress balances and a higher applicable borrowing rate.
Income Taxes
The following table presents effective income tax rates for the years ended December 31, 2017, 2016, 2023and 2015:2022: |
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
| Ameren | 52% | (a) | 37% | | 38% | |
| Ameren Missouri | 44% | (b) | 38% | | 37% | |
| Ameren Illinois | 38% | (c) | 38% | | 37% | |
| Ameren Illinois Electric Distribution | 38% | (c) | 38% | | 36% | |
| Ameren Illinois Natural Gas | 38% | (c) | 39% | | 40% | |
| Ameren Illinois Transmission | 37% | (c) | 38% | | 37% | |
| Ameren Transmission | 39% | (c) | 39% | | 38% | |
| |
(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. |
| | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | | |
| Ameren | 14% | | 14% | | | |
| Ameren Missouri | (2)% | | (2)% | | | |
| Ameren Illinois | 26% | | 26% | | | |
| Ameren Illinois Electric Distribution | 24% | | 25% | | | |
| Ameren Illinois Natural Gas | 27% | | 27% | | | |
| Ameren Illinois Transmission | 26% | | 26% | | | |
| Ameren Transmission | 26% | | 26% | | | |
See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois, as well as a discussion of the effect of the TCJA and the revaluation of deferred taxes in 2017.Illinois.
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, which decreased the federal statutory corporate income tax rate from 35% to 21% for years after 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.
2016 versus 2015
Ameren
The effective tax rate was comparable between years. The reduction in the 2016 effective tax rate, as compared with the 2015 effective tax rate, was primarily a result of 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. This reduction was partially offset by a higher effective tax rate in 2016 as compared with 2015 at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between years at the remaining Ameren segments.
Ameren Illinois
The effective tax rate was comparable between years. The effective tax rate was higher at Ameren Illinois Electric Distribution, primarily because of items detailed below. The effective tax rate was comparable between years at the remaining Ameren Illinois segments.
Ameren Illinois Electric Distribution
The effective tax rate was higher, primarily because of lower tax benefits from certain depreciation differences on property-related items.
Income (Loss) from Discontinued Operations, Net of Taxes
No material activity was recorded associated with discontinued operations in 2017 or 2016. In 2015, based on completion of the IRS audit of Ameren’s 2013 tax year, Ameren recognized a tax benefit of $53 million due to the resolution of an uncertain tax position from discontinued operations. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
LIQUIDITY AND CAPITAL RESOURCES
Collections from our tariff-based gross marginsrevenues 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, money pool borrowings, 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). The TCJA will benefit customers through lower ratesIn addition, to support a portion of its fuel requirements for our services but is not expectedgeneration, Ameren Missouri has entered into various long-term commitments to materially affect our earnings. However, our cash flowsmeet these requirements. Ameren Missouri and rate base are expected to be materially affectedAmeren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. Ameren’s, Ameren Missouri’s, and Ameren Illinois’ estimated minimum purchase obligations associated with these commitments totaled $2.3 billion, $1.1 billion, and, $1.2 billion, respectively, which include $0.9 billion, $0.4 billion, and, $0.6 billion, respectively, in the near term. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. 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 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. 2024.
We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. We also expect to make significant capital expenditures over the next five years, as discussed in the Capital Expenditures sections below, supported by a combination of long-term debt and equity, as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy target requirements, environmental compliance, and other improvements. For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see
Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. As part of its funding plan to fund thesefor capital expenditures, beginning in the first quarter of 2018, Ameren will useis using newly issued shares rather than market-purchased shares,of common stock to satisfy requirements under itsthe DRPlus and employee benefit plans and expects to continue to do so overthrough at least 2028. Additionally, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the next five years. Additionally, we mayability to enter into forward sale agreements, subject to market conditions and other factors. During 2023, Ameren issued a total of 3.2 million shares of common stock and received aggregate proceeds of $299 million under the ATM program. As of December 31, 2023, Ameren had multiple forward sale agreements that could be requiredsettled under the ATM program with various counterparties relating to 2.9 million shares of common stock. Ameren expects to settle approximately $230 million of the forward sale agreements with physical delivery of 2.9 million shares of common stock by December 31, 2024. Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue incremental debt and/orapproximately $300 million of equity with the long-term intentin 2024 and approximately $600 million of equity each year from 2025 to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.
The use2028. As of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments will periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2017,2023, Ameren had approximately $770 million of common stock available for sale under the Ameren Companies. The working capital deficitATM program, which takes into account the forward sale agreements in effect as of December 31, 2017, was primarily2023. Ameren expects its equity to total capitalization to support solid investment-grade credit ratings. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the result of current maturities of long-term debt and our decision to finance our businesses with lower-cost commercial paper issuances. WithATM program, including the credit capacity availableforward sale agreements under the Credit Agreements, the Ameren Companies had accessATM program relating to $1.6 billion of liquidity at December 31, 2017.common stock.
The following table presents net cash provided by (used in) operating, investing, and financing activities for the years ended December 31, 2017, 2016,2023 and 2015:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Cash Provided By
Operating Activities | | Net Cash Used In
Investing Activities | | Net Cash Provided By
Financing Activities |
| 2023 | | 2022 | | | Variance | | 2023 | | 2022 | | | Variance | | 2023 | | 2022 | | | Variance |
| Ameren | $ | 2,564 | | (a) | $ | 2,263 | | (a) | | $ | 301 | | | $ | (3,798) | | | $ | (3,370) | | | | $ | (428) | | | $ | 1,290 | | | $ | 1,168 | | | | $ | 122 | |
| | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | 1,341 | | | 1,130 | | | | 211 | | | (1,960) | | | (1,703) | | | | (257) | | | 616 | | | 578 | | | | 38 | |
| Ameren Illinois | 1,098 | | (a) | 1,048 | | (a) | | 50 | | | (1,733) | | | (1,602) | | | | (131) | | | 678 | | | 612 | | | | 66 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Cash Provided by (Used in) Operating Activities | | Net Cash Used in Investing Activities | | Net Cash Provided by (Used in) Financing Activities |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Ameren(a) – continuing operations | $ | 2,104 |
| | $ | 2,124 |
| | $ | 2,035 |
| | $ | (2,205 | ) | | $ | (2,141 | ) | | $ | (1,951 | ) | | $ | 102 |
| | $ | (265 | ) | | $ | 232 |
|
Ameren(a) – discontinued operations | — |
| | (1 | ) | | (4 | ) | | — |
| | — |
| | (25 | ) | | — |
| | — |
| | — |
|
| Ameren Missouri | 1,016 |
| | 1,169 |
| | 1,247 |
| | (685 | ) | | (934 | ) | | (724 | ) | | (331 | ) | | (434 | ) | | (325 | ) |
| Ameren Illinois | 815 |
| | 803 |
| | 763 |
| | (1,070 | ) | | (918 | ) | | (913 | ) | | 255 |
| | 44 |
| | 220 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional regulatory rate proceeding.review, subject to prudence reviews. Similar regulatory mechanisms exist for certain other operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by seasonal customer rates and changes in customer demand due to weather, significantly affectaffects 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.
2017 versus 2016As a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, Ameren Missouri and Ameren Illinois had under-recovered costs for the month of February 2021 under their PGA clauses and, for Ameren Missouri, under the FAC (Ameren Missouri - PGA $53 million, FAC $50 million; Ameren Illinois - PGA $221 million). Ameren Missouri’s PGA under-recovery is being collected from customers over 36 months beginning November 2021, pursuant to an October 2021 MoPSC order, and the FAC under-recovery was collected over eight months beginning October 2021. Ameren Illinois collected the PGA under-recovery over 18 months beginning April 2021.
Ameren
Ameren’s cash fromprovided by operating activities associated with continuing operations decreased $20increased $301 million in 2017,2023, compared with 2016.2022. The following items contributed to the decrease:increase:
•A $48$372 million increase in customer collections, primarily from base rate increases effective February 28, 2022, and July 9, 2023, pursuant to Ameren Missouri’s December 2021 and June 2023 MoPSC electric rate orders, respectively, electric transmission rate base growth, and an increase attributable to non-PGA regulatory mechanisms, partially offset by a decrease in cash related to customer energy-efficiency program recovery mechanisms.
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.
A $36 million decrease in cash recoveries associated withunder Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. ThePGA resulting from the 2022 recovery of costs for the mid-February 2021 weather event discussed above.
2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
•A $27$211 million decrease in net energy costs collected from Ameren Missouri customers undercollateral posted with counterparties, primarily due to changes in the FAC.market prices of power, natural gas, and other fuels.
•A $27$66 million decrease in cash related to Ameren Illinois’ power procurement cost recovery mechanism.
Refunds paid in 2017 of $21 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 $17 million decrease in cash associated with Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
A $14 million increase in the cost of natural gas held in storage, caused primarily by reduced withdrawals as a resultat Ameren Illinois, because of milder winter temperatures compared withlower commodity prices.
The following items partially offset the prior year.increase in Ameren’s cash from operating activities between periods:
•A $13$70 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates. This $70 million increase in interest payments includes a $24 million decrease in interest payments from financing obligations at Ameren Illinois.Missouri that were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements.
•A $10$65 million increase in coal inventory levels at Ameren Missouri, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes, which were affected by reduced generation at the Rush Island Energy Center, lower market prices for capacity and energy, and decreased retail load because of warmer winter and milder spring and summer temperatures.
•A $35 million increase in labor costs and payments to contractors primarily due to major storm restoration costs, primarily at Ameren Illinois, due to major storms in late June, July, and August 2023.
•A $25 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•A $25 million decrease due to the timing of payments received from the DOE for the annual reimbursement of spent nuclear fuel storage and related costs.
•A $24 million decrease in interest collections on industrial revenue bonds at Ameren Missouri, as these bonds were settled in December 2022 and Ameren Illinois, primarily becauseJanuary 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of wage increases.this report for additional information on the termination of the financing obligation agreements related to the investments in industrial development revenue bonds.
•A $7$23 million increase in pension and postretirement benefit plan contributions.workers’ compensation payments at Ameren Illinois.
A $4•An $11 million increase in property tax payments to contractors at Ameren IllinoisMissouri, primarily due to higher assessed property tax values.
Ameren Missouri
Ameren Missouri’s cash provided by operating activities increased $211 million in 2023, compared with 2022. The following items contributed to the increase:
•A $239 million increase in customer collections, primarily from base rate increases effective February 28, 2022, and July 9, 2023, pursuant to the December 2021 and June 2023 MoPSC electric rate orders, respectively, and an increase attributable to regulatory mechanisms.
•A $131 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.
•A $5 million decrease in interest payments, primarily due to a $24 million decrease in interest payments from financing obligations that were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional reliability, maintenance,information on the termination of the financing obligation agreements, partially offset by an increase in interest payments due to an increase in the average outstanding debt and increased natural gas compliance costs.an increase in interest rates.
The following items partially offset the decrease in Ameren’s cash from operating activities associated with continuing operations between years:
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 $37 million increase in cash collected from Ameren Illinois customers related to zero-emission credits pursuant to the FEJA. In the first quarter of 2018, these funds will be used for the purchase of zero-emission credits pursuant to an IPA procurement event.
A $23 million increase in cash collected from Ameren Illinois’ alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.
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.
Ameren’s cash from operating activities associated with discontinued operations was immaterial in both 2017 and 2016.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased $153 million in 2017, compared with 2016. 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 $27 million decrease in net energy costs collected from customers under the FAC.
A $20 million decrease in cash related to customer energy-efficiency program recovery mechanisms.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities between years:periods:
•A $70$65 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 levels, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes, which were affected by reduced generation at the Rush Island Energy Center, lower market prices for capacity and energy, and decreased purchasesretail load because of warmer winter and milder spring and summer temperatures.
•A $25 million decrease due to the timing of payments received from the DOE for the annual reimbursement of spent nuclear fuel storage and related costs.
•A $24 million decrease in interest collections on industrial revenue bonds, as a resultthese bonds were settled in December 2022 and January 2023. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of inventory reductions atthis report for additional information on the energy centers.termination of the financing obligation agreements related to the investments in industrial development revenue bonds.
•A $16 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•An $11 million increase in property tax payments, primarily due to higher assessed property tax values.
•A $7 million increase in major storm restoration costs, primarily due to major storms in July and August 2023.
Ameren Illinois
Ameren Illinois’ cash fromprovided by operating activities increased $12$50 million in 2017,2023, compared with 2016.2022. The following items contributed to the increase:
•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.
A $37$145 million increase in cash collectedcustomer collections, primarily from customers relatedelectric transmission rate base growth and an increase attributable to zero-emission credits pursuant tonon-PGA regulatory recovery mechanisms, partially offset by a decrease under the FEJA. InPGA resulting from the first quarterrecovery in 2022 of 2018, these funds will be usedcosts for the purchasemid-February 2021 weather event discussed above.
•An $83 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of zero-emission credits pursuant to an IPA procurement event.power and natural gas.
•A $63 million decrease in the cost of natural gas held in storage because of lower commodity prices.
A $30 million increase resulting from income tax refunds
A $23 million increase in cash collected from alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.
The following items partially offset the increase in Ameren Illinois’ cash from operating activities between periods:
•A $36 million decrease in cash recoveries associated with IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
A $28 million decrease in cash related to customer energy-efficiency program recovery mechanisms.
A $27 million decrease in cash related to the power procurement cost recovery mechanism.
A $17 million decrease in cash recoveries associated with the transmission revenue requirement reconciliation adjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.
Refunds paid in 2017 of $17 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 million increase in the cost of natural gas held in storage, caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.
A $13 million increase in interest payments, primarily due to an increase in the average outstanding debt.
2016 versus 2015
Ameren
Ameren’s cash from operating activities associated with continuing operations increased $89 million in 2016, compared with 2015. The following items contributed to the increase:
A $126 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.
A $70 million decrease in pension and postretirement benefit plan contributions.
A $42 million insurance receipt at Ameren Missouri related to the Taum Sauk breach that occurred in 2005.
A $40 million increase in cash associated with the recovery of Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
A $38 million increase in cash related to Ameren Illinois’ power procurement cost recovery mechanism.
A $37 million decrease in coal inventory purchases at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.
A $33 million increase in cash related to customer energy-efficiency program recovery mechanisms.
A $19 million increase in cash associated with the recovery of Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.
The following items partially offset the increase in Ameren’s cash from operating activities associated with continuing operations during 2016, compared with 2015:
A $166 million decrease resulting from the change in customer receivable balances.
A $94 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.
A $23 million increase in interest payments, primarily due to an increase in the cost and amount of outstanding debt of Ameren (parent) and an increase in the average outstanding debt at Ameren Illinois.
A $20 million increase in payments for the refueling and maintenance outage at Ameren Missouri’s Callaway energy center. There was no refueling and maintenance outage in 2015.
A $9 million increase in labor costs at Ameren Illinois, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.
A $7 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects.
Ameren’s cash from operating activities associated with discontinued operations was immaterial in both 2016 and 2015.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased $78 million in 2016, compared with 2015. The following items contributed to the decrease:
A $142 million decrease 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 $94 million decrease in net energy costs collected from customers under the FAC.
A $20 million increase in payments for the refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during 2016, compared with 2015:
A $45 million decrease in income tax payments, pursuant to the tax allocation agreement with Ameren (parent), primarily related to higher deductions related to increased capital expenditures in 2016.
A $42 million insurance receipt related to the Taum Sauk breach that occurred in December 2005.
A $37 million decrease in coal inventory purchases, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.
A $33 million decrease in pension and postretirement benefit plan contributions.
An $11 million increase in cash related to customer energy-efficiency program recovery mechanisms.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased $40 million in 2016, compared with 2015. The following items contributed to the increase:
A $58 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, which was partially offset by the change in customer receivable balances.
A $40 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
A $38 million increase in cash related to the power procurement cost recovery mechanism.
A $22 million decrease in pension and postretirement benefit plan contributions.
A $22 million increase in cash related to customer energy-efficiency program recovery mechanisms.
A $19 million increase in cash associated with the recovery of transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.
The following items partially offset the increase in Ameren Illinois’ cash from operating activities during 2016, compared with 2015:
A $121$79 million decrease resulting from income tax payments of $8 million in 2016, compared with income tax refunds of $113 million in 2015,to Ameren (parent) pursuant to the tax allocation agreement, with Ameren (parent). During 2015, Ameren Illinois used net operating loss carryforwards from prior years, resultingprimarily due to higher taxable income in a reduction in payments. Ameren Illinois also had higher deductions for increased capital expenditures in 2015.2023.
•A $9$64 million increase in labor costs primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals relateddecrease due to the IEIMA.timing of payments for accounts payable and prepaid expenses.
•A $7 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects.
A $7$43 million increase in interest payments, primarily due to an increase in the average outstanding debt including senior secured notes issued in December 2015.
Pension Plans
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 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, 2017, its investment performance in 2017, and its pension funding policy, Ameren expects to make annual contributions of less than $1 million to $60 million in each of the next five years, with aggregate estimated contributions of $120 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 35% and 55%, respectively. These amounts are estimates. They may change based on actual investment performance, changesan increase in interest rates, changesrates.
•A $28 million increase in our assumptions, changeslabor costs and payments to contractors primarily due to major storm restoration costs due to major storms in government regulations,late June, July, and any voluntary contributions. In 2017, Ameren contributed $64August 2023.
•A $23 million to its pension plans. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.increase in workers’ compensation payments.
Cash Flows from Investing Activities
2017 versus 2016
Ameren’s cash used in investing activities associated with continuing operations increased by $64$428 million during 2017,2023, compared with 2016. Capital expenditures increased $56 million2022, primarily as a result of activity at Ameren Missouri and Ameren Illinois, discussed below. The $187a $246 million increase in capital expenditures, largely resulting from increased storm-related expenditures at Ameren Missouri and Ameren Illinois was partially offset by a $127 million decrease inand electric transmission upgrades at ATXI. ATXI’s capital expenditures at ATXI due to reduced spending on the Illinois Rivers project, partially offset by an increase in spending on the Spoon River project. During 2017 and 2016, there was noincreased $56 million. Also, cash used in investing activities associated with discontinued operations.increased at Ameren Missouri, due to increased nuclear fuel expenditures of $145 million and the absence of receipt of $21 million in insurance proceeds in 2022 for the Callaway Energy Center’s generator.
Ameren Missouri’s cash used in investing activities decreased by $249increased $257 million during 2017,2023, compared with 2016,2022, primarily becausedue to increased nuclear fuel expenditures for future refuels of net money pool advances. During 2017, Ameren Missouri received $161$174 million in returns of net money pool advances2023 compared with investing $125to $29 million in net money pool advances2022. Also, cash used in 2016. This decrease was partially offset byinvesting activities increased $70 million as a $35 millionresult of increased capital expenditures, largely resulting from an increase in capitalstorm-related expenditures primarily relatedof $58 million. In addition, cash used in investing activities increased due to electric distribution and transmission system reliability and energy center projects.the absence of receipt of $21 million in insurance proceeds in 2022 for the Callaway Energy Center’s generator.
Ameren Illinois’ cash used in investing activities increased by $152$131 million during 2017,2023, compared with 2016, because of increased capital expenditures, primarily related2022, due to electric transmission system reliability projects and natural gas infrastructure projects.
2016 versus 2015
Ameren’s cash used in investing activities associated with continuing operations increased by $190 million during 2016, compared with 2015. Capital expenditures increased $159 million, primarily because of increased transmission expenditures, which included a $41 million increase at ATXI primarily related to the Illinois Rivers project, and increased Ameren Missouri and Ameren Illinois capital expenditures.
During 2016, there was no cash used in investing activities associated with discontinued operations. During 2015, Ameren’s cash used in investing activities associated with discontinued operations consisted of a $25 million payment for a liability associated with the New AER divestiture.
Ameren Missouri’s cash used in investing activities increased by $210 million during 2016, compared with 2015. Capital expenditures increased $116 million, primarily related to electric distribution system reliability and energy center projects. Additionally, there was an increase in net advances to the money pool of $89 million.
Ameren Illinois’ cash used in investing activities increased by $5 million during 2016, compared with 2015, because of increased capital expenditures, primarily related to qualified investments in natural gas infrastructure under the QIP rider, storm restoration costs, and reliability.largely resulting from increased storm-related expenditures of $103 million.
Capital Expenditures
The following table presents thecharts present our capital expenditures by the Ameren Companies for the years ended December 31, 2017, 2016,2023 and 2015:2022:
| | | | | | | | |
|
2023 – Total Ameren $3,597(a) | | 2022 – Total Ameren $3,351(a) |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri(b) | | Ameren Illinois Natural Gas | | ATXI and other electric transmission subsidiaries | |
| | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Transmission | | | |
(a)Includes Other capital expenditures of $(18) million and $(9) million for the years ended December 31, 2023 and 2022, respectively, which includes amounts for the elimination of intercompany transfers.
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 773 |
| | $ | 738 |
| | $ | 622 |
|
| Ameren Illinois Electric Distribution | 476 |
| | 470 |
| | 491 |
|
| Ameren Illinois Natural Gas | 245 |
| | 181 |
| | 133 |
|
| Ameren Illinois Transmission | 355 |
| | 273 |
| | 294 |
|
| ATXI | 289 |
| | 416 |
| | 375 |
|
Other (a) | (6 | ) | | (2 | ) | | 2 |
|
| Ameren | $ | 2,132 |
| | $ | 2,076 |
| | $ | 1,917 |
|
| |
(a) | Includes amounts for the elimination of intercompany transfers. |
Ameren’s 20172023 capital expenditures consisted of expenditures made by its subsidiaries, including $124 million by ATXI which spent $289 million primarily on the Illinois Rivers and Spoon River projects.other electric transmission subsidiaries. Ameren Illinois spent $355Natural Gas capital expenditures for 2023 included $165 million onrelated to natural gas projects eligible for QIP recovery. Ameren’s 2022 capital expenditures consisted of expenditures made by its subsidiaries, including $69 million by ATXI and other electric transmission subsidiaries. Ameren Illinois Natural Gas capital expenditures for 2022 included $183 million related to natural gas projects $153 million on projects that are recovered under theeligible for QIP rider, and $123 million on IEIMA projects. Otherrecovery. 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 2016 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $416 million primarily on the Illinois Rivers project. Ameren Illinois spent $273 million on transmission projects and $109 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 and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.
Ameren’s 2015 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $375 million primarily on the Illinois Rivers project. Ameren Illinois spent $294 million on transmission projects and $134 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 and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.
The following table presents Ameren’s estimate of capital expenditures that will be incurred from 20182024 through 2022,2028, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations. Ameren expects to continue to allocate more of its capital expenditures to Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission based, in part, on the constructive regulatory frameworks within which they operate.regulations: | | | | 2018 | | 2019-2022 | | Total |
| 2024 | | | 2024 | | 2025 – 2028 | | Total |
| Ameren Missouri | $ | 845 |
| | $ | 3,310 |
| - | $ | 3,660 |
| | $ | 4,155 |
| - | $ | 4,505 |
|
| Ameren Illinois Electric Distribution | 465 |
| | 1,815 |
| - | 2,005 |
| | 2,280 |
| - | 2,470 |
|
| Ameren Illinois Natural Gas | 330 |
| | 1,220 |
| - | 1,350 |
| | 1,550 |
| - | 1,680 |
|
| Ameren Illinois Transmission | 470 |
| | 1,765 |
| - | 1,950 |
| | 2,235 |
| - | 2,420 |
|
| ATXI | 70 |
| | 215 |
| - | 240 |
| | 285 |
| - | 310 |
|
| ATXI and other electric transmission subsidiaries | |
| Other | 5 |
| | 15 |
| - | 15 |
| | 20 |
| - | 20 |
|
| Ameren | $ | 2,185 |
| | $ | 8,340 |
| - | $ | 9,220 |
| | $ | 10,525 |
| - | $ | 11,405 |
|
Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, including $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments through 2028, consistent with Ameren Missouri’s 2023 IRP, as well as expenditures for compliance with environmental regulations. The estimates above do not reflect the potential additional investments identifiedCapital expenditures related to coal-fired generation of approximately $0.9 billion are included in Ameren Missouri’s integrated resource plan, which could represent incremental investments of approximately $1 billionestimated capital expenditures through 2020 and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made.2028. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, including investmentsto meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained. Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.
In 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade. In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects. In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion. The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024.
In February 2024, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2024. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $12.4 billion over the five-year period from 2024 through 2028, with expenditures to modernize its distribution system pursuant tolargely recoverable under the IEIMA, and capital expenditures for qualifiedPISA. Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas infrastructure under the QIP rider. ATXI’s estimated capital expenditures include expenditures for the three MISO-approved multi-value transmission projects. For additional information regarding the IEIMA capital expenditure requirements, the QIP rider, and ATXI’s transmission projects, see Part I, Item 1,distribution business, as well as removal costs, net of this report.salvage.
Ameren Missouri continually reviews its generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments.investments within and outside our service territories. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, future rate orders, and our ability and willingness to pursue transmission investments, as well as our ability to obtain necessary regulatory approvals, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.
Environmental Capital Expenditures
Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO2, NOx, and mercury emissions from its coal-fired energy centers.centers, compliance with the CCR Rule, and potential modifications to cooling water
intake structures at existing power plants under Clean Water Act rules. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws and regulations that affect, or may affect, our facilities and capital expenditures to comply with such laws and regulations.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 dividends declared by Ameren’s boardlevel of directors,dividends, and our long-term debt maturities, among other things.
2017 versus 2016
Ameren’s cash provided by financing activities associated with continuing operations provided net cash of $102increased $122 million in 2017,during 2023, compared with using net cash of $265 million in 2016.2022. During 2017,2023, Ameren utilized net proceeds of $2.3 billion of long-term debt for general corporate purposes, for capital expenditures, to repay then-outstanding short-term debt, and to repay $100 million of maturities of long-term debt. Ameren also repaid net commercial paper borrowings totaling $533 million. In addition, Ameren utilized aggregate cash proceeds of $346 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2022, Ameren utilized proceeds from the issuance of $1,345$1.5 billion of long-term debt to repay then-outstanding short-term debt, for capital expenditures, and to repay $505 million of maturities of long-term indebtedness to repay $681debt. Ameren also received aggregate cash proceeds of $333 million from the issuance of higher-cost long-term indebtedness, to repay $74common stock under the ATM program, the DRPlus, and the 401(k) plan, and $522 million offrom net commercial paper issuances, andissuances. These proceeds were used to fund, in part, investing activities. In comparison, during 2016,capital expenditures. During 2023, Ameren utilized net proceeds from the issuancepaid common stock dividends of $646$662 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$610 million in dividend payments in 2016. No cash from financing activities was used for discontinued operations during 2017.2022.
Ameren Missouri’s cash used inprovided by financing activities decreased by $103increased $38 million in 2017,during 2023, compared with 2016.2022. During 2017,2023, Ameren Missouri utilized net proceeds of $499 million from the issuance of $438long-term debt for capital expenditures and to repay then-outstanding short-term debt. Ameren Missouri also repaid net commercial paper borrowings totaling $159 million. In addition, Ameren Missouri utilized net proceeds of $306 million from money pool borrowings along with cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2022, Ameren Missouri utilized net proceeds of $524 million from the issuance of long-term indebtednessdebt to repay then-outstanding short-term debt and for capital expenditures. Ameren Missouri also utilized proceeds from net commercial paper issuances to repay $431of $164 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,provided by operating activities to repay $266 million of higher-cost long-term indebtedness. In 2017,fund, in part, capital expenditures. During 2023, Ameren Missouri paid $362common stock dividends of $9 million, compared with $46 million in dividends to Ameren (parent), compared with $355 million dividends paiddividend payments in 2016. Additionally, during 2017, Ameren Missouri received $30 million in capital contributions from Ameren (parent) associated with the tax allocation agreement, compared to $44 million received in 2016.2022.
Ameren Illinois’ cash provided by financing activities increased by $211$66 million in 2017,during 2023, compared with 2016.2022. During 2017,2023, Ameren Illinois utilized net proceeds of $498 million from the issuance of $507long-term debt to repay then-outstanding short-term debt and $100 million of long-term indebtedness anddebt maturities. In addition, Ameren Illinois utilized proceeds from net commercial paper issuances of $102 million, proceeds of $135 million from money pool borrowings, and capital contributions from Ameren (parent) of $91 million along with cash provided by operating activities to fund, in part, capital expenditures. In comparison, in 2022, Ameren Illinois utilized net proceeds of $848 million from the issuance of long-term debt to repay at maturity $250$400 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Illinois issued $291 millionmaturities of long-term indebtednessdebt and net commercial paper issuances and utilized the proceeds to repay at maturity $129 milliona portion of higher-cost long-term indebtedness.then-outstanding short-term debt. Additionally, in 2017, no dividends were paid to Ameren (parent) compared to $110 million paid in 2016.
2016 versus 2015
Ameren’s financing activities associated with continuing operations used net cash of $265 million in 2016, compared with providing net cash of $232 million in 2015. During 2016, Ameren utilized netthe proceeds from the issuance of $646 million of long-term indebtedness anddebt, proceeds from net commercial paper issuances to repay $395of $161 million, capital contributions from Ameren (parent) of higher-cost long-term indebtedness$15 million, and cash provided by operating activities were used to fund, in part, investing activities. In comparison, during 2015, Ameren utilized net proceeds from the issuance of $1,197 million of long-term indebtedness to repay $413 million of net commercial paper issuances, $120 million of higher-cost long-term indebtedness, and to fund, in part, investing activities. No cash from financing activities was used for discontinued operations during 2016.
Ameren Missouri’s cash used in financing activities increased by $109 million in 2016, compared with 2015.capital expenditures. During 2016, Ameren Missouri utilized net proceeds from the issuance of $149 million of long-term indebtedness, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In comparison, during 2015, Ameren Missouri utilized net proceeds from the issuance of $249 million of long-term indebtedness to repay $120 million of higher-cost long-term indebtedness and $97 million of net commercial paper issuances. Additionally, during 2016, Ameren Missouri paid $355 million in dividends to Ameren (parent), compared with $575 million dividends paid in the year-ago period. Also, in 2016, Ameren Missouri received $44 million as a capital contribution from Ameren (parent) compared to $224 million received in 2015.
Ameren Illinois’ cash provided by financing activities decreased by $176 million in 2016, compared with 2015. During 2016, Ameren Illinois issued $291 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. In comparison, during 2015, Ameren Illinois utilized proceeds from the issuance of $248 million of long-term indebtedness to repay $32 million of net commercial paper issuances and to fund, in part, investing activities. Additionally, in 20162023, Ameren Illinois paid $110 million incommon stock dividends to Ameren (parent) compared to no dividends paid in the year-ago period.of $41 million.
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, drawings under committed credit agreements, commercial paper issuances, and/or, proceeds fromin the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings, drawings under the Credit Agreements, or commercial paper issuances.borrowings. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, short-term affiliate borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s money pool arrangements.arrangements and related borrowings, and relevant interest rates.
The following table presents Ameren’s consolidated net available liquidity as of December 31, 2017:2023:
|
| | | | |
| | | Available at December 31, 2017 |
Ameren (parent) and Ameren Missouri (a): | | |
Missouri Credit Agreement – borrowing capacity | | $ | 1,000 |
|
| Less: Ameren (parent) commercial paper outstanding | | 224 |
|
| Less: Ameren Missouri commercial paper outstanding | | 39 |
|
Missouri Credit Agreement – credit available | | 737 |
|
Ameren (parent) and Ameren Illinois(b): | | |
Illinois Credit Agreement – borrowing capacity | | 1,100 |
|
| Less: Ameren (parent) commercial paper outstanding | | 159 |
|
| Less: Ameren Illinois commercial paper outstanding | | 62 |
|
| Less: Letters of credit | | 1 |
|
Illinois Credit Agreement – credit available | | 878 |
|
| Total Credit Available | | $ | 1,615 |
|
| Cash and cash equivalents | | 10 |
|
| Total Liquidity | | $ | 1,625 |
|
| | | | | | | | |
| | Available at December 31, 2023 |
(a) | The maximum aggregate amount available to Ameren (parent) and Ameren Missouri under the (a): | | |
Missouri Credit Agreement is $700 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, borrowing capacity | | $ | 1,400 | |
| | |
| Less: Ameren Missouri commercial paper outstanding | | 170 | |
Less: Letters of this report for further discussion of thecredit | | 2 | |
Missouri Credit Agreements. |
| Agreement – subtotal | | 1,228 | |
(b) | The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the (b): | | |
Illinois Credit Agreement is $500 million– borrowing capacity | | 1,200 | |
| | |
| Less: Ameren Illinois commercial paper outstanding | | 366 | |
| | |
Illinois Credit Agreement – subtotal | | 834 | |
| Subtotal | | $ | 2,062 | |
Cash 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.cash equivalents | | 25 | |
| Net available liquidity | | $ | 2,087 | |
(a) The Credit Agreements provide $2.1 billion of credit cumulatively through maturity in December 2021. The maturity date may be extended for two additional one-year periods upon mutual consent of the borrowers and lenders. Borrowings bymaximum aggregate amount available to both 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 thanunder 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 applicableMissouri Credit Agreement).Agreement is $1 billion.
(b) 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 Illinois under Ameren (parent)’s commercial paper program, subject to available credit capacity under the agreements. The Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. The Illinois Credit Agreement is available to support issuances$700 million and $1 billion, respectively.
The Credit Agreements, among other things, provide $2.6 billion of credit until maturity in December 2027. See Note 4 – Short-term Debt and Liquidity under Ameren Illinois’ commercial paper program. Issuances underPart II, Item 8, of this report for additional information on the Credit Agreements. During the year ended December 31, 2023, Ameren (parent), Ameren Missouri, and Ameren Illinois each issued commercial paper programs were available at lower interest rates than the interest rates of borrowingspaper. Borrowings under the Credit Agreements. CommercialAgreements and commercial paper issuances were thus preferred to credit facility borrowings as a sourceare based upon available interest rates at that time of third-party short-term debt.the borrowing or issuance.
Ameren has a money pool agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option has the lowest interest rates. 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 by the FERC under the Federal Power Act. In June 2017, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2019. In 2016,January 2023, the FERC issued orders authorizing Ameren Missouri, and Ameren Illinois, and ATXI to each issue up to $1 billion, $1 billion, and $300 million, respectively, of short-term debt securities through March 2018 and through September 2018, respectively.January 2025.
The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements for changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or to other short-term borrowing arrangements.arrangements, or other arrangements may be made.
Long-term Debt and Equity
The following table presents ourAmeren’s issuances (net of any issuance premiums or discounts), of long-term debt and equity, as well as redemptions repurchases, and maturities of long-term debt for the years ended December 31, 2017, 2016,2023 and 2015. The Ameren Companies did not issue any common stock or redeem or repurchase any preferred stock during the years ended 2017, 2016, and 2015. In 2017, 2016, and 2015, Ameren Missouri received cash capital contributions as a result of the tax allocation agreement from Ameren (parent). In 2017 and 2015, Ameren Illinois received cash capital contributions from Ameren (parent).2022. For additional information related to the terms and uses of these issuances and effective registration statements, and Ameren’s forward sale agreements relating to common stock, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. For information on capital contributions received by Ameren Missouri and Ameren Illinois from Ameren (parent), see Note 13 – Related-party Transactions under Part II, Item 8, of this report.
| | | | | | | | | | | | | | | | | | | |
| Month Issued, Redeemed, Repurchased, or Matured | | 2023 | | 2022 | | |
| Issuances of Long-term Debt | | | | | | | |
| Ameren: | | | | | | | |
| 5.70% Senior unsecured notes due 2026 | November | | $ | 599 | | | $ | — | | | |
| 5.00% Senior unsecured notes due 2029 | December | | 699 | | | — | | | |
| | | | | | | |
| Ameren Missouri: | | | | | | | |
| 5.45% First mortgage bonds due 2053 | March | | 499 | | | — | | | |
3.90% First mortgage bonds due 2052(a) | April | | — | | | 524 | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Ameren Illinois: | | | | | | | |
| 4.95% First mortgage bonds due 2033 | May | | 498 | | | — | | | |
| 3.85% First mortgage bonds due 2032 | August | | — | | | 499 | | | |
5.90% First mortgage bonds due 2052(a) | November | | — | | | 349 | | | |
| | | | | | | |
| ATXI: | | | | | | | |
| 2.96% Senior unsecured notes Series B due 2052 | August | | — | | | 95 | | | |
| Total Ameren long-term debt issuances | | | $ | 2,295 | | | $ | 1,467 | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Issuances of Common Stock | | | | | | | |
| Ameren: | | | | | | | |
DRPlus and 401(k)(b)(c) | Various | | $ | 47 | | | $ | 41 | | | |
| | | | | | | |
ATM program(d) | Various | | 299 | | | 292 | | | |
Total Ameren common stock issuances(e) | | | $ | 346 | | | $ | 333 | | | |
| | | | | | | |
| Maturities of Long-term Debt | | | | | | | |
| | | | | | | |
| | | | | | | |
| Ameren Missouri: | | | | | | | |
| Audrain County agreement (Audrain County CT) due 2023 | January | | $ | 240 | | | $ | — | | | |
| 1.60% 1992 Series bonds due 2022 | November | | — | | | 47 | | | |
| City of Bowling Green financing obligation (Peno Creek CT) | December | | — | | | 8 | | | |
| Ameren Illinois: | | | | | | | |
| 0.375% First mortgage bonds due 2023 | June | | 100 | | | — | | | |
| 2.70% Senior secured notes due 2022 | September | | — | | | 400 | | | |
| ATXI: | | | | | | | |
| 3.43% Senior unsecured notes due 2050 | August | | — | | | 50 | | | |
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 340 | | | $ | 505 | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
(a) Ameren Missouri and Ameren Illinois intend to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria. |
| | | | | | | | | | | | | |
| | Month Issued, Redeemed, Repurchased, or Matured | | 2017 | | 2016 | | 2015 |
| Issuances of Long-term Debt | | | | | | | |
| Ameren (parent) | | | | | | | |
| 2.70% Senior unsecured notes due 2020 | November | | $ | — |
| | $ | — |
| | $ | 350 |
|
| 3.65% Senior unsecured notes due 2026 | November | | — |
| | — |
| | 350 |
|
| Ameren Missouri: | | | | | | | |
| 3.65% Senior secured notes due 2045 | April | | — |
| | — |
| | 249 |
|
| 3.65% Senior secured notes due 2045 | June | | — |
| | 149 |
| | — |
|
| 2.95% Senior secured notes due 2027 | June | | 399 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | |
| 3.70% First mortgage bonds due 2047 | November | | 496 |
| | — |
| | — |
|
| 4.15% Senior secured notes due 2046 | December | | — |
| | 240 |
| | 248 |
|
| ATXI: | | | | | | | |
| 3.43% Senior notes due 2050 | June | | 150 |
| | — |
| | — |
|
| 3.43% Senior notes due 2050 | August | | 300 |
| | — |
| | — |
|
| Total long-term debt issuances | | | $ | 1,345 |
| | $ | 389 |
| | $ | 1,197 |
|
| Redemptions, Repurchases, and Maturities of Long-term Debt | | | | | | | |
| Ameren Missouri: | | | | | | | |
| 5.40% Senior secured notes due 2016 | February | | — |
| | 260 |
| | — |
|
| 4.75% Senior secured notes due 2015 | April | | — |
| | — |
| | 114 |
|
| 6.40% Senior secured notes due 2017 | June | | 425 |
| | — |
| — | — |
|
| City of Bowling Green capital lease (Peno Creek CT) | December | | 6 |
| | 6 |
| | 6 |
|
| Ameren Illinois: | | | | | | | |
| 6.20% Senior secured notes due 2016 | June | | — |
| | 54 |
| | — |
|
| 6.25% Senior secured notes due 2016 | June | | — |
| | 75 |
| | — |
|
| 6.125% Senior secured notes due 2017 | November | | 250 |
| | — |
| | — |
|
| Total long-term debt redemptions, repurchases, and maturities | | | $ | 681 |
| | $ | 395 |
| | $ | 120 |
|
(c) Excludes a $7 million and $8 million receivable at December 31, 2023 and 2022, respectively.
(d) Ameren issued 3.2 million and 3.4 million shares of common stock under the ATM program in 2023 and 2022, respectively.
(e) Excludes 0.5 million and 0.4 million shares of common stock valued at $40 million and $31 million issued for no cash consideration in connection with stock-based compensation in 2023 and 2022, respectively.
In June 2017,January 2024, Ameren Missouri issued $400$350 million of 2.95% senior secured notes5.25% first mortgage bonds due June 2027,January 2054, with interest payable semiannually on JuneJanuary 15 and DecemberJuly 15 of each year, beginning DecemberJuly 15, 2017. Ameren Missouri received2024. Net proceeds of $396 million, whichfrom this issuance were used in conjunction with other available funds,for capital expenditures and to repay at maturity $425 million of Ameren Missouri’s 6.40% senior secured notes in June 2017.
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 owed to Ameren (parent).
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.
In December 2017, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement 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, which expires in May 2020, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions.debt.
The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Indebtedness Provisions and Other Covenants
At December 31, 2017,2023, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.agreements. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings
under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreement.agreements.
We consider access to short-term and long-term capital and credit markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital and credit markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets.and credit markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital and credit markets or make access to the capital and credit markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital and credit markets.
Dividends
Ameren paid to its shareholders common stock dividends totaling $431$662 million, or $1.778$2.52 per share, in 2017, $4162023 and $610 million, or $1.715$2.36 per share, in 2016, and $402 million, or $1.655 per share, in 2015.
2022. The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70%65% of earnings over the next few years. On February 9, 2018,2024, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 45.7567 cents per share, payable on March 29, 2018,2024, to shareholders of record on March 14, 2018.13, 2024.
Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances.
Ameren Illinois’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions with respect to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in itsthe 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 itstheir respective stock unless, among other things, itstheir respective earnings and earned surplus are sufficient to declare and pay a dividend after provision isprovisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.
At December 31, 2017,2023, the amount of restricted net assets of Ameren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $2.3$4.6 billion.
The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren Missouri and Ameren Illinoissubsidiaries to their parent, Ameren:
| | | | 2017 | | 2016 | | 2015 |
| 2023 | |
| 2023 | |
| 2023 | |
| Ameren | |
| Ameren | |
| Ameren | $ | 431 |
| | $ | 416 |
| | $ | 402 |
|
| Ameren Missouri | 362 |
| | 355 |
| | 575 |
|
| Ameren Missouri | |
| Ameren Missouri | |
| Ameren Illinois | — |
| | 110 |
| | — |
|
| Ameren Illinois | |
| Ameren Illinois | |
| ATXI | |
| ATXI | |
| ATXI | |
Ameren Missouri and Ameren Illinois each have issued preferred stock, which providesprovide for cumulative preferred stock dividends. Each company’s board of directors considers the declaration of the preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.
65
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2017. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included. |
| | | | | | | | | | | | | | | | | | | |
| | Less Than 1 Year | | 1 – 3 Years | | 3 – 5 Years | | After 5 Years | | Total |
Ameren:(a) | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 841 |
| | $ | 1,023 |
| | $ | 514 |
| | $ | 5,617 |
| | $ | 7,995 |
|
Interest payments(c) | 464 |
| | 855 |
| | 814 |
| | 5,018 |
| | 7,151 |
|
| Operating leases | 10 |
| | 17 |
| | 12 |
| | 14 |
| | 53 |
|
Other obligations(d) | 981 |
| | 964 |
| | 206 |
| | 254 |
| | 2,405 |
|
| Total cash contractual obligations | $ | 2,296 |
| | $ | 2,859 |
| | $ | 1,546 |
| | $ | 10,903 |
| | $ | 17,604 |
|
| Ameren Missouri: | | | | | | | | | |
Long-term debt and capital lease obligations(b) | $ | 384 |
| | $ | 673 |
| | $ | 64 |
| | $ | 2,867 |
| | $ | 3,988 |
|
Interest payments(c) | 331 |
| | 592 |
| | 575 |
| | 3,208 |
| | 4,706 |
|
| Operating leases | 8 |
| | 15 |
| | 12 |
| | 14 |
| | 49 |
|
Other obligations(d) | 628 |
| | 654 |
| | 163 |
| | 194 |
| | 1,639 |
|
| Total cash contractual obligations | $ | 1,351 |
| | $ | 1,934 |
| | $ | 814 |
| | $ | 6,283 |
| | $ | 10,382 |
|
| Ameren Illinois: | | | | | | | | | |
Long-term debt(b) | $ | 457 |
| | $ | — |
| | $ | 400 |
| | $ | 2,000 |
| | $ | 2,857 |
|
Interest payments(c) | 106 |
| | 188 |
| | 185 |
| | 1,584 |
| | 2,063 |
|
| Operating leases | 1 |
| | — |
| | — |
| | 1 |
| | 2 |
|
Other obligations(d) | 352 |
| | 310 |
| | 43 |
| | 40 |
| | 745 |
|
| Total cash contractual obligations | $ | 916 |
| | $ | 498 |
| | $ | 628 |
| | $ | 3,625 |
| | $ | 5,667 |
|
| |
(a) | Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations. |
| |
(b) | Excludes unamortized discount and premium and debt issuance costs of $60 million, $27 million, and $27 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, 2017.
|
| |
(d) | See Other Obligations in Note 14 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein. |
AsOff-Balance-Sheet Arrangements
At December 31, 2017, 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, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries.
Credit Ratings
Our credit ratings affect our liquidity, our access to the capital and credit markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.
The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:
| | | | | | | | |
| Moody’s | S&P |
| Ameren: | | |
| 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+ |
SecuredSenior debt | A2 | A |
| Senior unsecured debt | Baa1 | BBB+Not Rated |
| Commercial paper | P-2 | A-2 |
| Ameren Illinois: | | |
| Issuer/corporate credit rating | A3 | BBB+ |
SecuredSenior debt | A1 | A |
| Senior unsecured debt | A3 | BBB+ |
| Commercial paper | P-2 | A-2 |
| ATXI: | | |
| Issuer credit rating | A2 | Not Rated |
| Senior unsecured debt | A2 | Not Rated |
A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
Collateral Postings
Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, were immaterial, and cash collateral posted by external parties were immaterial$53 million for Ameren and Ameren Illinois at December 31, 2017.2023. A sub-investment-grade issuer or senior unsecured debt rating (whether(below “Baa3” from Moody’s or below “BBB-” from S&P or below “Baa3” from Moody’s)&P) at December 31, 2017,2023, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade and contractual obligations amounting to $82$685 million, $44$604 million, and $38$81 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2017,2023, if market prices were 15% higher or lower than December 31, 2017,2023 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade and contractual obligations.
OUTLOOKEnvironmental Matters
We seek to earn competitive returns on investments in our businesses. We seek to improve our regulatory frameworksOur electric generation, transmission, 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 and 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 customer energy needs and to improve electricdistribution and natural gas system reliability,distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety, including permitting programs implemented by federal, state, and security withinlocal authorities. Such environmental laws address air emissions; discharges to water bodies; the storage, handling and disposal of hazardous substances and waste materials; siting and land use requirements; and potential ecological impacts. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws, including those that relate to climate change, that affect, or may affect, our service territories.facilities, operations, and capital expenditures to comply with such laws. The individual or combined effects of compliance with existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers.
Additionally, international agreements could lead to future federal or state legislation or regulations. In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris
Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius. The Biden administration made a policy commitment regarding a reduction in greenhouse gas emissions for the United States, but rulemaking to achieve such reductions has not yet been implemented. Actions taken to implement the Paris Agreement could result in future additional greenhouse gas reduction requirements in the United States. In addition, the EPA has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions from the utility industry.
We provide information regarding our sustainability initiatives through our website, including in our annual sustainability report, our responses to the annual climate change and water surveys conducted by CDP, and a sustainability investor presentation. In addition, we issue an annual report in accordance with the Edison Electric Institute’s (EEI) and American Gas Association’s (AGA) ESG and sustainability-related reporting program. We also evaluates competitive electric transmission investment opportunities as they arise.issue a periodic climate risk report and a report on our management of CCR. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition towe have posted a more diverse energy generation portfolio.Task Force on Climate-related Financial Disclosures (TCFD) and Sustainability Accounting Standards Board (SASB) mapping of sustainability data. The reports may be updated at any time. The information on Ameren’s website, including the reports and documents mentioned in this paragraph, is not incorporated by reference into this report.
OUTLOOK
Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 20182024 and beyond.
Operations
Ameren continues to invest in FERC-regulated electric transmission. ATXI has three MISO-approved multi-value projects, the Illinois Rivers, Spoon River, For additional information regarding recent rate orders, lawsuits, and Mark Twain projects. The Illinois Rivers project involves the construction of a transmission line from eastern
Missouri across Illinois to western Indiana. Construction activities for the Illinois Rivers project are continuing on schedule,pending requests filed with state and the last section of this project is expected to be completed by the end of 2019. The Spoon River project, located in northwest Illinois, was placed in service in February 2018. The Mark Twain project, located in northeast Missouri and connecting the Illinois Rivers project to Iowa, is expected to be completed by the end of 2019. Seefederal regulatory commissions, including those discussed below, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this reportreport.
Operations
•We are observing inflationary pressures on the prices of labor, services, materials, and supplies, as well as high interest rates. Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for information regardingfuel, purchased power, and natural gas supply. Additionally, for certain non-commodity cost changes, the Mark Twain projectuse of trackers, riders, formula ratemaking, and future test years, as applicable, mitigates our exposure. The inflationary pressures and high interest rates could impact our ability to control costs and/or make substantial investments in our businesses, including our ability to recover costs and investments, and to earn our allowed ROEs within frameworks established by our regulators, while maintaining rates that are affordable to our customers. In addition, these inflationary pressures and high interest rates could adversely affect our customers’ usage of, or payment for, our services.
•The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense for investments in qualifying property, plant, and equipment placed in service and not included in base rates. Investments not eligible for recovery under the PISA include amounts related to new nuclear and natural gas generating units and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC until added to rate base prospectively. Ameren Missouri recognizes an offset to “Interest Charges” on its consolidated statement of income for its carrying cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its approval processcarrying cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service to comply with Missouri’s renewable energy standard. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the Illinois Rivers project.RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through 2028 and an additional extension through 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things.
•In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023. As a result of this order, Ameren Missouri expects a year-over-year increase to 2024 earnings, compared to 2023, of approximately $22 million ($11 million, $8 million, and $3 million expected in the first, second, and third quarter, respectively).
•In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency and demand response programs through December 31, 2017, ATXI’s expected remaining investment2024. Ameren Missouri intends to invest approximately $420 million over the life of the plan, including $76 million in all three projects2024. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn revenues by achieving certain customer energy-efficiency goals. If the target program spending goal is approximately $300achieved for 2024, the performance incentive would result in revenues of $12 million in 2024.
•In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the total investmentMoPSC under the MEEIA. This filing proposed a three-year plan, which includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider discussed above. If the plan is approved, Ameren Missouri intends to be more than $1.6 billion.invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren IllinoisMissouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects to invest $2.3 billion in electric transmission assets from 2018 through 2022 to replace aging infrastructure and improve reliability.a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.
•Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base growth and the currently allowed 10.82% return on common equity,10.52% ROE, which includes a 50-basis-point incentive adder for participation in an RTO, the 2018 revenue requirements that will be included in 2024 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $270$549 million and $174$223 million, respectively. These revenue requirements represent an increaseincreases in Ameren Illinois'Illinois’ and ATXI'sATXI’s revenue requirements of $11$73 million and $4$29 million, respectively, from the revenue requirements reflected in 2023 rates, primarily becausedue to higher expected rate base. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2024, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2024 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the FERC formula ratemaking framework.
•The allowed base ROE for FERC-regulated transmission rates previously charged under the MISO tariff has been the subject of pending proceedings since 2013. Depending on the outcome of the rate base growth described above, partially offsetproceedings, the transmission rates charged during previous periods and the currently effective rates may be subject to change and refund. In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which increased the incentive ROE for participation in an RTO to 100 basis points from the current 50 basis points and revised the parameters for awarding incentives, while limiting the overall incentives to a cap of 250 basis points, among other things. In April 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking, which proposed to modify the Notice of Proposed Rulemaking’s incentive for participation in an RTO by limiting this incentive for utilities that join an RTO to 50 basis points and only allowing them to earn the incentive for three years, among other things. If this proposal is included in a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA.
The return on common equity for MISO transmission owners, includingfinal rule, Ameren Illinois and ATXI waswould no longer be eligible for the subject of a FERC complaint case filed in February 2015 which challenged the allowed base return on common equity. Ameren Illinois and ATXI currently use the FERC authorized total allowed return on common equity of 10.82% in customer rates. A final FERC order would establish the allowed return on common equity to be applied 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. The timing and amount of any adjustment to the total allowed return on common equity that may be ordered as a result of the complaint case is uncertain. A 50 basis point reductionRTO incentive adder, prospectively. The FERC is under no deadline to issue a final rule on this matter. Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy, or any further order on base ROE. A 50-basis-point change in the FERC-allowed base return on common equityROE would reduceaffect Ameren’s and Ameren Illinois’ annual earningsnet income by an estimated $8$16 million and $4$11 million, respectively, based on each company’s 20182024 projected rate base. See Note 2 – Rate
•Pursuant to December 2022 and Regulatory Matters under Part II, Item 8, of this report for information regarding FERC complaint cases.
In March 2017,2021 ICC orders, Ameren Illinois used the MoPSC issued an order approving a unanimous stipulationIEIMA formula framework to establish annual electric distribution service rates effective through 2023, and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annualwill reconcile the related revenue requirement for electric service, compared with the prior revenue requirementcustomer rates established in the MoPSC’s April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decreased by $54 million from the base level established in the MoPSC’s April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC’s April 2015 electric rate order.
In December 2017, the ICC issued an order in2023. As such, Ameren Illinois’ annual update filing that approved a $17 million decrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2018. However, Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and investment return in a given year with the revenue requirement that was2023 revenues reflected in customer rates for that year. Consequently, Ameren Illinois’ 2018 electric distribution service revenues will be based on its 2018 actual recoverable costs, year-end rate base, and a return at the applicable WACC, with the ROE component based on common equity as calculated under the Illinois performance-based formula ratemaking framework. The 2018 revenue requirement is expected to be comparable toannual average of the 2017 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of approximately 5%, and an expected increase in the monthly average yield of 30-year United States Treasury bonds, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA. The 2018 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2020. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $8 million change in Ameren’s andplus 580 basis points. By law, the decoupling provisions extend beyond 2023, which ensures that Ameren Illinois’ net income,electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of $110 million. The approved reconciliation adjustment will be collected from customers in 2024. In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base. The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.
•Pursuant to the CEJA, which was enacted in September 2021, Ameren Illinois may file an MYRP with the ICC to establish base rates for electric distribution service to be charged to customers for each calendar year of a four-year period. The base rates for a particular calendar year are based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ 2018 projected year-endforecasted average annual rate base.
base using a forecasted capital structure, with a common equity ratio of up to 50% being deemed prudent and reasonable by law and a higher equity ratio requiring specific ICC approval. The FEJAROE determined by the ICC for each calendar year of the four-year period is subject to annual adjustments based on certain performance incentives and penalties. An MYRP allows Ameren Illinois to earn
reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to a return onreconciliation cap and adjustments to the ROE. If a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the applicable annual period. Ameren Illinois’ existing riders will remain effective under the MYRP discussed below, and will continue to remain effective beyond 2027 whether it elects to file an MYRP or a traditional regulatory rate review. Additionally, electric distribution service revenues continue to be decoupled from sales volumes under either election.
•In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,162 million, $1,210 million, $1,242 million, and $1,255 million, respectively. These revenue requirements were established under an alternative methodology which used Ameren Illinois’ previously approved 2022 year-end rate base since the order rejected the Grid Plan that was filed by Ameren Illinois as a part of the MYRP proceeding. The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The 2022 year-end rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement. The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its electric energy-efficiency program investments.revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase. In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements of $1,214 million, $1,300 million, $1,371 million, and $1,420 million, for 2024, 2025, 2026, and 2027, respectively. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District. Ameren Illinois intends to take prudent steps to align its 2024 operations with the ICC order, while continuing to ensure safe and adequate service is maintained. This will include significant reductions to Ameren Illinois’ capital expenditure and operations and maintenance expense plans.
•Pursuant to Illinois law, Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the company’s weighted-average cost of capital,applicable WACC, with the equity returnROE component based on the annual average of the monthly average yieldyields 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 While the FEJA,ICC has approved a plan for Ameren Illinois plans to invest up to $99approximately $120 million per year in electric energy-efficiency programs from 2018 through 2021 that will earn a return.Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The2025, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future program years if there are insufficient cost-effective programs available, 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 will beare collected from customers through a rider; they will not be includedrider.
•In November 2023, the ICC issued an order in the IEIMA formula ratemaking framework. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ approved energy-efficiency program for 2018 through 2021.
In January 2018, Ameren Illinois filed a request with the ICC seeking approval2023 natural gas delivery service regulatory rate review, which resulted in an increase to increase its annual revenues for natural gas delivery service by $49of $112 million. The new rates became effective on November 28, 2023. In December 2023, Ameren Illinois filed a request for rehearing with the ICC to revise the approved ROE and capital structure common equity percentage, and reverse an approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request. Subsequently, in January 2024, Ameren Illinois filed an appeal of the November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal.
•The ICC’s November 2023 natural gas delivery service rate order also required Ameren Illinois to submit a plan outlining how it expects to comply with new PHMSA rules for natural gas transmission pipelines, including proposing a capital expenditures plan necessary to meet the new rules. In February 2024, Ameren Illinois filed its plan with the ICC, which included its proposal of natural gas transmission capital expenditures necessary to achieve compliance with the PHMSA rules. The plan includes delays to certain natural gas
transmission capital expenditures from 2024 to subsequent years to align with the November 2023 ICC order. The ICC is under no obligation to issue an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider. The request was based on a 10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for informationorder regarding Ameren Illinois’ Natural Gas Delivery Service Regulatory Rate Review.
plan.•The November 2023 order also directed the ICC staff to develop a plan for a future of gas proceeding. All of the Illinois natural gas utilities subject to ICC regulation will be included in this proceeding, which will explore issues involved with decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA. Some of the issues expected to be addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others.
•Ameren Missouri’s next scheduled refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2019. During the 2017 refueling, Ameren Missouri incurred maintenance expenses of $35 million.2025. During a scheduled outage,refueling, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally,are deferred as a regulatory asset and amortized until the completion of the next refueling and maintenance outage. During an outage, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri may incur increased nonnuclearnon-nuclear energy center maintenance costs in non-outage years.
•In September 2023, the United States District Court for the Eastern District of Missouri granted Ameren Missouri’s request to modify a September 2019 remedy order issued by the district court in order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri expect an approximately $15 million decrease in annual interest chargesto operate the energy center as directed by the MISO. The MISO designated the energy center as a resultsystem support resource in 2022 and concluded that certain reliability mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation through August 2024, and in September 2023, an agreement between Ameren Missouri and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the repaymentupgrades expected to be completed in the fall of $425 million of Ameren Missouri’s 6.40% senior secured notes at maturity and issuance of $400 million 2.95% senior secured notes in 2017. In 2018,2024. Ameren Missouri expects to refinance maturing long-term debt with lower-cost long-term debt, which would further reduce Ameren’s and Ameren Missouri’s annual interest charges.
| |
• | As we continue to make infrastructure investments and to experience cost increases, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. 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, and increased customer use of increasingly cost-effective technological advances, including private generation and storage. However, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy 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, result in rate base earnings growth but also higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property taxes, and higher state income taxes, among other costs.
|
complete the last of the upgrades by mid-2025. For additional information regarding recent rate orders, lawsuits,on the NSR and pending requests filed with state and federal regulatory commissions,Clean Air Act litigation, see Note 214 – RateCommitments and Regulatory MattersContingencies under Part II, Item 8, of this report. As part of the assessment of any potential future abandonment loss, consideration will be given to rate and securitization orders issued by the MoPSC to Ameren Missouri and to orders issued to other Missouri utilities with similar facts. See below for information regarding Ameren Missouri’s petition filed with the MoPSC requesting the securitization of costs associated with the planned accelerated retirement of the Rush Island Energy Center.
•Pursuant to Illinois law, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the CEJA, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service.
•Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek increases to electric and natural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, regulatory and legislative solutions to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, increasing inflation, higher cost of debt, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective advancements in innovative energy technologies, including private generation and energy storage. However, we expect the decreased demand to be offset by increased demand resulting from increased electrification of the economy, including in the transportation sector, and as a means to address economy-wide CO2 emission concerns. We expect that increased investments, including expected future investments for environmental compliance, system reliability improvements, and new generation sources, will result in rate base and revenue growth but also higher depreciation and financing costs.
Liquidity and Capital Resources
•In September 2017,2023, Ameren Missouri filed its nonbinding 20-year integrated resource plan2023 IRP with the MoPSC. This planMoPSC, which includes Ameren Missouri’s preferred approachplan for meeting customers’ projected long-term energy needs in a manner that maintains system reliability and customer affordability while transitioning to clean energy generation in an environmentally responsible manner. In connection with this plan, Ameren is continuing to target net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels. Ameren’s
goals include both direct emissions from operations (scope 1), as well as electricity usage at Ameren buildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. Achieving these goals will be dependent on a variety of factors, including cost-effective manner while maintainingadvancements in innovative clean energy technologies and constructive federal and state energy and economic policies. The preferred plan includes, among other things, the following:
•adding an 800-MW natural gas-fired simple-cycle energy center by 2027 and an additional 1,200-MW natural gas-fired combined-cycle energy center by 2033;
•adding 2,800 MWs of renewable generation by 2030, which includes the solar generation facilities discussed below, and an additional 1,900 MWs by 2036;
•adding 400 MWs of battery storage by 2030 and an additional 400 MWs by 2035;
•adding 1,200 MWs of other clean dispatchable generation resources by 2040 and an additional 1,200 MWs by 2043;
•retiring all of Ameren Missouri’s coal-fired energy centers by 2042;
•accelerating the retirement date of the Rush Island coal-fired energy center from 2025 to 2024;
•extending the retirement date of the Sioux coal-fired energy center from 2030 to 2032 to ensure reliability during the transition to clean energy generation, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC;
•retiring 1,800 MWs of Ameren Missouri’s natural gas-fired energy centers by 2040 to comply with Illinois law;
•the continued implementation of customer energy-efficiency and demand response programs; and
•the expectation that Ameren Missouri will seek and receive NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date.
Expected capital expenditures through 2028 related to the facilities discussed above are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below. Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources or natural gas-fired generation, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability to enter into agreements for renewable or natural gas-fired generation and acquire or construct that generation at a reasonable cost; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment, geopolitical conflict, or government actions, among other things; changes in the scope and timing of projects; the ability to qualify for, and use or transfer, federal production or investment tax credits; the cost of wind, solar, and other renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to maintain system reliability.reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; energy prices and demand; Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion; the ability to earn an adequate return on invested capital; and the ability to raise capital on reasonable terms. The next integrated resource plan is expected to be filed in September 2026.
•Pursuant to Missouri law, in November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.
•During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities, with various regulatory approvals pending. All of the solar generation facilities are aligned with the 2023 IRP discussed above, and expected capital expenditures related to these facilities are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below.
•Ameren Missouri's 2023 IRP targets cleaner and more diverse sources of energy generation, including solar wind, natural gas, hydro,generation. While rights to acquire build-transfer solar facilities and nuclear power. It also includes expanding renewable sourcessupplies for development-transfer and self-build solar facilities discussed above were secured through agreements, supply chain disruptions, including solar panel shortages and increasing material costs as a result of government tariffs and other factors, could affect the costs, as well as the timing, of these projects and other solar generation projects. The supply of
solar panel components to the United States was significantly disrupted as a result of an investigation conducted by adding at least 700 megawattsthe United States Department of wind generation by 2020Commerce that concluded in MissouriAugust 2023 and neighboring states,found that exporters and adding 100 megawattsproducers of solar generation over the next 10 years. The new wind generation facilities are expected to be located in Missouri and neighboring states. The source, location, and costpanel components from four Southeast Asian countries, with several exceptions, have been circumventing tariffs imposed on imports from China. As a result of the new wind generation, among other items, remaininvestigation, importers and exporters may submit certain certifications to the United States Department of Commerce to avoid the imposition of increased tariffs. Failure to submit the applicable certifications, or denial of the submitted certifications by the United States Department of Commerce, could result in increased tariffs on solar panel components that were subject to reaching agreements with developers. Basedthe investigation and entered the United States on currentor after April 1, 2022. Additionally, certain solar panel components from China have been subject to detention by the United States Customs and projected market pricesBorder Protection Agency as a result of the Uyghur Forced Labor Prevention Act that became effective in June 2022. Also, in June 2022, President Biden took executive action to temporarily lift certain tariffs on solar panel components imported from the four Southeast Asian countries investigated by the United States Department of Commerce for energy,24 months in order to allow the United States access to a sufficient supply of solar panel components. Any future tariffs or actions by the United States Customs and for windBorder Protection Agency could affect the cost and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost option for customers. The plan also provides for the expected implementation of continued customer energy-efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be affected by, among other factors: the availability of federal productionsolar panel components and investment tax credits related to renewable energythe timing and amount of Ameren Missouri’s ability to use such credits; the cost of wind andMissouri's estimated capital expenditures associated with solar generation technologies, as well as energy prices; Ameren Missouri’s ability to obtain timely interconnection agreements with MISO or other RTOs, including the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC for projects located in Missouri, and any other required project approvals.
| |
• | In connection with the integrated resource plan filing, discussed above, Ameren Missouri established a goal of reducing CO2 emissions 80% by 2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of its useful life.
|
investments.
•Through 2022,2028, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest up to $11.4$22.8 billion (Ameren Missouri – up to $4.5$13.5 billion; Ameren Illinois – up to $6.6$7.6 billion; ATXI – up to $0.3$1.7 billion) of capital expenditures during the period from 20182024 through 2022. These estimates do not reflect the potential additional investments identified in2028. Ameren’s and Ameren Missouri’s integrated resource planestimates include $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments through 2028, consistent with Ameren Missouri’s 2023 IRP. Ameren’s and Ameren Illinois’ estimates include investments necessary to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained. Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.
•In 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade. In October 2023, the FERC issued an order that approved transmission rate incentives relating to the projects assigned to Ameren. The incentives will allow construction work in progress to be included in rate base for projects constructed by ATXI, thereby improving the timeliness of cash recovery, and would allow recovery of prudently incurred costs, subject to FERC approval, for any portion of the projects if they are abandoned for reasons beyond the control of Ameren. As a result of the order, ATXI will not capitalize allowance for funds used during construction on the related projects. In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects. In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion. The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024. In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed above, that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025. In November 2022, the MISO released plans for a second tranche of projects and began the process of identifying a list of projects for consideration under this tranche. Ameren expects the second tranche of projects to be approved in the first half of 2024. In July 2022, a group of industrial customers filed a complaint with the FERC, challenging provisions of a MISO tariff that exclude regional transmission projects from the MISO’s competitive bid process based on state laws related to the right of first refusal, which provide an incumbent utility the right to build, maintain, and own transmission lines located within its service territory. The complaint seeks to require MISO to revise its tariff to prohibit the application of state laws related to the right of first refusal in the MISO’s long-range transmission planning and require projects to be bid on a competitive basis, to the maximum extent possible. It also is asking for refunds related to any costs under the tariff that would not comply with the sought-after revisions. The FERC is under no deadline to issue an order in this proceeding.
•In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from the MISO’s April 2022 capacity auction, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study of continued participation in the MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a period of five to 10 years beginning June 2024. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study.
•Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA or state regulators, or requirements that may result from the NSR and Clean Air Act Litigation, could represent incremental investmentsresult in significant increases in capital expenditures and operating costs. Regulations can be reviewed and repealed, and replacement or alternative regulations can be proposed or adopted by the current federal administration, including the EPA. See Note 14 – Commitments and Contingencies under Part II, Item 8, of approximately $1 billion through 2020this report, for additional information on environmental matters, including the NSR and Clean Air Act litigation. The ultimate implementation of any of these new regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal and natural gas-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances, as well as regulatory approval. They also do not reflect potential additionallag. 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 that Ameren Missouri could make if improvementsare reflected and recovered on a timely basis in its regulatory frameworks were made.customer rates.
| |
• | 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 or are being reviewed by the EPA, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing 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.
|
•The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1$2.6 billion of credit through December 2021,2027, subject to a 364-day repayment term in the case offor Ameren Missouri and Ameren Illinois.Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $3.2 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. BySee Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for outstanding forward sale agreements under the endATM, long-term debt issuances through the date of 2019, $951 millionthis report, and $457 millionmaturities of senior secured notes are scheduledlong-term debt from 2024 to mature2028 and beyond at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI. The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments at the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2023, for Ameren, Ameren Missouri, and Ameren Illinois. Ameren, Ameren Missouri, and Ameren Illinois respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. Ameren, Ameren Missouri, and Ameren Illinoiseach believe that their liquidity is adequate given their respective expected operating cash flows, capital expenditures, and related financing plans.plans, and expect to continue to have access to the capital and credit markets on reasonable terms when needed. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
Federal income tax legislation enacted under the TCJA will have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA will benefit customers through lower rates for our services but is not expected to materially affect our earnings. However, our cash flows and rate base are expected to be materially affected in the near term. Our rate-regulated businesses recover income taxes in customer rates based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds from our customers for income taxes and when we pay such taxes. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. 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 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers.Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion).
As of December 31, 2017, Ameren had $235 million in tax benefits from federal and state net operating loss carryforwards and $120 million in federal and state income tax credit carryforwards. These carryforwards are expected to partially offset income tax obligations until 2021, at which time Ameren expects to begin making material income tax payments. Consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries, Ameren Missouri and Ameren Illinois expect to begin making material income tax payments to Ameren (parent) beginning in 2018.
•Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its funding plan to fund these cash requirements, beginning in the first quarter of 2018,for capital expenditures, Ameren will useis using newly issued shares rather than market-purchased shares,of common stock to satisfy requirements under itsthe DRPlus and employee benefit plans and expects to continue to do so over the next five years.through at least 2028. Additionally, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sale agreements, subject to market conditions and other factors. As of December 31, 2023, Ameren had multiple forward sale agreements that could be requiredsettled under the ATM program with various counterparties relating to 2.9 million shares of common stock. Ameren expects to settle approximately $230 million of the forward sale agreements with physical delivery of 2.9 million shares of common stock by December 31, 2024. Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue incremental debt and/orapproximately $300 million of equity with in 2024 and approximately $600 million of equity each year from 2025 to 2028. As of December 31, 2023, Ameren had approximately $770 million of common stock available for sale under the long-
term intentATM program, which takes into account the forward sale agreements in effect as of December 31, 2023. Ameren expects its equity to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.total capitalization to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flowsflow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent),.
•The IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates clean energy tax credits for projects placed in service after 2024. The clean energy tax credits will apply to renewable energy production and investments, along with certain nuclear energy production, and will be phased out beginning in 2033, at the earliest. The phase-out is triggered when greenhouse gas emissions from the electric generation industry are reduced by at least 75% from the annual 2022 emission rate or at the beginning of 2033, whichever is later. The law allows for transferability to an unrelated party for cash of up to 100% of certain tax credits generated after 2022. In addition, the new law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the intentIRA have been and are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren as discussed below.
•Pursuant to the IRA discussed above, Ameren expects to transfer production tax credits generated by Ameren Missouri’s High Prairie Renewable and Atchison Renewable energy centers, as well as the solar facilities included in Ameren Missouri’s 2023 IRP discussed above, to unrelated parties from 2024 to 2028.
•In April 2023, the IRS issued guidance providing a safe harbor method of accounting for the capitalization or deduction of certain expenditures to maintain, strongrepair, replace, or improve natural gas distribution property. The safe harbor method of accounting may be implemented in the first, second, or third taxable year ending after May 1, 2023. Ameren is currently evaluating the potential impact of this guidance, including the timing of adoption.
•As of December 31, 2023, Ameren had $176 million in tax benefits from federal and state income tax credit carryforwards and $42 million in tax benefits from state net operating loss carryforwards, which will be utilized in future periods. Future expected income tax payments are based on expected taxable income, available income tax credit and net operating loss carryforwards, and current tax law. Expected taxable income is affected by expected capital expenditures, when property, plant, and equipment is placed in-service or retired, and the timing of regulatory reviews, among other things. Based on preliminary calculations, Ameren does not expect to be subject to the 15% minimum tax on adjusted financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.statement income imposed by the IRA through 2028. Ameren expects annual federal income tax payments to be immaterial through 2028.
The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are the most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.
|
| | | | | | | |
| Accounting Estimate | | Uncertainties Affecting Application |
| Regulatory Mechanisms and Cost Recovery | | |
| We defer costs and recognize revenues that we intend to collect in future rates. | | •Regulatory environment and external regulatory decisions and requirements •Anticipated future regulatory decisions and our assessment of their impact •The impact of prudence reviews, complaint cases, limitations on electric rate increases in Missouri and Illinois, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments •Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under the MYRP process, effective in 2024, which includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap •Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks •Ameren Missouri’s estimate of revenue recovery under the MEEIA plans |
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, 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 delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA 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
Any adjustments related to the TCJA
Basis for Judgment
The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, enacted legislation, or historical experience, as well as discussions with legal counsel. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers. We also recognize revenues for alternative revenue programs authorized by our regulators that allow for an automatic rate adjustment, are probable of recovery or refund, and are collected or refunded within 24 months following the end of the annual period in which they are recognized. Under the MYRP, Ameren Illinois' base rates for a particular calendar year are based on the forecasts of recoverable costs, average annual rate base, and capital structure. An ICC-determined ROE is applied to determine the base rates for a particular calendar year. Ameren Illinois estimateswill reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement pursuant toapproved by the IEIMA for interim periods by using internal forecasted rate base, and published forecasted data regarding that year’s monthly average 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.ICC. Variations in investments made or orders by the ICC can result in a subsequent change in Ameren Illinois’ resulting estimated regulatory assets or liabilities. Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated annually and become effective each January with forecasted information. The formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed ROE. Variations in investments made or orders by the FERC or courts can result in a subsequent change in Ameren Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses.ATXI’s estimated regulatory assets or liabilities. Ameren Missouri estimates lost revenueselectric 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. The Ameren Companies made provisional estimates to deferred tax balances as a result of the TCJA. The revaluation of certain deferred taxes was deferred as a regulatory asset or liability on the balance sheet and will be collected from or refunded to customers as determined by our regulators. These estimates are subject to change, as discussed in the Accounting for Income Taxes section below.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
The following table reflects the gain and other comprehensive income, which would be offset by the removal of regulatory mechanisms used by Ameren Missouriassets and Ameren Illinois.liabilities and an increase in accumulated other comprehensive income, that would have resulted if accounting guidance for rate-regulated businesses had been eliminated as of December 31, 2023:
Benefit Plan Accounting | | | | | | | | | | | | | | | | | | |
| Ameren | | Ameren
Missouri | | | Ameren
Illinois |
| Gains | $ | 3,078 | | | $ | 1,916 | | | | $ | 1,058 | |
| Other comprehensive income (before taxes) - pension and other postretirement benefit plan activity | 346 | | | 202 | | | | 144 | |
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.
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
| | | | | | | | |
| Accounting Estimate | | Uncertainties Affecting Application |
| Benefit Plan Accounting | | |
| Based on actuarial calculations, we accrue costs of providing future employee benefits for the benefit plans we offer our employees. See Note 10 – Retirement Benefits under Part II, Item 8, of this report. | | •Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable •Discount rate •Cash balance plan interest crediting rate on certain plans •Future compensation increase •Health care cost trend rates •The timing of employee retirements, terminations, benefit payments, and mortality •Ability to recover certain benefit plan costs from our customers •Changing market conditions that may affect investment and interest rate environments •Future rate of return on pension and other plan assets |
Basis for Judgment
Ameren has defined benefit pension 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, future compensation, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies, andincluding 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 following table reflects the sensitivity of Ameren’s benefitpension and postretirement plans to potential changes in these assumptions.key assumptions for the year ended December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Postretirement Benefits |
| Net Periodic
Benefit Cost | | | Projected Pension Benefit Obligation | | Net Periodic
Benefit Cost | | | | Projected Postretirement Benefit
Obligation |
| 0.25% decrease in discount rate | $ | 12 | | | | $ | 121 | | | $ | 2 | | | | | $ | 23 | |
| 0.25% decrease in return on assets | 12 | | | | (a) | | 4 | | | | | (a) |
| 0.25% increase in future compensation | 3 | | | | 11 | | | (a) | | | | (a) |
| | | | | | | | | | |
| | | | | | | | | | |
(a)Not applicable.
| | | | | | | | |
| Accounting Estimate | | Uncertainties Affecting Application |
| Accounting for Contingencies | | |
| We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. | | •Estimating financial impact of events •Estimating likelihood of various potential outcomes •Regulatory and political environments and requirements •Outcome of legal proceedings, settlements, or other factors •Changes in regulation, expected scope of work, technology, or timing of environmental remediation |
We make judgments and estimates in the recording and the disclosing76
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
ContentsBasis 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, 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
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
| | | | | | | | |
| 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, includingincluding: a change in forecasted financial condition and/or results of operations, changeoperations; changes in income tax laws, enacted tax rates or amounts subject to income tax,tax; the form, structure, and timing of asset or stock sales or dispositions, changedispositions; changes in the regulatory treatment of any tax reform benefits,benefits; and results ofchanges resulting from audits and examinations by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At each period end, and as new developments occur, management reevaluates its tax positions. Additional interpretations, regulations, amendments, or technical corrections related to the federal income tax code as a result of the TCJA, as well as the associated treatment by our regulators,IRA, may impact the estimates for income taxes discussed above. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information on the IRA and the amount of deferred income taxes recorded at December 31, 2017.2023.
Unbilled Revenue | | | | | | | | |
| 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 endestimated fair value of eachlegal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs for accretion and changes in the estimated fair values of the obligations, with a corresponding increase or decrease in the asset book value for the fair value changes. We estimate the fair value of our AROs using present value techniques, in which we make various assumptions about discount rates and cost escalation rates. In addition, these estimates include assumptions of the probability, timing, and amount of cash expenditures to settle the ARO, and are based on currently available technology. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with decommissioning of Ameren Missouri’s Callaway and wind renewable energy centers, certain Ameren Missouri solar energy centers, CCR facilities, and river structures at certain energy centers used for unloading coal and circulating water systems. Additionally, Ameren, Ameren Missouri, and Ameren Illinois estimatehave recorded AROs for retirement costs associated with asbestos removal and the usage that has been provided to customers but not yet billed. This usage amount, along with a per unit price, is used to estimate an unbilled balance. For its electric distribution business, Ameren Illinois then considers and reflects the effectdisposal of the decoupling provisions of the FEJA.
Estimating customer energy usage
Estimating impacts of weather and other usage-affecting factors for the unbilled period
Estimating loss of energy during transmission and delivery
Basis for Judgment
We base our estimate of unbilled revenue each period on the volume of energy delivered, as valued by a model of billing cycles and historical usage rates and by growth or contraction by customer class for our service area. This figure is then adjusted for the modeled impact of seasonal and weather variations based on historical results. As a result of its regulatory framework, Ameren Illinois adjusts unbilled electric distribution revenues to reflect the decoupling provisions of the FEJA, with an offset to a regulatory asset or liability.certain transformers. See the balance sheet for each of the Ameren CompaniesNote 15 – Supplemental Information under Part II, Item 8, of this report for unbilled revenue amounts.the amount of AROs recorded at December 31, 2023.
A significant portion of Ameren’s and Ameren Missouri’s AROs relate to the decommissioning of Ameren Missouri’s Callaway Energy Center. Changes in key assumptions could materially affect the decommissioning obligation. The following table reflects the sensitivity of potential changes in key assumptions to Ameren Missouri’s Callaway Energy Center decommissioning obligation as of December 31, 2023:
| | | | | |
| Change in Callaway Energy Center’s Key ARO Assumptions | Increase (Decrease) to ARO |
| |
| Discount rate decreased by 0.10% | $ | 12 | |
| Cost escalation rate increased by 0.25% | 28 | |
| Increase in the estimated decommissioning costs by 10% | 45 | |
| Two-year deferral in timing of cash expenditures | (30) | |
Impact of New Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
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. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois participates in performance-based formula ratemaking frameworks established pursuant to the IEIMA and the FEJA for its electric distribution business and its electric energy-efficiency investments. Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Within the IEIMA and the FEJA formula ratemaking frameworks, the monthly average yields of 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the annual return on equity applicable to Ameren Illinois’ electric distribution business and electric energy-efficiency investments. 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.
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 Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. The March 2017 MoPSC electric rate order approved Ameren Missouri’s request for continued use of 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 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 athe 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 AROs, goodwill, and defined pension and postretirement benefit plans, asset retirement obligations, and goodwill.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,AROs, goodwill, and the defined pension and postretirement benefit plans.
The following table presents 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, 2017:2023 is immaterial.
|
| | | | | | |
| | | Interest Expense | | Net Income(a) |
| Ameren | $ | 7 |
| $ | (5 | ) |
| Ameren Missouri | | 2 |
| | (2 | ) |
| Ameren Illinois | | 1 |
| | (1 | ) |
| |
(a) | Calculations are based on the 2018 statutory tax rates of 27%, 25%, and 28% for Ameren, Ameren Missouri, and Ameren Illinois, respectively. |
The returnallowed ROE under Ameren Illinois’ electric energy-efficiency investments formula ratemaking recovery mechanisms is based on equity component under the IEIMA and the FEJA is equal to the calendar yearannual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’
annual return on equity under the formula ratemaking frameworksROE for both its electric distribution service and its electric energy-efficiency investments is directly correlated to the yields on such bonds, which are outside of Ameren Illinois’ control. A 50 basis point changeInterest rate levels also influence the ROE allowed by our regulators in our other ratemaking jurisdictions, as well as the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $8 million change in Ameren’scarrying costs associated with certain regulatory assets and Ameren Illinois’ net income, based on its 2018 projected rate base.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, 2017.2023.
Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. Our physical and financial instruments are subject to credit risk consistingprimarily consist of trade accounts receivables and executory contracts with market risk exposures. TheCredit risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our diversified customer base. At December 31, 2017,2023, no nonaffiliated customer represented more than 10% of our accounts receivable. Additionally, Ameren Illinois faces risks associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois may be required to purchase the supplier’s receivables relating to Ameren Illinois’ distribution customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers to reflect charges for electric distribution and purchased receivables.receivables from the alternative retail electric suppler. As of December 31, 2017,2023, Ameren Illinois’ balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $31$42 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 rateseconomic conditions, including inflationary pressures, on customer collections.collections and customer account balances. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are adequate to cover estimated uncollectible customer account balances. See Note 15 – Supplemental Information under Part II, Item 8, of this report for more information on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement as of December 31, 2023.
Investment Price Risk
Plan assets of the pension and postretirement trusts, the nuclear decommissioning trust fund, and company-owned life insuranceCOLI 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 20182024 assumed return on plan assets of 7.00%6.75%.
Ameren Missouri also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2017,2023, this fund was invested in domestic equity securities (66%(68%) and debt securities (33%(31%). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri seeks to maximize the returns to be used to fund nuclear decommissioning costs within acceptable parameters of risk. Ameren Missouri actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the trust assets to various investment options. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Additionally, Ameren and Ameren Illinois have company-owned life insuranceCOLI contracts with net assetcash surrender values of $136$144 million and $9$7 million, respectively, as of December 31, 2017.2023. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest. As of December 31, 2023, that separate account is comprised of approximately 50% equity securities and 50% debt securities. To the extent not recovered through customer rates, changes in the market values of these contracts are reflected in earnings.
Commodity Price Risk
Ameren Missouri’s and Ameren Illinois’ electric and natural gas distribution 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 a cost recovery mechanismmechanisms for power purchased, on behalf of its customers.capacity, zero emission credit, and renewable energy credit costs. Ameren Illinois is required to serve as the provider of last resort for electric customers in its service territory who have not chosen an alternative retail electric supplier. In 2023, Ameren Illinois does not generate earnings basedprocured power on the resalebehalf of power but rather on the deliveryits customers for 28% of energy.its total kilowatthour sales. Ameren Illinois purchases power primarilyenergy and capacity through MISO, with additionalbilateral contracts resulting from IPA procurement events, administered bywith any remaining needs procured through the IPA.MISO marketplace. Ameren Illinois has purchased approximately 15% of its June 2024 to May 2025 capacity needs bilaterally, however, this percentage beyond May 2025 will be dependent on the results of future IPA procurement events. Daily energy balancing is also handled through the MISO marketplace. The IPA has proposed and the ICC has approved multiple procurement events covering portions of years through 2020. In 2017, acting in its role as the provider of last resort,2027 for capacity and energy. Ameren Illinois supplied powerhas also entered into ICC-approved contracts for 23% of its kilowatthour saleszero emission credits through May 2027 and for renewable energy credits with various terms, including contracts with 20-year terms ending 2032, and contracts entered into beginning in 2018 through 2024 with 15- to its electric customers.20-year terms. Ameren Illinois expects full recoverydoes not generate earnings based on the resale of its purchased power costs.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, 2023, the percentages of the projected required supply of coal and coal transportation for Ameren Missouri’s coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway Energy Center, natural gas for Ameren Missouri’s and Ameren Illinois’ retail distribution, and purchased power for Ameren Illinois that are price-hedged over the period 2024 through 2028. The projected required supply of these commodities could be significantly affected by changes in our assumptions about customer demand for electricity and natural gas supplied by us and inventory levels, as well as Ameren Missouri’s generation output, among other matters.
| | | | | | | | | | | | | | | | | |
| 2024 | | 2025 | | 2026 – 2028 |
| Ameren: | | | | | |
Coal(a) | 98 | % | | 85 | % | | 48 | % |
Coal transportation(a) | 100 | | | 100 | | | 98 | |
| Nuclear fuel | (b) | | 100 | | | 100 | |
| | | | | |
Natural gas for distribution(c) | 97 | | | 50 | | | 27 | |
Purchased power for Ameren Illinois(d) | 77 | | | 37 | | | 11 | |
| Ameren Missouri: | | | | | |
Coal(a) | 98 | % | | 85 | % | | 48 | % |
Coal transportation(a) | 100 | | | 100 | | | 98 | |
| Nuclear fuel | (b) | | 100 | | | 100 | |
| | | | | |
Natural gas for distribution(c) | 90 | | | 57 | | | 31 | |
| Ameren Illinois: | | | | | |
Natural gas for distribution(c) | 98 | % | | 49 | % | | 26 | % |
Purchased power(d) | 77 | | | 37 | | | 11 | |
(a)Ameren Missouri has agreements in place to purchase and transport coal to its energy centers. While Ameren Missouri has minimum purchase obligations associated with these agreements, the majority of these agreements are not associated with any specific coal-fired energy center.
(b)The Callaway Energy Center requires refueling at 18-month intervals. As there is no refueling and maintenance outage scheduled to occur during 2024, there are also no nuclear fuel deliveries anticipated to occur in 2024.
(c)Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2024 represents January 2024 through March 2024. The year 2025 represents November 2024 through March 2025. This continues each successive year through March 2028.
(d)Represents the percentage of purchased power price-hedged for fixed-price residential and nonresidential customers with less than 150 kilowatts of demand.
Our exposure to commodity price risk for construction and maintenance activities is related to changes in market prices for metal commodities and to labor availability.
See Transmission and Supply of Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear, natural gas, oil, and renewables. 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 20212028 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.limited. 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, and reduce generation to achieve compliance with environmental regulations, orregulations. Ameren Missouri would then need to purchase power necessary to meet demand.
TheCurrently, the Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse, which is the onlyEnergy Center has a single NRC-licensed supplier authorizedable to provide fuel assemblies to the Callaway energy center. DuringEnergy Center. Ameren Missouri is pursuing a program to qualify an alternate NRC-licensed supplier for contingency purposes. Ameren Missouri is awaiting approval from the first quarterNRC, which is under no deadline to issue the approval.
Ameren Missouri received a planned delivery of 2017, Westinghouse filed voluntary petitions forenriched uranium from a court-supervised restructuring process under Chapter 11Russian supplier in the spring of 2023. The planned delivery concluded the nuclear fuel supply agreement with this Russian supplier with no future deliveries planned with any Russian suppliers. Ameren Missouri has sufficient inventory and supply contracts with non-Russian suppliers that adequately meet all of the United States Bankruptcy Code. At this time, nuclear fuel needs of the Callaway Energy Center through the spring 2028 refueling.
Ameren Missouri's 2023 IRP targets cleaner and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the termsmore diverse sources of its existing contracts with Ameren Missouri,energy generation, including solar generation. While rights to acquire build-transfer solar facilities and therefore do not expect anysupplies for development-transfer and self-build solar facilities totaling 900 MWs were secured through agreements, supply chain disruptions, including solar panel shortages and increasing material impact to Ameren Missouri’s operations. However, Ameren and Ameren Missouri could incur material unexpected costs as a result of government tariffs and other factors, could affect the Westinghouse bankruptcy, such as the loss of fuel inventory that is stored at Westinghouse’s facility and the cost of replacement power if nuclear fuel assemblies were not available for a future scheduled refueling and maintenance outage. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement. See Note 9 – Callaway Energy Center under Part II, Item 8, of this report for additional information.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for natural gas, power, and uranium,costs, 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, 2017. 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 valuetiming, of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2),projects and other modeling and valuation methods that are not corroborated by market data (Level 3).solar generation projects. See Note 82 – Fair Value MeasurementsRate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the methods used to determine the fair value of these contracts.
|
| | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fair value of contracts at beginning of year, net | $ | (4 | ) | | $ | (180 | ) | | $ | (184 | ) |
| Contracts realized or otherwise settled during the period | (3 | ) | | 4 |
| | 1 |
|
| Fair value of new contracts entered into during the period | 11 |
| | (7 | ) | | 4 |
|
| Other changes in fair value | 4 |
| | (34 | ) | | (30 | ) |
| Fair value of contracts outstanding at end of year, net | $ | 8 |
| | $ | (217 | ) | | $ | (209 | ) |
The following table presents maturities of derivative contracts as of December 31, 2017, based on the hierarchy levels usedsolar facilities. See Outlook under Part II, Item 7, of this report for additional information on the United States Department of Commerce investigation into the supply of solar panels and the actions taken by the United States Customs and Border Protection Agency to determinedetain certain solar panel shipments from China. Any future tariffs or actions by the fair valueUnited States Customs and Border Protection Agency could affect the cost and the availability of solar panel components and the contracts:timing and amount of Ameren Missouri's estimated capital expenditures associated with solar generation investments.
|
| | | | | | | | | | | | | | | | | | | |
| Sources of Fair Value | Maturity Less Than 1 Year | | Maturity 1 – 3 Years | | Maturity
3 – 5 Years | | Maturity in Excess of 5 Years | | Total Fair Value |
| Ameren Missouri: |
| |
| |
| |
| |
|
| Level 1 | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Level 2(a) | (3 | ) | | (3 | ) | | — |
| | — |
| | (6 | ) |
Level 3(b) | 8 |
| | 2 |
| | — |
| | — |
| | 10 |
|
| Total | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Ameren Illinois: |
|
| |
|
| |
|
| |
|
| |
|
|
| Level 1 | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) |
Level 2(a) | (10 | ) | | (7 | ) | | (1 | ) | | — |
| | (18 | ) |
Level 3(b) | (14 | ) | | (30 | ) | | (29 | ) | | (125 | ) | | (198 | ) |
| Total | $ | (25 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (217 | ) |
| Ameren: | | | | | | | | | |
| Level 1 | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
Level 2(a) | (13 | ) | | (10 | ) | | (1 | ) | | — |
| | (24 | ) |
Level 3(b) | (6 | ) | | (28 | ) | | (29 | ) | | (125 | ) | | (188 | ) |
| Total | $ | (17 | ) | | $ | (37 | ) | | $ | (30 | ) | | $ | (125 | ) | | $ | (209 | ) |
| |
| Principally fixed-price vs. floating OTC power swaps, power forwards, and fixed-price vs. floating OTC 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 sheetssheet of Ameren Corporation and its subsidiaries (the “Company”) as of December 31, 20172023 and 2016,2022, and the related consolidated statements of income and comprehensive income, changes inof shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2017,2023, including the related notes and financial statement schedules listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2017,2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(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. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2023, there were approximately $2.2 billion of regulatory assets and approximately $5.6 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 201829, 2024
We have served as the Company’s auditor since at least 1932. We have not determinedbeen 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 consolidated balance sheetssheet of Union Electric Company and its subsidiaries (the “Company”) as of December 31, 20172023 and 2016,2022, and the related consolidated statements of income, and comprehensive income, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2017,2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
Theseconsolidatedfinancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’sconsolidatedfinancial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Regulation
As described in Notes 1 and 2 to the consolidated financial statements, the Company has operations that are subject to the decisions and requirements of its regulators. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2023, there were approximately $0.9 billion of regulatory assets and approximately $3.0 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were
impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
/s/ PricewaterhouseCoopers LLP
St. Louis, Missouri
February 29, 2024
We have served as the Company’s auditor since at least 1932. We have not been able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois Company
Opinion on the Financial Statements
We have audited the accompanying balance sheet of Ameren Illinois Company (the “Company”) as of December 31, 2023 and 2022, and the related statements of income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023 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. As disclosed by management, the Company’s use of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities for certain transactions that management expects will be recovered from or refunded to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. As of December 31, 2023, there were approximately $1.3 billion of regulatory assets and approximately $2.5 billion of regulatory liabilities. In some cases, management records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Additionally, management recognizes revenue for alternative revenue programs that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months of the end of the annual period in which they are recognized. Management’s conclusions are based on certain factors including, but not limited to, regulatory commission orders, legislation, or historical experience, as well as management’s discussions with legal counsel.
The principal considerations for our determination that performing procedures relating to accounting for the effects of regulation is a critical audit matter are the significant judgment by management when accounting for (i) new or existing regulatory assets or liabilities that were impacted by updates in regulatory commission orders, legislation, historical experience, or management’s discussions with legal counsel, (ii) the probability of recovery of regulatory assets and refund of regulatory liabilities recorded before approval has been received from the regulator, and (iii) regulatory mechanisms meeting the alternative revenue program criteria, which in turn led to a high degree of auditor
judgment, subjectivity, and effort when performing audit procedures and evaluating audit evidence obtained related to management’s application of regulatory accounting, assessment of probability of recovery of regulatory assets and refund of regulatory liabilities, and expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included testing the effectiveness of controls relating to management’s implementation and application of new or existing regulatory assets or liabilities, including controls related to evaluating the probability of recovery of regulatory assets and refund of regulatory liabilities, and alternative revenue programs. These procedures also included, among others, (i) testing calculations of new and existing regulatory assets or liabilities by comparison to provisions and formulas outlined in regulatory commission orders or legislation, (ii) evaluating management’s assessment of the probability of recovery of regulatory assets and refund of regulatory liabilities, and (iii) evaluating management’s assessment of regulatory mechanisms meeting the alternative revenue program criteria and the expected timing of collection within 24 months of the end of the annual period in which mechanisms are recognized.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 2018
We have served as the Company’s auditor since at least 1932. We have not determined 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:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ameren Illinois Company as of December 31, 2017 and 2016, and the related statements of income and comprehensive income, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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”) 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 28, 201829, 2024
We have served as the Company’s auditor since 1998.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (In millions, except per share amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 5,310 |
| | $ | 5,196 |
| | $ | 5,180 |
|
| Natural gas | 867 |
| | 880 |
| | 918 |
|
| Total operating revenues | 6,177 |
| | 6,076 |
| | 6,098 |
|
| Operating Expenses: |
| |
| | |
| Fuel | 737 |
| | 745 |
| | 878 |
|
| Purchased power | 638 |
| | 621 |
| | 514 |
|
| Natural gas purchased for resale | 311 |
| | 341 |
| | 415 |
|
| Other operations and maintenance | 1,660 |
| | 1,676 |
| | 1,694 |
|
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 896 |
| | 845 |
| | 796 |
|
| Taxes other than income taxes | 477 |
| | 467 |
| | 473 |
|
| Total operating expenses | 4,719 |
| | 4,695 |
| | 4,839 |
|
| Operating Income | 1,458 |
| | 1,381 |
| | 1,259 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 59 |
| | 74 |
| | 74 |
|
| Miscellaneous expense | 21 |
| | 32 |
| | 30 |
|
| Total other income | 38 |
| | 42 |
| | 44 |
|
| Interest Charges | 391 |
| | 382 |
| | 355 |
|
| Income Before Income Taxes | 1,105 |
| | 1,041 |
| | 948 |
|
| Income Taxes | 576 |
| | 382 |
| | 363 |
|
| Income from Continuing Operations | 529 |
| | 659 |
| | 585 |
|
| Income from Discontinued Operations, Net of Taxes | — |
| | — |
| | 51 |
|
| Net Income | 529 |
| | 659 |
| | 636 |
|
Less: Net Income from Continuing Operations Attributable to
Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Net Income Attributable to Ameren Common Shareholders: | | | | | |
| Continuing Operations | 523 |
| | 653 |
| | 579 |
|
| Discontinued Operations | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | |
| Earnings per Common Share – Basic: | | | | | |
| Continuing Operations | $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.39 |
|
| Discontinued Operations | — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Basic | $ | 2.16 |
| | $ | 2.69 |
| | $ | 2.60 |
|
| | | | | | |
| Earnings per Common Share – Diluted: | | | | | |
| Continuing Operations | $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.38 |
|
| Discontinued Operations | — |
| | — |
| | 0.21 |
|
| Earnings per Common Share – Diluted | $ | 2.14 |
| | $ | 2.68 |
| | $ | 2.59 |
|
| | | | | | |
| Dividends per Common Share | $ | 1.778 |
| | $ | 1.715 |
| | $ | 1.655 |
|
| Average Common Shares Outstanding – Basic | 242.6 |
| | 242.6 |
| | 242.6 |
|
| Average Common Shares Outstanding – Diluted | 244.2 |
| | 243.4 |
| | 243.6 |
|
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions, except per share amounts)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| Operating Revenues: | | | | | |
| Electric | $ | 6,439 | | | $ | 6,581 | | | $ | 5,297 | |
| Natural gas | 1,061 | | | 1,376 | | | 1,097 | |
| Total operating revenues | 7,500 | | | 7,957 | | | 6,394 | |
| Operating Expenses: | | | | | |
| Fuel | 514 | | | 473 | | | 581 | |
| Purchased power | 1,298 | | | 1,547 | | | 606 | |
| Natural gas purchased for resale | 355 | | | 657 | | | 442 | |
| Other operations and maintenance | 1,866 | | | 1,937 | | | 1,774 | |
| | | | | |
| Depreciation and amortization | 1,387 | | | 1,289 | | | 1,146 | |
| Taxes other than income taxes | 522 | | | 539 | | | 512 | |
| Total operating expenses | 5,942 | | | 6,442 | | | 5,061 | |
| Operating Income | 1,558 | | | 1,515 | | | 1,333 | |
| | | | | |
| | | | | |
| | | | | |
| Other Income, Net | 348 | | | 226 | | | 202 | |
| Interest Charges | 566 | | | 486 | | | 383 | |
| Income Before Income Taxes | 1,340 | | | 1,255 | | | 1,152 | |
| Income Taxes | 183 | | | 176 | | | 157 | |
| | | | | |
| | | | | |
| Net Income | 1,157 | | | 1,079 | | | 995 | |
| Less: Net Income Attributable to Noncontrolling Interests | 5 | | | 5 | | | 5 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 1,152 | | | $ | 1,074 | | | $ | 990 | |
| | | | | |
| | | | | |
| Net Income | $ | 1,157 | | | $ | 1,079 | | | $ | 995 | |
| Other Comprehensive Income (Loss), Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(2), $(4), and $4, respectively | (5) | | | (14) | | | 14 | |
| Comprehensive Income | 1,152 | | | 1,065 | | | 1,009 | |
| Less: Comprehensive Income Attributable to Noncontrolling Interests | 5 | | | 5 | | | 5 | |
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 1,147 | | | $ | 1,060 | | | $ | 1,004 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Earnings per Common Share – Basic | $ | 4.39 | | | $ | 4.16 | | | $ | 3.86 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Earnings per Common Share – Diluted | $ | 4.38 | | | $ | 4.14 | | | $ | 3.84 | |
| | | | | |
| Weighted-average Common Shares Outstanding – Basic | 262.8 | | | 258.4 | | | 256.3 | |
| Weighted-average Common Shares Outstanding – Diluted | 263.4 | | | 259.5 | | | 257.6 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Income from Continuing Operations | $ | 529 |
| | $ | 659 |
| | $ | 585 |
|
| Other Comprehensive Income (Loss) from Continuing Operations, Net of Taxes | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $3, respectively | 5 |
| | (20 | ) | | 6 |
|
| Comprehensive Income from Continuing Operations | 534 |
| | 639 |
| | 591 |
|
| Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 528 |
| | 633 |
| | 585 |
|
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
| | | | | | | | | | | |
| | December 31, |
| | 2023 | | 2022 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 25 | | | $ | 10 | |
| Accounts receivable – trade (less allowance for doubtful accounts of $30 and $31, respectively) | 494 | | | 600 | |
| Unbilled revenue | 319 | | | 446 | |
| Miscellaneous accounts receivable | 106 | | | 54 | |
| Inventories | 733 | | | 667 | |
| | | |
| Current regulatory assets | 365 | | | 354 | |
| Investments in industrial development revenue bonds | — | | | 240 | |
| Current collateral assets | 14 | | | 142 | |
| Other current assets | 125 | | | 155 | |
| | | |
| Total current assets | 2,181 | | | 2,668 | |
| Property, Plant, and Equipment, Net | 33,776 | | | 31,262 | |
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 1,150 | | | 958 | |
| Goodwill | 411 | | | 411 | |
| | | |
| Regulatory assets | 1,810 | | | 1,426 | |
| Pension and other postretirement benefits | 581 | | | 411 | |
| Other assets | 921 | | | 768 | |
| | | |
| Total investments and other assets | 4,873 | | | 3,974 | |
| TOTAL ASSETS | $ | 40,830 | | | $ | 37,904 | |
| LIABILITIES AND EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 849 | | | $ | 340 | |
| Short-term debt | 536 | | | 1,070 | |
| Accounts and wages payable | 1,136 | | | 1,159 | |
| | | |
| | | |
| Customer deposits | 176 | | | 115 | |
| | | |
| | | |
| Other current liabilities | 648 | | | 682 | |
| | | |
| Total current liabilities | 3,345 | | | 3,366 | |
| | | |
| Long-term Debt, Net | 15,121 | | | 13,685 | |
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 4,176 | | | 3,804 | |
| | | |
| Regulatory liabilities | 5,512 | | | 5,309 | |
| Asset retirement obligations | 772 | | | 763 | |
| | | |
| Other deferred credits and liabilities | 426 | | | 340 | |
| | | |
| Total deferred credits and other liabilities | 10,886 | | | 10,216 | |
| Commitments and Contingencies (Notes 2, 9, and 14) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 266.3 and 262.0, respectively | 3 | | | 3 | |
| Other paid-in capital, principally premium on common stock | 7,216 | | | 6,860 | |
| Retained earnings | 4,136 | | | 3,646 | |
| Accumulated other comprehensive loss | (6) | | | (1) | |
| Total shareholders’ equity | 11,349 | | | 10,508 | |
| Noncontrolling Interests | 129 | | | 129 | |
| Total equity | 11,478 | | | 10,637 | |
| TOTAL LIABILITIES AND EQUITY | $ | 40,830 | | | $ | 37,904 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) |
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 10 |
| | $ | 9 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively) | 445 |
| | 437 |
|
| Unbilled revenue | 323 |
| | 295 |
|
| Miscellaneous accounts and notes receivable | 70 |
| | 63 |
|
| Inventories | 522 |
| | 527 |
|
| Current regulatory assets | 144 |
| | 149 |
|
| Other current assets | 98 |
| | 113 |
|
| Total current assets | 1,612 |
| | 1,593 |
|
| Property, Plant, and Equipment, Net | 21,466 |
| | 20,113 |
|
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 704 |
| | 607 |
|
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 1,230 |
| | 1,437 |
|
| Other assets | 522 |
| | 538 |
|
| Total investments and other assets | 2,867 |
| | 2,993 |
|
| TOTAL ASSETS | $ | 25,945 |
| | $ | 24,699 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 841 |
| | $ | 681 |
|
| Short-term debt | 484 |
| | 558 |
|
| Accounts and wages payable | 902 |
| | 805 |
|
| Taxes accrued | 52 |
| | 46 |
|
| Interest accrued | 99 |
| | 93 |
|
| Customer deposits | 108 |
| | 107 |
|
| Current regulatory liabilities | 128 |
| | 110 |
|
| Other current liabilities | 326 |
| | 274 |
|
| Total current liabilities | 2,940 |
| | 2,674 |
|
| Long-term Debt, Net | 7,094 |
| | 6,595 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 2,506 |
| | 4,264 |
|
| Accumulated deferred investment tax credits | 49 |
| | 55 |
|
| Regulatory liabilities | 4,387 |
| | 1,985 |
|
| Asset retirement obligations | 638 |
| | 635 |
|
| Pension and other postretirement benefits | 545 |
| | 769 |
|
| Other deferred credits and liabilities | 460 |
| | 477 |
|
| Total deferred credits and other liabilities | 8,585 |
| | 8,185 |
|
| Commitments and Contingencies (Notes 2, 9, and 14) |
|
| |
|
|
| Ameren Corporation Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,540 |
| | 5,556 |
|
| Retained earnings | 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (18 | ) | | (23 | ) |
| Total Ameren Corporation shareholders’ equity | 7,184 |
| | 7,103 |
|
| Noncontrolling Interests | 142 |
| | 142 |
|
| Total equity | 7,326 |
| | 7,245 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 25,945 |
| | $ | 24,699 |
|
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 1,157 | | | $ | 1,079 | | | $ | 995 | |
| | | | | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| Depreciation and amortization | 1,432 | | | 1,373 | | | 1,219 | |
| Amortization of nuclear fuel | 68 | | | 65 | | | 58 | |
| Amortization of debt issuance costs and premium/discounts | 16 | | | 21 | | | 23 | |
| Deferred income taxes and investment tax credits, net | 229 | | | 170 | | | 156 | |
| Allowance for equity funds used during construction | (54) | | | (43) | | | (43) | |
| Stock-based compensation costs | 26 | | | 24 | | | 22 | |
| | | | | |
| Other | 16 | | | 68 | | | 19 | |
| Changes in assets and liabilities: | | | | | |
| Receivables | 144 | | | (317) | | | (74) | |
| Inventories | (67) | | | (77) | | | (71) | |
| Accounts and wages payable | (104) | | | 136 | | | 28 | |
| Taxes accrued | (4) | | | (13) | | | 1 | |
| Regulatory assets and liabilities | (165) | | | (72) | | | (439) | |
| Assets, other | (109) | | | (74) | | | (71) | |
| Liabilities, other | 115 | | | 52 | | | (75) | |
| Pension and other postretirement benefits | (283) | | | (65) | | | (33) | |
| Counterparty collateral, net | 147 | | | (64) | | | (54) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net cash provided by operating activities | 2,564 | | | 2,263 | | | 1,661 | |
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (3,597) | | | (3,351) | | | (3,479) | |
| | | | | |
| Nuclear fuel expenditures | (174) | | | (29) | | | (44) | |
| Purchases of securities – nuclear decommissioning trust fund | (266) | | | (229) | | | (452) | |
| Sales and maturities of securities – nuclear decommissioning trust fund | 240 | | | 216 | | | 439 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Other | (1) | | | 23 | | | 8 | |
| | | | | |
| | | | | |
| | | | | |
| Net cash used in investing activities | (3,798) | | | (3,370) | | | (3,528) | |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (662) | | | (610) | | | (565) | |
| Dividends paid to noncontrolling interest holders | (5) | | | (5) | | | (5) | |
| Short-term debt, net | (533) | | | 522 | | | 55 | |
| | | | | |
| Maturities of long-term debt | (100) | | | (505) | | | (8) | |
| | | | | |
| | | | | |
| Issuances of long-term debt | 2,295 | | | 1,467 | | | 1,997 | |
| Issuances of common stock | 346 | | | 333 | | | 308 | |
| | | | | |
| | | | | |
| | | | | |
| Redemptions of Ameren Illinois preferred stock | — | | | — | | | (13) | |
| Employee payroll taxes related to stock-based compensation | (20) | | | (16) | | | (17) | |
| Debt issuance costs | (21) | | | (18) | | | (18) | |
| Other | (10) | | | — | | | (13) | |
| Net cash provided by financing activities | 1,290 | | | 1,168 | | | 1,721 | |
| | | | | |
| | | | | |
| Net change in cash, cash equivalents, and restricted cash | 56 | | | 61 | | | (146) | |
| Cash, cash equivalents, and restricted cash at beginning of year | 216 | | | 155 | | | 301 | |
| Cash, cash equivalents, and restricted cash at end of year | $ | 272 | | | $ | 216 | | | $ | 155 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $48, $26, and $17 capitalized, respectively) | $ | 546 | | | $ | 476 | | | $ | 426 | |
| Income taxes, net (includes production tax credit sale proceeds of $49, $—, and $—, respectively) | (24) | | | (8) | | | (1) | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 529 |
| | $ | 659 |
| | $ | 636 |
|
| Income from discontinued operations, net of tax | — |
| | — |
| | (51 | ) |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 876 |
| | 835 |
| | 777 |
|
| Amortization of nuclear fuel | 76 |
| | 88 |
| | 97 |
|
| Amortization of debt issuance costs and premium/discounts | 22 |
| | 22 |
| | 22 |
|
| Deferred income taxes and investment tax credits, net | 539 |
| | 386 |
| | 369 |
|
| Allowance for equity funds used during construction | (24 | ) | | (27 | ) | | (30 | ) |
| Share-based compensation costs | 17 |
| | 17 |
| | 24 |
|
| Other | (10 | ) | | 4 |
| | (10 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | (53 | ) | | (71 | ) | | 83 |
|
| Inventories | 17 |
| | 11 |
| | (14 | ) |
| Accounts and wages payable | 32 |
| | 19 |
| | (2 | ) |
| Taxes accrued | 55 |
| | 13 |
| | (22 | ) |
| Regulatory assets and liabilities | 36 |
| | 215 |
| | 94 |
|
| Assets, other | 20 |
| | (22 | ) | | 46 |
|
| Liabilities, other | (7 | ) | | (9 | ) | | (44 | ) |
| Pension and other postretirement benefits | (21 | ) | | (16 | ) | | (9 | ) |
| Net cash provided by operating activities – continuing operations | 2,104 |
| | 2,124 |
| | 2,035 |
|
| Net cash used in operating activities – discontinued operations | — |
| | (1 | ) | | (4 | ) |
| Net cash provided by operating activities | 2,104 |
| | 2,123 |
| | 2,031 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (2,132 | ) | | (2,076 | ) | | (1,917 | ) |
| Nuclear fuel expenditures | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 396 |
| | 377 |
| | 349 |
|
| Other | 7 |
| | 5 |
| | 32 |
|
| Net cash used in investing activities – continuing operations | (2,205 | ) | | (2,141 | ) | | (1,951 | ) |
| Net cash used in investing activities – discontinued operations | — |
| | — |
| | (25 | ) |
| Net cash used in investing activities | (2,205 | ) | | (2,141 | ) | | (1,976 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (431 | ) | | (416 | ) | | (402 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt, net | (74 | ) | | 257 |
| | (413 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (681 | ) | | (395 | ) | | (120 | ) |
| Issuances of long-term debt | 1,345 |
| | 389 |
| | 1,197 |
|
| Debt issuance costs | (11 | ) | | (9 | ) | | (12 | ) |
| Share-based payments | (39 | ) | | (83 | ) | | (12 | ) |
| Other | (1 | ) | | (2 | ) | | — |
|
| Net cash provided by (used in) financing activities – continuing operations | 102 |
| | (265 | ) | | 232 |
|
| Net change in cash and cash equivalents | 1 |
| | (283 | ) | | 287 |
|
| Cash and cash equivalents at beginning of year | 9 |
| | 292 |
| | 5 |
|
| Cash and cash equivalents at end of year | $ | 10 |
| | $ | 9 |
| | $ | 292 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $14, $15, and $17 capitalized, respectively) | $ | 370 |
| | $ | 358 |
| | $ | 335 |
|
| Income taxes, net | (19 | ) | | (12 | ) | | (15 | ) |
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2023 | | 2022 | | 2021 |
| | | | | |
| Common Stock | $ | 3 | | | $ | 3 | | | $ | 3 | |
| | | | | |
| | | | | |
| | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 6,860 | | | 6,502 | | | 6,179 | |
| Settlement of non-ATM program forward sale agreement through common shares issuance | — | | | — | | | 113 | |
| Shares issued under the ATM program | 299 | | | 292 | | | 148 | |
| Shares issued under the DRPlus and 401(k) plan | 46 | | | 49 | | | 47 | |
| Stock-based compensation activity | 11 | | | 17 | | | 15 | |
| | | | | |
| Other paid-in capital, end of year | 7,216 | | | 6,860 | | | 6,502 | |
| | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 3,646 | | | 3,182 | | | 2,757 | |
| Net income attributable to Ameren common shareholders | 1,152 | | | 1,074 | | | 990 | |
| Dividends on common stock | (662) | | | (610) | | | (565) | |
| | | | | |
| Retained earnings, end of year | 4,136 | | | 3,646 | | | 3,182 | |
| | | | | |
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Deferred retirement benefit costs, beginning of year | (1) | | | 13 | | | (1) | |
| Change in deferred retirement benefit costs | (5) | | | (14) | | | 14 | |
| | | | | |
| Deferred retirement benefit costs, end of year | (6) | | | (1) | | | 13 | |
| Total accumulated other comprehensive gain (loss), end of year | (6) | | | (1) | | | 13 | |
| Total Shareholders’ Equity | $ | 11,349 | | | $ | 10,508 | | | $ | 9,700 | |
| | | | | |
| Noncontrolling Interests: | | | | | |
| Beginning of year | 129 | | | 129 | | | 142 | |
| Net income attributable to noncontrolling interest holders | 5 | | | 5 | | | 5 | |
| Dividends paid to noncontrolling interest holders | (5) | | | (5) | | | (5) | |
| Redemptions of Ameren Illinois preferred stock | — | | | — | | | (13) | |
| | | | | |
| | | | | |
| Noncontrolling interests, end of year | 129 | | | 129 | | | 129 | |
| Total Equity | $ | 11,478 | | | $ | 10,637 | | | $ | 9,829 | |
| | | | | |
| | | | | |
| Common stock shares outstanding at beginning of year | 262.0 | | | 257.7 | | | 253.3 | |
| Shares issued under non-ATM program forward sale agreement | — | | | — | | | 1.6 | |
| Shares issued under the ATM program | 3.2 | | | 3.4 | | | 1.8 | |
| Shares issued under the DRPlus and 401(k) plan | 0.6 | | | 0.5 | | | 0.5 | |
| Shares issued for stock-based compensation | 0.5 | | | 0.4 | | | 0.5 | |
| Common stock shares outstanding at end of year | 266.3 | | | 262.0 | | | 257.7 | |
| | | | | |
| Dividends per common share | $ | 2.52 | | | $ | 2.36 | | | $ | 2.20 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Common Stock | $ | 2 |
| | $ | 2 |
| | $ | 2 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 5,556 |
| | 5,616 |
| | 5,617 |
|
| Share-based compensation activity | (16 | ) | | (60 | ) | | (1 | ) |
| Other paid-in capital, end of year | 5,540 |
| | 5,556 |
| | 5,616 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 1,568 |
| | 1,331 |
| | 1,103 |
|
| Net income attributable to Ameren common shareholders | 523 |
| | 653 |
| | 630 |
|
| Dividends | (431 | ) | | (416 | ) | | (402 | ) |
| Retained earnings, end of year | 1,660 |
| | 1,568 |
| | 1,331 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| Deferred retirement benefit costs, beginning of year | (23 | ) | | (3 | ) | | (9 | ) |
| Change in deferred retirement benefit costs | 5 |
| | (20 | ) | | 6 |
|
| Deferred retirement benefit costs, end of year | (18 | ) | | (23 | ) | | (3 | ) |
| Total accumulated other comprehensive loss, end of year | (18 | ) | | (23 | ) | | (3 | ) |
| Total Ameren Corporation Shareholders’ Equity | $ | 7,184 |
| | $ | 7,103 |
| | $ | 6,946 |
|
| | | | | | |
| 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 | $ | 7,326 |
| | $ | 7,245 |
| | $ | 7,088 |
|
| | | | | | |
| Common stock shares at end of year | 242.6 |
| | 242.6 |
| | 242.6 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 |
| 2016 | | 2015 |
| Operating Revenues: |
|
|
| | |
| Electric | $ | 3,413 |
|
| $ | 3,394 |
| | $ | 3,470 |
|
| Natural gas | 126 |
|
| 128 |
| | 137 |
|
| Other | — |
|
| 1 |
| | 2 |
|
| Total operating revenues | 3,539 |
|
| 3,523 |
| | 3,609 |
|
| Operating Expenses: |
|
|
| | |
| Fuel | 737 |
|
| 745 |
| | 878 |
|
| Purchased power | 245 |
|
| 252 |
| | 111 |
|
| Natural gas purchased for resale | 47 |
| | 49 |
| | 57 |
|
| Other operations and maintenance | 902 |
| | 893 |
| | 925 |
|
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 533 |
| | 514 |
| | 492 |
|
| Taxes other than income taxes | 328 |
| | 325 |
| | 335 |
|
| Total operating expenses | 2,792 |
| | 2,778 |
| | 2,867 |
|
| Operating Income | 747 |
| | 745 |
| | 742 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 48 |
| | 52 |
| | 52 |
|
| Miscellaneous expense | 8 |
| | 10 |
| | 11 |
|
| Total other income | 40 |
| | 42 |
| | 41 |
|
| Interest Charges | 207 |
| | 211 |
| | 219 |
|
| Income Before Income Taxes | 580 |
| | 576 |
| | 564 |
|
| Income Taxes | 254 |
| | 216 |
| | 209 |
|
| Net Income | 326 |
| | 360 |
| | 355 |
|
| Other Comprehensive Income | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 323 |
| | $ | 357 |
| | $ | 352 |
|
CONSOLIDATED STATEMENT OF INCOME
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| Operating Revenues: | | | | | |
| Electric | $ | 3,694 | | | $ | 3,849 | | | $ | 3,212 | |
| Natural gas | 165 | | | 197 | | | 141 | |
| | | | | |
| Total operating revenues | 3,859 | | | 4,046 | | | 3,353 | |
| Operating Expenses: | | | | | |
| Fuel | 514 | | | 473 | | | 581 | |
| Purchased power | 483 | | | 677 | | | 227 | |
| Natural gas purchased for resale | 79 | | | 104 | | | 60 | |
| Other operations and maintenance | 1,003 | | | 1,028 | | | 948 | |
| | | | | |
| Depreciation and amortization | 783 | | | 732 | | | 632 | |
| Taxes other than income taxes | 360 | | | 363 | | | 343 | |
| Total operating expenses | 3,222 | | | 3,377 | | | 2,791 | |
| Operating Income | 637 | | | 669 | | | 562 | |
| | | | | |
| | | | | |
| | | | | |
| Other Income, Net | 130 | | | 99 | | | 99 | |
| Interest Charges | 227 | | | 213 | | | 137 | |
| Income Before Income Taxes | 540 | | | 555 | | | 524 | |
| Income Taxes (Benefit) | (8) | | | (10) | | | 3 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Net Income | 548 | | | 565 | | | 521 | |
| Preferred Stock Dividends | 3 | | | 3 | | | 3 | |
| Net Income Attributable to Ameren Common Shareholders | $ | 545 | | | $ | 562 | | | $ | 518 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) |
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Advances to money pool | — |
| | 161 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively) | 200 |
| | 187 |
|
| Accounts receivable – affiliates | 11 |
| | 12 |
|
| Unbilled revenue | 165 |
| | 154 |
|
| Miscellaneous accounts and notes receivable | 35 |
| | 14 |
|
| Inventories | 388 |
| | 392 |
|
| Current regulatory assets | 56 |
| | 35 |
|
| Other current assets | 50 |
| | 49 |
|
| Total current assets | 905 |
| | 1,004 |
|
| Property, Plant, and Equipment, Net | 11,751 |
| | 11,478 |
|
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 704 |
| | 607 |
|
| Regulatory assets | 395 |
| | 619 |
|
| Other assets | 288 |
| | 327 |
|
| Total investments and other assets | 1,387 |
| | 1,553 |
|
| TOTAL ASSETS | $ | 14,043 |
| | $ | 14,035 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 384 |
| | $ | 431 |
|
| Short-term debt | 39 |
| | — |
|
| Accounts and wages payable | 475 |
| | 444 |
|
| Accounts payable – affiliates | 60 |
| | 68 |
|
| Taxes accrued | 30 |
| | 30 |
|
| Interest accrued | 54 |
| | 54 |
|
| Current regulatory liabilities | 19 |
| | 12 |
|
| Other current liabilities | 103 |
| | 123 |
|
| Total current liabilities | 1,164 |
| | 1,162 |
|
| Long-term Debt, Net | 3,577 |
| | 3,563 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 1,650 |
| | 3,013 |
|
| Accumulated deferred investment tax credits | 48 |
| | 53 |
|
| Regulatory liabilities | 2,664 |
| | 1,215 |
|
| Asset retirement obligations | 634 |
| | 629 |
|
| Pension and other postretirement benefits | 213 |
| | 291 |
|
| Other deferred credits and liabilities | 12 |
| | 19 |
|
| Total deferred credits and other liabilities | 5,221 |
| | 5,220 |
|
| 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 | 1,858 |
| | 1,828 |
|
| Preferred stock | 80 |
| | 80 |
|
| Retained earnings | 1,632 |
| | 1,671 |
|
| Total shareholders’ equity | 4,081 |
| | 4,090 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 14,043 |
| | $ | 14,035 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
| | | | | | | | | | | |
| | December 31, |
| | 2023 | | 2022 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — | | | $ | — | |
| | | |
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | 204 | | | 244 | |
| Accounts receivable – affiliates | 72 | | | 51 | |
| Unbilled revenue | 163 | | | 184 | |
| Miscellaneous accounts receivable | 26 | | | 18 | |
| Inventories | 508 | | | 434 | |
| Current regulatory assets | 101 | | | 254 | |
| Investments in industrial development revenue bonds | — | | | 240 | |
| Current collateral assets | 5 | | | 101 | |
| Other current assets | 63 | | | 66 | |
| Total current assets | 1,142 | | | 1,592 | |
| Property, Plant, and Equipment, Net | 17,250 | | | 16,124 | |
| Investments and Other Assets: | | | |
| Nuclear decommissioning trust fund | 1,150 | | | 958 | |
| | | |
| Regulatory assets | 755 | | | 594 | |
| Pension and other postretirement benefits | 157 | | | 98 | |
| Other assets | 152 | | | 140 | |
| Total investments and other assets | 2,214 | | | 1,790 | |
| TOTAL ASSETS | $ | 20,606 | | | $ | 19,506 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 350 | | | $ | 240 | |
| Short-term debt | 170 | | | 329 | |
| Borrowings from money pool | 306 | | | — | |
| Accounts and wages payable | 618 | | | 606 | |
| Accounts payable – affiliates | 53 | | | 43 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Other current liabilities | 250 | | | 352 | |
| Total current liabilities | 1,747 | | | 1,570 | |
| Long-term Debt, Net | 5,991 | | | 5,846 | |
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 2,122 | | | 1,982 | |
| | | |
| Regulatory liabilities | 2,959 | | | 2,871 | |
| Asset retirement obligations | 768 | | | 759 | |
| | | |
| Other deferred credits and liabilities | 56 | | | 51 | |
| Total deferred credits and other liabilities | 5,905 | | | 5,663 | |
| Commitments and Contingencies (Notes 2, 9, 13, and 14) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | | | 511 | |
| Other paid-in capital, principally premium on common stock | 2,725 | | | 2,725 | |
| Preferred stock | 80 | | | 80 | |
| Retained earnings | 3,647 | | | 3,111 | |
| Total shareholders’ equity | 6,963 | | | 6,427 | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 20,606 | | | $ | 19,506 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 326 |
| | $ | 360 |
| | $ | 355 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Provision for Callaway construction and operating license | — |
| | — |
| | 69 |
|
| Depreciation and amortization | 514 |
| | 506 |
| | 476 |
|
| Amortization of nuclear fuel | 76 |
| | 88 |
| | 97 |
|
| Amortization of debt issuance costs and premium/discounts | 6 |
| | 6 |
| | 6 |
|
| Deferred income taxes and investment tax credits, net | 82 |
| | 179 |
| | 82 |
|
| Allowance for equity funds used during construction | (21 | ) | | (23 | ) | | (22 | ) |
| Other | 4 |
| | 5 |
| | 2 |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | (46 | ) | | 5 |
| | 72 |
|
| Inventories | 18 |
| | (4 | ) | | (39 | ) |
| Accounts and wages payable | 27 |
| | (18 | ) | | 3 |
|
| Taxes accrued | (1 | ) | | 11 |
| | 1 |
|
| Regulatory assets and liabilities | 26 |
| | 84 |
| | 117 |
|
| Assets, other | 30 |
| | (25 | ) | | 26 |
|
| Liabilities, other | (23 | ) | | (1 | ) | | 4 |
|
| Pension and other postretirement benefits | (2 | ) | | (4 | ) | | (2 | ) |
| Net cash provided by operating activities | 1,016 |
| | 1,169 |
| | 1,247 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (773 | ) | | (738 | ) | | (622 | ) |
| Nuclear fuel expenditures | (63 | ) | | (55 | ) | | (52 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (413 | ) | | (392 | ) | | (363 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 396 |
| | 377 |
| | 349 |
|
| Money pool advances, net | 161 |
| | (125 | ) | | (36 | ) |
| Other | 7 |
| | (1 | ) | | — |
|
| Net cash used in investing activities | (685 | ) | | (934 | ) | | (724 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (362 | ) | | (355 | ) | | (575 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 39 |
| | — |
| | (97 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (431 | ) | | (266 | ) | | (120 | ) |
| Issuances of long-term debt | 399 |
| | 149 |
| | 249 |
|
| Capital issuance costs | (3 | ) | | (3 | ) | | (3 | ) |
| Capital contribution from parent | 30 |
| | 44 |
| | 224 |
|
| Net cash used in financing activities | (331 | ) | | (434 | ) | | (325 | ) |
| Net change in cash and cash equivalents | — |
| | (199 | ) | | 198 |
|
| Cash and cash equivalents at beginning of year | — |
| | 199 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | — |
| | $ | — |
| | $ | 199 |
|
| | | | | | |
Noncash financing activity – capital contribution from parent | $ | — |
| | $ | — |
| | $ | 38 |
|
| | | | | | |
| Cash Paid During the Year: | | | | | |
| Interest (net of $10, $12, and $12 capitalized, respectively) | $ | 202 |
| | $ | 209 |
| | $ | 212 |
|
| Income taxes, net | 178 |
| | 27 |
| | 72 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 548 | | | $ | 565 | | | $ | 521 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Depreciation and amortization | 827 | | | 816 | | | 704 | |
| Amortization of nuclear fuel | 68 | | | 65 | | | 58 | |
| | | | | |
| Amortization of debt issuance costs and premium/discounts | 7 | | | 7 | | | 6 | |
| Deferred income taxes and investment tax credits, net | 28 | | | 21 | | | 3 | |
| Allowance for equity funds used during construction | (30) | | | (24) | | | (26) | |
| Other | (8) | | | 14 | | | 19 | |
| Changes in assets and liabilities: | | | | | |
| Receivables | 39 | | | (68) | | | (60) | |
| Inventories | (74) | | | (15) | | | (32) | |
| Accounts and wages payable | (8) | | | 19 | | | 28 | |
| Taxes accrued | (17) | | | (21) | | | (27) | |
| Regulatory assets and liabilities | (7) | | | (206) | | | (207) | |
| Assets, other | (25) | | | 1 | | | 28 | |
| Liabilities, other | 3 | | | 7 | | | (29) | |
| Pension and other postretirement benefits | (106) | | | (16) | | | (2) | |
| Counterparty collateral, net | 96 | | | (35) | | | (55) | |
| | | | | |
| Net cash provided by operating activities | 1,341 | | | 1,130 | | | 929 | |
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,760) | | | (1,690) | | | (2,015) | |
| | | | | |
| Nuclear fuel expenditures | (174) | | | (29) | | | (44) | |
| Purchases of securities – nuclear decommissioning trust fund | (266) | | | (229) | | | (452) | |
| Sales and maturities of securities – nuclear decommissioning trust fund | 240 | | | 216 | | | 439 | |
| | | | | |
| | | | | |
| Money pool advances, net | — | | | — | | | 139 | |
| | | | | |
| Other | — | | | 29 | | | 11 | |
| Net cash used in investing activities | (1,960) | | | (1,703) | | | (1,922) | |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (9) | | | (46) | | | (24) | |
| | | | | |
| Dividends on preferred stock | (3) | | | (3) | | | (3) | |
| Short-term debt, net | (159) | | | 164 | | | 165 | |
| Money pool borrowings, net | 306 | | | — | | | — | |
| | | | | |
| Maturities of long-term debt | — | | | (55) | | | (8) | |
| Issuances of long-term debt | 499 | | | 524 | | | 524 | |
| Debt issuance costs | (8) | | | (6) | | | (5) | |
| Capital contribution from parent | — | | | — | | | 207 | |
| Other | (10) | | | — | | | — | |
| | | | | |
| Net cash provided by financing activities | 616 | | | 578 | | | 856 | |
| Net change in cash, cash equivalents, and restricted cash | (3) | | | 5 | | | (137) | |
| Cash, cash equivalents, and restricted cash at beginning of year | 13 | | | 8 | | | 145 | |
| Cash, cash equivalents, and restricted cash at end of year | $ | 10 | | | $ | 13 | | | $ | 8 | |
| | | | | |
| | | | | |
| | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $27, $13, and $10 capitalized, respectively) | $ | 225 | | | $ | 230 | | | $ | 205 | |
| Income taxes, net (includes production tax credit sale proceeds of $49, $—, and $—, respectively) | (19) | | | (20) | | | 19 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 1,828 |
| | 1,822 |
| | 1,569 |
|
| Capital contribution from parent | 30 |
| | 6 |
| | 253 |
|
| Other paid-in capital, end of year | 1,858 |
| | 1,828 |
| | 1,822 |
|
| | | | | | |
| Preferred Stock | 80 |
| | 80 |
| | 80 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,671 |
| | 1,669 |
| | 1,892 |
|
| Net income | 326 |
| | 360 |
| | 355 |
|
| Common stock dividends | (362 | ) | | (355 | ) | | (575 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,632 |
| | 1,671 |
| | 1,669 |
|
| | | | | | |
| Total Shareholders’ Equity | $ | 4,081 |
| | $ | 4,090 |
| | $ | 4,082 |
|
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2023 | | 2022 | | 2021 |
| Common Stock | $ | 511 | | | $ | 511 | | | $ | 511 | |
| | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 2,725 | | | 2,725 | | | 2,518 | |
| Capital contribution from parent | — | | | — | | | 207 | |
| | | | | |
| Other paid-in capital, end of year | 2,725 | | | 2,725 | | | 2,725 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Preferred Stock | 80 | | | 80 | | | 80 | |
| | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 3,111 | | | 2,595 | | | 2,101 | |
| Net income | 548 | | | 565 | | | 521 | |
| Dividends on common stock | (9) | | | (46) | | | (24) | |
| Dividends on preferred stock | (3) | | | (3) | | | (3) | |
| Retained earnings, end of year | 3,647 | | | 3,111 | | | 2,595 | |
| | | | | |
| Total Shareholders’ Equity | $ | 6,963 | | | $ | 6,427 | | | $ | 5,911 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2023 | | 2022 | | 2021 |
| Operating Revenues: | | | | | |
| Electric | $ | 1,784 |
| | $ | 1,736 |
| | $ | 1,683 |
|
| Electric | |
| Electric | |
| Natural gas | 743 |
| | 754 |
| | 783 |
|
| Other | 1 |
| | — |
| | — |
|
| | Total operating revenues | |
| Total operating revenues | |
| Total operating revenues | 2,528 |
| | 2,490 |
| | 2,466 |
|
| Operating Expenses: | | | | | |
| Purchased power | |
| Purchased power | |
| Purchased power | 417 |
| | 399 |
| | 420 |
|
| Natural gas purchased for resale | 264 |
| | 292 |
| | 358 |
|
| Other operations and maintenance | 789 |
| | 804 |
| | 797 |
|
| Depreciation and amortization | 341 |
| | 319 |
| | 295 |
|
| Taxes other than income taxes | 137 |
| | 132 |
| | 130 |
|
| Total operating expenses | 1,948 |
| | 1,946 |
| | 2,000 |
|
| Operating Income | 580 |
| | 544 |
| | 466 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 11 |
| | 21 |
| | 21 |
|
| Miscellaneous expense | 10 |
| | 12 |
| | 12 |
|
| Total other income | 1 |
| | 9 |
| | 9 |
|
| | Other Income, Net | |
| | Other Income, Net | |
| | Other Income, Net | |
| Interest Charges | 144 |
| | 140 |
| | 131 |
|
| Income Before Income Taxes | 437 |
| | 413 |
| | 344 |
|
| Income Taxes | 166 |
| | 158 |
| | 127 |
|
| Net Income | 271 |
| | 255 |
| | 217 |
|
| Other Comprehensive Loss, Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $-, $(1), and $(2), respectively | — |
| | (5 | ) | | (3 | ) |
| Comprehensive Income | $ | 271 |
| | $ | 250 |
| | $ | 214 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| | Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Shareholder | $ | 268 |
| | $ | 252 |
| | $ | 214 |
|
| | Preferred Stock Dividends | |
| | Preferred Stock Dividends | |
| Net Income Attributable to Ameren Common Shareholders | |
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, |
| | 2017 | | 2016 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively) | 234 |
| | 242 |
|
| Accounts receivable – affiliates | 9 |
| | 10 |
|
| Unbilled revenue | 158 |
| | 141 |
|
| Miscellaneous accounts receivable | 35 |
| | 22 |
|
| Inventories | 134 |
| | 135 |
|
| Current regulatory assets | 87 |
| | 108 |
|
| Other current assets | 15 |
| | 25 |
|
| Total current assets | 672 |
| | 683 |
|
| Property, Plant, and Equipment, Net | 8,293 |
| | 7,469 |
|
| Investments and Other Assets: | | | |
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 822 |
| | 816 |
|
| Other assets | 147 |
| | 95 |
|
| Total investments and other assets | 1,380 |
| | 1,322 |
|
| TOTAL ASSETS | $ | 10,345 |
| | $ | 9,474 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 457 |
| | $ | 250 |
|
| Short-term debt | 62 |
| | 51 |
|
| Accounts and wages payable | 337 |
| | 264 |
|
| Accounts payable – affiliates | 70 |
| | 63 |
|
| Taxes accrued | 19 |
| | 16 |
|
| Interest accrued | 33 |
| | 33 |
|
| Customer deposits | 69 |
| | 69 |
|
| Current environmental remediation | 42 |
| | 38 |
|
| Current regulatory liabilities | 92 |
| | 78 |
|
| Other current liabilities | 177 |
| | 109 |
|
| Total current liabilities | 1,358 |
| | 971 |
|
| Long-term Debt, Net | 2,373 |
| | 2,338 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 1,021 |
| | 1,631 |
|
| Accumulated deferred investment tax credits | 1 |
| | 2 |
|
| Regulatory liabilities | 1,629 |
| | 768 |
|
| Pension and other postretirement benefits | 285 |
| | 346 |
|
| Environmental remediation | 134 |
| | 162 |
|
| Other deferred credits and liabilities | 234 |
| | 222 |
|
| Total deferred credits and other liabilities | 3,304 |
| | 3,131 |
|
| 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 | 2,013 |
| | 2,005 |
|
| Preferred stock | 62 |
| | 62 |
|
| Retained earnings | 1,235 |
| | 967 |
|
| Total shareholders’ equity | 3,310 |
| | 3,034 |
|
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 10,345 |
| | $ | 9,474 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
BALANCE SHEET
(In millions)
| | | | | | | | | | | |
| | December 31, |
| | 2023 | | 2022 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — | | | $ | — | |
| Accounts receivable – trade (less allowance for doubtful accounts of $18 and $18, respectively) | 273 | | | 341 | |
| Accounts receivable – affiliates | 35 | | | 12 | |
| Unbilled revenue | 156 | | | 262 | |
| Miscellaneous accounts receivable | 44 | | | 23 | |
| Inventories | 225 | | | 233 | |
| | | |
| Current regulatory assets | 252 | | | 87 | |
| | | |
| Other current assets | 62 | | | 98 | |
| Total current assets | 1,047 | | | 1,056 | |
| Property, Plant, and Equipment, Net | 14,632 | | | 13,353 | |
| Investments and Other Assets: | | | |
| Goodwill | 411 | | | 411 | |
| Regulatory assets | 1,035 | | | 821 | |
| Pension and other postretirement benefits | 394 | | | 318 | |
| Other assets | 603 | | | 482 | |
| Total investments and other assets | 2,443 | | | 2,032 | |
| TOTAL ASSETS | $ | 18,122 | | | $ | 16,441 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | — | | | $ | 100 | |
| Short-term debt | 366 | | | 264 | |
| Borrowings from money pool | 135 | | | — | |
| Accounts and wages payable | 370 | | | 451 | |
| Accounts payable – affiliates | 52 | | | 93 | |
| | | |
| | | |
| Customer deposits | 141 | | | 87 | |
| | | |
| | | |
| Current regulatory liabilities | 71 | | | 64 | |
| Other current liabilities | 298 | | | 232 | |
| Total current liabilities | 1,433 | | | 1,291 | |
| Long-term Debt, Net | 5,232 | | | 4,735 | |
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes and investment tax credits, net | 1,906 | | | 1,699 | |
| | | |
| Regulatory liabilities | 2,418 | | | 2,313 | |
| | | |
| | | |
| Other deferred credits and liabilities | 308 | | | 235 | |
| Total deferred credits and other liabilities | 4,632 | | | 4,247 | |
| Commitments and Contingencies (Notes 2, 13, and 14) | | | |
| Shareholders’ Equity: | | | |
| Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | — | | | — | |
| Other paid-in capital | 3,020 | | | 2,929 | |
| Preferred stock | 49 | | | 49 | |
| Retained earnings | 3,756 | | | 3,190 | |
| | | |
| Total shareholders’ equity | 6,825 | | | 6,168 | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 18,122 | | | $ | 16,441 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 271 |
| | $ | 255 |
| | $ | 217 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 341 |
| | 318 |
| | 292 |
|
| Amortization of debt issuance costs and premium/discounts | 13 |
| | 14 |
| | 14 |
|
| Deferred income taxes and investment tax credits, net | 171 |
| | 154 |
| | 221 |
|
| Other | — |
| | (1 | ) | | (14 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | (7 | ) | | (72 | ) | | 16 |
|
| Inventories | (1 | ) | | 15 |
| | 25 |
|
| Accounts and wages payable | 19 |
| | 12 |
| | 37 |
|
| Taxes accrued | 18 |
| | 1 |
| | (2 | ) |
| Regulatory assets and liabilities | 16 |
| | 120 |
| | (26 | ) |
| Assets, other | (15 | ) | | (3 | ) | | 17 |
|
| Liabilities, other | 3 |
| | (5 | ) | | (27 | ) |
| Pension and other postretirement benefits | (14 | ) | | (8 | ) | | (4 | ) |
| Counterparty collateral, net | — |
| | 3 |
| | (3 | ) |
| Net cash provided by operating activities | 815 |
| | 803 |
| | 763 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,076 | ) | | (924 | ) | | (918 | ) |
| Other | 6 |
| | 6 |
| | 5 |
|
| Net cash used in investing activities | (1,070 | ) | | (918 | ) | | (913 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | — |
| | (110 | ) | | — |
|
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Short-term debt, net | 11 |
| | 51 |
| | (32 | ) |
| Money pool borrowings, net | — |
| | — |
| | (15 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (250 | ) | | (129 | ) | | — |
|
| Issuances of long-term debt | 496 |
| | 240 |
| | 248 |
|
| Capital issuance costs | (6 | ) | | (4 | ) | | (3 | ) |
| Capital contribution from parent | 8 |
| | — |
| | 25 |
|
| Other | (1 | ) | | (1 | ) | | — |
|
| Net cash provided by financing activities | 255 |
| | 44 |
| | 220 |
|
| Net change in cash and cash equivalents | — |
| | (71 | ) | | 70 |
|
| Cash and cash equivalents at beginning of year | — |
| | 71 |
| | 1 |
|
| Cash and cash equivalents at end of year | $ | — |
| | $ | — |
| | $ | 71 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $4, $3, and $5 capitalized, respectively) | $ | 139 |
| | $ | 127 |
| | $ | 120 |
|
| Income taxes, net | (22 | ) | | 8 |
| | (113 | ) |
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF CASH FLOWS
(In millions)
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2023 | | 2022 | | 2021 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 609 | | | $ | 515 | | | $ | 427 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 557 | | | 514 | | | 471 | |
| Amortization of debt issuance costs and premium/discounts | 5 | | | 11 | | | 13 | |
| Deferred income taxes and investment tax credits, net | 177 | | | 117 | | | 165 | |
| Allowance for equity funds used during construction | (19) | | | (18) | | | (17) | |
| Other | 40 | | | 29 | | | 10 | |
| Changes in assets and liabilities: | | | | | |
| Receivables | 129 | | | (250) | | | (17) | |
| Inventories | 7 | | | (62) | | | (40) | |
| Accounts and wages payable | (107) | | | 117 | | | 2 | |
| Taxes accrued | (73) | | | 34 | | | 22 | |
| Regulatory assets and liabilities | (152) | | | 134 | | | (222) | |
| Assets, other | (123) | | | (67) | | | (75) | |
| Liabilities, other | 106 | | | 42 | | | (46) | |
| Pension and other postretirement benefits | (112) | | | (39) | | | (32) | |
| Counterparty collateral, net | 54 | | | (29) | | | 1 | |
| Net cash provided by operating activities | 1,098 | | | 1,048 | | | 662 | |
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,731) | | | (1,601) | | | (1,432) | |
| | | | | |
| Other | (2) | | | (1) | | | (5) | |
| Net cash used in investing activities | (1,733) | | | (1,602) | | | (1,437) | |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (41) | | | — | | | — | |
| Dividends on preferred stock | (2) | | | (2) | | | (2) | |
| Short-term debt, net | 102 | | | 161 | | | 103 | |
| Money pool borrowings, net | 135 | | | — | | | (19) | |
| | | | | |
| Maturities of long-term debt | (100) | | | (400) | | | — | |
| Redemption of preferred stock | — | | | — | | | (13) | |
| Issuances of long-term debt | 498 | | | 848 | | | 449 | |
| Debt issuance costs | (5) | | | (10) | | | (6) | |
| | | | | |
| | | | | |
| Capital contribution from parent | 91 | | | 15 | | | 262 | |
| Other | — | | | — | | | (13) | |
| Net cash provided by financing activities | 678 | | | 612 | | | 761 | |
| Net change in cash, cash equivalents, and restricted cash | 43 | | | 58 | | | (14) | |
| Cash, cash equivalents, and restricted cash at beginning of year | 191 | | | 133 | | | 147 | |
| Cash, cash equivalents, and restricted cash at end of year | $ | 234 | | | $ | 191 | | | $ | 133 | |
| | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $17, $12, and $7 capitalized, respectively) | $ | 195 | | | $ | 152 | | | $ | 148 | |
| Income taxes, net | 102 | | | 23 | | | (41) | |
| | | | | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF SHAREHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Other Paid-in Capital |
| |
| |
|
| Beginning of year | 2,005 |
| | 2,005 |
| | 1,980 |
|
| Capital contribution from parent | 8 |
| | — |
| | 25 |
|
| Other paid-in capital, end of year | 2,013 |
| | 2,005 |
| | 2,005 |
|
| | | | | | |
| Preferred Stock | 62 |
| | 62 |
| | 62 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 967 |
| | 825 |
| | 611 |
|
| Net income | 271 |
| | 255 |
| | 217 |
|
| Common stock dividends | — |
| | (110 | ) | | — |
|
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,235 |
| | 967 |
| | 825 |
|
| | | | | | |
| Accumulated Other Comprehensive Income: | | | | | |
| Deferred retirement benefit costs, beginning of year | — |
| | 5 |
| | 8 |
|
| Change in deferred retirement benefit costs | — |
| | (5 | ) | | (3 | ) |
| Deferred retirement benefit costs, end of year | — |
| | — |
| | 5 |
|
| Total accumulated other comprehensive income, end of year | — |
| | — |
| | 5 |
|
| | | | | | |
| Total Shareholders’ Equity | $ | 3,310 |
| | $ | 3,034 |
| | $ | 2,897 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF SHAREHOLDERS’ EQUITY
(In millions)
| | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2023 | | 2022 | | 2021 |
| Common Stock | $ | — | | | $ | — | | | $ | — | |
| | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 2,929 | | | 2,914 | | | 2,652 | |
| Capital contribution from parent | 91 | | | 15 | | | 262 | |
| | | | | |
| Other paid-in capital, end of year | 3,020 | | | 2,929 | | | 2,914 | |
| | | | | |
| | | | | |
| Preferred Stock: | | | | | |
| Beginning of year | 49 | | | 49 | | | 62 | |
| Redemptions of preferred stock | — | | | — | | | (13) | |
| | | | | |
| | | | | |
| Preferred stock, end of year | 49 | | | 49 | | | 49 | |
| | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 3,190 | | | 2,677 | | | 2,252 | |
| Net income | 609 | | | 515 | | | 427 | |
| Dividends on common stock | (41) | | | — | | | — | |
| Dividends on preferred stock | (2) | | | (2) | | | (2) | |
| | | | | |
| Retained earnings, end of year | 3,756 | | | 3,190 | | | 2,677 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total Shareholders’ Equity | $ | 6,825 | | | $ | 6,168 | | | $ | 5,640 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated) (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 20172023
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, including Ameren Missouri, Ameren Illinois, and ATXI.below. Ameren also has other subsidiaries that conduct other activities, such as the provision ofproviding shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise.
•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.
•ATXI operates a FERC rate-regulated electric transmission business.business in the MISO. ATXI is developing MISO-approved electric transmission projects, including thewas incorporated in Illinois Rivers and Mark Twain projects, and placedin 2006. ATXI operates, among other assets, the Spoon River, project in service in February 2018.Mark Twain, and Illinois Rivers transmission lines.
Ameren’s and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of itstheir majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri andMissouri’s subsidiaries were created for the ownership of renewable generation projects. Ameren Illinois havehas no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated. Unless otherwise stated, these notes to the financial statements exclude discontinued operations for all periods presented.
As of December 31, 2017 and December 31, 2016, Ameren had unconsolidated variable interests as a limited partner in various equity method investments totaling $17 million and $9 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly impact the activities of these variable interest entities. As of December 31, 2017, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $17 million plus associated outstanding funding commitments of $20 million.
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 returnedrefunded 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 electric 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 positions tracker, a renewable energy standards cost tracker, a solar rebate program tracker, and the MEEIA energy-efficiency rider. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois participates in performance-based formula ratemaking frameworks established pursuant to the IEIMA and the FEJA for its electric distribution business and its electric energy-efficiency investments. Ameren Illinois also has environmental cost riders, an asbestos-related litigation rider, natural gas energy-efficiency rider, a QIP rider, a VBA rider, and a bad debt rider. 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, 20172023 and 2016.2022.
The Ameren Illinois asbestos-related litigation rider includes a trust fund. At December 31, 2017We continually assess the recoverability of our regulatory assets and 2016, the trust fund balanceprobability of $23 million and $22 million, respectively, was reflected in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets. This balancerefund of our regulatory liabilities. Regulatory assets are charged to earnings when it is restricted only for the use of funding certain asbestos-related claims. The rider is subject to the following terms: 90% of the cash expenditures in excess of the amount included in base electric rates is tono longer probable that such amounts will be recovered fromthrough future revenues. To the trust fund. If cash expendituresextent that refunds to customers related to regulatory liabilities are less thanno longer probable, the amount in base rates, Ameren Illinois will contribute 90% of the differenceamounts are credited to the trust fund.earnings.
Cash, and Cash Equivalents, and Restricted Cash
Cash and cash equivalents include cash on hand and temporaryshort-term, highly liquid investments purchased with an original maturity of three months or less. Cash and cash equivalents subject to legal or contractual restrictions and not readily available for use for general corporate purposes are classified as restricted cash. See Note 15 – Supplemental Information for a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a bad debt riderriders that adjustsadjust rates for net write-offs of customer accounts receivable above or below those being collected in rates.
Inventories
Inventories are recorded at the lower of weighted-average cost or net realizable value. Inventories are capitalized when purchased and then expensed as consumed or capitalized as property, plant, and equipment when installed, as appropriate. The following table presents a breakdownappropriate using the weighted-average cost method. See Note 15 – Supplemental Information for the components of inventories for each of the Ameren Companies at December 31, 2017 and 2016:
|
| | | | | | | | | | | | |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2017 | | | | | | |
Fuel(a) | | $ | 154 |
| | $ | — |
| | $ | 154 |
|
| Natural gas stored underground | | 8 |
| | 74 |
| | 82 |
|
| Materials, supplies, and other | | 226 |
| | 60 |
| | 286 |
|
| Total inventories | | $ | 388 |
| | $ | 134 |
| | $ | 522 |
|
| 2016 | | | | | | |
Fuel(a) | | $ | 172 |
| | $ | — |
| | $ | 172 |
|
| Natural gas stored underground | | 9 |
| | 73 |
| | 82 |
|
| Materials, supplies, and other | | 211 |
| | 62 |
| | 273 |
|
| Total inventories | | $ | 392 |
| | $ | 135 |
| | $ | 527 |
|
| |
(a) | Consists of coal, oil, and propane. |
inventories.
Property, Plant, and Equipment, Net
We capitalize the cost of additions to, and betterments of, units of property, plant, and equipment. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures, includingexpenses related to scheduled Callaway nuclear refueling and maintenance outages are deferred and amortized over the number of expected months until the completion of the next refueling outage, which historically has been approximately 18 months. Other maintenance expenditures are expensed as incurred. When units of depreciable property are retired, the original costs, 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 and Removal Costs section below and Note 3 – Property, Plant, and Equipment, Net for additional information.
Ameren Missouri’s cost of nuclear fuel is capitalized as a part of “Property, Plant, and Equipment, Net” on Ameren and Ameren Missouri’s balance sheets and then amortized to “Operating Expenses – Fuel” in their respective statements of income on a unit-of-production basis. Nuclear fuel amortization is reflected as a part of “Depreciation and amortization” on their respective statements of cash flow.
Plant to be Abandoned, Net
When it becomes probable an asset will be retired significantly in advance of its previously expected useful life and in the near term, the Ameren Companies must assess the probability of recovery of the remaining net book value of the asset to be abandoned. We recognize a loss on abandonment when it becomes probable that all or part of the cost of an asset, including a return at the applicable WACC, will be disallowed from recovery either through customer rates or through the issuance of securitized utility tariff bonds and such amount is reasonably estimable. An abandonment loss, if any, would equal the difference between the remaining net book value of the asset and the present value of the expected future cash flows. If the asset is still in service, the net book value is classified as plant to be abandoned, net, within “Property, Plant, and Equipment, Net” on the balance sheet. The net book value will be classified as a regulatory asset on the balance sheet when the asset is no longer in service or as required by a rate order.
In relation to the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies, in December 2021, Ameren Missouri filed a motion with the United States District Court for the Eastern District of Missouri to modify a previously issued remedy order to allow the retirement of the Rush Island Energy Center in lieu of installing a flue gas desulfurization system, which was granted to establish an October 15, 2024 retirement date. As of December 31, 2023 and 2022, Ameren and Ameren Missouri determined that the Rush Island Energy Center met the criteria to be considered probable of abandonment and have classified its remaining net book value as plant to be abandoned, net, within “Property, Plant, and Equipment, Net” on Ameren’s and Ameren Missouri’s balance sheets. See Note 3 – Property, Plant, and Equipment, Net for our plant to be abandoned balance as of December 31, 2023 and 2022. Ameren Missouri concluded no abandonment loss was required for the Rush Island Energy Center as of December 31, 2023. As part of the assessment of any potential future abandonment loss, consideration will be given to rate and securitization orders issued by the MoPSC to Ameren Missouri and to orders issued to other Missouri utilities with similar facts. See Note 2 – Rate and Regulatory Matters for Ameren Missouri’s November 2023 petition filed with the MoPSC seeking securitization of the Rush Island Energy Center.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The composite rates include a provision for the estimated removal cost of property, plant, and equipment retired from service, net of salvage. See Asset Retirement Obligation and Removal Costs section below for additional information. The provision for depreciation for the Ameren Companies in 2017, 2016,2023, 2022, and 20152021 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. 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 annual allowance for funds used during construction debt and equity blended rates that were applied to construction projects in 2017, 2016, and 2015:
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | 7 | % | | 7 | % | | 7 | % |
| Ameren Illinois | 4 | % | | 5 | % | | 6 | % |
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, 20172023 and 2016.2022. Ameren has four reporting units: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. Ameren Illinois has three reporting units: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission had goodwill of $238 million, $80 million, and $93 million, respectively, at December 31, 20172023 and 2016.2022. The Ameren Transmission reporting unit had the same $93 million of goodwill as the Ameren Illinois Transmission reporting unit at December 31, 20172023 and 2016.2022.
Ameren and Ameren Illinois evaluate goodwill for impairment in each of their reporting units as of October 31 each year, or more frequently if events 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. On December 31, 2016, due to a change in reporting units, Ameren and Ameren Illinois performed a quantitative test and determined that the estimated fair value of each reporting unit significantly exceeded its respective carrying value as of that date. Based on these results, test.
Ameren and Ameren Illinois elected to perform a qualitative assessment for their annual goodwill impairment test conducted as of October 31, 2017.
2023. As part of this qualitative assessment, Ameren and Ameren Illinois evaluated, among other things, macroeconomic conditions, industry and market considerations such as observable industry market multiples, regulatory frameworks, cost factors, overall financial performance, and entity-specific events. The results of Ameren’s and Ameren Illinois’ qualitative assessment indicated that it was more likely than not that the fair value of each reporting unit significantly exceeded its carrying value as of October 31, 2017,2023, resulting in no 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, 2017:
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 30-year United States Treasury bonds;
an unexpected further reduction 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 material long-lived assets may not be recoverable in 20172023, 2022, or 2021.
Variable Interest Entities
As of December 31, 2023 and 2016.2022, Ameren had unconsolidated variable interests in various equity method investments, primarily to advance clean and resilient energy technologies, totaling $73 million and $68 million, respectively, included in “Other assets” on Ameren’s
consolidated balance sheet. Any earnings or losses related to these investments are included in “Other Income, Net” on Ameren’s consolidated statement of income and comprehensive income. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of December 31, 2023, the maximum exposure to loss related to these variable interest entities is limited to the investment in these partnerships of $73 million plus associated outstanding funding commitments of $14 million.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. See Note 14 – Commitments and Contingencies for additional information on liabilities for environmental costs.
Asset Retirement Obligations and Removal Costs
We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we adjust AROs 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 depreciationDepreciation is deferred as a regulatory balance. The depreciation of the asset book values at Ameren Missouri was $26$9 million $31, $7 million, and $13$14 million for the years ended December 31, 2017, 2016,2023, 2022, and 2015,2021, respectively, which was deferred as a reduction to the net regulatory liability. The net regulatory liability also reflects a deferral for the nuclear decommissioning trust fund balance for the Callaway Energy Center. The depreciation deferred to the regulatory asset at Ameren Illinois was immaterial in each respective period. Ameren and Ameren Missouri have a nuclear decommissioning trust fund for the decommissioning of the Callaway energy center. Net realized and unrealized gains and losses within the nuclear decommissioning trust fund are deferred as a regulatory liability. Uncertainties as to the probability, timing, or amount of cash expenditures associated with AROs affect our estimates of fair value. Ameren and Ameren Missouri have recorded AROs for retirement costs associated with decommissioning of Ameren Missouri’s Callaway and wind renewable energy center decommissioning,centers, certain Ameren Missouri solar energy centers, CCR facilities, and river structures. Also,structures at certain energy centers used for unloading coal and circulating water systems. Additionally, Ameren, Ameren Missouri, and Ameren Illinois have recorded AROs for retirement costs associated with asbestos removal and the disposal of certain transformers. AssetSee Note 15 – Supplemental Information for a reconciliation of the beginning and ending carrying amounts of AROs.
Estimated funds collected from customers to pay for the future removal costs that do not constitute legal obligations are classified ascost of property, plant, and equipment retired from service, net of salvage, represent a cost of removal regulatory liabilities.liability. See the cost of removal regulatory liability balance in Note 2 – Rate and Regulatory Matters.
COLI
Ameren (parent) and Ameren Illinois have COLI, which is recorded at the net cash surrender value. The following table provides a reconciliation ofnet cash surrender value is the beginning and ending carrying amount of AROs forthat can be realized under the years ended December 31, 2017 and 2016:
|
| | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren | |
| Balance at December 31, 2015 | $ | 617 |
| | $ | 6 |
| | $ | 623 |
| |
| Liabilities incurred | 3 |
| | — |
| | 3 |
| |
| Liabilities settled | (2 | ) | | (a) |
| | (2 | ) | |
Accretion in 2016(b) | 25 |
| | (a) |
| | 25 |
| |
| Change in estimates | 1 |
| | — |
| | 1 |
| |
| Balance at December 31, 2016 | $ | 644 |
| (c) | $ | 6 |
| (d) | $ | 650 |
| (c) |
| Liabilities incurred | — |
| | — |
| | — |
| |
| Liabilities settled | (12 | ) | | (1 | ) | | (13 | ) | |
Accretion in 2017(b) | 26 |
| | (a) |
| | 26 |
| |
Change in estimates(e) | (18 | ) | | (1 | ) | | (19 | ) | |
| Balance at December 31, 2017 | $ | 640 |
| (c) | $ | 4 |
| (d) | $ | 644 |
| (c) |
| |
(b) | Ameren Missouri’s accretion expense was deferred as a decrease to regulatory liabilities. |
| |
(c) | Balance included $6 million and $15 million in “Other current liabilities” on the balance sheet as of December 31, 2017 and 2016, respectively.
|
| |
(d) | Included in “Other deferred credits and liabilities” on the balance sheet. |
| |
(e) | 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. |
Noncontrolling Interests
insurance policies at the balance sheet date. As of December 31, 2017 and 2016, Ameren’s noncontrolling interests included2023, the preferred stockcash surrender value of COLI at Ameren Missouri and Ameren Illinois was $248 million (December 31, 2022 – $246 million) and $111 million (December 31, 2022 – $118 million), respectively, while total borrowings against the policies were $104 million (December 31, 2022 – $110 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets. The net cash surrender value of Ameren’s COLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest.
Operating RevenueRevenues
The Ameren CompaniesWe record operating revenuerevenues from contracts with customers for various electric orand natural gas serviceservices, 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 itthe commodity is delivered to our customers. We accrue an estimate of electric and natural gas retail distribution revenues for service renderedprovided but unbilled at the end of each accounting period. Electric transmission revenues are earned as electric transmission services are provided. Off-system revenues are primarily comprised of MISO revenues and wholesale bilateral revenues. MISO revenues include the sale of electricity, capacity, and ancillary services. Wholesale bilateral revenues include the sale of electricity and capacity. MISO-related electricity and wholesale bilateral electricity revenues are earned as electricity is delivered. Capacity and ancillary service revenues are earned as services are provided.
Ameren Illinois participates inRetail distribution, electric transmission, and off-system revenues, including the performance-based formula ratemaking framework pursuantunderlying 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 IEIMAamounts billed and our estimate of electric and natural gas retail distribution services provided but
unbilled at the FEJA. In addition, Ameren Illinois’end of each accounting period. Customers are billed at least monthly, and ATXI’s electric transmission service operatingpayments are due less than one month after goods and/or services are provided. See Note 16 – Segment Information for disaggregated revenue information.
For certain regulatory recovery mechanisms that are alternative revenue programs rather than revenues from contracts with customers, we recognize revenues that have been authorized for rate recovery, are regulated by the FERC. The provisionsobjectively determinable and probable of the IEIMArecovery, and the FERC’s electric transmission formula rate framework provide for annual reconciliations of the electric distribution and electric transmission service revenue requirements necessaryare expected to reflect the actual recoverable costs incurred in a given year with the revenue requirements in customer rates for that year, including an allowed return on equity. In each of those electric jurisdictions, if the current year’s revenue requirement varies from the amountbe collected from customers an adjustment is made to electric operatingwithin two years from the end of the year. Our alternative revenue programs include revenue requirement reconciliations, the MEEIA, the VBA, and the WNAR. These revenues are subsequently recognized as revenues from contracts with customers when billed, with an offset to a regulatory asset or liabilityalternative revenue program revenues.
As of December 31, 2023 and 2022, our remaining performance obligations were immaterial. The Ameren Companies elected not to reflect that year’s actual revenue requirement. The regulatory balance is then collected from, or refunded to, customers within two years. See Note 2 – Rate and Regulatory Matters for information regarding Ameren Illinois’ revenue requirement reconciliation pursuantdisclose the aggregate amount of the transaction price allocated to the IEIMA.performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, Ameren Missouri, and Ameren Illinois using settlement information provided by the MISO. Ameren Missouri records these purchase and sale transactions on a net hourly position. Ameren Missouri records net purchases in a single hour in “Operating Expenses – Purchased power” and net sales in a single hour in “Operating Revenues – Electric” in its statement of income. Ameren Illinois records net purchases in “Operating Expenses – Purchased power” in its statement of income to reflect all of its MISO transactions relating to the procurement of power for its customers. On occasion, Ameren Missouri’s and Ameren Illinois’ prior-period transactions will be resettled outside the routine settlement process because of a change in the MISO’s tariff or a material interpretation thereof. In these cases, Ameren Missouri and Ameren Illinois recognize revenues and expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated. Revenues are recognized once the resettlement amount is received. There were no material MISO resettlements in 2017, 2016,2023, 2022, or 2015.
Nuclear Fuel
Ameren Missouri’s cost of nuclear fuel is capitalized 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.2021.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date based on the fair value of the award, net of an assumed forfeiture rate. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite vesting period. To the extent that actual forfeitures differ from estimated forfeitures, such differences are accounted for as an adjustment to compensation expense and recorded in the period that estimates are revised. Compensation cost is ultimately recognized only for awards for which the requisite service was provided. See Note 11 – Stock-based Compensation for additional information.
Excise Taxes
Ameren Missouri and Ameren Illinois collect from their customers certain excise taxes that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business. They are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas,” and “Operating Expenses – Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes for electric service in Illinois are levied on customers and are therefore not included in Ameren Illinois’ revenues and expenses. The following table presents the excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas,” and “Operating Expenses – Taxes other than income taxes” for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 153 |
| | $ | 151 |
| | $ | 156 |
|
| Ameren Illinois | 57 |
| | 57 |
| | 57 |
|
| Ameren | $ | 210 |
| | $ | 208 |
| | $ | 213 |
|
Unamortized Debt Discounts, Premiums, and Issuance Costs
Long-term debt discounts, premiums, and issuance costs are amortized over the lives of the related issuances. Credit agreement fees are amortized over the term of the agreement.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We expect that regulators will reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in certain excess deferred tax liabilities that were recorded because of decreases in the statutory rate have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery through future customer rates of tax benefits related to the equity component of allowance for funds used during construction, as well as the effects of tax rate increases. To the extent deferred tax balances are included in rate base, the revaluation of deferred taxes is recorded as a regulatory asset or liability on the balance sheet and will be collected from, or refunded to, customers. For deferred tax balances not included in rate base, the revaluation of deferred taxes is recorded as an adjustment to income tax expense on the income statement. See Note 12 – Income Taxes for further information regarding both the revaluation of deferred taxes related to the TCJA.
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 partysubsidiary be allocated an amount of tax using a stand-alone calculation which is similarratio to that which would bethe total amount of tax owed or refunded hadby the party been separately subject to tax considering the impact of consolidation.consolidated group. Any net benefit attributable to Ameren (parent) is reallocated to the other parties.subsidiaries. This reallocation is treated as a capital contribution to the partysubsidiary receiving the benefit. See Note 13 – Related-party Transactions for information regarding capital contributions under the tax allocation agreement.
Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number
Divestiture Transactions and Discontinued Operations
In December 2013 and January 2014, Ameren completed the divestiture of New AER and certain other assets. All matters related to the final tax basis of New AER and the related tax benefit resulting from its divestiture were resolved with the completion of the IRS audit of 2013. During 2015, based on the completion of the IRS audit of 2013, Ameren removed a reserve for unrecognized tax benefits of $53 million recorded in 2013 and recognized a tax benefit from discontinued operations. Ameren also paid $25 million and concluded its obligations with New AER.
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.
Revenue from Contracts with Customers
In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The underlying principle of the guidance is that an entity will recognize revenue for the transfer of promised goods or services to customers at an amount that the entity expects to be entitled to receive in exchange for those goods or services. The guidance requires additional disclosures to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, as well as separate presentation of alternative revenue programs on the income statement. Entities can apply the guidance to each reporting period presented (the full retrospective method), or they can record a cumulative effect adjustment to retained earnings in the period of initial adoption (the modified retrospective method).
We have completed the evaluation of our contracts. Adoption of this guidance will not result in material changes to the amount or timing of revenue recognition. We will apply the guidance using the full retrospective method. We will include disaggregated revenue disclosures by segment and customer class in the combined notes to the financial statements. This guidance will be effective for the Ameren Companies for the first quarter of 2018.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement 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 benefit cost separately from the service cost component and outside of operating income. Our adoption of this guidance will result in the reclassification of 2017 net benefit income of $44 million, $22 million, and $10 million, currently presented as a reduction of "Other operations and maintenance expense," on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income. These amounts will be presented outside of operating income. Similarly, 2016 net benefit income of $55 million, $18 million, and $24 million, currently presented as a reduction of "Other operations and maintenance expense" on Ameren's, Ameren Missouri's, and Ameren Illinois' respective statements of income, will also be reclassified and presented outside of operating income.
The guidance also permits 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. This guidance will be effective for the Ameren Companies in the first quarter of 2018. See Note 10 – Retirement Benefits for the components of net benefit cost.
Restricted Cash
In November 2016, the FASB issued authoritative guidance that requires restricted cash and restricted cash equivalents 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. We are currently assessing the impacts of this guidance on our statements of cash flows and disclosures. The guidance will be effective for the Ameren Companies in the first quarter of 2018, and requires changes to be applied retrospectively to each period presented.
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 will be effective for the Ameren Companies in the first quarter of 2018, and requires changes to be applied retrospectively. For Ameren and Ameren Illinois, the adoption of this guidance will result in the retrospective reclassification from operating activities to financing activities of $7 million of bond premiums received in 2016.
Financial Instruments – Recognition and Measurement, and Credit Losses
In January 2016, the FASB issued authoritative guidance that addressed certain aspects of recognition, measurement, presentation and disclosure of financial instruments. This guidance requires an entity to measure equity investments, other than those accounted for under the equity method of accounting, at fair value and to recognize changes in fair value in net income. The adoption of this guidance will not have a material impact on our results of operations or financial position. The recognition, measurement, and disclosure guidance will be effective for the Ameren Companies in the first quarter of 2018. The guidance requires changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date.
In June 2016, the FASB issued authoritative guidance that requires an entity to recognize an allowance for financial instruments that reflects its current estimate of credit losses expected to be incurred over the life of the financial instruments. 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 assessing the impacts of this guidance on our results of operations, financial position, and disclosures. The credit loss guidance will be effective for the Ameren Companies in the first quarter of 2020. It requires changes to be applied retrospectively with a cumulative effect adjustment to retained earnings as of the adoption date.
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. Consistent with 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. This guidance will affect the Ameren Companies’ financial position by increasing the assets and liabilities recorded relating to their operating leases, which will be recognized and measured at the beginning of the earliest period presented. Other arrangements not previously accounted for as leases may be required to be accounted for as leases; these arrangements would similarly result in increases to assets and liabilities recorded. We are currently assessing our arrangements to determine those that are within the scope of this guidance. We are also
assessing the impacts of this guidance for effects on our results of operations, cash flows, and disclosures. 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.
Reclassification of Certain Tax Effects from Accumulated OCI
In February 2018, the FASB issued authoritative guidance allowing a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the TCJA. This optional reclassification can be applied retrospectively to December 31, 2017, or in the period of adoption. We are currently assessing whether we will elect to perform such a reclassification and the potential impact.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of our regulatory frameworks and significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the effect on our results of operations, financial position, or liquidity.
Regulatory Frameworks
The following table presents the regulatory frameworks and significant regulatory recovery mechanisms for each of Ameren’s rate-regulated businesses, which are discussed in more detail below:
| | | | | | | | | | | | | | |
| Ameren Missouri | Ameren Illinois’ electric distribution business | Ameren Illinois’ natural gas delivery business | Ameren Illinois’ and ATXI’s electric transmission businesses |
| Regulatory framework | •Historical test year ratemaking •Natural gas revenues for residential customers adjusted for sales volume deviations resulting from weather through the WNAR
| •MYRP(a) •Initial rates based on future test years •Revenues decoupled from sales volumes | •Future test year ratemaking •Revenues for residential and small nonresidential customers decoupled from sales volumes through the VBA
| •Formula ratemaking •Initial rates based on future test year •Revenues decoupled from sales volumes |
| Regulatory mechanisms | •PISA
Riders: •RESRAM •FAC •MEEIA •PGA •WNAR
Trackers: •Pension and postretirement benefit costs •Certain excess deferred income taxes •Renewable energy standard costs •Property taxes •Production and investment tax credits or proceeds from the sale of certain tax credits allowed under the IRA
| •Electric distribution service and energy-efficiency revenue requirement reconciliation adjustments(b)
Riders: •Power procurement •Transmission services •Renewable energy credit compliance •Zero emission credits •Certain environmental costs •Bad debt write-offs •Costs of certain asbestos-related claims | Riders: •QIP(c) •PGA •VBA •Energy-efficiency program costs •Certain environmental costs •Bad debt write-offs •Invested capital taxes | •Revenue requirement reconciliation adjustment |
(a)Ameren Illinois used the IEIMA performance-based formula ratemaking framework to establish annual electric distribution customer rates effective through 2023. In December 2023, the ICC approved an MYRP to establish rates effective 2024 through 2027. See below for additional information regarding the MYRP approved in December 2023.
(b)Reconciliation adjustments under an MYRP are subject to a reconciliation cap which limits annual adjustment to 105%. See below for additional information regarding the reconciliation cap.
(c)The QIP expired in December 2023. Reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP from 2020 to 2023 are ongoing.
Missouri
March 2017 Electric Rate Order
In March 2017, theThe MoPSC issued an order approving a unanimous stipulationregulates rates and agreement inother matters for Ameren Missouri’s July 2016electric service and natural gas distribution businesses. The rates Ameren Missouri charges customers for these services are established in a traditional regulatory rate review. The order resulted inreview, which takes up to 11 months to complete, based on a $3.4 billion revenue requirement, which was a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared withhistorical test year and the prior revenue requirement established in the MoPSC’s April 2015review.
Ameren Missouri has recovery mechanisms, including the RESRAM, FAC, MEEIA, PGA, and WNAR, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, along with the PISA, each described in more detail below, partially mitigate the effects of regulatory lag. Ameren Missouri also employs other recovery mechanisms, including a renewable energy standard cost tracker, as well as electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017.
The order authorized the continued use of the FAC and the regulatory tracking mechanismsnatural gas trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, property taxes, and renewable energy standards thatpension and postretirement benefit costs. Each of these trackers allows Ameren Missouri to defer the MoPSC authorizeddifference between actual costs incurred and costs included in earlier electric rate orders. Thesecustomer rates as a regulatory tracking mechanisms provide for a base level of expenseasset or regulatory liability, with the difference expected to be reflected in base rates in a subsequent MoPSC rate order. Ameren Missouri also employs a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. Production and investment tax credits produced by renewable energy centers that support compliance with the state of Missouri’s renewable energy standard, such as the High Prairie Renewable and Atchison Renewable energy centers, are not eligible for tracking under this mechanism as they are included in the RESRAM. Ameren Missouri’s cost recovery under any of its recovery mechanisms is subject to MoPSC prudence reviews.
The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense for investments in qualifying property, plant, and equipment placed in service and not included in base electric ratesrates. Investments not eligible for recovery under the PISA include amounts related to new nuclear and natural gas generating units and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC until added to rate base prospectively. Ameren Missouri recognizes an offset to “Interest Charges” on its consolidated statement of income for its carrying cost of debt relating to each return allowed under the PISA, with differencesthe difference between the base amountapplicable WACC and its carrying cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service to comply with Missouri’s renewable energy standard. The RESRAM deferrals are a regulatory asset until they are included in customer rates and collected in a subsequent period. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. The rate increase approved by the June 2023 MoPSC electric rate order discussed below did not exceed the rate increase limitation applicable through 2023. Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through December 2028 and an additional extension through December 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things. This law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates, compared to the revenue requirement established in the immediately preceding rate order, due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024.
The RESRAM permits Ameren Missouri to recover or refund, through customer rates, the difference between the cost of compliance, net of federal production and investment tax credits, with Missouri’s renewable energy standard and the amount set in base rates. Effective February 28, 2022, all sales from the High Prairie Renewable and Atchison Renewable energy centers are included in the RESRAM. Previously, 95% of these sales were included in the FAC and 5% were included in the RESRAM. Customer rates are adjusted for the RESRAM on an annual basis without a traditional regulatory rate review, subject to MoPSC prudence reviews. The difference between actual expenses incurredcompliance costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. ExcludingThe deferred amount is either billed or refunded to customers in a subsequent period. RESRAM regulatory assets earn carrying costs at short-term interest rates. The RESRAM permits Ameren Missouri to recover investments in wind generation and other renewables related to compliance with Missouri’s renewable energy standard, and earn a return at the applicable WACC on those investments not already provided for in customer rates or any other recovery mechanism, such as the renewable energy standard cost reductionstracker. The renewable energy standard cost tracker allows Ameren Missouri to defer differences between actual costs primarily associated with reduced sales volumes, the base levelMaryland Heights Energy Center and renewable energy credits obtained through a 102-MW power purchase agreement with a wind farm operator, which expires in August 2024, and those costs included in customer rates.
The FAC permits Ameren Missouri to recover or refund, through customer rates, 95% of the variance in net energy costs decreased by $54 million from the amount set in base level established in the MoPSC’s April 2015 electricrates without a traditional regulatory rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC’s April 2015 electric rate order.
MEEIA
In November 2016, thereview, subject to 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 will collect the performance incentive over a two-year period that began in February 2017.
In November 2015, the MoPSC issued an order regarding the determination of a certain input used to calculate the performance incentive. Ameren Missouri filed an appeal of the orderprudence reviews, with the Missouri Courtremaining 5% of Appeals, Western District. In December 2016, the Missouri Court of Appeals, Western District, upheld the November 2015 MoPSC order.changes retained by Ameren Missouri then appealed that decision to the Missouri Supreme Court. If the decision is overturned, Ameren Missouri would recognize an additional $9 million MEEIA 2013 performance incentive.
The MEEIA 2016 program provided 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 were achieved during the three-year period, with the potential to earn more ifMissouri. As such, Ameren Missouri’s energy savings exceeded those goals. In September 2017, Ameren Missouri received an order fromresults of operations are affected by the MoPSC approving Ameren Missouri’s energy savings results for the first year of the MEEIA 2016 programs. As a result of this order and in accordance with revenue recognition guidance, Ameren Missouri will recognize $5 million of additional revenues in the first quarter of 2018 relating to the MEEIA 2016 performance incentive.
MoPSC Federal Income Tax Proceeding
In February 2018, the MoPSC initiated proceedings to investigate how the effect of the reduction in the federal statutory corporate income tax rate enacted5% not recovered or refunded under the TCJA should be reflectedFAC. The 95% variance in rates paid by customers of Missouri’s regulated utilities, including rates paid by electric and natural gas customers of Ameren Missouri. At this time, Ameren Missourinet energy costs in a given period is unable to predict the timing or the magnitude of any impact on its electric and natural gas rates that may result from the ultimate resolution of this matter.
ATXI’s Mark Twain Project
The Mark Twain project is a MISO-approved transmission line to be located in northeast Missouri with an expected investment of $250 million. In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with Ameren Missouri and an electric cooperative in northeast Missouri to locate almost all of the Mark Twain project on existing line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to begin construction in the second quarter of 2018 and to complete the project by the end of 2019.
Illinois
IEIMA & FEJA
Under a formula ratemaking framework effective through 2022, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. The formula ratemaking framework qualifiesdeferred as an alternative revenue program under GAAP. Each year, Ameren Illinois records a regulatory asset or a regulatory liability, and either billed or refunded to customers in a corresponding increase or decreasesubsequent period. FAC regulatory assets earn carrying costs at short-term interest rates. Ameren Missouri’s base rates for electric service are required to operating revenuesbe reset at least every four years to allow for continued use of the FAC.
The MEEIA permits Ameren Missouri to recover customer energy-efficiency program costs, the related lost electric margins, and any differences betweenperformance incentive through the MEEIA without a traditional regulatory rate review, subject to MoPSC prudence reviews. MEEIA assets earn carrying costs at short-term interest rates.
Ameren Missouri is a member of the MISO, and its transmission rate is calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. The FERC regulates the rates charged and the terms and conditions for wholesale electric transmission service. The transmission rate update each June is based on Ameren Missouri’s actual historical cost from the prior calendar year. This rate is not directly charged to Missouri retail customers because, in Missouri, the revenue requirement reflectedused to set bundled retail base rates includes an amount for transmission-related costs and revenues.
The PGA allows Ameren Missouri to recover costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review, subject to MoPSC prudence reviews. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins, as any change in customercosts is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The WNAR allows Ameren Missouri to adjust natural gas delivery service rates for that year and its estimatecharged to residential customers without a traditional regulatory rate review when
deviations from normal weather conditions cause natural gas revenues to vary from the probable increase or decrease in therelated revenue requirement expected to ultimately be approved by the ICC. AsMoPSC in the previous regulatory rate review. The impact of December 31, 2017, Ameren Illinois had recorded regulatory assets of $54 million and $24 million, including interest, to reflect its expected 2017 and its approved 2016 revenue requirement reconciliation adjustments, respectively. As of December 31, 2016, Ameren Illinois had recorded a $68 million regulatory asset to reflect its approved 2015 revenue requirement reconciliation adjustment, which was collected, with interest,deviations from customers during 2017.
In December 2017, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $17 million decrease in Ameren Illinois’ electricnormal weather on natural gas delivery service revenue requirement beginning in January 2018. This update reflected an increaserevenues billed to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, as well as an increase to include the 2016 revenue requirement reconciliation adjustment. The increases in the update filing were more than offset by a decrease for the conclusion of the 2015 revenue requirement reconciliation adjustment, which was fully collected fromresidential customers in 2017, consistent with the ICC’s December 2016 annual update filing order.
The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking framework through 2022, and clarifying 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 distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as 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 previous revenue recognition method resulted in more revenue during the third quarter and less revenue during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed the method it uses to recognize interim-period revenue. Ameren Illinois now recognizes revenue consistent with the timing of actual incurred electric distribution recoverable costs, and it recognizes revenue associated with the expected return on its rate base ratably over the year. The decoupling provisions of the FEJA do not expire at the end of 2022.
The FEJA allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset or liability. WNAR regulatory assets earn carrying costs at short-term interest rates. The deferred amount is either billed or refunded to residential customers in a subsequent period.
Illinois
The ICC regulates rates and earnother matters for Ameren Illinois’ electric distribution service and natural gas distribution businesses. Ameren Illinois used the IEIMA formula framework to establish annual customer electric distribution service rates effective through 2023. Under the framework, Ameren Illinois is allowed to reconcile its revenue requirement for customer rates established through 2023. Ameren Illinois’ 2021, 2022, and 2023 revenues reflected each year’s actual recoverable costs, year-end rate base, and a return at the company’s weighted-average cost of capital,applicable WACC, with the equity returnROE component based on the annual average of the monthly average yieldyields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion2022 and 2023 revenue requirement reconciliation adjustments will be collected from customers within two years from the end of the reconciled year. By law, the decoupling provisions extend beyond 2023, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. The rates Ameren Illinois charges customers for natural gas distribution service are established in a traditional regulatory rate review, which takes up to 11 months to complete, based on a future test year and the revenue requirement established in the review.
Ameren Illinois’ electric distribution service has cost recovery mechanisms in place that allow customer rates to be adjusted without an MYRP or a traditional regulatory rate review. Ameren Illinois’ electric distribution service business has riders for power procurement and transmission services incurred on behalf of its customers, renewable energy credit compliance, zero emission credits, and certain environmental costs, as well as bad debt write-offs and the costs of certain asbestos-related claims not recovered in base rates. These pass-through costs do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
Pursuant to the CEJA, Ameren Illinois may elect to establish electric distribution service rates through either an MYRP or a traditional regulatory rate review for 2024 and beyond. See below for additional information regarding the MYRP approved by the ICC in December 2023, which established rates effective 2024 through 2027. Under the MYRP, Ameren Illinois will reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs are excluded from the reconciliation cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and amortization of certain assets. The reconciliation cap also excludes costs recovered outside of base rates through riders, such as those described above and the electric energy-efficiency rider discussed below, among others. Ameren Illinois’ existing riders remain effective and electric distribution service revenues continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year incorporates Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the resulting revenue requirement does not exceed the 105% reconciliation cap and the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. Subject to the reconciliation cap, if a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the applicable annual period. Regulatory assets applicable to the MYRP earn a return at the applicable WACC. However, Ameren Illinois recognizes the carrying cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates.
Ameren Illinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for its electric energy-efficiency investments, the revenue requirements are based on recoverable costs, year-end rate base, and a year-end ratemaking capital structure, and earn a return at the applicable WACC. The ROE component of the applicable WACC is based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points and any performance-related basis-point adjustments, described in more detail below. Therefore, Ameren Illinois’ annual ROE for its electric energy-efficiency investments is directly correlated to the yields on such bonds. Regulatory assets applicable to formula ratemaking for electric energy-efficiency investments earn a return at the applicable WACC. However, Ameren Illinois recognizes the carrying cost of debt on these regulatory assets in revenue, instead of the applicable WACC, with the difference recognized in revenues when recovery of such regulatory assets is reflected in customer rates.
Ameren Illinois’ electric distribution service business is also subject to performance metrics. Failure to achieve the metrics would result in a reduction in the company’s allowed ROE calculated under the MYRP. In 2022, the ICC issued an order approving total ROE incentives and penalties of 24 basis points under the MYRP, allocated among seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of
spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above. In addition, the allowed ROE on energy-efficiency investments can be increased or decreased 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 2023, 2022, and 2021, there were no performance-related basis-point adjustments that materially affected financial results.
Ameren Illinois’ natural gas distribution business has recovery mechanisms, including the PGA and VBA, that allow customer rates to be adjusted without a traditional regulatory rate review. These riders, described in more detail below, mitigate the effects of regulatory lag. Ameren Illinois employs other riders for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt write-offs and invested capital taxes not recovered in base rates. Pass-through costs under the riders do not affect Ameren Illinois’ net income, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois’ cost recovery under any of its recovery mechanisms is subject to ICC prudence reviews.
The FEJAPGA allows Ameren Illinois to recover costs of natural gas purchased on behalf of its customers without a traditional regulatory rate review, subject to ICC prudence reviews. These pass-through purchased gas costs do not affect Ameren Illinois natural gas margins, as any change in costs is offset by a corresponding change in revenues. The difference between actual natural gas costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is either billed or refunded to customers in a subsequent period. PGA regulatory assets earn carrying costs at short-term interest rates. The VBA ensures recoverability of the natural gas distribution service revenue requirement that is dependent on sales volumes for residential and small nonresidential customers. For these rate classes, the VBA allows Ameren Illinois to adjust natural gas distribution service rates without a traditional regulatory rate review when changes occur in sales volumes from those volumes approved by the ICC in a previous regulatory rate review. The difference between allowed sales revenues and amounts billed to customers in a given period is deferred as a regulatory asset or liability. The deferred amount is collected from, or refunded to, customers in a subsequent period. VBA regulatory assets for a given year that are not fully collected by the end of the following year begin earning carrying costs at short-term interest rates.
The QIP expired in December 2023. Previously, it provided Ameren Illinois with recovery of, and a return on, qualifying natural gas infrastructure investments that were placed in service between regulatory rate reviews. Infrastructure investments under the QIP earned a return at the applicable WACC. Eligible natural gas investments included projects to improve safety and reliability and modernization investments, such as smart meters. The deferrals were recorded as a regulatory asset, with recovery beginning two months after the qualifying natural gas plant was placed in service and continuing until such plant was included in base rates in a natural gas delivery service rate order. Ameren Illinois’ QIP was subject to a rate impact limitation of a cumulative 4% per year since the most recent delivery service rate order, with no single year exceeding 5.5%. Ameren Illinois did not exceed the rate impact limitation in 2023. Upon issuance of a natural gas delivery service rate order, QIP rate base was transferred to base rates and the QIP was reset to zero. Reconciliation hearings to determine the accuracy and prudence of natural gas capital investments recovered under the QIP are still ongoing. See below for additional information on the recovery of capital investments that were made during 2020.
Federal
The FERC regulates rates and other matters for Ameren Illinois’ transmission business and ATXI, as well as for Ameren Missouri. See the discussion above related to Ameren Missouri. Both Ameren Illinois and ATXI are members of the MISO, and their transmission rates are calculated in accordance with the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff. Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated annually and become effective each January with forecasted information. The formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed ROE. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is collected from, or refunded to, customers within two years from the end of the year. FERC revenue requirement reconciliation adjustment regulatory assets earn carrying costs at each company’s short-term interest rates. In addition, the FERC has approved transmission rate incentives, including a 50-basis-point incentive adder to the allowed base ROE for Ameren Illinois and ATXI for participation in an RTO.
Proceedings and Updates
Missouri
June 2023 MoPSC Electric Rate Order
In June 2023, the MoPSC issued an order in Ameren Missouri’s 2022 electric service regulatory rate review, approving a nonunanimous stipulation and agreement. The order resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The approved revenue requirement was based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to 2030. The order did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard compliance costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker. It also includes a tracker for the utilization of production and investment tax credits or proceeds from the sale of such tax credits allowed under the IRA. Production and investment tax credits produced by renewable energy centers that support compliance with the state of Missouri’s renewable energy standard, such as the High Prairie Renewable and Atchison Renewable energy centers, are not eligible for tracking under this mechanism as they are included in the RESRAM. The order increased the annualized base level of electric energy-efficiency saving targets through 2030. In June 2017,net energy costs pursuant to the FEJA,FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023.
Solar Generation Facilities
During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities, which, if placed in-service, would be eligible for recovery under the PISA. The following table provides information with respect to each agreement:
| | | | | | | | | | | | | | | | | | | | |
| Huck Finn Solar Project(a)(b) | Boomtown Solar Project(b)(c) | Split Rail Solar Project(d) | Cass County Solar Project(c) | Vandalia Solar Project(d) | Bowling Green Solar Project(d) |
| Agreement type | Build-transfer | Build-transfer | Build-transfer(e) | Development-transfer(e)(f) | Self-build(e)(g) | Self-build(e)(g) |
| Facility size | 200-MW | 150-MW | 300-MW | 150-MW | 50-MW | 50-MW |
| Status of MoPSC CCN | Approved February 2023 | Approved April 2023 | Filed June 2023(h) | Filed June 2023(h) | Filed June 2023(h) | Filed June 2023(h) |
| Status of FERC approval of acquisition | Received March 2023 | Received October 2023 | Expect to request by mid-2024 | Not applicable | Not applicable | Not applicable |
Earliest completion date(i) | Fourth quarter 2024 | Fourth quarter 2024 | Mid-2026 | Fourth quarter 2024 | Fourth quarter 2025 | First quarter 2026 |
(a)The Huck Finn Solar Project is expected to support Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Investments in the project will be eligible for recovery under the RESRAM.
(b)These projects collectively represent approximately $0.65 billion of expected capital expenditures.
(c)The Boomtown and Cass County solar projects are expected to support Ameren Missouri’s transition to renewable energy generation and serve customers under the Renewable Solutions Program discussed below.
(d)These solar projects are expected to support Ameren Missouri’s transition to renewable energy generation.
(e)These projects, and applicable agreements, are subject to the issuance of a CCN by the MoPSC.
(f)Ameren Missouri entered into an agreement to acquire the Cass County Solar Project, which includes project design, land rights, and engineering, procurement, and construction agreements for a solar generation facility. Ameren Missouri will construct the facility after obtaining a CCN from the MoPSC and acquiring the project. Acquisition of the project is expected by mid-2024.
(g)Ameren Missouri entered into engineering, procurement, and construction agreements to construct these solar projects.
(h)In February 2024, Ameren Missouri, the MoPSC staff, andthe MoOPC filed a nonunanimous stipulation and agreement requesting the MoPSC approve Ameren Missouri’s requests for CCNs for the Split Rail, Vandalia, and Bowling Green solar projects. The stipulation and agreement also requests MoPSC approval of the CCN request for the Cass County Solar Project conditioned upon the facility supporting the Renewable Solutions Program discussed below and full subscription of the portion of the program supported by this facility, subject to certain other terms and conditions. The remaining intervenors did not object to the agreement. Ameren Missouri expects a decision by the MoPSC in March 2024.
(i)Expected completion dates are dependent on the timing of regulatory approvals, among other things.
Renewable Solutions Program
The April 2023 MoPSC order approving the CCN for the Boomtown Solar Project also approved Ameren Missouri’s Renewable Solutions Program and a tariff related to participation in the program. The program allows certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. Separate enrollment occurs for each
renewable resource serving customers under the program. Collection under the tariff will not begin until the Boomtown Solar Project is placed in service.
MoPSC Staff Review of Planned Rush Island Energy Center Retirement
In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center as a result of the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies. The MoPSC staff’s review includes potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. Ameren Missouri is unable to predict the results of this matter. Results of the review could be used in the securitization proceeding discussed below, which could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri if Ameren Missouri is not allowed to recover Rush Island costs through securitization.
Securitization of Rush Island Energy Center Costs
In November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility. Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance. In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request. However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews. If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.
MEEIA
In August 2023, the MoPSC issued an order approving a nonunanimous stipulation and agreement to extend Ameren Missouri’s MEEIA 2019 program for an additional year through 2024. For 2024, the order approved the establishment of a portfolio of customer energy-efficiency programs and performance incentives that will provide Ameren Missouri an opportunity to earn revenues, including $12 million of performance incentive revenues if Ameren Missouri achieves certain program spending goals. In 2024, Ameren Missouri expects to invest $76 million in energy-efficiency programs.
In December 2023 and 2022, Ameren Missouri achieved certain energy-efficiency spending goals for the MEEIA 2019 program. As a result of achieving these spending goals and MoPSC orders issued in August 2022 and September 2021, Ameren Missouri recognized performance incentive revenues of $12 million, $22 million, and $9 million in 2023, 2022, and 2021, respectively.
In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA. This filing proposed a three-year plan, which includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027. In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals. If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan. Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals. Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.
Illinois
MYRP
In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding. Rate changes consistent with the order became effective in January 2024. The ICC concluded that the proposed Grid Plan did not meet certain statutory
requirements and directed Ameren Illinois to file a revised Grid Plan within three months. Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024. The ICC will be under no deadline to act on the revised Grid Plan when filed. The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027, using the 2022 year-end rate base approved by the ICC in its 2022 electric distribution service revenue requirement reconciliation adjustment order discussed below. This rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement.
In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order. The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA. In addition, the filing requested the ICC revise the order to include an energy-efficiency planallowed ROE of at least 9.82% for 2018each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things. In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP. Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP. In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements and annual rate base amounts to reflect a base level of investments to maintain grid reliability for 2024 through 2021. 2027. An ICC decision in this rehearing is expected by late June 2024. Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District.
The following table presents the approved revenue requirements, ROE, capital structure common equity percentage, and annual rate base in the ICC’s December 2023 order, as well as the proposed revenue requirements and annual rate base amounts in Ameren Illinois’ February 2024 rehearing request filing:
| | | | | | | | | | | | | | |
| Year | Revenue Requirement (in millions) | ROE | Capital Structure Common Equity Percentage | Annual Rate Base (in billions) |
| ICC’s December 2023 MYRP Order: | | | | |
| 2024 | $1,162 | 8.72% | 50% | $3.9 |
| 2025 | $1,210 | 8.72% | 50% | $3.9 |
| 2026 | $1,242 | 8.72% | 50% | $3.9 |
| 2027 | $1,255 | 8.72% | 50% | $3.9 |
| Ameren Illinois’ February 2024 Rehearing Request Filing: | | | | |
| 2024 | $1,214 | (a) | 50% | $4.2 |
| 2025 | $1,300 | (a) | 50% | $4.5 |
| 2026 | $1,371 | (a) | 50% | $4.7 |
| 2027 | $1,420 | (a) | 50% | $4.9 |
(a)The ROE is under appeal as discussed above.
The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing. The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase.
2022 Electric Distribution Revenue Requirement Reconciliation Adjustment Order
In September 2017,November 2023, the ICC issued an order approving Ameren Illinois’ implementation2022 electric distribution service revenue requirement reconciliation adjustment filing. This order approved a reconciliation adjustment of the FEJA electric energy-efficiency savings targets$110 million, which reflected Ameren Illinois’ actual 2022 recoverable costs, year-end rate base of $3.9 billion, and investments. Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030.a capital structure composed of 50% common equity. 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 investmentsapproved reconciliation adjustment will be collected from customers through a rider; theyin 2024. In addition, Ameren Illinois will not be included in the IEIMA formula ratemaking framework.
Income Tax Regulatory Mechanisms
In February 2018,file its 2023 electric distribution service revenue requirement reconciliation with the ICC granted Ameren Illinois’ request, filed in January 2018, to establish a rider to pass through to Ameren Illinois’ electric distribution customers the reduction in the federal statutory corporate income taxby May 2024, which will reflect its 2023 year-end rate enacted under the TCJA and the return of excess deferred taxes, net of the increase in state income taxes enacted in July 2017. Ameren Illinois' electric distribution customers will receive up to an estimated $50 million per year through the rider beginning in the first quarter of 2018 and continuing through 2019. Absent
this rider, Ameren Illinois' electric distribution customers would not benefit from Ameren Illinois' reduced income tax liability until 2020, at which time the net reduction in income taxes would have been reflected in customer rates through the revenuebase. The 2023 reconciliation process.
In January 2018, the ICC initiated a proceeding to require that Ameren Illinois record a regulatory liability, beginning January 25, 2018, for the net amount of the difference between revenues billed under natural gas rates in effect, pursuant to Ameren Illinois’ most recent natural gas rate order, and the revenues that would have been billed had the state and federal tax rate changes been in effect. In February 2018, Ameren Illinois filed a response to the ICC seeking approval of a rider that calculates such differences, specifically by evaluating the return of excess deferred taxes and income taxes included in the revenue requirement prior to the reduction in the federal statutory corporate income tax rate enacted under the TCJA and the increase in state income taxes enacted in July 2017. Ameren Illinois’ natural gas customers may receive up to an estimated $16 million through the proposed rider, or through some other tariffadjustment, if approved by the ICC, over a one-year periodwill be collected from customers in 2025.
Electric Customer Energy-Efficiency Investments
In November 2023, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $100 million beginning in May 2018.January 2024, which represents an increase of $24 million from 2023 rates. The order was based on a projected 2024 year-end rate base of$394 million.
2023 Natural Gas Delivery Service Regulatory Rate ReviewOrder
In January 2018, Ameren Illinois filed a request withNovember 2023, the ICC seeking approvalissued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to increase its annual revenues for natural gas delivery service by $49of $112 million which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider. The request was based on a 10.3% return on common equity,9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of $1.6approximately $2.85 billion. The order reflected a reduction of approximately $93 million of planned distribution and transmission capital investments included in Ameren Illinois’ requested revenue increase, which used a 2024 future test year. The new rates became effective on November 28, 2023.
In December 2023, Ameren Illinois filed a request reflectsfor rehearing of the ICC's November 2023 order. The filing requested the ICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and transmission capital investments included in the federal corporate income tax rate as a resultorder, among other things. In January 2024, the ICC denied Ameren Illinois’ rehearing request. Subsequently, in January 2024, Ameren Illinois filed an appeal of the TCJA,November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District. The court is under no deadline to address the appeal. Ameren Illinois cannot predict the ultimate outcome of this appeal.
The ICC’s November 2023 natural gas delivery service rate order also required Ameren Illinois to submit a plan outlining how it expects to comply with new PHMSA rules for natural gas transmission pipelines, including proposing a capital expenditures plan necessary to meet the new rules. In February 2024, Ameren Illinois filed its plan with the ICC, which included its proposal of natural gas transmission capital expenditures necessary to achieve compliance with the PHMSA rules. The plan includes delays to certain natural gas transmission capital expenditures from 2024 to subsequent years to align with the November 2023 ICC order. The ICC is under no obligation to issue an order regarding Ameren Illinois’ plan.
Future of Gas Proceeding
The ICC’s November 2023 natural gas delivery service rate order discussed above directed the ICC staff to develop a plan for a future of gas proceeding. All of the Illinois natural gas utilities subject to ICC regulation will be included in this proceeding, which will explore issues involved with decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA. Some of the issues expected to be addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others.
QIP Reconciliation Hearing
In March 2021, Ameren Illinois filed a request with the ICC for a reconciliation hearing to determine the accuracy and prudence of natural gas capital investments recovered under the QIP rider during 2020. In October 2023, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2020, alleging that the ICC should disallow approximately $53 million in natural gas capital investments as well asimproper and imprudent, providing a potential over-recovery of approximately $3 million in 2020. In October 2023, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2020. Ameren Illinois’ 2020 QIP rate recovery request under review by the ICC was within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding. Ameren Illinois cannot predict the ultimate outcome of this regulatory proceeding.
RTO Cost-Benefit Study
In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from the MISO’s April 2022 capacity auction, the ICC issued an order requiring Ameren Illinois to perform a cost-benefit study of continued participation in the Illinois corporate income tax rate that became effectiveMISO compared to participation in PJM Interconnection LLC, another RTO. In July 2017. In an attempt to reduce regulatory lag,2023, Ameren Illinois usedfiled its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a 2019 future test yearperiod of five to 10 years beginning June 2024. The study concluded that continued participation in this proceeding.the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. Intervenor comments on the study were filed in October 2023 and reply comments were filed in November 2023. In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership. The ICC is under no obligation to issue an order related to the cost-benefit study.
MISO Long-Range Transmission Projects CCN
In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed below that are expected to be constructed within the ICC’s jurisdiction. A decision by the ICC is expected by February 2025.
Federal
MISO Transmission Rate Incentives
In July 2022, the MISO approved the first tranche of projects related to a preliminary long-range transmission planning roadmap of projects through 2039. A portion of these projects were assigned to various utilities, including Ameren. The projects assigned to Ameren are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. In October 2023, the FERC issued an order that approved transmission rate incentives relating to the projects assigned to Ameren. The incentives will allow construction work in this proceeding is required by December 2018, with new rates expectedprogress to be effectiveincluded in January 2019. Ameren Illinois cannot predictrate base for projects constructed by ATXI, thereby improving the leveltimeliness of cash recovery, and would allow recovery of prudently incurred costs, subject to FERC approval, for any delivery service rate changesportion of the ICC may approve, nor whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and to earnprojects if they are abandoned for reasons beyond the control of Ameren. As a reasonable return on investments when the rate changes go into effect.
ATXI’s Illinois Rivers Project
In August 2017, the Illinois Circuit Court for Edgar County dismissed severalresult of ATXI’s condemnation cases related to one line segment in the Illinois Rivers project. The estimated line segment capital expenditure investment is approximately $85 million, of which $36 million was invested as of December 31, 2017. 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 given to the relevant landowners during the underlying ICC proceeding. In November 2017, ATXI appealed this decision to the Illinois Supreme Court. ATXI plans to complete the project by the end of 2019; however, delays associated with the condemnation proceedings or an appeal arising from the order, dismissingATXI will not capitalize allowance for funds used during construction on the Edgar County cases could delay the completion date. The other eight line segments of the Illinois Rivers project are not affected by these proceedings.
Federalrelated projects.
FERC Complaint Cases
InSince 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%has been subject to 9.15%.customer complaint cases and has been changed by various FERC orders. In September 2016,May 2020, the FERC issued a finalan order, in the November 2013 complaint case, which loweredset the allowed base return on common equityROE to 10.02%, and required refunds, with interest, for the 15-month period ofperiods November 2013 to February 2015 to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. In 2017,and from late September 2016 forward. Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the November 2013 complaint case. The 10.82% total allowed return on common equity has been reflected in rates since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.
Since 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 seeks a further reduction in the allowed base return on common equity for FERC-regulated transmission rate base under the MISO tariff.paid these refunds, including interest, by March 31, 2022. 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.The timing of the issuance of the final order in the February 2015 complaint case is uncertain for two reasons. First, while the FERC reestablished a quorum of commissioners in August 2017 after six months without a quorum, the FERC is under no deadline to issue a final order. Second, in the second quarter of 2017, the United States Court of Appeals for the District of
Columbia Circuit vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. Ameren is unable to predict the impact of the outcome of the United States Court of Appeals for the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time.
In September 2017, MISO transmission owners, includingJuly 2020, Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. The MISO transmission owners maintain that the February 2015 complaint was predicated on the premise that the now superseded 12.38% allowed base return on common equity was an unjust and unreasonable return 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 byas well as various customers, petitioned the United States Court of Appeals for the District of Columbia Circuit as discussed above.for review of the May 2020 order, challenging certain aspects of the new ROE methodology established. The petition filed by Ameren Missouri, Ameren Illinois, and ATXI challenged the refunds required for the period from September 2016 to May 2020. In August 2022, the court issued a ruling that granted the customers’ petition for review, vacated the FERC’s previous MISO ROE-determining orders, and remanded the proceedings to the FERC. The court elected not to rule on the issues raised by Ameren Missouri, Ameren Illinois, and ATXI. The currently allowed base ROE of 10.02% will remain effective for customer billings, but the transmission rates charged during previous periods and the currently effective rates may be subject to refund if the base ROE is changed by the FERC in a future order. The FERC is under no deadline to issue an order on this motion.
As of December 31, 2017, Ameren and Ameren Illinois recorded current regulatory liabilities of $42 million and $25 million, respectively,related to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reductionthese proceedings. A 50-basis-point change in the FERC-allowed base return on common equityROE would be material to its results of operations, financial position, or liquidity.
MISO Federal Income Tax Proceeding
In February 2018, MISO transmission owners with forward-looking rate formulas, includingaffect Ameren’s and Ameren Illinois and ATXI, filed a request with the FERC to allow revisions to their 2018 electric transmission rates to reflect the impact of the reduction in federal income taxes enacted under the TCJA. If approved, Ameren Illinois and ATXI’s 2018 electric transmission rates would be reducedIllinois’ annual revenue by $27an estimated $21 million and $23$15 million, respectively. Absent this revision, the reduction in federal income taxes enacted under the TCJA would not be reflected in Ameren Illinois' and ATXI's electric transmission rates until 2020 through the revenue reconciliation process.respectively, based on each company’s 2024 projected rate base.
Combined Construction and Operating License
In 2008, Ameren Missouri filed an application with the NRC for a COL for a second nuclear unit at Ameren Missouri’s existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a second nuclear unit at its existing Callaway site, and the NRC suspended reviewRegulatory Assets and Liabilities
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, we defer certain costs as regulatory assets pursuant to actions of regulators or because we expect to recover such costs in rates charged to customers. We may also defer certain amounts as regulatory liabilities because of actions of regulators or because we expect that such amounts will be returned to customers in future rates. The following table presents our regulatory assets and regulatory liabilities at December 31, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2023 | | | 2022 |
| | Ameren
Missouri | | Ameren
Illinois | | Ameren | | | Ameren
Missouri | | Ameren
Illinois | | Ameren |
| Regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a) | | $ | 72 | | | $ | — | | | $ | 72 | | | | $ | 140 | | | $ | — | | | $ | 140 | |
Under-recovered Illinois electric power costs(b) | | — | | | 10 | | | 10 | | | | — | | | 33 | | | 33 | |
Under-recovered PGA(b)(c) | | 6 | | | — | | | 6 | | | | 23 | | | — | | | 23 | |
MTM derivative losses(d) | | 25 | | | 143 | | | 168 | | | | 68 | | | 68 | | | 136 | |
| | | | | | | | | | | | | |
IEIMA revenue requirement reconciliation adjustment(e)(f) | | — | | | 239 | | | 239 | | | | — | | | 134 | | | 134 | |
FERC revenue requirement reconciliation adjustment(g) | | — | | | 25 | | | 54 | | | | — | | | 11 | | | 33 | |
Under-recovered VBA(h) | | — | | | 49 | | | 49 | | | | — | | | — | | | — | |
| | | | | | | | | | | | | |
Income taxes(i) | | 126 | | | 78 | | | 207 | | | | 111 | | | 72 | | | 185 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Bad debt rider(j) | | — | | | 43 | | | 43 | | | | — | | | 5 | | | 5 | |
| | | | | | | | | | | | | |
Callaway refueling and maintenance outage costs(k) | | 37 | | | — | | | 37 | | | | 33 | | | — | | | 33 | |
Unamortized loss on reacquired debt(l) | | 45 | | | 5 | | | 50 | | | | 47 | | | 7 | | | 54 | |
Environmental cost riders(m) | | — | | | 50 | | | 50 | | | | — | | | 64 | | | 64 | |
Storm costs(f)(n) | | — | | | 27 | | | 27 | | | | — | | | 14 | | | 14 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Allowance for funds used during construction for pollution control equipment(f)(o) | | 10 | | | — | | | 10 | | | | 11 | | | — | | | 11 | |
Customer generation rebate program(f)(p) | | — | | | 54 | | | 54 | | | | — | | | 50 | | | 50 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
PISA(f)(q) | | 386 | | | — | | | 386 | | | | 320 | | | — | | | 320 | |
RESRAM(r) | | 48 | | | — | | | 48 | | | | 6 | | | — | | | 6 | |
Certain Meramec Energy Center costs(s) | | 39 | | | — | | | 39 | | | | 51 | | | — | | | 51 | |
FEJA energy-efficiency rider(f)(t) | | — | | | 500 | | | 500 | | | | — | | | 416 | | | 416 | |
Property tax tracker(u) | | 13 | | | — | | | 13 | | | | 3 | | | — | | | 3 | |
| Other | | 49 | | | 64 | | | 113 | | | | 35 | | | 34 | | | 69 | |
| Total regulatory assets | | $ | 856 | | | $ | 1,287 | | | $ | 2,175 | | | | $ | 848 | | | $ | 908 | | | $ | 1,780 | |
| Less: current regulatory assets | | (101) | | | (252) | | | (365) | | | | (254) | | | (87) | | | (354) | |
| Noncurrent regulatory assets | | $ | 755 | | | $ | 1,035 | | | $ | 1,810 | | | | $ | 594 | | | $ | 821 | | | $ | 1,426 | |
| Regulatory liabilities: | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Over-recovered Illinois electric power costs(b) | | — | | | 36 | | | 36 | | | | — | | | — | | | — | |
Over-recovered PGA(b) | | 7 | | | 33 | | | 40 | | | | — | | | 10 | | | 10 | |
| | | | | | | | | | | | | |
MTM derivative gains(d) | | 19 | | | 3 | | | 22 | | | | 51 | | | 40 | | | 91 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Income taxes(i) | | 999 | | | 724 | | | 1,809 | | | | 1,095 | | | 749 | | | 1,931 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Cost of removal(v) | | 1,098 | | | 1,038 | | | 2,186 | | | | 1,064 | | | 989 | | | 2,091 | |
AROs(w) | | 524 | | | — | | | 524 | | | | 365 | | | — | | | 365 | |
| | | | | | | | | | | | | |
Bad debt rider(j) | | — | | | 7 | | | 7 | | | | — | | | 21 | | | 21 | |
Pension and postretirement benefit costs(x) | | 202 | | | 144 | | | 346 | | | | 242 | | | 162 | | | 404 | |
Pension and postretirement benefit costs tracker(y) | | 111 | | | — | | | 111 | | | | 60 | | | — | | | 60 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Renewable energy credits and zero emission credits(z) | | — | | | 489 | | | 489 | | | | — | | | 373 | | | 373 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Other | | 14 | | | 15 | | | 29 | | | | 64 | | | 33 | | | 99 | |
| Total regulatory liabilities | | $ | 2,974 | | | $ | 2,489 | | | $ | 5,599 | | | | $ | 2,941 | | | $ | 2,377 | | | $ | 5,445 | |
| Less: current regulatory liabilities | | (15) | | | (71) | | | (87) | | | | (70) | | | (64) | | | (136) | |
| Noncurrent regulatory liabilities | | $ | 2,959 | | | $ | 2,418 | | | $ | 5,512 | | | | $ | 2,871 | | | $ | 2,313 | | | $ | 5,309 | |
(a)Under-recovered fuel and purchased power costs to be recovered through the FAC. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.
(b)Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(c)As a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, for the month of February 2021, Ameren Missouri had under-recovered costs under its PGA clause of $53 million. Pursuant to an October 2021 MoPSC order, the collection period for Ameren Missouri’s cumulative PGA under-recovery as of August 2021, which included the February 2021 under-recovery, was extended from 12 months to 36 months, beginning November 2021.
(d)Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.
(e)The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the IEIMA performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. The under-recovery will be recovered from customers with a return at the applicable WACC within two years.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Current regulatory assets: | | | | | | | | | | | | | |
Under-recovered FAC(a)(b) | | $ | 47 |
| | $ | — |
| | $ | 47 |
| | | $ | 21 |
| | $ | — |
| | $ | 21 |
|
Under-recovered Illinois electric power costs(c) | | — |
| | — |
| | — |
| | | — |
| | 3 |
| | 3 |
|
Under-recovered PGA(c) | | 1 |
| | 13 |
| | 14 |
| | | — |
| | 4 |
| | 4 |
|
MTM derivative losses(d) | | 8 |
|
| 25 |
| | 33 |
| | | 9 |
| | 15 |
| | 24 |
|
Energy-efficiency riders(e) | | — |
| | — |
| | — |
| | | 5 |
| | — |
| | 5 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 24 |
| | 24 |
| | | — |
| | 68 |
| | 68 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 9 |
| | 10 |
| | | — |
| | 7 |
| | 13 |
|
VBA rider(a)(h) | | — |
| | 15 |
| | 15 |
| | | — |
| | 11 |
| | 11 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2016 |
| | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Other | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
| Total current regulatory assets | | $ | 56 |
| | $ | 87 |
| | $ | 144 |
| | | $ | 35 |
| | $ | 108 |
| | $ | 149 |
|
| Noncurrent regulatory assets: | | | | | | | | | | | | | |
Pension and postretirement benefit costs(i) | | $ | 84 |
| | $ | 215 |
| | $ | 299 |
| | | $ | 175 |
| | $ | 319 |
| | $ | 494 |
|
Income taxes(j) | | 139 |
| | 56 |
| | 197 |
| | | 229 |
| | 1 |
| | 230 |
|
Uncertain tax positions tracker(a)(k) | | 5 |
| | — |
| | 5 |
| | | 7 |
| | — |
| | 7 |
|
ARO(l) | | — |
| | 1 |
| | 1 |
| | | — |
| | 3 |
| | 3 |
|
Callaway costs(a)(m) | | 25 |
| | — |
| | 25 |
| | | 29 |
| | — |
| | 29 |
|
Unamortized loss on reacquired debt(a)(n) | | 61 |
| | 49 |
| | 110 |
| | | 65 |
| | 59 |
| | 124 |
|
Environmental cost riders(o) | | — |
| | 173 |
| | 173 |
| | | — |
| | 196 |
| | 196 |
|
MTM derivative losses(d) | | 4 |
|
| 192 |
| | 196 |
|
|
| 9 |
| | 178 |
| | 187 |
|
Storm costs(a)(p) | | — |
| | 10 |
| | 10 |
| | | — |
| | 15 |
| | 15 |
|
Demand-side costs before the MEEIA implementation(a)(q) | | 11 |
| | — |
| | 11 |
| | | 18 |
| | — |
| | 18 |
|
Workers’ compensation claims(r) | | 5 |
| | 7 |
| | 12 |
| | | 6 |
| | 7 |
| | 13 |
|
Credit facilities fees(s) | | 3 |
| | — |
| | 3 |
| | | 4 |
| | — |
| | 4 |
|
Construction accounting for pollution control equipment(a)(t) | | 18 |
| | — |
| | 18 |
| | | 19 |
| | — |
| | 19 |
|
Solar rebate program(a)(u) | | 31 |
| | — |
| | 31 |
| | | 49 |
| | — |
| | 49 |
|
IEIMA revenue requirement reconciliation adjustment(a)(f) | | — |
| | 54 |
| | 54 |
| | | — |
| | 23 |
| | 23 |
|
FERC revenue requirement reconciliation adjustment(a)(g) | | — |
| | 16 |
| | 27 |
| | | — |
| | 8 |
| | 10 |
|
FEJA energy-efficiency riders(a)(v) | | — |
| | 41 |
| | 41 |
| | | — |
| | — |
| | — |
|
| Other | | 9 |
| | 8 |
| | 17 |
| | | 9 |
| | 7 |
| | 16 |
|
| Total noncurrent regulatory assets | | $ | 395 |
| | $ | 822 |
| | $ | 1,230 |
| | | $ | 619 |
| | $ | 816 |
| | $ | 1,437 |
|
| Current regulatory liabilities: | | | | | | | | | | | | | |
Over-recovered FAC(b) | | $ | 4 |
| | $ | — |
| | $ | 4 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Over-recovered Illinois electric power costs(c) | | — |
| | 16 |
| | 16 |
| | | — |
| | 25 |
| | 25 |
|
Over-recovered PGA(c) | | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
MTM derivative gains(d) | | 13 |
| | — |
| | 13 |
|
| | 12 |
| | 11 |
| | 23 |
|
Energy-efficiency riders(e) | | 2 |
| | 40 |
| | 42 |
| | | — |
| | — |
| | — |
|
Estimated refund for FERC complaint case(w) | | — |
| | 25 |
| | 42 |
| | | — |
| | 42 |
| | 62 |
|
| Other | | — |
| | 10 |
| | 10 |
| | | — |
| | — |
| | — |
|
| Total current regulatory liabilities | | $ | 19 |
| | $ | 92 |
| | $ | 128 |
| | | $ | 12 |
| | $ | 78 |
| | $ | 110 |
|
| Noncurrent regulatory liabilities: | | | | | | | | | | | | | |
Income taxes(j) | | $ | 1,392 |
| | $ | 842 |
| | $ | 2,323 |
| | | $ | 33 |
| | $ | 4 |
| | $ | 37 |
|
Uncertain tax positions tracker(k) | | 2 |
| | — |
| | 2 |
| | | 3 |
| | — |
| | 3 |
|
Asset removal costs(x) | | 995 |
| | 725 |
| | 1,725 |
| | | 970 |
| | 697 |
| | 1,669 |
|
ARO(l) | | 223 |
| | — |
| | 223 |
| | | 162 |
| | — |
| | 162 |
|
Bad debt rider(y) | | — |
| | 2 |
| | 2 |
| | | — |
| | 3 |
| | 3 |
|
Pension and postretirement benefit costs tracker(z) | | 35 |
| | — |
| | 35 |
| | | 35 |
| | — |
| | 35 |
|
Energy-efficiency riders(e) | | — |
| | — |
| | — |
| | | — |
| | 45 |
| | 45 |
|
Renewable energy credits and zero-emission credits(aa) | | — |
| | 58 |
| | 58 |
| | | — |
| | 15 |
| | 15 |
|
Storm tracker(ab) | | 6 |
| | — |
| | 6 |
| | | 7 |
| | — |
| | 7 |
|
| Other | | 11 |
| | 2 |
| | 13 |
| | | 5 |
| | 4 |
| | 9 |
|
| Total noncurrent regulatory liabilities | | $ | 2,664 |
| | $ | 1,629 |
| | $ | 4,387 |
| | | $ | 1,215 |
| | $ | 768 |
| | $ | 1,985 |
|
| |
(a) | These assets earn a return. |
| |
(b) | 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. |
| |
(c) | Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. |
| |
(d) | Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information. |
| |
(e) | 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, net shared benefits, and the throughput disincentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, net shared benefits, and the throughput disincentive are incurred. The Ameren Illinois balance relates to a regulatory tracking mechanism to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer |
energy efficiency(g)Ameren Illinois’ and demand response programs.ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years.
(h)Under-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in rate regulatory reviews. Each year’s amount will be recovered from customers from April through December of the following year.
(i)The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction and the effects of tax rate increases. The regulatory liabilities represent amounts that will be refunded to customers for excess deferred income taxes related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits all recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 36, 28, and 43 years.
(j)A rider for the difference between the level of bad debt write-offs, net of any subsequent recoveries, incurred by Ameren Illinois and the level of such costs included in electric distribution and natural gas delivery service rates. Under-recovered or over-recovered costs for each year are collected from, or refunded to, customers over a twelve-month period beginning in June of the following year.
(k)Maintenance expenses related to scheduled refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. Amounts are amortized over the period between refueling and maintenance outages, which has historically been approximately 18 months.
(l)Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued.
(m)The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information.
(n)Storm costs from 2020 through 2023 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred.
(o)The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux Energy Center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux Energy Center, currently through 2030.
(p)Costs associated with Ameren Illinois’ customer generation rebate program. Costs are amortized over a 15-year period, beginning in the year rebates are paid.
(q)Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on investments in certain property, plant, and equipment placed in service and not included in base rates. Accumulated PISA deferrals, which also earn a return at the applicable WACC, are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.
(r)Under-recovered costs associated with Ameren Missouri’s compliance with the planstate of Missouri’s renewable energy standard. Under-recovered or over-recovered costs are aggregated over a twelve-month period beginning each August and are amortized over a twelve-month period beginning in February of the following year.
| |
(f) | 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. |
| |
(g) | Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from or refunded to customers within two years. |
| |
(h) | Under-recovered natural gas sales volumes, including deviations from normal weather conditions. Each year’s amount will be recovered from, or refunded to, customers from April through December of the following year. |
| |
(i) | 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. |
| |
(j) | 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, depreciation differences, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. The amortization period for the effects of tax rate changes from the TCJA and the increased income tax rate in Illinois and the other tax liabilities will be determined in future rate orders by the applicable regulators. See Note 12 – Income Taxes for amounts related to the revaluation of deferred income taxes under the TCJA. |
| |
(k) | The tracker is amortized over three years, beginning from the date the amounts are included in rates. See Note 12 – Income Taxes for additional information. |
| |
(l) | 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. |
| |
(m) | Ameren Missouri’s Callaway energy center operations and maintenance expenses,(s)Certain costs associated with the Meramec Energy Center, which were authorized for recovery by a December 2021 MoPSC electric rate order. These costs are being collected over five years beginning in February 2022. (t)The electric energy-efficiency investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from three to 12 years. (u)A regulatory recovery mechanism for the difference between actual property taxes 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 remaining life of the energy center’s original operating license through 2024. |
| |
(n) | 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. |
| |
(o) | 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. |
| |
(p) | Storm costs from 2013, 2015, and 2016 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred. |
| |
(q) | 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 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. |
| |
(r) | The period of recovery will depend on the timing of actual expenditures. |
| |
(s) | Ameren Missouri’s costs incurred to enter into and maintain the Missouri Credit Agreement. These costs are being amortized over the life of the credit facility to construction work in progress, which will be depreciated when assets are placed in service. Additional costs were incurred in December 2016 to amend and restate the Missouri Credit Agreement. |
| |
(t) | 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. |
| |
(u) | Costs associated with Ameren Missouri’s solar rebate program to fulfill its renewable energy portfolio requirement. Costs incurred from 2010 to 2014 are being amortized over a two-year period that began in April 2017 as modified per the MoPSC March 2017 electric rate order. Costs incurred from 2015 to 2016 are being amortized over a three-year period that began in April 2017. |
| |
(v) | Electric energy-efficiency program investments deferred under the FEJA. These investments will earn a return at Ameren Illinois’ weighted-average cost of capital with the equity return based on the monthly average yield 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. |
| |
(w) | Estimated refunds to transmission customers related to the February 2015 FERC Complaint Case discussed above. |
| |
(x) | Estimated funds collected for the eventual dismantling and removal of plant retired from service, net of salvage value. |
| |
(y) | A regulatory tracking mechanism for the difference between the level of bad debt incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 2015 was refunded to customers from June 2016 through May 2017. The over-recovery relating to 2016 is being refunded to customers from June 2017 through May 2018. The over-recovery relating to 2017 will be refunded to customers from June 2018 through May 2019. |
| |
(z) | 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 2012 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. |
| |
(aa) | Funds collected from customers and alternative retail electric suppliers 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) | A regulatory tracking mechanism at Ameren Missouri for the difference between the level of storm costs incurred in a particular year and the level of such costs included in rates. For periods prior to December 2014, the MoPSC’s April 2015 electric rate order directed the amortization to occur over a five-year period that began in June 2015. For periods after December 2014, the MoPSC’s March 2017 electric rate order directed the amortization to occur over a five-year period that began in April 2017. The April 2015 MoPSC order did not approve the continued use of the storm cost regulatory tracking mechanism. |
Ameren, Ameren Missouri and Ameren Illinois continually assess the recoverabilityrelated taxes included in customer rates. The period of theirrecovery, or refund, varies based on MoPSC approval in a regulatory assets. Regulatory assetsrate review. Amounts accumulated through 2022 are charged to earnings when it is no longer probable that suchbeing collected over two years beginning July 2023. The amortization period for amounts accumulated after 2022 will be recovereddetermined in a future regulatory rate review.
(v)Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment when retired from service, net of salvage.
(w)The ARO regulatory liability includes the nuclear decommissioning trust fund balance ($1,150 million and $958 million at December 31, 2023 and 2022, respectively), net of recoverable removal costs for AROs ($626 million and $593 million at December 31, 2023 and 2022, respectively). See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations and Removal Costs.
(x)Over-recovered costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information.
(y)A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For electric and natural gas related costs incurred prior to 2023 and 2022, respectively, the weighted-average remaining amortization period is three years. For electric and natural gas related costs incurred after 2023 and 2022, respectively, the amortization period will be determined in a future regulatory rate review.
(z)Funds collected for the purchase of renewable energy credits and zero emission credits through future revenues. ToIPA procurements. The balance will be amortized as the extent that paymentscredits are purchased. Pursuant to the CEJA, if funds collected from customers are not used to procure renewable energy credits, they would be refunded to customers pursuant to a reconciliation proceeding, the first of regulatory liabilities are no longer probable,which was initiated in August 2023. Based on amounts collected from customers and renewable energy credit purchases under contract, the amounts are creditedAugust 2023 reconciliation proceeding did not result in refunds to earnings.customers.
NOTE 3 – PROPERTY, PLANT, AND EQUIPMENT, NET
The following table presents components of “Property, plant, and equipment, net” at December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren
Missouri | | Ameren
Illinois | | Other | | Ameren |
| 2023 | | | | | | | | |
Property, plant, and equipment at original cost(a): | | | | | | | | |
| Electric generation: | | | | | | | | |
Coal(b) | | $ | 3,452 | | | $ | — | | | $ | — | | | $ | 3,452 | |
| Natural gas | | 921 | | | — | | | — | | | 921 | |
| Nuclear | | 5,879 | | | — | | | — | | | 5,879 | |
Renewable(c) | | 1,973 | | | 11 | | | — | | | 1,984 | |
| Electric distribution | | 8,638 | | | 7,820 | | | — | | | 16,458 | |
| Electric transmission | | 2,134 | | | 5,381 | | | 1,993 | | | 9,508 | |
| Natural gas | | 688 | | | 4,186 | | | — | | | 4,874 | |
Other(d) | | 2,191 | | | 1,657 | | | 255 | | | 4,103 | |
| | 25,876 | | | 19,055 | | | 2,248 | | | 47,179 | |
| Less: Accumulated depreciation and amortization | | 10,243 | | | 4,783 | | | 400 | | | 15,426 | |
| | 15,633 | | | 14,272 | | | 1,848 | | | 31,753 | |
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in progress | | 173 | | | — | | | — | | | 173 | |
| Other | | 914 | | | 360 | | | 46 | | | 1,320 | |
Plant to be abandoned, net(e) | | 530 | | | — | | | — | | | 530 | |
| Property, plant, and equipment, net | | $ | 17,250 | | | $ | 14,632 | | | $ | 1,894 | | | $ | 33,776 | |
| 2022 | | | | | | | | |
Property, plant, and equipment at original cost(a): | | | | | | | | |
| Electric generation: | | | | | | | | |
Coal(b)(f) | | $ | 3,454 | | | $ | — | | | $ | — | | | $ | 3,454 | |
| Natural gas | | 961 | | | — | | | — | | | 961 | |
| Nuclear | | 5,725 | | | — | | | — | | | 5,725 | |
Renewable(c) | | 1,957 | | | 11 | | | — | | | 1,968 | |
| Electric distribution | | 7,993 | | | 7,351 | | | — | | | 15,344 | |
| Electric transmission | | 1,884 | | | 4,617 | | | 1,815 | | | 8,316 | |
| Natural gas | | 640 | | | 3,883 | | | — | | | 4,523 | |
Other(d) | | 1,904 | | | 1,395 | | | 249 | | | 3,548 | |
| | 24,518 | | | 17,257 | | | 2,064 | | | 43,839 | |
Less: Accumulated depreciation and amortization(f) | | 9,682 | | | 4,418 | | | 365 | | | 14,465 | |
| | 14,836 | | | 12,839 | | | 1,699 | | | 29,374 | |
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in progress | | 108 | | | — | | | — | | | 108 | |
| Other | | 598 | | | 514 | | | 86 | | | 1,198 | |
Plant to be abandoned, net(e) | | 582 | | | — | | | — | | | 582 | |
| Property, plant, and equipment, net | | $ | 16,124 | | | $ | 13,353 | | | $ | 1,785 | | | $ | 31,262 | |
(a)The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydroelectric generating assets, which have useful lives of up to 150 years; 20 to 80 years for electric distribution; 50 to 75 years for electric transmission; 20 to 80 years for natural gas; and 2 to 55 years for other.
(b)Includes $29 million of oil-fired generation at December 31, 2023 and 2022.
(c)Renewable includes hydroelectric, wind, solar, and methane gas generation facilities.
(d)Other property, plant, and equipment includes assets used to support electric and natural gas services.
(e)Represents the net for eachbook value of the Rush Island Energy Center as Ameren Companies at Missouri expects to retire the energy center significantly in advance of its previously expected useful life and in the near term. See Plant to be Abandoned, Net under Note 1 – Summary of Significant Accounting Policies, NSR and Clean Air Act Litigation under Note 14 – Commitments and Contingencies, and Securitization of the Rush Island Energy Center under Note 2 – Rate and Regulatory Matters for additional information on the planned accelerated retirement of the Rush Island Energy Center.
(f)Original cost amounts include two CTs that had related financing obligations. The financing obligation for the Peno Creek CT Energy Center was settled in December 2022, while the financing obligation for the Audrain CT Energy Center was settled in January 2023. The gross cumulative plant asset values related to outstanding financing obligations as of December 31, 20172022 was $125 million and 2016:the related accumulated depreciation was $54 million. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.
|
| | | | | | | | | | | | | | | | |
| | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a) |
| 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 |
|
| 2016 | | | | | | | | |
Property, plant, and equipment at original cost:(b) | | | | | | | | |
| Electric generation | | $ | 10,911 |
| | $ | — |
| | $ | — |
| | $ | 10,911 |
|
| Electric distribution | | 5,563 |
| | 5,287 |
| | — |
| | 10,850 |
|
| Electric transmission | | 1,151 |
| | 2,016 |
| | 712 |
| | 3,879 |
|
| Natural gas | | 455 |
| | 2,186 |
| | — |
| | 2,641 |
|
Other(c) | | 879 |
| | 719 |
| | 239 |
| | 1,837 |
|
| | | 18,959 |
| | 10,208 |
| | 951 |
| | 30,118 |
|
| Less: Accumulated depreciation and amortization | | 7,880 |
| | 2,850 |
| | 231 |
| | 10,961 |
|
| | | 11,079 |
| | 7,358 |
| | 720 |
| | 19,157 |
|
| Construction work in progress: | | | | | | | | |
| Nuclear fuel in process | | 206 |
| | — |
| | — |
| | 206 |
|
| Other | | 193 |
| | 111 |
| | 446 |
| | 750 |
|
| Property, plant, and equipment, net | | $ | 11,478 |
| | $ | 7,469 |
| | $ | 1,166 |
| | $ | 20,113 |
|
| |
(a) | Amounts in Ameren and Ameren Missouri include two CTs under separate capital lease agreements. The gross cumulative asset value of those agreements was $233 million and $232 million at December 31, 2017 and 2016, respectively. The total accumulated depreciation associated with the two CTs was $83 million and $77 million at December 31, 2017 and 2016, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these capital lease 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. |
Capitalized software costs are classified within “Property, Plant, and Equipment, Net” on the balance sheet and are amortized on a straight-line basis over the expected period of benefit, ranging from 2 to 15 years, with the amortization expense included in “Depreciation and amortization” on the statement of income. Deferred cloud implementation costs are classified within “Other Assets” on the balance sheet and are amortized on a straight-line basis over the term of the associated hosting arrangement, ranging from 5 to 10 years.15 years, with the amortization expense included in “Other operations and maintenance” on the statement of income. The following table presents the amortization expense, gross carrying value, and related accumulated amortization of capitalized software the related accumulated amortization, and thedeferred cloud implementation costs by year:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Amortization Expense | | Gross Carrying Value | | Accumulated Amortization |
| | 2023 | 2022 | 2021 | | 2023 | 2022 | | 2023 | 2022 |
| Capitalized software costs: | | | | | | | | | | |
| Ameren | | $ | 212 | | $ | 159 | | $ | 125 | | | $ | 1,823 | | $ | 1,443 | | | $ | (1,126) | | $ | (914) | |
| Ameren Missouri | | 114 | | 85 | | 66 | | | 795 | | 613 | | | (453) | | (339) | |
| Ameren Illinois | | 92 | | 69 | | 53 | | | 786 | | 601 | | | (452) | | (360) | |
| Deferred cloud implementation costs: | | | | | | | | | | |
| Ameren | | $ | 17 | | $ | 15 | | $ | 13 | | | $ | 142 | | $ | 106 | | | $ | (51) | | $ | (34) | |
| Ameren Missouri | | 8 | | 7 | | 6 | | | 63 | | 48 | | | (23) | | (15) | |
| Ameren Illinois | | 9 | | 8 | | 6 | | | 76 | | 54 | | | (26) | | (17) | |
Annual amortization expense offor capitalized software by year:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Amortization Expense(a) | | Gross Carrying Value | | Accumulated Amortization |
| | | 2017 | 2016 | 2015 | | 2017 | 2016 | | 2017 | 2016 |
| Ameren | | $ | 58 |
| $ | 52 |
| $ | 47 |
| | $ | 655 |
| $ | 622 |
| | $ | (466 | ) | $ | (408 | ) |
| Ameren Missouri | | 20 |
| 17 |
| 16 |
| | 191 |
| 178 |
| | (107 | ) | (87 | ) |
| Ameren Illinois | | 36 |
| 33 |
| 27 |
| | 241 |
| 225 |
| | (146 | ) | (110 | ) |
| |
(a) | Asplaced in service as of December 31, 2017, 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, 2017, 2016, and 2015, which represent noncash investing activity excluded from the accompanying statements of cash flows:2023, is estimated to be as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027 | | 2028 |
| Ameren | | $ | 202 | | | $ | 147 | | | $ | 106 | | | $ | 79 | | | $ | 45 | |
| Ameren Missouri | | 106 | | | 76 | | | 52 | | | 38 | | | 22 | |
| Ameren Illinois | | 90 | | | 65 | | | 51 | | | 38 | | | 23 | |
|
| | | | | | | | | | | |
| | Ameren(a) | | Ameren Missouri | | Ameren Illinois |
| Accrued capital expenditures: | | | | | |
| 2017 | $ | 361 |
| | $ | 159 |
| | $ | 175 |
|
| 2016 | 251 |
| | 116 |
| | 87 |
|
| 2015 | 235 |
| | 85 |
| | 92 |
|
| Accrued nuclear fuel expenditures: | | | | | |
| 2017 | 10 |
| | 10 |
| | (b) |
|
| 2016 | 20 |
| | 20 |
| | (b) |
|
| 2015 | 16 |
| | 16 |
| | (b) |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
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
The Credit Agreements provide $2.1$2.6 billion of credit cumulatively through maturity in December 2021.2027. The total facility size of the Missouri Credit Agreement and Illinois Credit Agreement is $1.4 billion and $1.2 billion, respectively. The maturity date of each Credit Agreement may be extended for two additional one-year periods upon the mutual consent of the respective borrowers and the lenders. Credit available under the agreements is provided by a group of 2221 international, national, and regional lenders, with no single lender providing more than $118$156 million of credit in aggregate.
The obligations of each borrower under the respective Credit Agreements to which it is a party are several and not joint. Except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective Credit Agreements are not guaranteed by Ameren (parent) or any other subsidiary of Ameren. The following table presents the maximum aggregate amount available to each borrower under each facility: | | | | | Missouri Credit Agreement | Illinois Credit Agreement |
| | Missouri
Credit Agreement | | | | Missouri
Credit Agreement | Illinois
Credit Agreement |
| Ameren (parent) | | $ | 700 |
| $ | 500 |
|
| Ameren Missouri | | 800 |
| (a) |
| Ameren Missouri | | 1,000 | | (a) | (a) |
| Ameren Illinois | | (a) |
| 800 |
|
(a)Not applicable.
The borrowers have the option to seek additional commitments from existing or new lenders to increase the total facility size of the Credit Agreements to a maximum of $1.2$1.7 billion for the Missouri Credit Agreement and $1.3$1.5 billion for the Illinois Credit Agreement. Ameren (parent) borrowings are due and payable no later than the maturity date of the Credit Agreements. Ameren Missouri and Ameren Illinois borrowings under the applicable Credit Agreement are due and payable no later than the earlier of the maturity date or 364 days after the 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$2.6 billion overall combined facility borrowing limitations of the Credit Agreements.
The borrowers will use the proceeds from any borrowings under the Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, 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, 2017,2023, based on commercial paper outstanding and letters of credit issuedcapacity available under the Credit Agreements, along with cash and cash equivalents, the aggregate amount of credit capacitynet liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $1.6$2.1 billion.
Ameren, Ameren Missouri, and Ameren Illinois did not borrow under the Credit Agreements for the years ended December 31, 2017 and 2016.
Commercial Paper
The following table summarizes the borrowing activity and relevant interest rates underfor 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, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren (parent) | | Ameren Missouri | | Ameren Illinois | | Ameren Consolidated | |
| 2023 | | | | | | | | | |
| Average daily amount outstanding | | $ | 726 | | | $ | 274 | | | $ | 166 | | | $ | 1,166 | | |
| Commercial paper issuances outstanding at period-end | | — | | | 170 | | | 366 | | | 536 | | |
| Weighted-average interest rate | | 5.38 | % | | 5.22 | % | | 5.23 | % | | 5.32 | % | |
Peak amount outstanding during period(a) | | $ | 1,298 | | | $ | 592 | | | $ | 450 | | | $ | 1,526 | | |
| Peak interest rate | | 5.65 | % | | 5.68 | % | | 5.68 | % | | 5.68 | % | |
| 2022 | | | | | | | | | |
| Average daily amount outstanding | | $ | 485 | | | $ | 229 | | | $ | 138 | | | $ | 852 | | |
| Commercial paper issuances outstanding at period-end | | 477 | | | 329 | | | 264 | | | 1,070 | | |
| Weighted-average interest rate | | 2.41 | % | | 1.71 | % | | 2.79 | % | | 2.28 | % | |
Peak amount outstanding during period(a) | | $ | 718 | | | $ | 539 | | | $ | 404 | | | $ | 1,267 | | |
| Peak interest rate | | 4.80 | % | | 4.95 | % | | 4.80 | % | | 4.95 | % | |
|
| | | | | | | | | | | | | | |
| | | Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated |
| 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 | % |
| 2016 | | | | | | |
| Average daily commercial paper outstanding | | $ | 440 |
| | $ | 60 |
| $ | 52 |
| $ | 552 |
|
| Outstanding borrowings at period-end | | 507 |
| | — |
| 51 |
| 558 |
|
| Weighted-average interest rate | | 0.82 | % | | 0.74 | % | 0.69 | % | 0.80 | % |
Peak outstanding commercial paper during period(a) | | $ | 574 |
| | $ | 208 |
| $ | 195 |
| $ | 839 |
|
| Peak interest rate | | 1.05 | % | | 0.85 | % | 0.90 | % | 1.05 | % |
| |
(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. |
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, 2017,2023, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the Credit Agreements, were 53%59%, 48%50%, and 47%46%, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
The Credit Agreements contain default provisions that apply separately to each borrower. However, a default of Ameren Missouri or Ameren Illinois under the applicable credit agreement is also deemed to constitute a default of Ameren (parent) under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $100 million in the aggregate (including under the other credit agreement). However, under the default provisions of the Credit Agreements, any default of Ameren (parent) under either credit agreement that results solely from a default of Ameren Missouri or Ameren Illinois does not result in a
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 Ameren Companies’ credit agreementsCredit 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 their credit agreementsthe Credit Agreements at December 31, 20172023.
Money Pools
Ameren (parent) has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.
Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the money pool from participants. The primary sources of external funds for the utility money pool are the Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but it is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2017,2023, was 1.19% (20165.29% (2022 – 0.52%1.95%).
See Note 13 – Related-party Transactions for the amount of interest income and expense from the utility money pool arrangementsagreement recorded by the Ameren CompaniesMissouri and Ameren Illinois for the years ended December 31, 2017, 2016,2023, 2022, and 2015.2021.
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding, including maturities due within one year, as of December 31, 2023 and 2022:
| | | | | | | | | | | |
| 2023 | | 2022 |
| Ameren (Parent): | | | |
| | | |
| 2.50% Senior unsecured notes due 2024 | $ | 450 | | | $ | 450 | |
| 3.65% Senior unsecured notes due 2026 | 350 | | | 350 | |
| 5.70% Senior unsecured notes due 2026 | 600 | | | — | |
| 1.95% Senior unsecured notes due 2027 | 500 | | | 500 | |
| 1.75% Senior unsecured notes due 2028 | 450 | | | 450 | |
| 5.00% Senior unsecured notes due 2029 | 700 | | | — | |
| 3.50% Senior unsecured notes due 2031 | 800 | | | 800 | |
| Total long-term debt, gross | 3,850 | | | 2,550 | |
| Less: Unamortized discount and premium | (4) | | | (2) | |
| Less: Unamortized debt issuance costs | (17) | | | (12) | |
| Less: Maturities due within one year | (450) | | | — | |
| Long-term debt, net | $ | 3,379 | | | $ | 2,536 | |
| Ameren Missouri: | | | |
| Bonds and notes: | | | |
3.50% Senior secured notes due 2024(a) | $ | 350 | | | $ | 350 | |
2.95% Senior secured notes due 2027(a) | 400 | | | 400 | |
3.50% First mortgage bonds due 2029(b) | 450 | | | 450 | |
2.95% First mortgage bonds due 2030(b) | 465 | | | 465 | |
2.15% First mortgage bonds due 2032(b) | 525 | | | 525 | |
2.90% 1998 Series A bonds due 2033(c) | 60 | | | 60 | |
2.90% 1998 Series B bonds due 2033(c) | 50 | | | 50 | |
2.75% 1998 Series C bonds due 2033(c) | 50 | | | 50 | |
5.50% Senior secured notes due 2034(a) | 184 | | | 184 | |
5.30% Senior secured notes due 2037(a) | 300 | | | 300 | |
8.45% Senior secured notes due 2039(a)(d) | 350 | | | 350 | |
3.90% Senior secured notes due 2042(a)(d) | 485 | | | 485 | |
3.65% Senior secured notes due 2045(a) | 400 | | | 400 | |
4.00% First mortgage bonds due 2048(b) | 425 | | | 425 | |
3.25% First mortgage bonds due 2049(b) | 330 | | | 330 | |
2.625% First mortgage bonds due 2051(b) | 550 | | | 550 | |
3.90% First mortgage bonds due 2052(b) | 525 | | | 525 | |
5.45% First mortgage bonds due 2053(b) | 500 | | | — | |
| Finance obligations: | | | |
Audrain County agreement (Audrain County CT) due 2023(e) | — | | | 240 | |
| Total long-term debt, gross | 6,399 | | | 6,139 | |
| Less: Unamortized discount and premium | (13) | | | (12) | |
| Less: Unamortized debt issuance costs | (45) | | | (41) | |
| Less: Maturities due within one year | (350) | | | (240) | |
| Long-term debt, net | $ | 5,991 | | | $ | 5,846 | |
| | | | | | | | | | | |
| 2023 | | 2022 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
0.375% First mortgage bonds due 2023(f) | $ | — | | | $ | 100 | |
3.25% Senior secured notes due 2025(g) | 300 | | | 300 | |
6.125% Senior secured notes due 2028(g) | 60 | | | 60 | |
3.80% First mortgage bonds due 2028(f) | 430 | | | 430 | |
1.55% First mortgage bonds due 2030(f) | 375 | | | 375 | |
3.85% First mortgage bonds due 2032(f) | 500 | | | 500 | |
4.95% First mortgage bonds due 2033(f) | 500 | | | — | |
6.70% Senior secured notes due 2036(g) | 61 | | | 61 | |
6.70% Senior secured notes due 2036(g) | 42 | | | 42 | |
4.80% Senior secured notes due 2043(g) | 280 | | | 280 | |
4.30% Senior secured notes due 2044(g) | 250 | | | 250 | |
4.15% Senior secured notes due 2046(g) | 490 | | | 490 | |
3.70% First mortgage bonds due 2047(f) | 500 | | | 500 | |
4.50% First mortgage bonds due 2049(f) | 500 | | | 500 | |
3.25% First mortgage bonds due 2050(f) | 300 | | | 300 | |
2.90% First mortgage bonds due 2051(f) | 350 | | | 350 | |
5.90% First mortgage bonds due 2052(f) | 350 | | | 350 | |
| Total long-term debt, gross | 5,288 | | | 4,888 | |
| Less: Unamortized discount and premium | (9) | | | (9) | |
| Less: Unamortized debt issuance costs | (47) | | | (44) | |
| Less: Maturities due within one year | — | | | (100) | |
| Long-term debt, net | $ | 5,232 | | | $ | 4,735 | |
| ATXI: | | | |
2.45% Senior unsecured notes due 2036(h) | $ | 75 | | | $ | 75 | |
3.43% Senior unsecured notes due 2050(i) | 400 | | | 400 | |
2.96% Senior unsecured notes due 2052(j) | 95 | | | 95 | |
| Total long-term debt, gross | 570 | | | 570 | |
| | | |
| Less: Unamortized debt issuance costs | (2) | | | (2) | |
| Less: Maturities due within one year | (49) | | | — | |
| Long-term debt, net | $ | 519 | | | $ | 568 | |
| Ameren consolidated long-term debt, net | $ | 15,121 | | | $ | 13,685 | |
(a)These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2053 maturity of the 5.45% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (d) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.
(b)These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri bond indenture. They are secured by substantially all Ameren Missouri property and franchises.
(c)These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes.
(d)Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions.
(e)No cash was exchanged associated with the termination of the Audrain County agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri. The balance of the financing obligation and the related investment in debt securities was $240 million as of December 31, 2022. The investment was recorded in “Investments in industrial development revenue bonds” as of December 31, 2022. See below for additional information on this financing obligation.
(f)These bonds are first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises.
(g)These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under its mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2052 maturity date of the 5.90% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.
(h)The following table presents the principal maturities schedule for the Ameren Companies as of December 31, 2017 and 2016:2.45% senior unsecured notes due 2036: | | | | | | | | |
| Payment Date | | Principal Payment |
| November 2029 | $ | 30 |
| November 2036 | | 45 |
| Total | $ | 75 |
(i)The following table presents the principal maturities schedule for the 3.43% senior unsecured notes due 2050: |
| | | | | | | |
| | 2017 | | 2016 |
| 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 | (4 | ) | | (6 | ) |
| Long-term debt, net | $ | 696 |
| | $ | 694 |
|
| Ameren Missouri: | | | |
| Bonds and notes: | | | |
6.40% Senior secured notes due 2017(a) | $ | — |
| | $ | 425 |
|
6.00% Senior secured notes due 2018(a)(b) | 179 |
| | 179 |
|
5.10% Senior secured notes due 2018(a) | 199 |
| | 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 |
| | — |
|
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 |
|
| Capital lease obligations: | | | |
City of Bowling Green capital lease (Peno Creek CT) due 2022(f) | 36 |
| | 42 |
|
Audrain County capital lease (Audrain County CT) due 2023(f) | 240 |
| | 240 |
|
| Total long-term debt, gross | 3,988 |
| | 4,019 |
|
| Less: Unamortized discount and premium | (7 | ) | | (6 | ) |
| Less: Unamortized debt issuance costs | (20 | ) | | (19 | ) |
| Less: Maturities due within one year | (384 | ) | | (431 | ) |
| Long-term debt, net | $ | 3,577 |
| | $ | 3,563 |
|
| | | | | | | | |
| Payment Date | | Principal Payment |
| August 2024 | $ | 49 |
| August 2027 | | 50 |
| August 2030 | | 49 |
| August 2032 | | 50 |
| August 2038 | | 49 |
| August 2043 | | 77 |
| August 2050 | | 76 |
| Total | $ | 400 |
(j)The following table presents the principal maturities schedule for the 2.96% senior unsecured notes due 2052:
| | | | | | | | |
| Payment Date | | Principal Payment |
| August 2040 | $ | 45 |
| August 2052 | | 50 |
| Total | $ | 95 |
|
| | | | | | | |
| | 2017 | | 2016 |
| Ameren Illinois: | | | |
| Bonds and notes: | | | |
6.125% Senior secured notes due 2017(g)(h) | $ | — |
| | $ | 250 |
|
6.25% Senior secured notes due 2018(g)(h) | 144 |
| | 144 |
|
9.75% Senior secured notes due 2018(g)(h) | 313 |
| | 313 |
|
2.70% Senior secured notes due 2022(g)(h) | 400 |
| | 400 |
|
5.90% First mortgage bonds due 2023(i) | (i) |
| | (i) |
|
5.70% First mortgage bonds due 2024(j) | (j) |
| | (j) |
|
3.25% Senior secured notes due 2025(g) | 300 |
| | 300 |
|
6.125% Senior secured notes due 2028(g) | 60 |
| | 60 |
|
1993 Series B-1 Senior unsecured notes due 2028(d)(k) | 17 |
| | 17 |
|
6.70% Senior secured notes due 2036(g) | 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(l) | 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(g) | 280 |
| | 280 |
|
4.30% Senior secured notes due 2044(g) | 250 |
| | 250 |
|
4.15% Senior secured notes due 2046(g) | 490 |
| | 490 |
|
3.70% First mortgage bonds due 2047(m) | 500 |
| | — |
|
| Total long-term debt, gross | 2,857 |
| | 2,607 |
|
| Less: Unamortized discount and premium | (3 | ) | | — |
|
| Less: Unamortized debt issuance costs | (24 | ) | | (19 | ) |
| Less: Maturities due within one year | (457 | ) | | (250 | ) |
| Long-term debt, net | $ | 2,373 |
| | $ | 2,338 |
|
| ATXI: | | | |
3.43% Senior notes due 2050(n) | $ | 450 |
| | $ | — |
|
| Total long-term debt, gross | 450 |
| | — |
|
| Less: Unamortized debt issuance costs | (2 | ) | | — |
|
| Long-term debt, net | $ | 448 |
| | $ | — |
|
| Ameren consolidated long-term debt, net | $ | 7,094 |
| | $ | 6,595 |
|
| |
(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 Ameren Missouri senior secured notes currently outstanding, we do not expect the first mortgage bond lien protection associated with these notes to fall away before 2042. |
| |
(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 6.00% senior secured notes due 2018, 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 bonds are callable at 100% of par value. The average interest rates for 2017 and 2016 were as follows:
|
|
| | | |
| | 2017 | | 2016 |
| Ameren Missouri 1992 Series due 2022 | 1.43% | | 0.66% |
| Ameren Missouri 1998 Series A due 2033 | 1.77% | | 0.91% |
| Ameren Missouri 1998 Series B due 2033 | 1.75% | | 0.92% |
| Ameren Missouri 1998 Series C due 2033 | 1.73% | | 0.97% |
| Ameren Illinois 1993 Series B-1 due 2028 | 1.08% | | 0.70% |
| |
(e) | These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value. Less than $1 million principal amount of the bonds remain outstanding.
|
| |
(f) | Payments due to the lessor under these capital lease 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 lessor and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the capital lease 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 capital lease obligations and the related investments in debt securities, recorded in "Other Assets," was $276 million and $282 million, respectively, as of December 31, 2017 and 2016. |
| |
(g) | 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 maturity date of these senior secured notes and the 3.70% first mortgage bonds due 2047, we do not expect the mortgage bond lien protection associated with these notes to fall away. |
| |
(h) | 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, and so long as any of the 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018 are outstanding, Ameren Illinois will not optionally redeem, purchase or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions; therefore, a release date will not occur so long as any of these notes |
remain outstanding.
| |
(i) | 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. |
| |
(j) | 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 callable at 100% of par value. The bonds are also backed by an insurance guarantee policy. Less than $1 million principal amount of the bonds remains outstanding. |
| |
(k) | The bonds are callable at 100% of par value. |
| |
(l) | 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). |
| |
(m) | 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. |
| |
(n) | 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, 2017:2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated(a) |
| 2024 | $ | 450 | | | $ | 350 | | | $ | — | | | $ | 49 | | | $ | 849 | |
| 2025 | — | | | — | | | 300 | | | — | | | 300 | |
| 2026 | 950 | | | — | | | — | | | — | | | 950 | |
| 2027 | 500 | | | 400 | | | — | | | 50 | | | 950 | |
| 2028 | 450 | | | — | | | 490 | | | — | | | 940 | |
| Thereafter | 1,500 | | | 5,649 | | | 4,498 | | | 471 | | | 12,118 | |
| Total | $ | 3,850 | | | $ | 6,399 | | | $ | 5,288 | | | $ | 570 | | | $ | 16,107 | |
(a)Excludes unamortized discount, premium, and debt issuance costs of $21 million, $58 million, $56 million, and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI, respectively.
|
| | | | | | | | | | | | | | | | | | | |
| | Ameren (parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a) | | ATXI(a) | | Ameren Consolidated |
| 2018 | $ | — |
| | $ | 384 |
| | $ | 457 |
| | $ | — |
| | $ | 841 |
|
| 2019 | — |
| | 581 |
| | — |
| | — |
| | 581 |
|
| 2020 | 350 |
| | 92 |
| | — |
| | — |
| | 442 |
|
| 2021 | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| 2022 | — |
| | 56 |
| | 400 |
| | 50 |
| | 506 |
|
| Thereafter | 350 |
| | 2,867 |
| | 2,000 |
| | 400 |
| | 5,617 |
|
| Total | $ | 700 |
| | $ | 3,988 |
| | $ | 2,857 |
| | $ | 450 |
| | $ | 7,995 |
|
| |
(a) | Excludes unamortized discount, unamortized premium, and debt issuance costs of $4 million, $27 million, $27 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, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| Shares Outstanding | | Redemption Price (per share) | | 2023 | | 2022 |
| Ameren Missouri: | | | | | | | |
| Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | |
| $3.50 Series | 130,000 shares | | $ | 110.00 | | | $ | 13 | | | $ | 13 | |
| $3.70 Series | 40,000 shares | | 104.75 | | | 4 | | | 4 | |
| $4.00 Series | 150,000 shares | | 105.625 | | | 15 | | | 15 | |
| $4.30 Series | 40,000 shares | | 105.00 | | | 4 | | | 4 | |
| $4.50 Series | 213,595 shares | | 110.00 | | (a) | 21 | | | 21 | |
| $4.56 Series | 200,000 shares | | 102.47 | | | 20 | | | 20 | |
| $4.75 Series | 20,000 shares | | 102.176 | | | 2 | | | 2 | |
| $5.50 Series A | 14,000 shares | | 110.00 | | | 1 | | | 1 | |
| Total | | | | $ | 80 | | | $ | 80 | |
| Ameren Illinois: | | | | | | | |
| With par value of $100 per share, 2 million shares authorized | | | | | | |
| 4.00% Series | 144,275 shares | | $ | 101.00 | | | $ | 14 | | | $ | 14 | |
| 4.08% Series | 45,224 shares | | 103.00 | | | 5 | | | 5 | |
| 4.20% Series | 23,655 shares | | 104.00 | | | 2 | | | 2 | |
| 4.25% Series | 50,000 shares | | 102.00 | | | 5 | | | 5 | |
| 4.26% Series | 16,621 shares | | 103.00 | | | 2 | | | 2 | |
| 4.42% Series | 16,190 shares | | 103.00 | | | 2 | | | 2 | |
| 4.70% Series | 18,429 shares | | 104.30 | | | 2 | | | 2 | |
| 4.90% Series | 73,825 shares | | 102.00 | | | 7 | | | 7 | |
| 4.92% Series | 49,289 shares | | 103.50 | | | 5 | | | 5 | |
| 5.16% Series | 50,000 shares | | 102.00 | | | 5 | | | 5 | |
| | | | | | | |
| | | | | | | |
| Total | | | | $ | 49 | | | $ | 49 | |
| Total Ameren | | | | $ | 129 | | | $ | 129 | |
|
| | | | | | | | | | | | | |
| | | | Redemption Price (per share) | | 2017 | | 2016 |
| 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 no such shares outstanding. Ameren Missouri has 7.5 million shares of $1$1 par value preference stock authorized, with no such shares outstanding. Ameren Illinois has 2.6 million shares of no par value preferred stock authorized, with no such shares outstanding.
Ameren
Under the DRPlus and its 401(k) plan, Ameren issued 0.6 million, 0.5 million, and 0.5 million shares of common stock in 2023, 2022, and 2021, respectively, received proceeds of $39 million, $41 million, and $47 million for the respective years, and had a receivable of $7 million and $8 million as of December 31, 2023 and 2022. In December 2017,addition, Ameren issued 0.5 million, 0.4 million, and 0.5 million shares of common stock valued at $40 million, $31 million, and $33 million in 2023, 2022, 2021, respectively, for no cash consideration in connection with stock-based compensation.
In May 2023, Ameren filed a Form S-3 registration statement with the SEC, authorizing the offering of 3 million additional shares of its common stock under the DRPlus, which expires in May 2026. Shares of common stock sold under the DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated contracts.
In October 2023, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuance of an indeterminateunspecified amount of certain types of securities. TheThis registration statement became effective immediately upon filing and expires in December 2020.October 2026.
Ameren filed a Form S-3 registration statement with the SEC inIn May 2017, authorizing the offering of 6 million additional shares of its common stock under DRPlus, which expires in 2020. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. As of December 31, 2017 and 2016, DRPlus participant funds of $8 million were reflected on Ameren’s consolidated balance sheets in “Other current assets.”
In 2013,2022, Ameren filed a Form S-8 registration statement with the SEC, authorizing the offering of 47.5 million additional shares of its common stock under its 401(k) plan. Shares of common stock soldissuable 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.contracts.
Ameren has entered into an equity distribution sales agreement pursuant to which Ameren may offer and sell from time to time up to $1.75 billion of its common stock through 2017,an ATM program, which includes the ability to enter into forward sale agreements. Under the ATM, Ameren issued 3.2 million, 3.4 million, and 1.8 million shares of common stock and received proceeds of $299 million, $292 million, and $148 million in 2023, 2022 and 2021, respectively. These proceeds were net of $3 million, $3 million and $2 million, respectively, in compensation paid to selling agents. As of December 31, 2023, Ameren had approximately $770 million of common stock available for its DRPlussale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2023, discussed below.
The forward sale agreements outstanding as of December 31, 2023, can be settled at Ameren’s discretion on or prior to dates ranging from October 3, 2024 to February 28, 2025. On a settlement date or dates, if Ameren elects to physically settle a forward sale agreement, Ameren will issue shares of common stock to the counterparties at the then-applicable forward sale price. The initial forward sale price for the agreements ranged from $76.69 to $89.31, with an average initial forward sale price of $80.45. Each forward sale price is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and its 401(k) plans were purchasedwill be subject to decrease on certain dates specified in the open market.
forward sale agreements by specified amounts related to expected dividends on shares of the common stock during the term of the forward sale agreements. If the overnight bank funding rate is less than the spread on any day, the interest rate factor will result in a reduction of the forward sale price. The forward sale agreements will be physically settled unless Ameren Missourielects to settle in cash or to net share settle. At December 31, 2023, Ameren could have settled the forward sale agreements with physical delivery of 2.9 million shares of common stock to the respective counterparties in exchange for cash of $230 million. Alternatively, the forward sale agreements could have also been settled at December 31, 2023, with the counterparties delivering approximately $24 million of cash or approximately 0.3 million shares of common stock to Ameren. In connection to the forward sale agreements, the various counterparties, or their affiliates, borrowed from third parties and sold 2.9 million shares of common stock. The gross sales price of these shares totaled $232 million. Ameren has not received any proceeds from such sales of borrowed shares. The forward sale agreements have been classified as equity transactions.
In June 2017,February 2021, Ameren Missourisettled the remainder of a forward sale agreement entered into in August 2019, by physically delivering 1.6 million shares of common stock for cash proceeds of $113 million. The proceeds were used to fund a portion of Ameren Missouri’s wind generation investments.
In November 2023, Ameren (parent) issued $400$600 million of 2.95%5.70% senior securedunsecured notes due June 2027,December 2026, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2024. Net proceeds from this issuance were used to repay short-term debt.
In December 2023, Ameren (parent) issued $700 million of 5.00% senior unsecured notes due January 2029, with interest payable semiannually on January 15 and DecemberJuly 15 of each year, beginning DecemberJuly 15, 2017.2024. Net proceeds from this issuance were used for general corporate purposes, including the repayment of short-term debt.
Ameren Missouri
In January 2024, Ameren Missouri receivedissued $350 million of 5.25% first mortgage bonds due January 2054, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2024. Net proceeds of $396 million, whichfrom this issuance were used in conjunction with other available funds,for capital expenditures and to repay short-term debt.
In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri. Ownership of the energy center was transferred to Ameren Missouri in January 2023, at maturity $425which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture.
In March 2023, Ameren Missouri issued $500 million of Ameren Missouri’s 6.40% senior secured notes in June 2017.5.45% first mortgage bonds due March 2053, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2023. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.
In February 2016, $260April 2022, Ameren Missouri issued $525 million of 3.90% green first mortgage bonds due April 2052, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2022. Net proceeds from this issuance were used for capital expenditures and to repay short-term debt. Ameren Missouri intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.
In November 2022, $47 million principal amount of Ameren Missouri’s 5.40% senior secured notes1.60% 1992 Series bonds matured and were repaid with cash on hand and commercial paper borrowings.
In June 2016,December 2022, Ameren Missouri issued $150repaid $8 million of 3.65% senior secured notesthe remaining principal amount of the financing obligation related to the Peno Creek CT Energy Center to a trustee, which is authorized to utilize the cash only to pay equal amounts due in April 2045, with interest payable semiannually in April and October of each year, beginning in October 2016.to Ameren Missouri received proceedsunder related bonds issued by the city of $148 millionBowling Green and held by Ameren Missouri. The timing and amounts of payments due from the June 2016 issuance, which was used to repay outstanding short-term debt, including short-term debt that Ameren Missouri incurredunder the agreement were equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in connection withno net cash flow. Under the repaymentterms of $114 millionthis agreement, Ameren Missouri was responsible for all operation and maintenance for the energy center. Ownership of its 4.75% senior secured notes that maturedthe energy center transferred to Ameren Missouri in April 2015.December 2022, at which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture.
For information on Ameren Missouri’s capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
Ameren Illinois
In November 2017,May 2023, Ameren Illinois issued $500 million of 3.70%4.95% first mortgage bonds due June 2033, with interest payable semiannually on June 1 and December 1 of each year, beginning December 1, 2023. Net proceeds from this issuance were used to repay $100 million principal amount of its 0.375% first mortgage bonds that matured in June 2023 and short-term debt.
In August 2022, Ameren Illinois issued $500 million of 3.85% first mortgage bonds due September 2032, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2023. Net proceeds from this issuance were used to repay $400 million principal amount of its 2.70% senior secured notes that matured in September 2022 and short-term debt.
In November 2022, Ameren Illinois issued $350 million of 5.90% first mortgage bonds due December 2047,2052, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2018. Ameren Illinois received2023. Net proceeds of $492 million, whichfrom this issuance were used to repay outstanding short-term debt, including short-term debt thatdebt. Ameren Illinois incurred in connection withintends to allocate an amount equal to the repayment of $250 million of its 6.125% senior secured notes that matured in November 2017.
In June 2016, Ameren Illinois’ $54 million principal amount of 6.20% senior secured notes and $75 million principal amount of 6.25% senior secured notes matured and were repaid with commercial paper borrowings.
In December 2016, Ameren Illinois issued $240 million of 4.15% senior secured notes due in March 2046, with interest payable semiannually in March and September, beginning in March 2017. Ameren Illinois receivednet proceeds of $245 million from the issuance, which was used to repay a portion of its short-term debt.sustainability projects meeting certain eligibility criteria.
For information on Ameren Illinois’ capital contributions, refer to Capital Contributions in Note 13 – Related-party Transactions.
ATXI
In June 2017, pursuant to a note purchase agreement,August 2022, ATXI agreed to issue $450issued $95 million principal amount of 3.43%its 2.96% senior unsecured notes due 2050,2052 pursuant to a November 2021 note purchase agreement, with interest payable semiannually on the last day of February 25 and August 25 of each year, beginning February 28, 2018,25, 2023, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150Net proceeds from this issuance were used to refinance the remaining portion of an intercompany long-term note with Ameren (parent), repay a $50 million principal amountpayment of the notes in June 2017 and the remaining $300 million principal amount of theits 3.43% senior unsecured notes in August 2017. ATXI received proceeds of $449 million from the notes, which were used by ATXI2022, and to repay existing short-term and long-term affiliate debt.
ATXI may prepay at any time not less than 5% of the principal amount of notes then outstanding at 100% of the principal amount plus a make-whole premium. In the event of a change of control, as defined in the agreement, each holder of notes may require ATXI to prepay the entire unpaid principal amount of the notes held by such holder at a price equal to 100% of the principal amount of such notes together with accrued and unpaid interest thereon.
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, 2017,2023, at an assumed interest rate of 5%7% and dividend rate of 6%8%.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Required Interest Coverage Ratio(a) | Actual Interest
Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend
Coverage Ratio | Preferred Stock
Issuable | |
| Ameren Missouri | >2.0 | 3.3 | $4,209 | | >2.5 | 160.5 | $2,701 | |
| Ameren Illinois | >2.0 | 6.9 | 8,517 | | >1.5 | 3.8 | 203 | (d) |
|
| | | | | | | | | | | | | | |
| | 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 | 4.8 |
| $ | 4,222 |
| | >2.5 | 95.4 |
| $ | 2,118 |
| |
| Ameren Illinois | >2.0 | 7.1 |
| 4,119 |
| (d) | >1.5 | 2.9 |
| 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 $1,959 million and $1,143 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 $1,629 million and $529 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. |
| |
(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) | Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under its 1992 mortgage indenture. |
| |
(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 itstheir respective stock unless, among other things, itstheir respective earnings and earned surplus are sufficient to declare and pay a dividend after provision isprovisions 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, 2017,2023, using the FERC-agreed upon calculation method, Ameren Illinois’ ratio of common stock equity to total capitalization was 51%53%.
ATXI’s note purchase agreementagreements 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. The note purchase agreement also contains restrictive covenants that, among other things, restrict the ability of ATXI to (1) enter into certain transactions with affiliates; (2) consolidate, merge, transfer or lease all or substantially all of its assets; and (3) create liens.
At December 31, 2017,2023, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.agreements. In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable requirements in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2017,2023, none of the Ameren Companies had any significantmaterial off-balance-sheet financing arrangements, other than operating leases entered intotheir investments in variable interest entities and the ordinary coursemultiple forward sale agreements under the ATM program relating to common stock. See Note 1 – Summary of business, lettersSignificant Accounting Policies for further detail concerning variable interest entities.
NOTE 6 – OTHER INCOME, AND EXPENSESNET
The following table presents the components of “Other Income, and Expenses”Net” in the Ameren Companies’ statements of income for the years ended December 31, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | |
| Ameren: | | | | | | |
| Other Income, Net | | | | | | |
| Allowance for equity funds used during construction | $ | 54 | | | $ | 43 | | | $ | 43 | | |
| Interest income on industrial development revenue bonds | 1 | | | 24 | | | 25 | | |
| Other interest income | 32 | | | 11 | | | 2 | | |
Non-service cost components of net periodic benefit income(a) | 295 | | | 184 | | | 136 | | |
| Miscellaneous income | 7 | | | 10 | | | 10 | | |
| Earnings related to equity method investments | 1 | | | 2 | | | 12 | | |
| Donations | (24) | | | (26) | | | (9) | | |
| Miscellaneous expense | (18) | | | (22) | | | (17) | | |
| Total Other Income, Net | $ | 348 | | | $ | 226 | | | $ | 202 | | |
| Ameren Missouri: | | | | | | |
| Other Income, Net | | | | | | |
| Allowance for equity funds used during construction | $ | 30 | | | $ | 24 | | | $ | 26 | | |
| Interest income on industrial development revenue bonds | 1 | | | 24 | | | 25 | | |
| Other interest income | 10 | | | 4 | | | 1 | | |
Non-service cost components of net periodic benefit income(a) | 97 | | | 55 | | | 55 | | |
| Miscellaneous income | 3 | | | 4 | | | 3 | | |
| Donations | (2) | | | (3) | |
| (4) | | |
| Miscellaneous expense | (9) | | | (9) | | | (7) | | |
| Total Other Income, Net | $ | 130 | | | $ | 99 | | | $ | 99 | | |
| Ameren Illinois: | | | | | | |
| Other Income, Net | | | | | | |
| Allowance for equity funds used during construction | $ | 19 | | | $ | 18 | | | $ | 17 | | |
| Interest income | 21 | | | 7 | | | 1 | | |
| Non-service cost components of net periodic benefit income | 124 | | | 84 | | | 55 | | |
| Miscellaneous income | 4 | | | 5 | | | 6 | | |
| Donations | (4) | | | (8) | | | (5) | | |
| Miscellaneous expense | (8) | | | (10) | | | (8) | | |
| Total Other Income, Net | $ | 156 | | | $ | 96 | | | $ | 66 | | |
(a)For the years ended December 31, 2023, 2022, and 2021, the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $27 million, $22 million, and $(7) million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
|
| | | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | |
Ameren:(a) | | | | | | |
| Miscellaneous income: | | | | | | |
| Allowance for equity funds used during construction | $ | 24 |
| | $ | 27 |
| | $ | 30 |
| |
| Interest income on industrial development revenue bonds | 26 |
| | 27 |
| | 27 |
| |
Interest income(b) | 8 |
| | 13 |
| | 14 |
| |
| Other | 1 |
| | 7 |
| | 3 |
| |
| Total miscellaneous income | $ | 59 |
| | $ | 74 |
| | $ | 74 |
| |
| Miscellaneous expense: | | | | | | |
| Donations | $ | 8 |
| | $ | 16 |
| | $ | 15 |
| |
| Other | 13 |
| | 16 |
| | 15 |
| |
| Total miscellaneous expense | $ | 21 |
| | $ | 32 |
| | $ | 30 |
| |
| Ameren Missouri: | | | | | | |
| Miscellaneous income: | | | | | | |
| Allowance for equity funds used during construction | $ | 21 |
| | $ | 23 |
| | $ | 22 |
| |
| Interest income on industrial development revenue bonds | 26 |
| | 27 |
| | 27 |
| |
| Interest income | 1 |
| | 1 |
| | 1 |
| |
| Other | — |
| | 1 |
| | 2 |
| |
| Total miscellaneous income | $ | 48 |
| | $ | 52 |
| | $ | 52 |
| |
| Miscellaneous expense: | | | | | | |
| Donations | $ | 2 |
| | $ | 4 |
| | $ | 5 |
| |
| Other | 6 |
| | 6 |
| | 6 |
| |
| Total miscellaneous expense | $ | 8 |
| | $ | 10 |
| | $ | 11 |
| |
| Ameren Illinois: | | | | | | |
| Miscellaneous income: | | | | | | |
| Allowance for equity funds used during construction | $ | 3 |
| | $ | 4 |
| | $ | 8 |
| |
Interest income(b) | 7 |
| | 12 |
| | 12 |
| |
| Other | 1 |
| | 5 |
| | 1 |
| |
| Total miscellaneous income | $ | 11 |
| | $ | 21 |
| | $ | 21 |
| |
| Miscellaneous expense: | | | | | | |
| Donations | $ | 5 |
| | $ | 6 |
| | $ | 5 |
| |
| Other | 5 |
| | 6 |
| | 7 |
| |
| Total miscellaneous expense | $ | 10 |
| | $ | 12 |
| | $ | 12 |
| |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | Includes Ameren Illinois’ interest income on the IEIMA revenue requirement reconciliation adjustment regulatory assets. |
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:
•an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory; 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 asTable of December 31, 2017 and 2016. As of December 31, 2017, these contracts extended through October 2019, March 2023, May 2032, and September 2021 for fuel oils, natural gas, power, and uranium, respectively. |
| | | | | | | | | | | | |
| | Quantity (in millions, except as indicated) |
| | 2017 | 2016 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
Fuel oils (in gallons)(a) | 28 |
| (b) |
| 28 |
| 30 |
| (b) |
| 30 |
|
| Natural gas (in mmbtu) | 24 |
| 139 |
| 163 |
| 25 |
| 129 |
| 154 |
|
| Power (in megawatthours) | 3 |
| 9 |
| 12 |
| 1 |
| 9 |
| 10 |
|
| Uranium (pounds in thousands) | 370 |
| (b) |
| 370 |
| 345 |
| (b) |
| 345 |
|
| |
(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, 20172023 and 2016,2022, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. The cash flows from our derivative financial instruments follow the cash flow classification of the hedged item.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 2023 and 2022. As of December 31, 2023, these contracts extended through October 2026, October 2029, May 2032, and March 2024 for fuel oils, natural gas, power, and uranium, respectively.
| | | | | | | | | | | | | | | | | | | | |
| Quantity (in millions, except as indicated) |
| 2023 | 2022 |
| Commodity | Ameren Missouri | Ameren
Illinois | Ameren | Ameren Missouri | Ameren
Illinois | Ameren |
| Fuel oils (in gallons) | 17 | | — | | 17 | | 18 | | — | | 18 | |
| Natural gas (in mmbtu) | 53 | | 218 | | 271 | | 48 | | 157 | | 205 | |
| Power (in MWhs) | — | | 5 | | 5 | | 1 | | 6 | | 7 | |
| Uranium (pounds in thousands) | 186 | | — | | 186 | | 514 | | — | | 514 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of December 31, 20172023 and 2016:2022:
|
| | | | | | | | | | | |
| | Balance Sheet Location | | Ameren Missouri | | Ameren Illinois | | Ameren | |
| 2017 | | | | | | | | |
| Fuel oils | Other current assets | $ | 5 |
| $ | — |
| $ | 5 |
| |
| | Other assets | | 2 |
| | — |
| | 2 |
| |
| Natural gas | Other assets | | 1 |
| | — |
| | 1 |
| |
| Power | Other current assets | | 9 |
| | — |
| | 9 |
| |
| | Total assets (a) | $ | 17 |
| $ | — |
| $ | 17 |
| |
| Natural gas | Other current liabilities | | 5 |
| | 12 |
| | 17 |
| |
| | Other deferred credits and liabilities | | 3 |
| | 10 |
| | 13 |
| |
| Power | Other current liabilities | | 1 |
| | 13 |
| | 14 |
| |
| | Other deferred credits and liabilities | | — |
| | 182 |
| | 182 |
| |
| Uranium | Other deferred credits and liabilities | | — |
| (b) | — |
| | — |
| (b) |
| | Total liabilities (c) | $ | 9 |
| $ | 217 |
| $ | 226 |
| |
| 2016 | | | | | | | | |
| Fuel oils | Other current assets | $ | 2 |
| $ | — |
| $ | 2 |
| |
| | Other assets | | 1 |
| | — |
| | 1 |
| |
| Natural gas | Other current assets | | 1 |
| | 11 |
| | 12 |
| |
| | Other assets | | 1 |
| | 2 |
| | 3 |
| |
| Power | Other current assets | | 9 |
| | — |
| | 9 |
| |
| | Total assets (a) | $ | 14 |
| $ | 13 |
| $ | 27 |
| |
| Fuel oils | Other current liabilities | $ | 5 |
| $ | — |
| $ | 5 |
| |
| Natural gas | Other current liabilities | | 1 |
| | 3 |
| | 4 |
| |
| | Other deferred credits and liabilities | | 5 |
| | 5 |
| | 10 |
| |
| Power | Other current liabilities | | 3 |
| | 12 |
| | 15 |
| |
| | Other deferred credits and liabilities | | — |
| | 173 |
| | 173 |
| |
| Uranium | Other deferred credits and liabilities | | 4 |
| | — |
| | 4 |
| |
| | Total liabilities (c) | $ | 18 |
| $ | 193 |
| $ | 211 |
| |
| |
(a) | The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability. |
| |
(b) | Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet. |
| |
(c) | The cumulative amount of pretax net losses on all derivative instruments is deferred as a regulatory asset. |
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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | | | 2022 |
| Commodity | Balance Sheet Location | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren | | | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren |
| Fuel oils | Other current assets | | $ | 2 | | | | $ | — | | | | $ | 2 | | | | | $ | 13 | | | | $ | — | | | | $ | 13 | |
| Other assets | | — | | | | — | | | | — | | | | | 3 | | | | — | | | | 3 | |
| | | | | | | | | | | | | | | | | | | |
| Natural gas | Other current assets | | — | | | | — | | | | — | | | | | 7 | | | | 23 | | | | 30 | |
| Other assets | | 3 | | | | 3 | | | | 6 | | | | | 9 | | | | 11 | | | | 20 | |
| | | | | | | | | | | | | | | | | | | |
| Power | Other current assets | | 5 | | | | — | | | | 5 | | | | | 14 | | | | 2 | | | | 16 | |
| | Other assets | | — | | | | — | | | | — | | | | | — | | | | 4 | | | | 4 | |
| Uranium | Other current assets | | 9 | | | | — | | | | 9 | | | | | 2 | | | | — | | | | 2 | |
| Other assets | | — | | | | — | | | | — | | | | | 1 | | | | — | | | | 1 | |
| | Total assets | | $ | 19 | | | | $ | 3 | | | | $ | 22 | | | | | $ | 49 | | | | $ | 40 | | | | $ | 89 | |
| | | | | | | | | | | | | | | | | | | |
| Fuel oils | Other current liabilities | | $ | 1 | | | | $ | — | | | | $ | 1 | | | | | $ | — | | | | $ | — | | | | $ | — | |
| Other deferred credits and liabilities | | 1 | | | | — | | | | 1 | | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Natural gas | Other current liabilities | | 12 | | | | 45 | | | | 57 | | | | | 7 | | | | 20 | | | | 27 | |
| Other deferred credits and liabilities | | 10 | | | | 30 | | | | 40 | | | | | 2 | | | | 9 | | | | 11 | |
| | | | | | | | | | | | | | | | | | | |
| Power | Other current liabilities | | 1 | | | | 12 | | | | 13 | | | | | 59 | | | | 2 | | | | 61 | |
| Other deferred credits and liabilities | | — | | | | 56 | | | | 56 | | | | | — | | | | 37 | | | | 37 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | Total liabilities | | $ | 25 | | | | $ | 143 | | | | $ | 168 | | | | | $ | 68 | | | | $ | 68 | | | | $ | 136 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar agreement level by counterparty.
The Ameren Companies elect to presentfollowing table provides the fair valuerecognized gross derivative balances and the net amounts of derivative assets and derivative liabilitiesthose derivatives subject to an enforceable master netting arrangement or similar agreement as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Gross Amounts Not Offset in the Balance Sheet | | |
| Commodity Contracts Eligible to be Offset | | Gross Amounts Recognized in the Balance Sheet | | Derivative Instruments | | Cash Collateral Received/Posted(a) | | Net
Amount |
| 2023 | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | $ | 19 | | | $ | 6 | | | $ | — | | | $ | 13 | |
| Ameren Illinois | 3 | | | 1 | | | — | | | 2 | |
| Ameren | $ | 22 | | | $ | 7 | | | $ | — | | | $ | 15 | |
| Liabilities: | | | | | | | | |
| Ameren Missouri | $ | 25 | | | $ | 6 | | | $ | — | | | $ | 19 | |
| Ameren Illinois | 143 | | | 1 | | | 6 | | | 136 | |
| Ameren | $ | 168 | | | $ | 7 | | | $ | 6 | | | $ | 155 | |
| 2022 | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | $ | 49 | | | $ | 9 | | | $ | — | | | $ | 40 | |
| Ameren Illinois | 40 | | | 20 | | | — | | | 20 | |
| Ameren | $ | 89 | | | $ | 29 | | | $ | — | | | $ | 60 | |
| Liabilities: | | | | | | | | |
| Ameren Missouri | $ | 68 | | | $ | 9 | | | $ | 56 | | | $ | 3 | |
| Ameren Illinois | 68 | | | 20 | | | — | | | 48 | |
| Ameren | $ | 136 | | | $ | 29 | | | $ | 56 | | | $ | 51 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
(a)Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. However, if theCash collateral posted reduces gross amounts recognizedliability balances and is included in “Current collateral assets” and “Other assets” on the balance sheet were netted with derivative instrumentsfor Ameren and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at December 31, 2017Ameren Missouri and 2016.“Other current assets” and “Other assets” for Ameren Illinois.
Concentrations of 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, 2017,2023, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets, predominantly from financial institutions, would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.
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 additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered and (2) those counterparties with rights to do so requested collateral. The following table presents, as of December 31, 2017,2023, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additionalrequire:
| | | | | | | | | | | | | | | | | |
| | | | | |
| Aggregate Fair Value of Derivative Liabilities(a) | | Cash
Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| Ameren Missouri | $ | 24 | | | $ | — | | | $ | 19 | |
| Ameren Illinois | 74 | | | 6 | | | 66 | |
| Ameren | $ | 98 | | | $ | 6 | | | $ | 85 | |
(a)Before consideration of master netting arrangements or similar agreements.
(b)As collateral required is the net liability position allowed under therequirements with certain counterparties are based on master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on December 31, 2017, and (2) those counterparties with rightsaggregate amount of additional collateral required to do so requested collateral.be posted is determined after consideration of the effects of such arrangements.
|
| | | | | | | | | | | |
| | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| 2017 | | | | | |
| Ameren Missouri | $ | 55 |
| | $ | 3 |
| | $ | 44 |
|
| Ameren Illinois | 43 |
| | — |
| | 38 |
|
| Ameren | $ | 98 |
| | $ | 3 |
| | $ | 82 |
|
| |
(a) | Before consideration of master netting arrangements or similar agreements and including NPNS and other accrual contract exposures. |
| |
(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 1:1 (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, such as those held in Ameren Missouri’s nuclear decommissioning trust fund.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, United States Treasury and agency 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. Level 2 fixed income securities in the nuclear decommissioning trust fund are primarily corporate bonds, asset-backed securities, and United States agency bonds.
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 derivativesderivative 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
Level 3 (significant other unobservable adjustments.
Level 3: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.
The following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and 2016:
|
| | | | | | | | | | | | |
| | | Fair Value | | | | | Weighted |
| | | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
Level 3 Derivative asset and liability – commodity contracts(a): | | | |
| 2017 | | | | | | | | |
| | Fuel oils | $ | 3 |
| $ | — |
| | Option model | Volatilities(%)(b) | 20 – 26 | 22 |
| | | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.12 – 0.72 | 0.41 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.37 | (e) |
| | Natural Gas | 1 |
| (4 | ) | | Option model | Volatilities(%)(b) | 26 – 46 | 37 |
| |
|
|
| |
| Nodal basis($/mmbtu)(c) | (0.50) – (0.30) | (0.40) |
| |
|
|
| | Discounted cash flow | Nodal basis($/mmbtu)(b) | (1.20) – 0.10 | (1) |
| |
|
|
| |
| Counterparty credit risk(%)(c)(d) | 0.37 – 0.92 | 0.53 |
| |
|
|
| |
| Ameren credit risk(%)(c)(d) | 0.37 | (e) |
| | Power(f) | 8 |
| (196 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 24 – 46 | 28 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (65) – 1,823 | 251 |
| | | | | | | Nodal basis($/MWh)(g) | (10) – 0 | (2) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.28 | (e) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.37 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| 2016 | | | | | | | | |
| | Fuel oils | $ | 1 |
| $ | — |
| | Option model | Volatilities(%)(b) | 24 – 66 | 28 |
| | | | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.13 – 0.22 | 0.15 |
| | | | | | | Ameren Missouri credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | | | Escalation rate(%)(b)(i) | (2) – 2 | 0 |
| | Natural Gas | $ | 1 |
| $ | (1 | ) | | Option model | Volatilities(%)(b) | 31 – 66 | 36 |
| | | | | | | Nodal basis($/mmbtu)(b) | (0.40) – (0.10) | (0.20) |
| | | | | | Discounted cash flow | Nodal basis($/mmbtu)(b) | (0.80) – 0 | (0.50) |
| | | | | | | Counterparty credit risk(%)(c)(d) | 0.13 – 8 | 1 |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | Power(f) | 9 |
| (187 | ) | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps($/MWh)(g) | 26 – 44 | 29 |
| | | | | | | Estimated auction price for FTRs($/MW)(b) | (71) – 5,270 | 125 |
| | | | | | | Nodal basis($/MWh)(g) | (6) – 0 | (2) |
| | | | | | | Ameren Illinois credit risk(%)(c)(d) | 0.38 | (e) |
| | | | | | Fundamental energy production model | Estimated future natural gas prices($/mmbtu)(b) | 3 – 4 | 3 |
| | | | | | | Escalation rate(%)(b)(h) | 5 | (e) |
| | | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 – 7 | 6 |
| | Uranium | — |
| (4 | ) | | Option model | Volatilities(%)(b) | 24 | (e) |
|
| | | | | | | | | | | | |
| | Fair Value | | | | | Weighted |
| | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input | Range | Average |
| | | | | Discounted cash flow | Average forward uranium pricing($/pound)(b)
| 22 – 24 | 22 |
| | | | | | Ameren Missouri credit risk(%)(c)(d)
| 0.38 | (e) |
| |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
| |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
| |
(d) | Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances. |
| |
(f) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2021. Valuations beyond 2021 use fundamentally modeled pricing by month for peak and off-peak demand. |
| |
(g) | Ameren Missouri and Ameren Illinois power contracts respond differently to unobservable input changes because of their opposing positions. |
| |
(h) | Escalation rate applies to power prices in 2031 and beyond. |
| |
(i) | Escalation rate applies to fuel oil prices in 2019 and beyond. |
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 2017, 2016,2023, 2022, or 2015.2021. At December 31, 20172023 and 2016,2022, 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, 2017:2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2023 | | | December 31, 2022 | |
| | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | 2 | | $ | — | | $ | — | | $ | 2 | | | | $ | 16 | | $ | — | | $ | — | | $ | 16 | | |
| Natural gas | — | | 3 | | — | | 3 | | | | 1 | | 15 | | — | | 16 | | |
| Power | — | | — | | 5 | | 5 | | | | — | | — | | 14 | | 14 | | |
| Uranium | — | | — | | 9 | | 9 | | | | — | | — | | 3 | | 3 | | |
| Total derivative assets – commodity contracts | $ | 2 | | $ | 3 | | $ | 14 | | $ | 19 | | | | $ | 17 | | $ | 15 | | $ | 17 | | $ | 49 | | |
| Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | | | | | | | | | | | |
| Equity securities: | | | | | | | | | | | |
| U.S. large capitalization | $ | 787 | | $ | — | | $ | — | | $ | 787 | | | | $ | 618 | | $ | — | | $ | — | | $ | 618 | | |
| Debt securities: | | | | | | | | | | | |
| U.S. Treasury and agency securities | — | | 150 | | — | | 150 | | | | — | | 137 | | — | | 137 | | |
| Corporate bonds | — | | 136 | | — | | 136 | | | | — | | 122 | | — | | 122 | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Other | — | | 68 | | — | | 68 | | | | — | | 70 | | — | | 70 | | |
| Total nuclear decommissioning trust fund | $ | 787 | | $ | 354 | | $ | — | | $ | 1,141 | | (a) | | $ | 618 | | $ | 329 | | $ | — | | $ | 947 | | (a) |
| Total Ameren Missouri | $ | 789 | | $ | 357 | | $ | 14 | | $ | 1,160 | | | | $ | 635 | | $ | 344 | | $ | 17 | | $ | 996 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | — | | $ | 1 | | $ | 2 | | $ | 3 | | | | $ | 1 | | $ | 28 | | $ | 5 | | $ | 34 | | |
| Power | — | | — | | — | | — | | | | — | | — | | 6 | | 6 | | |
| Total Ameren Illinois | $ | — | | $ | 1 | | $ | 2 | | $ | 3 | | | | $ | 1 | | $ | 28 | | $ | 11 | | $ | 40 | | |
| Ameren | | | | | | | | | | | |
| Derivative assets – commodity contracts(b) | $ | 2 | | $ | 4 | | $ | 16 | | $ | 22 | | | | $ | 18 | | $ | 43 | | $ | 28 | | $ | 89 | | |
| Nuclear decommissioning trust fund(c) | 787 | | 354 | | — | | 1,141 | | (a) | | 618 | | 329 | | — | | 947 | | (a) |
| Total Ameren | $ | 789 | | $ | 358 | | $ | 16 | | $ | 1,163 | | | | $ | 636 | | $ | 372 | | $ | 28 | | $ | 1,036 | | |
| Liabilities: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | 2 | | $ | — | | $ | — | | $ | 2 | | | | $ | — | | $ | — | | $ | — | | $ | — | | |
| Natural gas | $ | — | | $ | 19 | | $ | 3 | | $ | 22 | | | | $ | — | | $ | 6 | | $ | 3 | | $ | 9 | | |
| Power | — | | — | | 1 | | 1 | | | | 57 | | — | | 2 | | 59 | | |
| | | | | | | | | | | | |
| Total Ameren Missouri | $ | 2 | | $ | 19 | | $ | 4 | | $ | 25 | | | | $ | 57 | | $ | 6 | | $ | 5 | | $ | 68 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | 4 | | $ | 60 | | $ | 11 | | $ | 75 | | | | $ | — | | $ | 19 | | $ | 10 | | $ | 29 | | |
| Power | — | | — | | 68 | | 68 | | | | — | | — | | 39 | | 39 | | |
| Total Ameren Illinois | $ | 4 | | $ | 60 | | $ | 79 | | $ | 143 | | | | $ | — | | $ | 19 | | $ | 49 | | $ | 68 | | |
| Ameren | | | | | | | | | | | |
| Derivative liabilities – commodity contracts(b) | $ | 6 | | $ | 79 | | $ | 83 | | $ | 168 | | | | $ | 57 | | $ | 25 | | $ | 54 | | $ | 136 | | |
(a)Balance excludes $9 million and $11 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2023 and 2022, respectively.
(b)See the Ameren Missouri and Ameren Illinois sections of the table for a breakout of the fair value of Ameren’s derivative assets and liabilities by type of commodity.
(c)See the Ameren Missouri section of the table for a breakout of Ameren’s nuclear decommissioning trust fund by investment type.
See Note 10 – Retirement Benefits for tables that set forth, by level within the fair value hierarchy, Ameren’s pension and postretirement plan assets as of December 31, 2023 and 2022.
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| Assets: | | | | | | | | | | |
| Ameren | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | Total Ameren | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 3 |
| | $ | 7 |
| |
| | Natural gas | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 1 |
| | $ | 12 |
| | $ | 17 |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | | | 2022 |
| Ameren
Missouri | Ameren
Illinois | Ameren | | | Ameren
Missouri | Ameren
Illinois | Ameren |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Beginning balance at January 1 | $ | 12 | | $ | (33) | | $ | (21) | | | | $ | (15) | | $ | (117) | | $ | (132) | |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | 1 | | (48) | | (47) | | | | (45) | | 92 | | 47 | |
| | | | | | | | |
| | | | | | | | |
| Settlements | (9) | | 13 | | 4 | | | | 72 | | (8) | | 64 | |
| | | | | | | | |
| | | | | | | | |
| Ending balance at December 31 | $ | 4 | | $ | (68) | | $ | (64) | | | | $ | 12 | | $ | (33) | | $ | (21) | |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | 4 | | $ | (36) | | $ | (32) | | | | $ | 12 | | $ | 75 | | $ | 87 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
All gains or losses related to our Level 3 derivative commodity contracts are expected to be recovered or returned through customer rates; therefore, there is no impact to either net income or other comprehensive income resulting from changes in the fair value of these instruments.
The following table describes the valuation techniques and significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value | | | | | Weighted Average(b) |
| Commodity | Assets | Liabilities | | Valuation Technique(s) | Unobservable Input(a) | Range |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| 2023 | Power(c) | $ | 5 | | $ | (69) | | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 31 – 65 | 43 |
| | | | | | | | |
| | | | | | Nodal basis ($/MWh) | (8) – (1) | (5) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| 2022 | Power(d) | $ | 20 | | $ | (41) | | | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 38 – 89 | 51 |
| | | | | | Nodal basis ($/MWh) | (10) – (1) | (4) |
| | | | | | | | |
| | | | | | | | |
| | | | | | Trend rate (%) | 0– 1 | 0 |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
(a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.
(b)Unobservable inputs were weighted by relative fair value.
(c)Valuations use visible forward prices adjusted for nodal-to-hub basis differentials.
(d)Valuations through 2031 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2031 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 468 |
| | — |
| | — |
| | 468 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 125 |
| | — |
| | 125 |
| |
| | Corporate bonds | | — |
| | 82 |
| | — |
| | 82 |
| |
| | Other | | — |
| | 25 |
| | — |
| | 25 |
| |
| | Total nuclear decommissioning trust fund | | $ | 470 |
| | $ | 232 |
| | $ | — |
| | $ | 702 |
| (b) |
| | Total Ameren Missouri | | $ | 474 |
| | $ | 233 |
| | $ | 12 |
| | $ | 719 |
| |
| Liabilities: | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | 1 |
| | 25 |
| | 4 |
| | 30 |
| |
| | Power | | — |
| | — |
| | 196 |
| | 196 |
| |
| | Total Ameren | | $ | 1 |
| | $ | 25 |
| | $ | 200 |
| | $ | 226 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | — |
| | 7 |
| | 1 |
| | 8 |
| |
| | Power | | — |
| | — |
| | 1 |
| | 1 |
| |
| | Total Ameren Missouri | | $ | — |
| | $ | 7 |
| | $ | 2 |
| | $ | 9 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | 1 |
| | $ | 18 |
| | $ | 3 |
| | $ | 22 |
| |
| | Power | | — |
| | — |
| | 195 |
| | 195 |
| |
| | Total Ameren Illinois | | $ | 1 |
| | $ | 18 |
| | $ | 198 |
| | $ | 217 |
| |
| |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
The following table sets forth, by level within the fair value hierarchy, our assetsthe carrying amount and liabilities measured at fair value on a recurring basis as ofDecember 31, 2016:
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| Assets: | | | | | | | | | | |
| Ameren | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Natural gas | | 2 |
| | 12 |
| | 1 |
| | 15 |
| |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 12 |
| | $ | 11 |
| | $ | 27 |
| |
|
| | | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | Total Ameren | | $ | 413 |
| | $ | 208 |
| | $ | 11 |
| | $ | 632 |
| |
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | 1 |
| | $ | 3 |
| |
| | Natural gas | | — |
| | 1 |
| | 1 |
| | 2 |
| |
| | Power | | — |
| | — |
| | 9 |
| | 9 |
| |
| | Total derivative assets – commodity contracts | | $ | 2 |
| | $ | 1 |
| | $ | 11 |
| | $ | 14 |
| |
| | Nuclear decommissioning trust fund: | | | | | | | | | |
| | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 408 |
| | — |
| | — |
| | 408 |
| |
| | Debt securities: | | | | | | | | | |
| | U.S. Treasury and agency securities | | — |
| | 112 |
| | — |
| | 112 |
| |
| | Corporate bonds | | — |
| | 67 |
| | — |
| | 67 |
| |
| | Other | | — |
| | 17 |
| | — |
| | 17 |
| |
| | Total nuclear decommissioning trust fund | | $ | 409 |
| | $ | 196 |
| | $ | — |
| | $ | 605 |
| (b) |
| | Total Ameren Missouri | | $ | 411 |
| | $ | 197 |
| | $ | 11 |
| | $ | 619 |
| |
| Ameren Illinois | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | 2 |
| | $ | 11 |
| | $ | — |
| | $ | 13 |
| |
| Liabilities: | | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | — |
| | 13 |
| | 1 |
| | 14 |
| |
| | Power | | — |
| | 1 |
| | 187 |
| | 188 |
| |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren | | $ | 5 |
| | $ | 14 |
| | $ | 192 |
| | $ | 211 |
| |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | Natural gas | | — |
| | 6 |
| | — |
| | 6 |
| |
| | Power | | — |
| | 1 |
| | 2 |
| | 3 |
| |
| | Uranium | | — |
| | — |
| | 4 |
| | 4 |
| |
| | Total Ameren Missouri | | $ | 5 |
| | $ | 7 |
| | $ | 6 |
| | $ | 18 |
| |
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 7 |
| | $ | 1 |
| | $ | 8 |
| |
| | Power | | — |
| | — |
| | 185 |
| | 185 |
| |
| | Total Ameren Illinois | | $ | — |
| | $ | 7 |
| | $ | 186 |
| | $ | 193 |
| |
| |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
All costs related to financial assets and liabilities classified as Level 3 in thedisclosed, but not carried, at fair value hierarchy are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. For the years ended December 31, 2017 and 2016, the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils, natural gas, and uranium were immaterial.
The following table summarizes the changes in the fair value of power financial assets and liabilities classified as Level 3 in the fair value hierarchy:
|
| | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| For the year ended December 31, 2016 | | | | | | |
| Beginning balance at January 1, 2016 | $ | 16 |
| $ | (170 | ) | $ | (154 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | (1 | ) | | (29 | ) | | (30 | ) |
| Purchases | | 13 |
| | — |
| | 13 |
|
| Settlements | | (21 | ) | | 14 |
| | (7 | ) |
| Ending balance at December 31, 2016 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2016 | $ | — |
| $ | (27 | ) | $ | (27 | ) |
| For the year ended December 31, 2017 | | | | | | |
| Beginning balance at January 1, 2017 | $ | 7 |
| $ | (185 | ) | $ | (178 | ) |
| Realized and unrealized gains (losses) included in regulatory assets/liabilities | | (4 | ) | | (21 | ) | | (25 | ) |
| Purchases | | 14 |
| | — |
| | 14 |
|
| Sales | | 1 |
| | — |
| | 1 |
|
| Settlements | | (11 | ) | | 11 |
| | — |
|
| Ending balance at December 31, 2017 | $ | 7 |
| $ | (195 | ) | $ | (188 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2017 | $ | — |
| $ | (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, 2017 and 2016, 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.
See Note 10 – Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 2017, as well as a table summarizing the changes in Level 3 plan assets during 2017.2023 and 2022:
The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, unbilled revenue, accounts payable, and other current financial instruments approximate fair value because of the short-term nature of these instruments. They are considered to be Level 1 in | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Carrying
Amount | | Fair Value | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| December 31, 2023 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 272 | | | $ | 272 | | | $ | — | | | $ | — | | | $ | 272 | |
| | | | | | | | | |
| Short-term debt | 536 | | | — | | | 536 | | | — | | | 536 | |
| Long-term debt (including current portion) | 15,970 | | (a) | — | | | 14,366 | | | 467 | | (b) | 14,833 | |
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 10 | | | $ | 10 | | | $ | — | | | $ | — | | | $ | 10 | |
| | | | | | | | | |
| | | | | | | | | |
| Short-term debt | 170 | | | — | | | 170 | | | — | | | 170 | |
| Borrowings from money pool | 306 | | | — | | | 306 | | | — | | | 306 | |
| Long-term debt (including current portion) | 6,341 | | (a) | — | | | 5,800 | | | — | | | 5,800 | |
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 234 | | | $ | 234 | | | $ | — | | | $ | — | | | $ | 234 | |
| | | | | | | | | |
| Short-term debt | 366 | | | — | | | 366 | | | — | | | 366 | |
| Borrowings from money pool | 135 | | | — | | | 135 | | | — | | | 135 | |
| Long-term debt (including current portion) | 5,232 | | (a) | — | | | 4,867 | | | — | | | 4,867 | |
| December 31, 2022 |
| Ameren: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 216 | | | $ | 216 | | | $ | — | | | $ | — | | | $ | 216 | |
Investments in industrial development revenue bonds(c) | 240 | | | — | | | 240 | | | — | | | 240 | |
| Short-term debt | 1,070 | | | — | | | 1,070 | | | — | | | 1,070 | |
Long-term debt (including current portion)(c) | 14,025 | | (a) | — | | | 11,989 | | | 464 | | (b) | 12,453 | |
| Ameren Missouri: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | |
| | | | | | | | | |
Investments in industrial development revenue bonds(c) | 240 | | | — | | | 240 | | | — | | | 240 | |
| Short-term debt | 329 | | | — | | | 329 | | | — | | | 329 | |
| | | | | | | | | |
Long-term debt (including current portion)(c) | 6,086 | | (a) | — | | | 5,365 | | | — | | | 5,365 | |
| Ameren Illinois: | | | | | | | | | |
| Cash, cash equivalents, and restricted cash | $ | 191 | | | $ | 191 | | | $ | — | | | $ | — | | | $ | 191 | |
| | | | | | | | | |
| Short-term debt | 264 | | | — | | | 264 | | | — | | | 264 | |
| | | | | | | | | |
| Long-term debt (including current portion) | 4,835 | | (a) | — | | | 4,320 | | | — | | | 4,320 | |
(a)Included unamortized debt issuance costs, which were excluded from the fair value hierarchy. Themeasurement, of $111 million, $45 million, and $47 million for Ameren, Companies’ short-term borrowings also approximateAmeren Missouri, and Ameren Illinois, respectively, as of December 31, 2023. Included unamortized debt issuance costs, which were excluded from the fair value becausemeasurement, of their short-term nature. $99 million, $41 million, and $44 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2022.
(b)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.
(c)Ameren and Ameren Illinois have company-owned life insurance that isMissouri had investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets” on“Investments in industrial development revenue bonds,” as of December 31, 2022, respectively, that were equal to the respective balance sheet and measured at net asset value. These investments do not considerfinance obligation for the observability of inputs; therefore, they are not included within the fair value hierarchy.Audrain CT energy center. As of December 31, 2017 and 2016, the net asset value of Ameren (parent)’s company-owned life insurance was $136 million and $123 million, respectively. As of December 31, 2017 and 2016, the net asset value of Ameren Illinois’ company owned life insurance was $9 million and $8 million, respectively.
Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.
The following table presents2022, the carrying amountsamount of the investments in industrial development revenue bonds and estimatedthe finance obligations approximated fair values of our long-term debt, capital lease obligations,value. The financing obligation for the Audrain CT Energy Center was settled in January 2023. See Note 5 – Long-term Debt and preferred stock at December 31, 2017 and 2016:Equity Financings for additional information on these agreements.
|
| | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Ameren: | | | | | | | |
Long-term debt and capital lease obligations (including current portion)(a) | $ | 7,935 |
| | $ | 8,531 |
| | $ | 7,276 |
| | $ | 7,772 |
|
Preferred stock(b) | 142 |
| | 131 |
| | 142 |
| | 131 |
|
| Ameren Missouri: | | | | | | | |
Long-term debt and capital lease obligations (including current portion)(a) | $ | 3,961 |
| | $ | 4,348 |
| | $ | 3,994 |
| | $ | 4,304 |
|
| Preferred stock | 80 |
| | 80 |
| | 80 |
| | 79 |
|
| Ameren Illinois: | | | | | | | |
| Long-term debt (including current portion) | $ | 2,830 |
| | $ | 3,028 |
| | $ | 2,588 |
| | $ | 2,765 |
|
| Preferred stock | 62 |
| | 51 |
| | 62 |
| | 52 |
|
| |
(a) | Ameren and Ameren Missouri have two CTs under separate capital lease agreements. The capital lease obligations as of December 31, 2017 and 2016, were $276 million and $282 million, respectively. In addition, Ameren and Ameren Missouri have investments in debt securities, classified as held-to-maturity and recorded in “Other Assets” that are related to the capital lease obligation CTs from the city of Bowling Green and Audrain County. As of December 31, 2017 and 2016, the fair value of these investments approximate carrying value of $276 million and $282 million, respectively. |
| |
(b) | Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet. |
NOTE 9 – 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. The NWPA established the fee paid by Ameren Missouri and other utilities that own and operate those energy centers to the federal government for disposing of the spent nuclear fuel at one mill, (one-tenth of one cent), for each kilowatthour generated and sold by those plants. The NWPA also requires the DOE to review the nuclear waste fee annually against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA,act, Ameren Missouri and other utilities have entered into standard contracts with the DOE. Consistent with the NWPA and its standard contract,DOE, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998, Ameren Missouri had historically collected one mill from its electric customers for each kilowatthour of electricity that it generated and sold from its Callaway energy center. Because1998. However, the federal government is not meeting its disposal obligation, the collection of this fee was suspended in May 2014. The DOE’s delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operations of the energy center.
As a result of the DOE’s failureDOE failed to fulfill its contractualdisposal obligations, and Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs incurred for ongoing storage of their spent fuel. TheAmeren 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 $3 million, $24 million,in the years ended December 31, 2023, 2022, and $14 million in 2017, 2016, and 2015, respectively.2021. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.
Supplier The DOE’s delay in carrying out its obligation to dispose of Fuel Assemblies
The Callaway energy center usesspent nuclear fuel assemblies fabricated by Westinghouse, which is the only NRC-licensed supplier authorized to provide fuel assemblies tofrom the Callaway energy center. DuringEnergy Center is not expected to adversely affect the first quarter of 2017, Westinghouse filed voluntary petitions for a court-supervised restructuring process under Chapter 11continued operations of the United States Bankruptcy Code. Westinghouse could petition the bankruptcy court to reject Ameren Missouri’s contracts as partenergy 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 eventually 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.value. Annual decommissioning costs of $7 million are included in the costs used to establish electric rates for Ameren Missouri’s customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center.Energy Center. An updated cost study and funding analysis was filed with the MoPSC in September 2017December 2023 and reflected within the ARO. In January 2018, the MoPSC approvedAmeren Missouri’s filing supported no change in electric service rates for decommissioning costs based on costs. There is no deadline by which the MoPSC must issue an order regarding the filing.
Ameren Missouri’s updated cost study and funding analysis.Ameren Missouri have classified the investments in debt and equity securities that are held in the nuclear decommissioning trust fund as available for sale, and have recorded all such investments at their fair market value at December 31, 2023 and 2022. Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities.
The fair value of the trust fund for Ameren Missouri’s Callaway energy 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, 2023. If the assumed return on trust assets is not earned, Ameren Missouri believes that it is probable that any additional funding requirements resulting from such earnings deficiency will be recovered in customer rates.
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, 2017 and 2016. 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 salesales 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, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 |
| Proceeds from sales and maturities | $ | 240 | | | $ | 216 | | | $ | 439 | |
| Gross realized gains | 6 | | | 40 | | | 32 | |
| Gross realized losses | 11 | | | 10 | | | 6 | |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Proceeds from sales and maturities | $ | 396 |
| | $ | 377 |
| | $ | 349 |
|
| Gross realized gains | 13 |
| | 7 |
| | 8 |
|
| Gross realized losses | 5 |
| | 4 |
| | 2 |
|
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, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2023 | | | | | | | |
| Debt securities | $ | 382 | | | $ | 3 | | | $ | 31 | | | $ | 354 | |
| Equity securities | 191 | | | 603 | | | 7 | | | 787 | |
| Cash and cash equivalents | 5 | | | — | | | — | | | 5 | |
Other(a) | 4 | | | — | | | — | | | 4 | |
| Total | $ | 582 | | | $ | 606 | | | $ | 38 | | | $ | 1,150 | |
| 2022 | | | | | | | |
| Debt securities | $ | 374 | | | $ | — | | | $ | 45 | | | $ | 329 | |
| Equity securities | 177 | | | 455 | | | 14 | | | 618 | |
| Cash and cash equivalents | 8 | | | — | | | — | | | 8 | |
Other(a) | 3 | | | — | | | — | | | 3 | |
| Total | $ | 562 | | | $ | 455 | | | $ | 59 | | | $ | 958 | |
(a)Represents net receivables and payables relating to pending securities sales, interest, and securities purchases.
|
| | | | | | | | | | | | | | |
| Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 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 |
|
| 2016 | | | | | | | |
| Debt securities | $ | 197 |
| | $ | 3 |
| $ | 4 |
| | $ | 196 |
|
| Equity securities | 161 |
| | 253 |
| | 6 |
| | 408 |
|
| Cash and cash equivalents | 1 |
| | — |
| | — |
| | 1 |
|
Other(a) | 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 361 |
| | $ | 256 |
| $ | 10 |
| | $ | 607 |
|
| |
(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, 2017:2023:
| | | | | | | | | | | |
| Cost | | Fair Value |
| Less than 5 years | $ | 101 | | | $ | 98 | |
| 5 years to 10 years | 163 | | | 156 | |
| Due after 10 years | 118 | | | 100 | |
| Total | $ | 382 | | | $ | 354 | |
|
| | | | | | | |
| | Cost | | Fair Value |
| Less than 5 years | $ | 120 |
| | $ | 120 |
|
| 5 years to 10 years | 54 |
| | 55 |
|
| Due after 10 years | 54 |
| | 57 |
|
| Total | $ | 228 |
| | $ | 232 |
|
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, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively,2024:
| | | | | | | | | | | | | | | | | |
| Type and Source of Coverage | Most Recent
Renewal Date | Maximum Coverages | | Maximum Assessments
for Single Incidents | |
| Public liability and nuclear worker liability: | | | | | |
| American Nuclear Insurers | January 1, 2024 | $ | 500 | | | $ | — | | |
| Pool participation | (a) | 15,763 | | (a) | 166 | | (b) |
| | $ | 16,263 | | (c) | $ | 166 | | |
| Property damage: | | | | | |
| NEIL and EMANI | April 1, 2023 | $ | 3,200 | | (d) | $ | 28 | | (e) |
| Accidental outage: | | | | | |
| NEIL | April 1, 2023 | $ | 490 | | (f) | $ | 9 | | (e) |
(a)Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.
(b)Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $500 million in the event of an incident at any licensed United States commercial reactor, payable at $24.7 million per year.
(c)Limit of liability for each year.incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors.
(d)NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events. |
| | | | | | | | |
| Type and Source of Coverage | Maximum Coverages | | Maximum Assessments for Single Incidents | |
| Public liability and nuclear worker liability: | | | | |
| American Nuclear Insurers | $ | 450 |
| | $ | — |
| |
| Pool participation | 12,986 |
| (a) | 127 |
| (b) |
| | $ | 13,436 |
| (c) | $ | 127 |
| |
| Property damage: | | | | |
| NEIL and EMANI | $ | 3,200 |
| (d) | $ | 30 |
| (e) |
| Replacement power: | | | | |
| NEIL | $ | 490 |
| (f) | $ | 7 |
| (e) |
| |
(a) | Provided through mandatory participation in an industrywide retrospective premium assessment 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 $19 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. |
(f)Accidental outage insurance provides for lost sales in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in September 2013.October 2023. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates. Terroristaggregates, such that terrorist acts against one or more commercial nuclear power plants insured by NEIL or EMANI within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share one fullthe 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 have an aggregate limitare not subject to industrywide aggregates in the event of €600 million for radiation and nonradiation events within a period of 72 hours.terrorist attacks on nuclear facilities.
If losses from a nuclear incident at the Callaway energy centerEnergy Center exceed the insurance 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. Ameren uses a measurement date of December 31
for its pension2015 and postretirement benefit plans.union employees hired before January 2020. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. All non-union employees participate in a cash balance pension plan. Ameren Missouri union employees hired after June 2013, and Ameren Illinois union employees hired after mid-October 2012, participate in a cash balance pension plan. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren’s other postretirement plan is the Ameren Retiree Welfare Benefit Plan. Ameren also has an unfunded nonqualified pension plan, the Ameren Supplemental Retirement Plan, which is available to provide certain managementnon-union 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. Effective December 31, 2016, the applicable assets and liabilities of the Ameren Group Life Insurance Plan were merged with the Ameren Retiree Welfare Benefit Plan. Only Ameren subsidiaries participate in the plans listed above.
Ameren’s unfunded obligation under its pension and other postretirement benefit plans waswere overfunded by $551 million and $774$377 million in the aggregate as of December 31, 20172023 and 2016,2022, respectively. These net liabilitiesassets are recorded in “Other current liabilities” and “Pension and other postretirement benefits”benefits,” “Other current liabilities,” and “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. The decreaseincrease in the unfunded obligationoverfunded pension and postretirement benefit plans during 20172023 was primarily the result of a larger-than-expected increase in the returngains on plan assets of the pension and postretirement trusts during 2023 offset by a 50 basis point30-basis-point decrease in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligation. The decrease in the unfunded obligationoverfunded pension and other postretirement benefit 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, 20172023 and 2016:2022:
| | | | | | | | | | | |
| 2023 | | 2022 |
Ameren(a) | $ | (551) | | | $ | (377) | |
Ameren Missouri(a) | (142) | | | (84) | |
Ameren Illinois(a) | (351) | | | (263) | |
(a)Liabilities associated with pension and other postretirement benefits are recorded in “Other current liabilities” and “Other deferred credits and liabilities” on Ameren’s, Ameren Missouri’s, and Ameren Illinois’ balance sheets.
|
| | | | | | |
| | 2017 |
| 2016 |
|
Ameren(a) | $ | 551 |
| $ | 774 |
|
| Ameren Missouri | 215 |
| 293 |
|
Ameren Illinois(b) | 213 |
| 315 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(b) | Other postretirement benefit liability is 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, 20172023 and 2016.2022. It also provides the amounts included in regulatory assets or liabilities and accumulated OCI at December 31, 20172023 and 2016,2022, that have not been recognized in net periodic benefit costs.
| | | | | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 |
| Pension
Benefits | | Postretirement
Benefits | | Pension
Benefits | | Postretirement
Benefits |
| Accumulated benefit obligation at end of year | $ | 4,102 | | $ | (a) | | $ | 3,911 | | $ | (a) |
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,061 | | $ | 838 | | | $ | 5,457 | | $ | 1,129 | |
| Service cost | 79 | | | 12 | | | 128 | | | 20 | |
| Interest cost | 221 | | | 45 | | | 163 | | | 34 | |
| | | | | | | |
| Participant contributions | — | | | 7 | | | — | | | 8 | |
| Actuarial (gain) loss | 170 | | | 17 | | | (1,425) | | | (289) | |
| | | | | | | |
| Benefits paid | (273) | | | (63) | | | (262) | | | (64) | |
| | | | | | | |
| | | | | | | |
| Net benefit obligation at end of year | 4,258 | | | 856 | | | 4,061 | | | 838 | |
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 4,027 | | | 1,249 | | | 5,745 | | | 1,558 | |
| Actual return on plan assets | 514 | | | 197 | | | (1,461) | | | (255) | |
| Employer contributions | 4 | | | 3 | | | 5 | | | 2 | |
| | | | | | | |
| | | | | | | |
| Participant contributions | — | | | 7 | | | — | | | 8 | |
| | | | | | | |
| | | | | | | |
| Benefits paid | (273) | | | (63) | | | (262) | | | (64) | |
| Fair value of plan assets at end of year | 4,272 | | | 1,393 | | | 4,027 | | | 1,249 | |
| Funded status – deficiency (surplus) | (14) | | | (537) | | | 34 | | | (411) | |
| Accrued benefit cost (asset) at December 31 | $ | (14) | | $ | (537) | | | $ | 34 | | $ | (411) | |
| Amounts recognized in the balance sheet consist of: | | | | | | | |
| Noncurrent asset | $ | (44) | | $ | (537) | | | $ | — | | $ | (411) | |
Current liability(b) | 2 | | | — | | | 3 | | | — | |
Noncurrent liability(c) | 28 | | | — | | | 31 | | | — | |
| Net liability (asset) recognized | $ | (14) | | $ | (537) | | | $ | 34 | | $ | (411) | |
| Amounts recognized in regulatory assets or liabilities consist of: | | | | | | | |
| Net actuarial gain | $ | (10) | | $ | (311) | | | $ | (107) | | $ | (268) | |
| Prior service credit | — | | | (25) | | | — | | | (29) | |
| | | | | | | |
| Amounts recognized in accumulated OCI (pretax) consist of: | | | | | | | |
| Net actuarial (gain) loss | 22 | | | (4) | | | 15 | | | (4) | |
| | | | | | | |
| Total | $ | 12 | | $ | (340) | | | $ | (92) | | $ | (301) | |
(a)Not applicable.
(b)Included in “Other current liabilities” on Ameren’s consolidated balance sheet.
(c)Included in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet.
|
| | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Pension Benefits(a) | | Postretirement Benefits(a) | | Pension Benefits(a) | | Postretirement Benefits(a) |
| Accumulated benefit obligation at end of year | $ | 4,577 |
| $ | (b) |
| | $ | 4,288 |
| $ | (b) |
|
| Change in benefit obligation: | | | | | | | |
| Net benefit obligation at beginning of year | $ | 4,518 |
| $ | 1,170 |
| | $ | 4,197 |
| $ | 1,094 |
|
| Service cost | 93 |
| | 21 |
| | 81 |
| | 19 |
|
| Interest cost | 179 |
| | 47 |
| | 185 |
| | 50 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 8 |
|
| Actuarial loss | 255 |
| | 53 |
| | 265 |
| | 52 |
|
| Benefits paid | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Federal subsidy on benefits paid | (b) |
| | — |
| | (b) |
| | 1 |
|
| Net benefit obligation at end of year | 4,827 |
| | 1,240 |
| | 4,518 |
| | 1,170 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 3,813 |
| | 1,101 |
| | 3,653 |
| | 1,071 |
|
| Actual return on plan assets | 634 |
| | 171 |
| | 313 |
| | 73 |
|
| Employer contributions | 64 |
| | 2 |
| | 57 |
| | 2 |
|
| Federal subsidy on benefits paid | (b) |
| | — |
| | (b) |
| | 1 |
|
| Participant contributions | — |
| | 8 |
| | — |
| | 8 |
|
| Benefits paid | (218 | ) | | (59 | ) | | (210 | ) | | (54 | ) |
| Fair value of plan assets at end of year | 4,293 |
| | 1,223 |
| | 3,813 |
| | 1,101 |
|
| Funded status – deficiency | 534 |
| | 17 |
| | 705 |
| | 69 |
|
| Accrued benefit cost at December 31 | $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in the balance sheet consist of: | | | | | | | |
Current liability(c) | 3 |
| | 3 |
| | 3 |
| | 2 |
|
| Noncurrent liability | 531 |
| | 14 |
| | 702 |
| | 67 |
|
| Net liability recognized | $ | 534 |
| $ | 17 |
| | $ | 705 |
| $ | 69 |
|
| Amounts recognized in regulatory assets consist of: | | | | | | | |
| Net actuarial (gain) loss | $ | 374 |
| $ | (69 | ) | | $ | 535 |
| $ | (29 | ) |
| Prior service credit | (3 | ) | | (3 | ) | | (4 | ) | | (8 | ) |
| Amounts (pretax) recognized in accumulated OCI consist of: | | | | | | | |
| Net actuarial loss | 30 |
| | 2 |
| | 43 |
| | — |
|
| Prior service credit | — |
| | — |
| | — |
| | (1 | ) |
| Total | $ | 401 |
| $ | (70 | ) | | $ | 574 |
| $ | (38 | ) |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(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, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Postretirement Benefits | |
| 2023 | | 2022 | | 2023 | | 2022 | |
| Discount rate at measurement date | 5.25 | % | | 5.55 | % | | 5.25 | % | | 5.55 | % | |
| Increase in future compensation | 3.50 | | (a) | 3.50 | | (a) | 3.50 | | (a) | 3.50 | | (a) |
| Cash balance pension plan interest crediting rate | 5.50 | | | 5.00 | | (b) | (c) | | (c) | |
Medical cost trend rate (initial)(d) | (c) | | (c) | | (e) | | (e) | |
Medical cost trend rate (ultimate)(d) | (c) | | (c) | | 5.00 | | | 5.00 | | |
| | | | | | | | |
|
| | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Discount rate at measurement date | 3.50 | % | | 4.00 | % | | 3.50 | % | | 4.00 | % |
| 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)Cash balance pension plan interest crediting rate was 5.50% for 2023 and 2024, and 5.00% thereafter.
(c)Not applicable.
(d)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants was 2.50% at December 31, 2023 and 2022.
(e)Initial medical cost trend rates of 6.93% and 7.25% for pre-Medicare plan participants and 6.50% and 6.75% for post-Medicare plan participants at December 31, 2023 and 2022, respectively, trend down to the ultimate rate by 2030, with a 3.00% upward adjustment to the post-Medicare trend rate in 2025.
Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan’s projected benefit payments. The settlement portfolio of bonds is selected from a pool of more than 600approximately 860 high-quality corporate bonds. A single discount rate is then determined; that rate results in a discounted value of the plan’s benefit payments that equates to the market value of the selected bonds. In addition, during 2017,2023, Ameren adoptedelected to continue to use the Society of Actuaries 2017mortality table and the Society of Actuaries 2020 Mortality Improvement Scale. The updated scale assumes a lower rate of mortality improvement as compared to the 2016 Mortality Improvement Scale that Ameren
used in 2016, resulting 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 requirements, and other regulatory requirements. As a result, Ameren expects to fund its pension planplans at a level equal to the greater of the pension cost or the legally required minimum contribution. ConsideringBased on its assumptions at December 31, 2017,2023, its investment performance in 2017,2023, and its pension funding policy, Ameren does not expect to make material contributions in 2024 and 2025, and expects to make annualaggregate contributions of less than $1$120 million to $60 million in each of the next five years, with aggregate estimated contributions of $120 million.2026 through 2028. Ameren Missouri and Ameren Illinois expectestimate that their portion of the future funding requirements towill be 35%40% and 55%50%, respectively. These amounts are estimates. Theyestimated contributions may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the cash contributions made to our defined benefit retirement planplans and to our postretirement plansplan during 2017, 2016,2023, 2022, and 2015:2021:
| | | | Pension Benefits | | Postretirement Benefits |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Pension Benefits | |
| Pension Benefits | |
| Pension Benefits | |
| 2023 | |
| 2023 | |
| 2023 | |
| Ameren Missouri | |
| Ameren Missouri | |
| Ameren Missouri | $ | 19 |
| | $ | 21 |
| | $ | 47 |
| | $ | 1 |
| | $ | 1 |
| | $ | 8 |
|
| Ameren Illinois | 37 |
| | 30 |
| | 45 |
| | 1 |
| | 1 |
| | 8 |
|
| Other | 8 |
| | 6 |
| | 19 |
| | — |
| | — |
| | 2 |
|
| Ameren Illinois | |
| Ameren Illinois | |
| Ameren Services | |
| Ameren Services | |
| Ameren Services | |
| Ameren | 64 |
| | 57 |
| | 111 |
| | 2 |
| | 2 |
| | 18 |
|
| Ameren | |
| Ameren | |
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 adjustedreviewed 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%6.75% in 2018. No plan assets are expected to be returned to Ameren during 2018.2024.
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.
Ameren’s investment committee developed and implemented a liability hedging investment strategy for its qualified pension plans designed to reduce interest rate risk as part of an objective for its long-term investment strategy. The plan invests in derivative instruments mainly consisting of interest rate futures intended to extend the duration of the pension plan assets so that the assets are more closely aligned with the duration of the liabilities. In addition, part of Ameren’s investment strategy includes participation in a securities lending program, which allows it to lend eligible securities to third party borrowers. All loans are collateralized by at least 103% of the loaned asset’s market value and the collateral is invested in the form of cash, government obligations, and U.S. agency obligations. Ameren’s fair value of securities loaned was $234 million and $239 million as of December 31, 2023 and 2022, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2023 and 2022.
The following table presents our target allocations for 2018 and our pension and postretirement plans’ asset categories as of December 31, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | |
Asset
Category | Target Allocation 2023 | | Percentage of Plan Assets at December 31, | |
| 2023 | | 2022 | |
| Pension Plan: | | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 1 | % | |
| Equity securities: | | | | | | |
| U.S. large-capitalization | 11% – 21% | | 15 | % | | 15 | % | |
| U.S. small- and mid-capitalization | 3% – 13% | | 8 | % | | 8 | % | |
| Global | 10% – 20% | | 16 | % | | 12 | % | |
| International | 6% – 16% | | 12 | % | | 16 | % | |
| Total equity | 45% – 55% | | 51 | % | | 51 | % | |
| Debt securities | 35% – 45% | | 35 | % | (a) | 35 | % | (a) |
| Diversified credit | 0% – 10% | | 7 | % | | 7 | % | |
| Real estate | 0% – 10% | | 6 | % | | 6 | % | |
| Private equity | 0% – 5% | | (b) | | (b) | |
| Total | | | 100 | % | | 100 | % | |
| Postretirement Plans: | | | | | | |
| Cash and cash equivalents | 0% – 7% | | 1 | % | | 2 | % | |
| Equity securities: | | | | | | |
| U.S. large-capitalization | 23% – 33% | | 32 | % | | 29 | % | |
| U.S. small- and mid-capitalization | 3% – 13% | | 8 | % | | 8 | % | |
| Global | 9% – 19% | | 15 | % | | 10 | % | |
| International | 5% – 15% | | 8 | % | | 13 | % | |
| Total equity | 55% – 65% | | 63 | % | | 60 | % | |
| Debt securities | 33% – 43% | | 36 | % | | 38 | % | |
| Total | | | 100 | % | | 100 | % | |
|
| | | | | | | |
Asset Category | Target Allocation 2018 | | Percentage of Plan Assets at December 31, |
| 2017 | | 2016 |
| Pension Plan: | | | | | |
| Cash and cash equivalents | 0% – 5% | | 1 | % | | 1 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 29% – 39% | | 34 | % | | 34 | % |
| U.S. small- and mid-capitalization | 3% – 13% | | 9 | % | | 9 | % |
| International and emerging markets | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 51% – 61% | | 57 | % | | 57 | % |
| Debt securities | 35% – 45% | | 37 | % | | 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 | % | | 3 | % |
| Equity securities: | | | | | |
| U.S. large-capitalization | 34% – 44% | | 41 | % | | 40 | % |
| U.S. small- and mid-capitalization | 2% – 12% | | 8 | % | | 7 | % |
| International and emerging markets | 9% – 19% | | 14 | % | | 14 | % |
| Total equity | 55% – 65% | | 63 | % | | 61 | % |
| Debt securities | 33% – 43% | | 35 | % | | 36 | % |
| Total | | | 100 | % | | 100 | % |
| |
(a)
| Less than 1% of plan assets. |
(b)Less than 1% of plan assets.
In general, the United States large-capitalization equity investments are passively managed or indexed, whereas the international, emerging markets,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 emerging market securities, and non-United-States-dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Diversified credit investments include but are not limited to, sub-investment grade rated bonds and loans, securitized credit, and emerging market debt. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. 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, 2017. The fair2023. Fair value of an asset is defined as the amountprice that would be received upon its salefor an asset in the principal or most advantageous market for the asset in an orderly transaction between market participants aton 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, 2017:2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | | December 31, 2022 |
| Level 1 | | Level 2 | | | NAV | | Total | | | Level 1 | | Level 2 | | | NAV | | Total |
| Cash and cash equivalents | $ | — | | | $ | — | | | | $ | 90 | | | $ | 90 | | | | $ | — | | | $ | — | | | | $ | 172 | | | $ | 172 | |
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | — | | | — | | | | 663 | | | 663 | | | | — | | | — | | | | 658 | | | 658 | |
| U.S. small- and mid-capitalization | 353 | | | — | | | | — | | | 353 | | | | 321 | | | — | | | | — | | | 321 | |
| International | 316 | | | — | | | | 229 | | | 545 | | | | 266 | | | — | | | | 395 | | | 661 | |
| Global | — | | | — | | | | 721 | | | 721 | | | | — | | | — | | | | 493 | | | 493 | |
| Debt securities: | | | | | | | | | | | | | | | | | | |
| Corporate bonds | — | | | 479 | | | | — | | | 479 | | | | — | | | 397 | | | | — | | | 397 | |
| Municipal bonds | — | | | 43 | | | | — | | | 43 | | | | — | | | 41 | | | | — | | | 41 | |
| U.S. Treasury and agency securities | — | | | 994 | | | | — | | | 994 | | | | — | | | 859 | | | | — | | | 859 | |
| Diversified credit | — | | | — | | | | 305 | | | 305 | | | | — | | | — | | | | 281 | | | 281 | |
| Other | 49 | | | 13 | | | | — | | | 62 | | | | (3) | | | 7 | | | | — | | | 4 | |
| Real estate | — | | | — | | | | 248 | | | 248 | | | | — | | | — | | | | 271 | | | 271 | |
| Private equity | — | | | — | | | | — | | | — | | | | — | | | — | | | | 1 | | | 1 | |
| Total | $ | 718 | | | $ | 1,529 | | | | $ | 2,256 | | | $ | 4,503 | | | | $ | 584 | | | $ | 1,304 | | | | $ | 2,271 | | | $ | 4,159 | |
Less: Medical benefit assets(a) | | | | | | | | (196) | | | | | | | | | | | (172) | |
Plus: Net receivables (payables)(b) | | | | | | | | (35) | | | | | | | | | | | 40 | |
| Fair value of pension plans’ assets | | | | | | | | $ | 4,272 | | | | | | | | | | | $ | 4,027 | |
(a)Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation.
(b)Net of receivables related to pending securities sales and payables related to pending securities purchases.
|
| | | | | | | | | | | | | | | | | | | |
| | 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 | $ | — |
| | $ | — |
| | $ | — |
| | $ | 25 |
| | $ | 25 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,523 |
| | 1,523 |
|
| U.S. small- and mid-capitalization | 379 |
| | — |
| | — |
| | — |
| | 379 |
|
| International and emerging markets | 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 pension plans’ assets measured at fair value as of December 31, 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | 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 | $ | — |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | — |
| | — |
| | — |
| | 1,352 |
| | 1,352 |
|
| U.S. small- and mid-capitalization | 361 |
| | — |
| | — |
| | — |
| | 361 |
|
| International and emerging markets | 133 |
| | — |
| | — |
| | 389 |
| | 522 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 617 |
| | — |
| | 13 |
| | 630 |
|
| Municipal bonds | — |
| | 95 |
| | — |
| | — |
| | 95 |
|
| U.S. Treasury and agency securities | — |
| | 701 |
| | — |
| | — |
| | 701 |
|
| Other | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Real estate | — |
| | — |
| | — |
| | 202 |
| | 202 |
|
| Private equity | — |
| | — |
| | — |
| | 6 |
| | 6 |
|
| Total | $ | 494 |
| | $ | 1,434 |
| | $ | — |
| | $ | 1,995 |
| | $ | 3,923 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | | | (132 | ) |
Plus: Net receivables at December 31(b) | | | | | | | | | 22 |
|
| Fair value of pension plans’ assets at December 31 | | �� | | | | | | | $ | 3,813 |
|
| |
(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, 2017:2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | | December 31, 2022 |
| Level 1 | | Level 2 | | | NAV | | Total | | | Level 1 | | Level 2 | | | NAV | | Total |
| Cash and cash equivalents | $ | 10 | | | $ | — | | | | $ | — | | | $ | 10 | | | | $ | 14 | | | $ | — | | | | $ | — | | | $ | 14 | |
| Equity securities: | | | | | | | | | | | | | | | | | | |
| U.S. large-capitalization | 302 | | | — | | | | 81 | | | 383 | | | | 221 | | | — | | | | 87 | | | 308 | |
| U.S. small- and mid-capitalization | 96 | | | — | | | | — | | | 96 | | | | 92 | | | — | | | | — | | | 92 | |
| International | 51 | | | — | | | | 49 | | | 100 | | | | 43 | | | — | | | | 98 | | | 141 | |
| Global | — | | | — | | | | 174 | | | 174 | | | | — | | | — | | | | 110 | | | 110 | |
| | | | | | | | | | | | | | | | | | |
| Debt securities: | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Municipal bonds | — | | | 161 | | | | — | | | 161 | | | | — | | | 123 | | | | — | | | 123 | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Other | — | | | — | | | | 271 | | | 271 | | | | — | | | — | | | | 287 | | | 287 | |
| Total | $ | 459 | | | $ | 161 | | | | $ | 575 | | | $ | 1,195 | | | | $ | 370 | | | $ | 123 | | | | $ | 582 | | | $ | 1,075 | |
Plus: Medical benefit assets(a) | | | | | | | | 196 | | | | | | | | | | | 172 | |
Plus: Net receivables(b) | | | | | | | | 2 | | | | | | | | | | | 2 | |
| Fair value of postretirement benefit plans’ assets | | | | | | | | $ | 1,393 | | | | | | | | | | | $ | 1,249 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 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 and emerging markets | 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) | (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)Net of December 31, 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | 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 | $ | 53 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 53 |
|
| Equity securities: | | | | | | | | | |
| U.S. large-capitalization | 291 |
| | — |
| | — |
| | 101 |
| | 392 |
|
| U.S. small- and mid-capitalization | 72 |
| | — |
| | — |
| | — |
| | 72 |
|
| International and emerging markets | 40 |
| | — |
| | — |
| | 92 |
| | 132 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Debt securities: | | | | | | | | | |
| Corporate bonds | — |
| | 141 |
| | — |
| | — |
| | 141 |
|
| Municipal bonds | — |
| | 110 |
| | — |
| | — |
| | 110 |
|
| U.S. Treasury and agency securities | — |
| | 68 |
| | — |
| | — |
| | 68 |
|
| Other | — |
| | — |
| | — |
| | 19 |
| | 19 |
|
| Total | $ | 456 |
| | $ | 326 |
| | $ | — |
| | $ | 212 |
| | $ | 994 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | | | 132 |
|
Less: Net payables at December 31(b) | | | | | | | | | (25 | ) |
| Fair value of postretirement benefit plans’ assets at December 31 | | | | | | | | | $ | 1,101 |
|
| |
(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. |
receivables related to pending securities sales and payables related to pending securities purchases.
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost (income) of Ameren’s pension and postretirement benefit plans during 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | | Postretirement Benefits |
| 2023 | | 2022 | | 2021 | | | 2023 | | 2022 | | 2021 |
Service cost(a) | $ | 79 | | | $ | 128 | | | $ | 134 | | | | $ | 12 | | | $ | 20 | | | $ | 23 | |
| Non-service cost components: | | | | | | | | | | | | |
| Interest cost | 221 | | | 163 | | | 152 | | | | 45 | | | 34 | | | 33 | |
Expected return on plan assets(b) | (333) | | | (320) | | | (297) | | | | (91) | | | (85) | | | (80) | |
Amortization of(b): | | | | | | | | | | | | |
| | | | | | | | | | | | |
| Prior service credit | — | | | — | | | — | | | | (4) | | | (4) | | | (4) | |
| Actuarial (gain) loss | (115) | | | 25 | | | 73 | | | | (45) | | | (19) | | | (6) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Total non-service cost components(c) | $ | (227) | | | $ | (132) | | | $ | (72) | | | | $ | (95) | | | $ | (74) | | | $ | (57) | |
Net periodic benefit cost (income)(d) | $ | (148) | | | $ | (4) | | | $ | 62 | | | | $ | (83) | | | $ | (54) | | | $ | (34) | |
|
| | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| 2017 | | | |
| Service cost | $ | 93 |
| | $ | 21 |
|
| Interest cost | 179 |
| | 47 |
|
| Expected return on plan assets | (262 | ) | | (75 | ) |
| Amortization of: | | | |
| Prior service credit | (1 | ) | | (5 | ) |
| Actuarial (gain) loss | 55 |
| | (6 | ) |
| Net periodic benefit cost (income) | $ | 64 |
| | $ | (18 | ) |
| 2016 | | | |
| Service cost | $ | 81 |
| | $ | 19 |
|
| Interest cost | 185 |
| | 50 |
|
| Expected return on plan assets | (253 | ) | | (72 | ) |
| Amortization of: | | | |
| Prior service credit | (1 | ) | | (5 | ) |
| Actuarial (gain) loss | 32 |
| | (11 | ) |
| Net periodic benefit cost (income) | $ | 44 |
| | $ | (19 | ) |
| 2015 | | | |
| Service cost | $ | 92 |
| | $ | 24 |
|
| Interest cost | 174 |
| | 48 |
|
| Expected return on plan assets | (248 | ) | | (68 | ) |
| Amortization of: | | | |
| Prior service credit | (1 | ) | | (5 | ) |
| Actuarial loss | 74 |
| | 5 |
|
| Curtailment gain | 1 |
| | — |
|
| Net periodic benefit cost | $ | 92 |
| | $ | 4 |
|
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into Ameren’s net periodic benefit cost in 2018 are as follows:
|
| | | | | | | |
| Pension Benefits(a) | | Postretirement Benefits(a) |
| Regulatory assets: | | | |
| Prior service credit | $ | (1 | ) | | $ | (2 | ) |
| Net actuarial (gain) loss | 60 |
| | (1 | ) |
| Accumulated OCI: | | | |
| Net actuarial loss | 5 |
| | — |
|
| Total | $ | 64 |
| | $ | (3 | ) |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
(b)Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. Net actuarial gains or losses related to the net benefit obligation subject to amortization are amortized on a straight-line basis over 10 years. The difference between the actual and expected return on plan assets is amortized over 4 years.
(c)Non-service cost components are reflected in “Other Income, Net” on Ameren’s consolidated statement of income. See Note 6 – Other Income, Net for additional information.
(d)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs.costs (income). The following table presents the pension costs and the postretirement benefit costs (income) incurred for the years ended December 31, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Costs | | Postretirement Costs |
| 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 |
Ameren Missouri(a) | $ | (76) | | | $ | (3) | | | $ | 29 | | | $ | (30) | | | $ | (14) | | | $ | (4) | |
| Ameren Illinois | (62) | | | 3 | | | 34 | | | (54) | | | (41) | | | (31) | |
| Other | (10) | | | (4) | | | (1) | | | 1 | | | 1 | | | 1 | |
| Ameren | $ | (148) | | | $ | (4) | | | $ | 62 | | | $ | (83) | | | $ | (54) | | | $ | (34) | |
(a)Does not include the impact of the tracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in customer rates.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Costs | | Postretirement Costs |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Ameren Missouri(a) | $ | 24 |
| | $ | 26 |
| | $ | 54 |
| | $ | (4 | ) | | $ | (5 | ) | | $ | 8 |
|
| Ameren Illinois | 41 |
| | 22 |
| | 38 |
| | (14 | ) | | (13 | ) | | (3 | ) |
| Other | (1 | ) | | (4 | ) | | — |
| | — |
| | (1 | ) | | (1 | ) |
| Ameren | 64 |
| | 44 |
| | 92 |
| | (18 | ) | | (19 | ) | | 4 |
|
| |
(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, 2017,2023, are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Postretirement Benefits |
| Paid from
Qualified
Trust Funds | | Paid from
Company
Funds | | Paid from
Qualified
Trust Funds | | Paid from
Company
Funds | | |
| 2024 | $ | 277 | | | $ | 3 | | | $ | 56 | | | $ | 3 | | | |
| 2025 | 281 | | | 3 | | | 58 | | | 3 | | | |
| 2026 | 287 | | | 3 | | | 58 | | | 3 | | | |
| 2027 | 290 | | | 3 | | | 58 | | | 3 | | | |
| 2028 | 293 | | | 2 | | | 58 | | | 3 | | | |
| 2029 – 2033 | 1,488 | | | 13 | | | 289 | | | 15 | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | Paid from Qualified Trust Funds | | Paid from Company Funds | | Paid from Qualified Trust Funds | | Paid from Company Funds |
| 2018 | $ | 255 |
| | $ | 3 |
| | $ | 57 |
| | $ | 2 |
|
| 2019 | 261 |
| | 3 |
| | 59 |
| | 2 |
|
| 2020 | 266 |
| | 3 |
| | 62 |
| | 2 |
|
| 2021 | 277 |
| | 3 |
| | 64 |
| | 2 |
|
| 2022 | 280 |
| | 3 |
| | 65 |
| | 2 |
|
2023 – 2027 | 1,421 |
| | 13 |
| | 331 |
| | 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, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Postretirement Benefits |
| 2023 | | 2022 | | 2021 | | 2023 | | 2022 | | 2021 |
| Discount rate at measurement date | 5.55 | % | | 3.00 | % | | 2.75 | % | | 5.55 | % | | 3.00 | % | | 2.75 | % |
| Expected return on plan assets | 6.75 | | | 6.50 | | | 6.50 | | | 6.75 | | | 6.50 | | | 6.50 | |
| Increase in future compensation | 3.50 | | (a) | 3.50 | | | 3.50 | | | 3.50 | | (a) | 3.50 | | | 3.50 | |
| Cash balance pension plan interest crediting rate | 5.00 | | (b) | 5.00 | | | 5.00 | | | (c) | | (c) | | (c) |
Medical cost trend rate (initial)(d) | (c) | | (c) | | (c) | | (e) | | 5.00 | | | 5.00 | |
Medical cost trend rate (ultimate)(d) | (c) | | (c) | | (c) | | 5.00 | | | 5.00 | | | 5.00 | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Discount rate at measurement date | 4.00 | % | | 4.50 | % | | 4.00 | % | | 4.00 | % | | 4.50 | % | | 4.00 | % |
| Expected return on plan assets | 7.00 |
| | 7.00 |
| | 7.25 |
| | 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(a)Increase in future compensation is 4.50% for 2023, 4.00% in 2024, and 3.50% thereafter for certain Medicare-eligible participants is 3.00%. |
The table below reflects the sensitivityyear ended December 31, 2023.
(b)Cash balance pension plan interest crediting rate is 5.50% for 2023 and 2024, and 5.00% thereafter for the year ended December 31, 2023.
(c)Not applicable.
(d)Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 2.50% for the year ended December 31, 2023 and 3.00% for the years ended December 31, 2022 and 2021.
(e)Initial medical cost trend rates of Ameren’s plans7.25% for pre-Medicare plan participants and 6.75% for post-Medicare plan participants trend down to potential changesthe ultimate rate by 2030, with a 3.00% upward adjustment to the post-Medicare trend rate in key assumptions:
|
| | | | | | | | | | | | | | | |
| | 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 | $ | (1 | ) | | $ | 157 |
| | $ | — |
| | $ | 44 |
|
| 0.25% increase in salary scale | 2 |
| | 15 |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | 4 |
| | 71 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | (4 | ) | | (71 | ) |
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible Ameren employees at December 31, 2017.2023. The plan allows employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matches a percentage of the employee contributions up to certain limits. The following table presents the portion of the matching contribution to the Ameren 401(k) plan attributable to the continuing operations for each of the Ameren Companies for the years ended December 31, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 |
| Ameren Missouri | $ | 27 | | | $ | 23 | | | $ | 21 | |
| Ameren Illinois | 21 | | | 19 | | | 16 | |
| Other | 1 | | | 1 | | | 1 | |
| Ameren | $ | 49 | | | $ | 43 | | | $ | 38 | |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 16 |
| | $ | 16 |
| | $ | 16 |
|
| Ameren Illinois | 13 |
| | 12 |
| | 12 |
|
| Other | 1 |
| | 1 |
| | 1 |
|
| Ameren | 30 |
| | 29 |
| | 29 |
|
NOTE 11 – STOCK-BASED COMPENSATION
The 20142022 Omnibus Incentive Compensation Plan is Ameren’s long-term stock compensationincentive plan available for eligible employees and directors. The 2014 Incentive PlanIt provides for a maximum of 88.8 million common shares to be available for grant to eligible employees and directors. At December 31, 2017,2023, there were 4.98.2 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, stock options (incentive stock options and nonqualified stock options), stock appreciation rights, performance shares, performance share units,awards, cash-based awards and other stock-based awards. Ameren used newly issued shares to fulfill its stock-based compensation obligations for 2023, 2022, and 2021, and intends to use newly issued shares to fulfill its stock-based compensation obligations for 2024.
AThe following table summarizes Ameren’s outstanding performance share unit vests and entitles an employeerestricted stock unit activity for the year ended December 31, 2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Performance Share Units – Market Condition(a) | | Performance Share Units – Performance Condition(b) | | Restricted Stock Units |
| Share
Units | | Weighted-average Fair Value per Share Unit | | Share
Units | | Weighted-average Fair Value per Share Unit | | Stock
Units | | Weighted-average Fair Value per Stock Unit |
Outstanding at January 1, 2023(c) | 744,273 | | | $ | 87.23 | | | 119,737 | | | $ | 80.65 | | | 436,812 | | | $ | 80.94 | |
| Granted | 311,674 | | | 88.52 | | | 40,118 | | | 84.70 | | | 130,600 | | | 84.44 | |
| Forfeitures | (45,080) | | | 90.97 | | | (7,389) | | | 84.73 | | | (22,566) | | | 84.75 | |
Dividend equivalents(d) | 14,749 | | | 89.79 | | | 2,372 | | | 82.66 | | | 9,132 | | | 82.44 | |
| Vested and distributed | (263,904) | | | 82.50 | | | (42,447) | | | 76.70 | | | (176,114) | | | 76.94 | |
| | | | | | | | | | | |
Outstanding at December 31, 2023(c) | 761,712 | | | $ | 89.22 | | | 112,391 | | | $ | 83.36 | | | 377,864 | | | $ | 83.82 | |
(a)The exact number of shares issued pursuant to receive sharesa 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 common stock (plus accumulated dividends) if, atachieves the end ofspecified market conditions.
the three-year performance period, certain specified performance or market conditions have been met and if the individual remains employed by Ameren through the required vesting period. (b)The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. Compensation cost is recognized ratably over the requisite service period only for awards for which it is probable that the performance condition will be satisfied.
(c)Outstanding awards include awards that vest on a pro-rata basis due to attainment of retirement eligibility by certain employees, but have not yet been distributed. In these cases, the pro-rata basis awards have not yet been distributed as the entire performance period has not been completed. The number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.
(d)Dividend equivalents represent the right to receive shares measured by the dividend payable with respect to the corresponding number of outstanding share units. Dividend equivalents will accrue and be reinvested in additional share units throughout the performance period.
Performance Share Units – Market Condition
A market condition performance share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified market conditions have been met and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date.
In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The following table summarizes the nonvested performanceexact number of shares issued pursuant to a share unit activity forvaries from 0% to 200% of the year ended December 31, 2017:
|
| | | | | | |
| | Performance Share Units |
| | Share Units | | Weighted-average Grant Date Fair Value per Share Unit |
Nonvested at January 1, 2017(a) | 780,545 |
| | $ | 47.54 |
|
Granted(b) | 508,161 |
| | 59.16 |
|
| Forfeitures | (50,523 | ) | | 52.50 |
|
Undistributed vested units(c) | (342,694 | ) | | 51.65 |
|
Nonvested at December 31, 2017(a) | 895,489 |
| | $ | 52.28 |
|
| |
(a) | Excludes 369,878 and 712,572 performance share units granted to retirement-eligible employees as of January 1, 2017 and December 31, 2017, respectively, as the undistributed performance share units are fully vested. |
| |
(b) | Includes performance share units granted to certain executive and nonexecutive officers and other eligible employees in 2017 under the 2014 Incentive Plan. |
| |
(c) | Includes performance share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period. |
The following table presents the stock-based compensation expense for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Ameren Missouri | $ | 4 |
| | $ | 4 |
| | $ | 5 |
|
| Ameren Illinois | 2 |
| | 2 |
| | 3 |
|
Other(a) | 12 |
| | 11 |
| | 11 |
|
| Ameren | 18 |
| | 17 |
| | 19 |
|
| Less income tax benefit | 7 |
| | 6 |
| | 7 |
|
| Stock-based compensation expense, net | $ | 11 |
| | $ | 11 |
| | $ | 12 |
|
| |
(a) | Represents compensation expense of employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above. |
Ameren settledtarget award, depending on actual company performance share units of $39 million, $83 million, and $27 million for the years ended December 31, 2017, 2016, and 2015. There were no significant compensation costs capitalized relatedrelative to the performance share units during the years ended December 31, 2017, 2016, and 2015. As of December 31, 2017, total compensation cost of $29 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.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 31st31 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 3-yearthree-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.occurred and/or in which the payout is above 100% due to Ameren’s projected TSR performance. The significantkey assumptions used to calculate fair value also include a three-year risk-free rate, Ameren’s common stock volatility, and volatility for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.group. 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, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | |
| 2023 | 2022 | 2021 |
| Fair value of share units awarded | $91.07 | $92.75 | $87.11 |
| | | |
| Three-year risk-free rate | 4.19% | 1.80% | 0.17% |
Ameren’s common stock volatility(a) | 26% | 29% | 28% |
Volatility range for the peer group(a) | 24% – 32% | 26% – 35% | 26% – 36% |
(a)Based on a historical period that is equal to the remaining term of the performance period as of the grant date.
In addition to the market condition performance share units described above, there are an immaterial number of market condition performance share units with different vesting conditions and target payout percentages.
|
| | | |
| | 2017 | 2016 | 2015 |
| Fair value of share units awarded | $59.16 | $44.13 | $52.88 |
| Ameren’s closing common share price at December 31 of the prior year | $52.46 | $43.23 | $46.13 |
| Three-year risk free rate | 1.47% | 1.31% | 1.10% |
| Volatility range | 15% - 21% | 15% - 20% | 12% - 18% |
A performance condition share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has met the specified performance condition and if the individual remains employed by Ameren through the required vesting period. The vesting period for share units awarded extends beyond the three-year performance period to the payout date, which is approximately 38 months after the grant date. In the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis over the three-year performance period. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual performance conditions achieved. The specified performance condition in each award year is based on Ameren’s clean energy transition. The grant-date fair value for an individual outcome of a performance condition is determined by Ameren’s closing common share price on the grant date. Restricted Stock Units
Restricted stock units vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if the individual remains employed with Ameren through the payment date of the awards. Generally, in the event of a participant’s death or retirement at age 55 or older with five years or more of service, awards vest on a pro-rata basis. The payout date of the awards is approximately 38 months after the grant date. The fair value of each restricted stock unit is determined by Ameren’s closing common share price on the grant date.
Stock-Based Compensation Expense
The following table presents the stock-based compensation expense for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 |
| Ameren Missouri | $ | 6 | | | $ | 4 | | | $ | 5 | |
| Ameren Illinois | 4 | | | 2 | | | 3 | |
Other(a) | 16 | | | 18 | | | 14 | |
| Ameren | 26 | | | 24 | | | 22 | |
| Less: Income tax benefit | 7 | | | 6 | | | 6 | |
| Stock-based compensation expense, net | $ | 19 | | | $ | 18 | | | $ | 16 | |
(a)Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above.
Ameren settled performance share units and restricted stock units of $60 million, $47 million, and $50 million for the years ended December 31, 2023, 2022, and 2021, respectively. There were no significant stock-based compensation costs capitalized during the years ended December 31, 2023, 2022, and 2021. As of December 31, 2023, total compensation cost of $41 million related to outstanding awards not yet recognized is expected to be recognized over a weighted-average period of 26 months.
For the years ended December 31, 2023, 2022, and 2021, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $6 million, $5 million, and $5 million, respectively.
NOTE 12 – INCOME TAXES
Federal Tax ReformIRA
The TCJAIRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates clean energy tax credits for projects placed in service after 2024. The clean energy tax credits will apply to renewable energy production and investments, along with certain nuclear energy production, and will be phased out beginning in 2033, at the earliest. The phase-out is triggered when greenhouse gas emissions from the electric generation industry are reduced by at least 75% from the annual 2022 emission rate or at the beginning of 2033, whichever is later. The law allows for transferability to an unrelated party for cash of up to 100% of certain tax credits generated after 2022. In addition, the new law imposes a 15% minimum tax on December 22, 2017. Substantially all ofadjusted financial statement income, as defined in the provisions of the TCJA affecting the Ameren Companies, other than certain transition depreciation rules, arelaw, for corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for taxabletax 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 statutory2022. Once a corporation exceeds this three-year average annual adjusted financial statement 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 depreciation tax benefits from certain regulated utility capital investments acquired after September 27, 2017, and the continuation of certain rate normalization requirements related to the flow back of excess deferred taxes. Ameren (parent)threshold, it will be subject to provisions of the TCJA that limitminimum tax for all future tax years. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the deductibility of interest expense.
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 assetsIRA have been and liabilitiesare expected to be measured atissued by the tax rate that is expected to apply when temporary differences are realizedIRS 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 revaluationUnited States Department 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 a result of the complexity of the TCJA, the SEC staff issued guidance to clarify the accounting for income taxes if information is not yet available or complete. This guidance provides for up to a one year period inTreasury, which to complete the required analysis and update provisional estimates. The guidance provides three scenarios associated with a company’s status of accounting for income tax reform: (1) a company has completed itsaccounting for certain effects of tax reform, (2) a company is able to make areasonable estimate for certain effects of tax reform and records that estimate as aprovisional amount, or (3) a company is not able to make a reasonable estimate andtherefore continues to apply income tax accounting that is based on the taxlaws in effect immediately prior to the enactment of the TCJA.
As of December 31, 2017, the Ameren Companies have made reasonable estimates for the measurement and accounting of certain effects of the TCJA, which have been reflected in their financial statements. We have recorded provisional estimates primarily related to depreciation transition rules and 2017 property, plant, and equipment, compensation, and pension-related deductions which wouldmay impact our revaluation of deferred taxes at December 31, 2017. These items may be resolved through additional analysis, which is incomplete due to the timing of when the enactment15% minimum tax becomes applicable for Ameren.
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| Increase (Decrease) | | | | | | | |
| Accumulated deferred income taxes, net | $ | (1,419 | ) | | $ | (871 | ) | | $ | 37 |
| | $ | (2,253 | ) |
Income tax expense (benefit)(a) | 32 |
| | (5 | ) | | 127 |
| | 154 |
|
| Noncurrent regulatory assets | (89 | ) | | (24 | ) | | (1 | ) | | (114 | ) |
| Noncurrent regulatory liabilities | 1,362 |
| | 842 |
| | 89 |
| | 2,293 |
|
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 35 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 2 – Rate and Regulatory Matters for information regarding the various proceedings for the TCJA impacts with our regulators.
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 July 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 does not expect this tax increase to have a material impact on its consolidated net income prospectively. The tax increase is not expected to materially impact 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 the third quarter of 2017, Ameren’s 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.
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, 2017, 2016,2023, 2022, and 2015:2021:
| | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois | | Ameren | |
| 2023 | | | | | | |
| Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | |
| Increases (decreases) from: | | | | | | |
Amortization of excess deferred income taxes(a) | (15) | | | (2) | | | (8) | | |
| | | | | | |
| Amortization of deferred investment tax credit | (1) | | | — | | | — | | |
Production and other tax credits(b) | (10) | | | — | | | (4) | | |
| State tax | 3 | | | 7 | | | 5 | | |
| | | | | | |
| | | | | | |
| Effective income tax rate | (2) | % | | 26 | % | | 14 | % | |
| 2022 | | | | | | |
| Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | |
| Increases (decreases) from: | | | | | | |
Amortization of excess deferred income taxes(a) | (15) | | | (2) | | | (8) | | |
| | | | | | |
| Amortization of deferred investment tax credit | (1) | | | — | | | — | | |
Production and other tax credits(b) | (10) | | | — | | | (4) | | |
| State tax | 3 | | | 7 | | | 5 | | |
| | | | | | |
| | | | | | |
| Effective income tax rate | (2) | % | | 26 | % | | 14 | % | |
| 2021 | | | | | | |
| Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | |
| Increases (decreases) from: | | | | | | |
Amortization of excess deferred income taxes(a) | (15) | | | (3) | | | (8) | | |
| | | | | | |
| Amortization of deferred investment tax credit | (1) | | | — | | | — | | |
Production and other tax credits(b) | (7) | | | — | | | (3) | | |
| State tax | 3 | | | 7 | | | 5 | | |
| Stock-based compensation | — | | | — | | | (1) | | |
| Effective income tax rate | 1 | % | | 25 | % | | 14 | % | |
(a)Reflects the amortization of amounts resulting from the revaluation of deferred income taxes subject to regulatory ratemaking, which are being refunded to customers. Deferred income taxes are revalued when federal or state income tax rates change, and the offset to the revaluation of deferred income taxes subject to regulatory ratemaking is recorded to a regulatory asset or liability.
(b)The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM.
|
| | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Ameren |
| 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 | % |
| 2015 | | | | | |
| Federal statutory corporate income tax rate: | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | |
| Depreciation differences | — |
| | (2 | ) | | (1 | ) |
| Amortization of deferred investment tax credit | (1 | ) | | — |
| | (1 | ) |
| State tax | 3 |
| | 5 |
| | 5 |
|
| Other permanent items | — |
| | (1 | ) | | — |
|
| Effective income tax rate | 37 | % | | 37 | % | | 38 | % |
| |
(a) | Reflects the adoption of authoritative accounting guidance related to share-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 (benefit) for the years ended December 31, 2017, 2016,2023, 2022, and 2015:2021: | | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2017 | | | | | | | |
| Ameren Missouri | | | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2023 | |
| Current taxes: | | | | | | | |
| Current taxes: | |
| Current taxes: | |
| Federal | |
| Federal | |
| Federal | $ | 149 |
| | $ | (34 | ) | | $ | (110 | ) | | $ | 5 |
|
| State | 23 |
| | 29 |
| | (20 | ) | | 32 |
|
| Deferred taxes: | | | | | | | |
| Federal | 76 |
| | 185 |
| | 250 |
| | 511 |
|
| Federal | |
| Federal | |
| State | 11 |
| | (13 | ) | | 36 |
| | 34 |
|
| Amortization of excess deferred income taxes | |
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 254 |
| | $ | 166 |
| | $ | 156 |
| | $ | 576 |
|
| 2016 | | | | | | | |
| Total income tax expense (benefit) | |
| 2022 | |
| Current taxes: | | | | | | | |
| Current taxes: | |
| Current taxes: | |
| Federal | |
| Federal | |
| Federal | $ | 31 |
| | $ | (8 | ) | | $ | (24 | ) | | $ | (1 | ) |
| State | 6 |
| | 12 |
| | (21 | ) | | (3 | ) |
| Deferred taxes: | | | | | | | |
| Federal | 161 |
| | 117 |
| | 21 |
| | 299 |
|
| Federal | |
| Federal | |
| State | 23 |
| | 37 |
| | 32 |
| | 92 |
|
| Amortization of excess deferred income taxes | |
| Amortization of deferred investment tax credits | (5 | ) | | — |
| | — |
| | (5 | ) |
| Total income tax expense | $ | 216 |
| | $ | 158 |
| | $ | 8 |
| | $ | 382 |
|
| 2015 | | | | | | | |
| Total income tax expense (benefit) | |
| 2021 | |
| Current taxes: | | | | | | | |
| Current taxes: | |
| Current taxes: | |
| Federal | |
| Federal | |
| Federal | $ | 110 |
| | $ | (83 | ) | | $ | (29 | ) | | $ | (2 | ) |
| State | 17 |
| | (11 | ) | | (10 | ) | | (4 | ) |
| Deferred taxes: | | | | | | | |
| Federal | 71 |
| | 193 |
| | 35 |
| | 299 |
|
| Federal | |
| Federal | |
| State | 16 |
| | 29 |
| | 31 |
| | 76 |
|
| Amortization of excess deferred income taxes | |
| Amortization of deferred investment tax credits | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 209 |
| | $ | 127 |
| | $ | 27 |
| | $ | 363 |
|
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, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2023 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,370 | | | $ | 2,030 | | | $ | 246 | | | $ | 4,646 | |
| Regulatory assets and liabilities, net | (206) | | | (184) | | | (23) | | | (413) | |
| Deferred employee benefit costs | (48) | | | 55 | | | (33) | | | (26) | |
| Tax carryforwards | (124) | | | (33) | | | (61) | | | (218) | |
| Other | 104 | | | 38 | | | 19 | | | 161 | |
| Total net accumulated deferred income tax liabilities (assets) | 2,096 | | | 1,906 | | | 148 | | | 4,150 | |
| Accumulated deferred investment tax credits | 26 | | | — | | | — | | | 26 | |
| Accumulated deferred income taxes and investment tax credits | $ | 2,122 | | | $ | 1,906 | | | $ | 148 | | | $ | 4,176 | |
| 2022 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant-related | $ | 2,297 | | | $ | 1,880 | | | $ | 239 | | | $ | 4,416 | |
| Regulatory assets and liabilities, net | (233) | | | (193) | | | (23) | | | (449) | |
| Deferred employee benefit costs | (55) | | | 28 | | | (43) | | | (70) | |
| Tax carryforwards | (122) | | | (34) | | | (72) | | | (228) | |
| Other | 70 | | | 18 | | | 22 | | | 110 | |
| Total net accumulated deferred income tax liabilities (assets) | 1,957 | | | 1,699 | | | 123 | | | 3,779 | |
| Accumulated deferred investment tax credits | 25 | | | — | | | — | | | 25 | |
| Accumulated deferred income taxes and investment tax credits | $ | 1,982 | | | $ | 1,699 | | | $ | 123 | | | $ | 3,804 | |
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 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 |
|
| 2016 | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | |
| Plant related | $ | 3,103 |
| | $ | 1,769 |
| | $ | 147 |
| | $ | 5,019 |
|
| Regulatory assets and liabilities, net | 75 |
| | (1 | ) | | — |
| | 74 |
|
| Deferred employee benefit costs | (76 | ) | | (38 | ) | | (97 | ) | | (211 | ) |
| Revenue requirement reconciliation adjustments | — |
| | 34 |
| | — |
| | 34 |
|
| Tax carryforwards | (66 | ) | | (138 | ) | | (472 | ) | | (676 | ) |
| Other | (23 | ) | | 5 |
| | 42 |
| | 24 |
|
| Total net accumulated deferred income tax liabilities (assets) | $ | 3,013 |
| | $ | 1,631 |
| | $ | (380 | ) | | $ | 4,264 |
|
The following table presents the components of accumulated deferred income tax assets relating to net operating loss carryforwards and tax credit carryforwards and charitable contribution carryforwards at December 31, 20172023 and 2016:2022:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2023 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| | | | | | | |
State(a) | $ | — | | | $ | 26 | | | $ | 16 | | | $ | 42 | |
| Total net operating loss carryforwards | $ | — | | | $ | 26 | | | $ | 16 | | | $ | 42 | |
| Tax credit carryforwards: | | | | | | | |
Federal(b) | $ | 124 | | | $ | 5 | | | $ | 45 | | | $ | 174 | |
State(c) | — | | | 2 | | | — | | | 2 | |
| | | | | | | |
| Total tax credit carryforwards | $ | 124 | | | $ | 7 | | | $ | 45 | | | $ | 176 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| 2022 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| Federal | $ | 3 | | | $ | 4 | | | $ | 4 | | | $ | 11 | |
| State | 1 | | | 26 | | | 9 | | | 36 | |
| Total net operating loss carryforwards | $ | 4 | | | $ | 30 | | | $ | 13 | | | $ | 47 | |
| Tax credit carryforwards: | | | | | | | |
| Federal | $ | 118 | | | $ | 3 | | | $ | 55 | | | $ | 176 | |
| State | — | | | 1 | | | 4 | | | 5 | |
| | | | | | | |
| Total tax credit carryforwards | $ | 118 | | | $ | 4 | | | $ | 59 | | | $ | 181 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren |
| 2017 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
Federal(a) | $ | — |
| | $ | 41 |
| | $ | 162 |
| | $ | 203 |
|
State(a) | — |
| | — |
| | 32 |
| | 32 |
|
| Total net operating loss carryforwards | $ | — |
| | $ | 41 |
| | $ | 194 |
| | $ | 235 |
|
| Tax credit carryforwards: | | | | | | | |
Federal(b) | $ | 31 |
| | $ | 2 |
| | $ | 80 |
| | $ | 113 |
|
State(c) | — |
| | — |
| | 7 |
| | 7 |
|
| Total tax credit carryforwards | $ | 31 |
| | $ | 2 |
| | $ | 87 |
| | $ | 120 |
|
Charitable contribution carryforwards(d) | $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 11 |
|
Valuation allowance(e) | — |
| | — |
| | (5 | ) | | (5 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
|
| 2016 | | | | | | | |
| Net operating loss carryforwards: | | | | | | | |
| Federal | $ | 33 |
| | $ | 137 |
| | $ | 324 |
| | $ | 494 |
|
| State | 4 |
| | — |
| | 41 |
| | 45 |
|
| Total net operating loss carryforwards | $ | 37 |
| | $ | 137 |
| | $ | 365 |
| | $ | 539 |
|
| Tax credit carryforwards: | | | | | | | |
| Federal | $ | 29 |
| | $ | 1 |
| | $ | 79 |
| | $ | 109 |
|
| State | — |
| | — |
| | 21 |
| | 21 |
|
| Total tax credit carryforwards | $ | 29 |
| | $ | 1 |
| | $ | 100 |
| | $ | 130 |
|
| Charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 18 |
| | $ | 18 |
|
| Valuation allowance | — |
| | — |
| | (11 | ) | | (11 | ) |
| Total charitable contribution carryforwards | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | 7 |
|
| |
(a) | Will expire between 2033 and 2036. 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 between2019 and 2022. |
| |
(d) | Will expire between 2018 and 2021. |
| |
(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 2043.
(c)Will expire between 2025 and 2028.
Uncertain Tax Positions
As of December 31, 20172023 and 2016,2022, the Ameren Companies did not record any uncertain tax positions.
In 2015, final settlements for tax years 2012 and 2013 were reached with the IRS. The 2015 settlementAmeren is a part of the 2013IRS’s compliance assurance process program, which involves real-time review of compliance with federal income tax year affected discontinued operations. See Note 1 – Summary of Significant Accounting Policies for additional information.
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 2020, 2021, and 2022 tax years are open, but, at the time of this filing, the Ameren Companies currently do not have material state 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, using the weighted-average cost of capital 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 will be amortized over three years, beginning on the effective date of new rates established in the next electric 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. 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 2012,2021, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $3$2 million for the 12 months endedfrom June 2022 through May 31, 2015. In a procurement event in 2015, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements for $15 million for the 12 months ending 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 agreements the companies have entered into, as well as the specified performance period, average price per MWh, and amount of megawatthoursMWhs included in each agreement: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 |
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, 2017 and 2016, there were no collateral postings required of Ameren Missouri related to the Illinois energy product agreements. | | | | | | | | | | | | | | |
| IPA Procurement Event | Performance Period | MWhs | | Average Price per MWh |
| April 2019 | January 2020 – December 2021 | 288,000 | | $ | 35 | |
| September 2019 | April 2020 – November 2021 | 170,800 | | 29 | |
| September 2020 | September 2021 – November 2022 | 204,800 | | 31 | |
| April 2021 | July 2022 – November 2022 | 33,600 | | 34 | |
| September 2021 | January 2022 – September 2023 | 136,000 | | 37 | |
Interconnection 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.
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 primarily Ameren Services, with access to their facilities for administrative purposes.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.
Ameren Missouri and Ameren Illinois had long-term receivables included in “Other assets” from Ameren Services of $31 million and $34 million, respectively, as of December 31, 2023, and $41 million and $43 million, respectively, as of December 31, 2022, related to Ameren Services’ allocated portion of Ameren’s pension and postretirement benefit plans.
Transmission Services
Ameren Missouri and Ameren Illinois each receives transmission services from ATXI for itstheir respective retail loadloads.
Electric Transmission Maintenance and Construction Agreements
ATXI entered into separate agreements with Ameren Missouri and Ameren Illinois in the AMIL pricing zone.
which Ameren Missouri or Ameren Illinois, as applicable, may perform certain maintenance and construction services related to ATXI’s electric transmission assets.
Money Pool
See Note 4 – Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies for a discussion of the tax allocation agreement. AsThe following table presents the affiliate balances related to income taxes for Ameren Missouri and Ameren Illinois as of December 31, 20172023 and 2016, Ameren Missouri had income taxes payable to Ameren (parent) of $11 million and $16 million, respectively, included2022:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | | 2022 |
| Ameren Missouri | Ameren Illinois | | | Ameren Missouri | Ameren Illinois |
Income taxes payable to parent(a) | $ | — | | $ | 2 | | | | $ | — | | $ | 50 | |
Income taxes receivable from parent(b) | 56 | | 22 | | | | 39 | | — | |
(a)Included in “Accounts payable -– affiliates” on itsthe balance sheet. As of December 31, 2017 and 2016, Ameren Illinois had income taxes payable to Ameren (parent) of $17 million and $3 million, respectively, included
(b)Included in “Accounts payable -receivable – affiliates” on itsthe balance sheet. See below for
Capital Contributions
The following table presents cash capital contributions received related to the tax allocation agreement.
Capital Contributions
In 2017,from Ameren (parent) by Ameren Missouri received cashand Ameren Illinois for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | |
Ameren Missouri(a) | $ | — | | | $ | — | | | $ | 207 | | |
Ameren Illinois(a) | 91 | | | 15 | | | 262 | | |
(a)Includes capital contributions of $30 million from Ameren (parent)made as a result of the tax allocation agreement. In 2017, Ameren Illinois received cash capital contributions
Effects of $8 million from Ameren (parent).Related-party Transactions on the Statement of Income
In 2016, Ameren Missouri received cash capital contributions of $44 million from Ameren (parent) as a result of the tax allocation agreement, which included the accrued capital contribution from 2015.
In 2015, Ameren Missouri received cash capital contributions of $224 million from Ameren (parent) as a result of the tax allocation agreement, which included the accrued capital contribution from 2014. Additionally, as of December 31, 2015, Ameren Missouri accrued a $38 million capital contribution related to the same agreement. In 2015, Ameren Illinois received cash capital contributions of $25 million from Ameren (parent).
The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the years ended December 31, 2017, 2016,2023, 2022, and 2015.2021. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 – Short-term Debt and Liquidity.
| | | | | | | | | | | | | | | | | | | | | | | |
| Agreement | Income Statement Line Item | | | | Ameren
Missouri | | Ameren
Illinois |
| Ameren Missouri power supply agreements | Operating Revenues | | 2023 | $ | 2 | | $ | (a) |
| with Ameren Illinois | | | 2022 | | 9 | | | (a) |
| | | | 2021 | | 16 | | | (a) |
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2023 | | 32 | | | (b) |
| rent and facility services | | | 2022 | | 25 | | | (b) |
| | | | 2021 | | 26 | | | 1 | |
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2023 | | (b) | | 2 | |
| miscellaneous support services | | | 2022 | | (b) | | 2 | |
| | | 2021 | | (b) | | 5 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Total Operating Revenues | | | 2023 | $ | 34 | | $ | 2 | |
| | | 2022 | | 34 | | | 2 | |
| | | | 2021 | | 42 | | | 6 | |
| Ameren Illinois power supply | Purchased Power | | 2023 | $ | (a) | $ | 2 | |
| agreements with Ameren Missouri | | | 2022 | | (a) | | 9 | |
| | | | 2021 | | (a) | | 16 | |
| Ameren Missouri and Ameren Illinois | Purchased Power | | 2023 | | 2 | | | 1 | |
| transmission services from ATXI | | | 2022 | | 1 | | | (b) |
| | | 2021 | | 4 | | | 1 | |
| Total Purchased Power | | | 2023 | $ | 2 | | $ | 3 | |
| | | 2022 | | 1 | | | 9 | |
| | | 2021 | | 4 | | | 17 | |
| Ameren Missouri and Ameren Illinois | Other Operations and | | 2023 | $ | (b) | $ | 3 | |
| rent and facility services | Maintenance | | 2022 | | (b) | | 3 | |
| | | 2021 | | 1 | | | 4 | |
| Ameren Services support services | Other Operations and | | 2023 | | 148 | | | 138 | |
| agreement | Maintenance | | 2022 | | 150 | | | 141 | |
| | | | 2021 | | 147 | | | 137 | |
| Total Other Operations and | | | 2023 | $ | 148 | | $ | 141 | |
| Maintenance Expenses | | | 2022 | | 150 | | | 144 | |
| | | | 2021 | | 148 | | | 141 | |
| Money pool borrowings (advances) | (Interest Charges) | | 2023 | $ | (b) | $ | (b) |
| Other Income, Net | | 2022 | | (b) | | (b) |
| | | | 2021 | | (b) | | (b) |
(a)Not applicable.
(b)Amount less than $1 million.
|
| | | | | | | | | |
| Agreement | Income Statement Line Item | | | | Ameren Missouri | | Ameren Illinois |
| Ameren Missouri power supply agreements | Operating Revenues | | 2017 | $ | 23 |
| $ | (a) |
|
| with Ameren Illinois | | | 2016 | | 28 |
| | (a) |
|
| | | | 2015 | | 15 |
| | (a) |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2017 | | 26 |
| | 4 |
|
| rent and facility services | | | 2016 | | 25 |
| | 5 |
|
| | | | 2015 | | 25 |
| | 4 |
|
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2017 | | (b) |
| | 1 |
|
| miscellaneous support services | | | 2016 | | 1 |
| | (b) |
|
| | | | 2015 | | 2 |
| | (b) |
|
| Total Operating Revenues | | | 2017 | $ | 49 |
| $ | 5 |
|
| | | | 2016 | | 54 |
| | 5 |
|
| | | | 2015 | | 42 |
| | 4 |
|
| Ameren Illinois power supply | Purchased Power | | 2017 | $ | (a) |
| $ | 23 |
|
| agreements with Ameren Missouri | | | 2016 | | (a) |
| | 28 |
|
| | | | 2015 | | (a) |
| | 15 |
|
| Ameren Illinois transmission | Purchased Power | | 2017 | | (a) |
| | 2 |
|
| services from ATXI | | | 2016 | | (a) |
| | 2 |
|
| | | | 2015 | | (a) |
| | 2 |
|
| Total Purchased Power | | | 2017 | $ | (a) |
| $ | 25 |
|
| | | | 2016 | | (a) |
| | 30 |
|
| | | | 2015 | | (a) |
| | 17 |
|
| Ameren Services support services | Other Operations and | | 2017 | $ | 149 |
| $ | 139 |
|
| agreement | Maintenance | | 2016 | | 129 |
| | 123 |
|
| | | | 2015 | | 131 |
| | 119 |
|
| Money pool borrowings (advances) | (Interest Charges) | | 2017 | $ | 1 |
| $ | (b) |
|
| | Miscellaneous Income | | 2016 | | (b) |
| | (b) |
|
| | | | 2015 | | (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.
LeasesEnvironmental Matters
We lease various facilities, office equipment, plant equipment,Our electric generation, transmission, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | After 5 Years | | Total |
Ameren:(a) | | | | | | | | | | | | | |
Minimum capital lease payments(b)(c) | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
| Operating leases | 10 |
| | 9 |
| | 8 |
| | 6 |
| | 6 |
| | 14 |
| | 53 |
|
| Total lease obligations | $ | 16 |
| | $ | 16 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 329 |
|
| Ameren Missouri: | | | | | | | | | | | | | |
Minimum capital lease payments(b)(c) | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 32 |
| | $ | 264 |
| | $ | 425 |
|
| Less amount representing interest | 26 |
| | 25 |
| | 25 |
| | 25 |
| | 24 |
| | 24 |
| | 149 |
|
| Present value of minimum capital lease payments | $ | 6 |
| | $ | 7 |
| | $ | 7 |
| | $ | 8 |
| | $ | 8 |
| | $ | 240 |
| | $ | 276 |
|
| Operating leases | 8 |
| | 8 |
| | 7 |
| | 6 |
| | 6 |
| | 14 |
| | 49 |
|
| Total lease obligations | $ | 14 |
| | $ | 15 |
| | $ | 14 |
| | $ | 14 |
| | $ | 14 |
| | $ | 254 |
| | $ | 325 |
|
| Ameren Illinois: | | | | | | | | | | | | | |
| Operating leases | $ | 1 |
| | (d) |
| | (d) |
| | (d) |
| | (d) |
| | $ | 1 |
| | $ | 2 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | See Note 3 – Property, Plant, and Equipment, Net for additional information. |
| |
(c) | See Note 5 – Long-term Debt and Equity Financings for additional information on Ameren’s and Ameren Missouri’s capital lease agreements. |
The following table presents total operating lease expenses included in “Operating Expenses” in the statement of income for the years ended December 31, 2017, 2016, and 2015:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
Ameren(a) | $ | 11 |
| | $ | 38 |
| | $ | 36 |
|
| Ameren Missouri | 10 |
| | 34 |
| | 34 |
|
| Ameren Illinois | 1 |
| | 30 |
| | 28 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
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 powerdistribution and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power,distribution and other commitments at December 31, 2017. Ameren’sstorage operations must comply with a variety of statutes and Ameren Illinois’ purchased power commitments includeregulations relating to the Ameren Illinois agreements entered into as partprotection of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, designenvironment and construction,human health and meter reading services, among other agreements, at December 31, 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b)(c) | | Methane Gas | | Other | | Total |
Ameren:(d) | | | | | | | | | | | | | |
| 2018 | $ | 463 |
| | $ | 205 |
| | $ | 67 |
| | $ | 170 |
| | $ | 3 |
| | $ | 73 |
| | $ | 981 |
|
| 2019 | 383 |
| | 163 |
| | 26 |
| | 63 |
| | 4 |
| | 37 |
| | 676 |
|
| 2020 | 85 |
| | 110 |
| | 39 |
| | 14 |
| | 4 |
| | 36 |
| | 288 |
|
| 2021 | 27 |
| | 46 |
| | 45 |
| | 3 |
| | 5 |
| | 25 |
| | 151 |
|
| 2022 | — |
| | 11 |
| | 12 |
| | 2 |
| | 5 |
| | 25 |
| | 55 |
|
| Thereafter | — |
| | 38 |
| | 45 |
| | 18 |
| | 58 |
| | 95 |
| | 254 |
|
| Total | $ | 958 |
| | $ | 573 |
| | $ | 234 |
| | $ | 270 |
| | $ | 79 |
| | $ | 291 |
| | $ | 2,405 |
|
| Ameren Missouri: | | | | | | | | | | | | | |
| 2018 | $ | 463 |
| | $ | 42 |
| | $ | 67 |
| | $ | — |
| | $ | 3 |
| | $ | 53 |
| | $ | 628 |
|
| 2019 | 383 |
| | 36 |
| | 26 |
| | — |
| | 4 |
| | 24 |
| | 473 |
|
| 2020 | 85 |
| | 29 |
| | 39 |
| | — |
| | 4 |
| | 24 |
| | 181 |
|
| 2021 | 27 |
| | 13 |
| | 45 |
| | — |
| | 5 |
| | 25 |
| | 115 |
|
| 2022 | — |
| | 6 |
| | 12 |
| | — |
| | 5 |
| | 25 |
| | 48 |
|
| Thereafter | — |
| | 16 |
| | 45 |
| | — |
| | 58 |
| | 75 |
| | 194 |
|
| Total | $ | 958 |
| | $ | 142 |
| | $ | 234 |
| | $ | — |
| | $ | 79 |
| | $ | 226 |
| | $ | 1,639 |
|
| Ameren Illinois: | | | | | | | | | | | | | |
| 2018 | $ | — |
| | $ | 163 |
| | $ | — |
| | $ | 170 |
| | $ | — |
| | $ | 19 |
| | $ | 352 |
|
| 2019 | — |
| | 127 |
| | — |
| | 63 |
| | — |
| | 13 |
| | 203 |
|
| 2020 | — |
| | 81 |
| | — |
| | 14 |
| | — |
| | 12 |
| | 107 |
|
| 2021 | — |
| | 33 |
| | — |
| | 3 |
| | — |
| | — |
| | 36 |
|
| 2022 | — |
| | 5 |
| | — |
| | 2 |
| | — |
| | — |
| | 7 |
|
| Thereafter | — |
| | 22 |
| | — |
| | 18 |
| | — |
| | — |
| | 40 |
|
| Total | $ | — |
| | $ | 431 |
| | $ | — |
| | $ | 270 |
| | $ | — |
| | $ | 44 |
| | $ | 745 |
|
| |
(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 2032 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. |
| |
(d) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
Environmental Matters
We are subject to various environmental laws and regulations enforcedsafety, including permitting programs implemented by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect toSuch environmental laws and regulations. These laws and regulations address emissions,air emissions; discharges to water water usage, 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 energy-related facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. We employ dedicated personnel knowledgeable in environmental matters to oversee our business activities’ compliance with requirements of environmental laws.
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, 2017, Ameren Missouri’s fossil fuel-fired energy centers represented 17% and 33% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations under the Clean Air Act that apply to air emissions from the electric utility industry include the NSPS, the CSAPR, the MATS, and the revised 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. emissions. Regulations implementing the Clean Water Act govern both intake and discharges from power plants are regulated underof water, as well as evaluation of the Clean Water Act. Such regulationecological and biological impact of those operations, and could require modifications to water intake structures or more stringent limitations on wastewater discharges at Ameren Missouri’s energy centers, eitherdischarges. Depending upon the scope of whichmodifications ultimately required by state regulators, capital expenditures associated with these modifications could result in significant capital
expenditures.be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR rule,Rule, which will require the closure of 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 compliance with existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.
Additionally, Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning ultra-low-sulfur coalwind generation facilities may be subject to operating restrictions to limit the impact on protected species. Since 2021, Ameren Missouri’s High Prairie Renewable Energy Center curtailed nighttime operations from April through October to limit impacts on protected species during the critical biological season. The extent and installing newduration of future curtailments are unknown at this time as assessment of mitigation technologies is ongoing. Ameren Missouri does not anticipate these operating curtailments will have a material impact on its results of operations, financial position, or optimizing existing pollution control equipment. liquidity.
Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $325$90 million to $425$120 million from 20182024 through 20222028 in order to comply with existing environmental regulations. Additional capital expenditures for environmental controls beyond 20222028 could be required. This estimate of capital expenditures includes expendituressurface impoundment closure and corrective action measures required by the CCR regulations, by the Clean Water Act rule applicableRule and modifications to cooling water intake structures at existing power plants and by effluent limitation guidelines applicable to steam electric generating units,under Clean Water Act rules, all of which are discussed below. In addition to planned retirements of coal-fired energy centers as set forth in the 2023 IRP filed with the MoPSC in September 2023 and as noted below with respect to the NSR and Clean Air Act litigation and Illinois emissions standards, Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning low-sulfur coal and installing new or optimizing existing air pollution control equipment. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimateestimates because of uncertainty as to whetherfuture permitting requirements by state regulators and the EPA, will substantially reviserevisions to regulatory obligations, exactly whichand varying cost of potential compliance strategies, will be used and their ultimate cost, among other things.
The following sections describe the more significant environmental lawsstatutes and rulesregulations and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of severalperiodically amends and revises its regulations and rulemaking activities, including the effluent limitationproposes amendments to regulations and guidelines, and the CCR rule, which could ultimately result in the revision of all or part of such rules.regulations.
Clean Air Act
Federal and state laws, require significant reductions inincluding the CSAPR, regulate emissions of SO2and NOx through either emissionthe reduction of emissions at their source reductions orand the use and retirement of emission allowances. The first phaseIn April 2022, the EPA proposed plans for additional NOx emission reductions from power plants in Missouri, Illinois, and other states through revisions to the CSAPR. In January 2023, the EPA issued its final disapproval of Missouri’s proposed state implementation plan for addressing the transport of ozone under the Good Neighbor Plan of the Clean Air Act. The disapproval of the state plan allows the EPA to implement revisions to the CSAPR emission reduction requirements became effective in 2015. The second phase of emission reductionthrough a federal implementation plan. In March 2023, the EPA announced federal implementation plan requirements, which were revised bysubsequently published to the Federal Register in June 2023, reducing the amount of NOx allowances available for state budgets and imposing NOx emission limits on electric generating units for Missouri, Illinois, and other states under the Good Neighbor Plan of the Clean Air Act. In April 2023, the Missouri Attorney General and Ameren Missouri separately filed lawsuits in the United States Court of Appeals for the Eighth Circuit challenging the EPA’s disapproval of the Missouri state plan and sought a stay of the EPA’s disapproval of the Missouri state plan. The United States Court of Appeals for the Eighth Circuit in May 2023 granted those stay motions thereby preventing the EPA in 2016, became effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliancefrom imposing the federal implementation plan until the court of appeals issues a ruling. In December 2023, the United States Supreme Court agreed to hear challenges to the Good Neighbor Plan and scheduled oral argument for February 2024, with a decision expected by June 2024. Ameren Missouri complies with the current CSAPR Ameren Missouri burns ultra-low-sulfurrequirements by minimizing emissions through the use of low-sulfur coal, operatesoperation of two scrubbers at its Sioux energy center,Energy Center, and optimizes otheroptimization of existing NOx air pollution control equipment. Reducing the amount of state budget NOx allowances for compliance with NOx emission limits could result in additional controls being required on Ameren Missouri did not make additional capital investments to comply withMissouri’s generating units and/or the 2017 CSAPR requirements. However, Ameren Missouri expects to incurreduction of operations. Any additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costsfor compliance are expected to be recovered from customers, subject to MoPSC prudence review, through the FAC or higher base rates.
CO2 Emissions Standards
In 2015,June 2022, the EPA issued the Clean Power Plan, which would have established CO2 emissions standards applicable to existing power plants. The United States Supreme Court stayed the ruleissued its decision in February 2016, pending various legal challenges. In October 2017,West Virginia v. EPA, clarifying that there are limits on how the EPA announced a proposalmay regulate greenhouse gases absent further direction from the United States Congress. The court concluded that the EPA’s proposed rules were designed to repeal the Clean Power Plan.shift generation from fossil-fuel-fired power plants to renewable energy facilities, which was improper absent specific congressional authorization. In December 2017,May 2023, the EPA issued an advanced notice ofa new proposed rulemaking to solicit input from stakeholders as to how the EPA should regulaterule that would set CO2 emissions from emission standards for new and existing fossil-fuel-fired power plants underbased on the Clean Air Act. Accordingly, we no longer expectadoption of carbon capture technology, natural gas co-firing, and co-firing hydrogen fuel to reduce emissions. If the Clean Power Planproposed rule were adopted, the affected fossil-fuel-fired power plants would be required to take effect. However,comply with the rule through a phased-in approach or retire. Capacity restrictions for coal-fired units could apply as early as 2030. Larger natural gas-fired power plants would be required to co-fire with hydrogen by 2032, with additional requirements by 2038. The EPA mayexpects to issue new requirements that would regulate CO2 emissions from existing power plants. Wea final rule in 2024. Legal challenges to the final rule, if adopted as proposed, are expected. Ameren and Ameren Missouri cannot predict the outcome of the EPA’s future rulemaking or the outcomeresults of any legalsuch challenges relating toor potential impacts of any such future rulemakings, any of which could have an adverse effectregulations on ourtheir results of operations, financial position, and liquidity.liquidity until final regulations are adopted and the merits of such legal challenges are determined.
NSR and Clean Air Act Litigation
In January 2011, the United States Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The complaint, as amended in October 2013, allegedMissouri alleging that in performing projects at its Rush Island coal-fired energy centerperformed in 2007 and 2010 Ameren Missouriat the coal-fired Rush Island Energy Center violated provisions of the Clean Air Act and Missouri law. The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling that the projects violated provisions of the Clean Air Act and Missouri law. The case then proceeded to the second phase to determine the actions required to remedy the violations found in the liability phase. The EPA previously withdrew all claims for penalties and fines. No date has been set by the district court for a trial on the remedy phase of the litigation. At the conclusion of both phases of the litigation,against Ameren Missouri intendsand, in September 2019, entered a remedy order that required Ameren Missouri to install a flue gas desulfurization system at the Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. Following an appeal the liability ruling tofrom Ameren Missouri, in August 2021, the United States Court of Appeals for the Eighth Circuit.Circuit affirmed the liability ruling and the district court’s remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In September 2023, the district court granted Ameren Missouri’s request to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri to operate the energy center as directed by the MISO. The United States Department of Justice is seeking an order from the district court providing for additional mitigation relief. Ameren Missouri could be required to implement mitigation relief measures, the costs of which could be material and which Ameren Missouri would not expect to recover. Ameren Missouri is challenging such mitigation claims, noting that the scope of any such potential additional mitigation relief should be limited by the August 2021 court of appeals decision and offset by emission reductions resulting from the accelerated retirement of the Rush Island Energy Center.
The MISO designated the energy center as a system support resource in 2022 and concluded that certain reliability mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation through August 2024, and in September 2023, an agreement between Ameren Missouri and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies. The system support resource
designation and the related agreement are subject to annual renewal and revision. Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the upgrades expected to be completed in the fall of 2024. Ameren Missouri expects to complete the last of the upgrades by mid-2025. In addition, in August 2023, the FERC approved a settlement agreement for Ameren Missouri’s request for recovery of non-energy costs under the related MISO tariff between Ameren Missouri and certain intervenors, which provided for recovery of substantially all of Ameren Missouri’s requested non-energy costs through August 2023. In October 2023, Ameren Missouri received FERC approval for the recovery of non-energy costs under the related MISO tariff from September 2023 to August 2024. Revenues and costs under the MISO tariff are included in the FAC. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review the planned accelerated retirement of the Rush Island Energy Center. See Note 2 – Rate and Regulatory Matters for additional information.
In connection with the accelerated retirement of the Rush Island Energy Center, Ameren Missouri is seeking approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to Missouri’s securitization statute. See Note 2 – Rate and Regulatory Matters for additional information. As of December 31, 2023, the Rush Island Energy Center had a net plant balance of $530 million included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net”. See Note 1 – Summary of Significant Accounting Policies for additional information regarding plant to be abandoned, net.
Ameren Missouri is unable to predict the ultimate resolution of this mattermatter; however, such resolution 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 pollution control equipment, as well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of this matter or the costs that might be incurred.
Clean Water Act
In 2014,Among other items, the EPA issued its final rule applicableClean Water Act requires 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 the facility’sa 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 thethis cooling water intake structures rule. TheRequirements of the rule will beare implemented duringby state regulators through the permit renewal process of each energy center’spower plant’s water discharge permit, between 2018permit. Permits for Ameren Missouri’s coal-fired and 2023.nuclear energy centers have been issued or are in the process of renewal.
Additionally, inIn 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 prohibitsprohibit effluent discharges of certain waste streams, and imposesimpose more stringent limitations on certain water discharges from power plants. In September 2017, the EPA published a rule that postponed the compliance datesplants by two years for the limitations applicable to two specific waste streams so that it could potentially revise those standards.
Both the intake and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s and2025. To comply with these guidelines, Ameren Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications to the cooling waterMissouri installed dry ash handling systems and water discharge systemswastewater treatment facilities at Ameren Missouri’sits coal-fired energy centers, and if such investments are not recovered on a timely basis in electric rates charged to Ameren Missouri’s customers.centers.
CCR Management
In 2015, the EPA issued regulations regardingThe EPA’s CCR Rule establishes requirements for the management and disposal of CCR from coal-fired energy centers. These regulations affect CCR disposalpower plants and handling costshas resulted in the closure of surface impoundments at Ameren Missouri’s energy centers. They require closurecenters, with closures of surface impoundments if performance criteria relatingin process at its Sioux Energy Center and retired Meramec Energy Center. Ameren Missouri plans to substantially complete the closures of remaining surface impoundments by the end of 2026. Ameren Missouri’s CCR management compliance plan includes installation of groundwater impactsmonitoring equipment and location restrictions are not achieved. In September 2017, the EPA granted petitions filed on behalf of coal-fired electricity generators in which the EPA agreed to reconsider certain provisions of the CCR rules.groundwater treatment facilities. Ameren and Ameren Missouri have AROs of $150$40 million recorded on their respective balance sheets as of December 31, 2017,2023, associated with CCR storage facilities that reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2024. Ameren Missouri also estimates it will need to make capital expenditures of $300 million to $350 million from 2018 through 2022 to implement its CCR management compliance plan.facilities.
Remediation
The Ameren Companies are involved in a number of remediation actions to clean up sites affectedimpacted 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, 2017,2023, Ameren Illinois owned or was otherwise responsible forhas remediated the majority of the 44 former MGP sites in Illinois which are in various stages of investigation, evaluation, remediation, and closure. Ameren Illinois estimates it could substantially conclude remediation efforts 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, 2017, Ameren Illinoiswith an estimated theremaining obligation primarily related to three of these former MGP sites at $175$51 million to $249$96 million. Ameren and Ameren Illinois recorded a liability of $175$51 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.
Ameren cannot estimate the completion date of the estimated remaining obligation due to site accessibility, among other things. The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the 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.
The ICC allows Ameren Missouri participated in the investigation of various sites known as Sauget Area 2 located in Sauget, Illinois. In 2000, the EPA notified Ameren MissouriIllinois to recover MGP remediation and numerous other companiesrelated litigation costs from its electric and natural gas utility customers through environmental cost riders that former landfills and lagoons at those sites may contain soil and groundwater contamination. In 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation actions recommendedare subject to annual prudence reviews by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementationICC.
Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such historical practices will result in future environmental commitments, including additional or more stringent cleanup standards, or will affect our results of operations, financial position, or liquidity.
Illinois Emission Standards
The CEJA established emission standards that became effective in September 2021. Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO2 and NOx. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by the end of 2029. The reductions could also limit the operations of Ameren Missouri's four other natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the CEJA, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service. Ameren Missouri Municipal Taxes
The citiesfiled its 2023 IRP with the MoPSC in September 2023 to reflect, among other things, the updated scheduled retirement dates of Creve Coeur and Winchester, Missouri, on behalf of themselves and other municipalities in Ameren Missouri’s service area, filed a class action lawsuit in November 2011 against Ameren Missourithe natural gas-fired energy centers located in the Circuit Courtstate of St. Louis County, Missouri. Illinois.
NOTE 15 – SUPPLEMENTAL INFORMATION
Cash, Cash Equivalents, and Restricted Cash
The lawsuit alleges that Ameren Missouri failed to collectfollowing table provides a reconciliation of cash, cash equivalents, and pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. In December 2017,restricted cash reported within the court issued a final order approving a settlement agreement between Ameren Missouribalance sheets and the municipalities. The settlement agreement requires Ameren Missouri to make payments representing certain tax receipts to the municipalities during the first quarterstatements of 2018, in addition to payment of certain future gross receipts taxes. The future gross receipts taxes are recoverable from customers. Ameren and Ameren Missouri recorded immaterial current liabilities on their respective balance sheetscash flows as of December 31, 2017,2023and2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | | December 31, 2022 |
| Ameren | Ameren
Missouri | Ameren
Illinois | | | Ameren | Ameren
Missouri | Ameren
Illinois |
| Cash and cash equivalents | $ | 25 | | $ | — | | $ | — | | | | $ | 10 | | $ | — | | $ | — | |
| Restricted cash included in “Other current assets” | 13 | | 5 | | 5 | | | | 13 | | 5 | | 6 | |
| Restricted cash included in “Other assets” | 229 | | — | | 229 | | | | 185 | | — | | 185 | |
| Restricted cash included in “Nuclear decommissioning trust fund” | 5 | | 5 | | — | | | | 8 | | 8 | | — | |
| Total cash, cash equivalents, and restricted cash | $ | 272 | | $ | 10 | | $ | 234 | | | | $ | 216 | | $ | 13 | | $ | 191 | |
Restricted cash included in “Other current assets” primarily represents funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees. Restricted cash included in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets primarily represents amounts collected under a cost recovery rider restricted for use in the procurement of renewable energy credits and amounts in a trust fund restricted for the use of funding certain asbestos-related claims.
Accounts Receivable
“Accounts receivable – trade” on Ameren’s and Ameren Illinois’ balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to representparticipate in the utility consolidated billing program. At December 31, 2023 and 2022, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $42 million and $31 million, respectively.
The following table provides a reconciliation of the beginning and ending amount of the allowance for doubtful accounts for the years ended December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | | December 31, 2022 |
| Ameren Missouri | | Ameren Illinois(a) | Ameren | | | Ameren Missouri | Ameren Illinois(a) | Ameren |
| Beginning balance at January 1 | $ | 13 | | | $ | 18 | | $ | 31 | | | | $ | 13 | | $ | 16 | | $ | 29 | |
| Bad debt expense | 11 | | | 40 | | 51 | | | | 9 | | 25 | | 34 | |
Charged to other accounts(b) | — | | | 5 | | 5 | | | | — | | 4 | | 4 | |
| Net write-offs | (12) | | | (45) | | (57) | | | | (9) | | (27) | | (36) | |
| Ending balance at December 31 | $ | 12 | | | $ | 18 | | $ | 30 | | | | $ | 13 | | $ | 18 | | $ | 31 | |
(a)Ameren Illinois has rate-adjustment mechanisms that allow it to recover the difference between its actual net bad debt write-offs under GAAP, including those associated with receivables purchased from alternative retail electric suppliers, and the amount of net bad debt write-offs included in its base rates.
(b)Amounts associated with the allowance for doubtful accounts related to receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.
As of December 31, 2023, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 22%, 16%, and 27%, or $114 million, $35 million, and $79 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. In comparison, as of December 31, 2022, these percentages were 17%, 14%, and 20%, or $107 million, $35 million, and $71 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
Inventories
The following table presents the components of inventories for each of the Ameren Companies at December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | | December 31, 2022 |
| Ameren
Missouri | Ameren
Illinois | Ameren | | | Ameren
Missouri | Ameren
Illinois | Ameren |
Fuel(a) | $ | 109 | | $ | — | | $ | 109 | | | | $ | 79 | | $ | — | | $ | 79 | |
| Natural gas stored underground | 8 | | 87 | | 95 | | | | 10 | | 120 | | 130 | |
| Materials, supplies, and other | 391 | | 138 | | 529 | | | | 345 | | 113 | | 458 | |
| Total inventories | $ | 508 | | $ | 225 | | $ | 733 | | | | $ | 434 | | $ | 233 | | $ | 667 | |
(a)Consists of coal, oil, and propane.
Asset Retirement Obligations
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years ended December 31, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | | December 31, 2022 |
| Ameren
Missouri | | Ameren
Illinois | | Ameren | | | | Ameren
Missouri | | Ameren
Illinois | | Ameren | |
| Beginning balance at January 1 | $ | 782 | | (a) | $ | 4 | | (b) | $ | 786 | | (a) | | | $ | 760 | | | $ | 4 | | | $ | 764 | | |
| Liabilities incurred | — | | | — | | | — | | | | | 1 | |
| — | | | 1 | | |
| Liabilities settled | (10) | | | — | | | (10) | | | | | (4) | | | — | | | (4) | | |
Accretion(c) | 33 | | | — | | | 33 | | | | | 32 | | | — | | | 32 | | |
| Change in estimates | (18) | | | — | | | (18) | | | | | (7) | | | — | | | (7) | | |
| Ending balance at December 31 | $ | 787 | | (a)(d) | $ | 4 | | (b) | $ | 791 | | (a)(d) | | | $ | 782 | | (a) | $ | 4 | | (b) | $ | 786 | | (a) |
(a)Balance included $19 million and $23 million in “Other current liabilities” on the balance sheet as of December 31, 2023 and 2022, respectively.
(b)Included in “Other deferred credits and liabilities” on the balance sheet.
(c)Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.
(d)The balance as of December 31, 2023, included an ARO related to the decommissioning of the Callaway Enter Center of $619 million.
Deferred Compensation
As of December 31, 2023, and 2022, the present value of benefits to be paid for deferred compensation obligations was $85 million and $87 million, respectively, which was primarily reflected in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet. Deferred compensation obligations are primarily recorded on the balance sheet of Ameren (parent).
Excise Taxes
Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes, that are levied on the sale or distribution of natural gas and electricity. The following table presents the excise taxes recorded on a gross basis in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | |
| Ameren Missouri | $ | 166 | | | $ | 162 | | | $ | 150 | | |
| Ameren Illinois | 121 | | | 133 | | | 125 | | |
| Ameren | $ | 287 | | | $ | 295 | | | $ | 275 | | |
Allowance for Funds Used During Construction
The following table presents the average rate that was applied to eligible construction work in progress and the amounts of allowance for funds used during construction capitalized in 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | |
| Average rate: | | | | | | |
| Ameren Missouri | 6 | % | | 5 | % | | 6 | % | |
| Ameren Illinois | 6 | % | | 5 | % | | 5 | % | |
| Ameren: | | | | | | |
| Allowance for equity funds used during construction | $ | 54 | | | $ | 43 | | | $ | 43 | | |
| Allowance for borrowed funds used during construction | 48 | | | 26 | | | 17 | | |
| Total Ameren | $ | 102 | | | $ | 69 | | | $ | 60 | | |
| Ameren Missouri: | | | | | | |
| Allowance for equity funds used during construction | $ | 30 | | | $ | 24 | | | $ | 26 | | |
| Allowance for borrowed funds used during construction | 27 | | | 13 | | | 10 | | |
| Total Ameren Missouri | $ | 57 | | | $ | 37 | | | $ | 36 | | |
| Ameren Illinois: | | | | | | |
| Allowance for equity funds used during construction | $ | 19 | | | $ | 18 | | | $ | 17 | | |
| Allowance for borrowed funds used during construction | 17 | | | 12 | | | 7 | | |
| Total Ameren Illinois | $ | 36 | | | $ | 30 | | | $ | 24 | | |
Earnings per Share
Earnings per basic and diluted share are computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of basic and diluted common shares outstanding, respectively, during the applicable period. The weighted-average shares outstanding for earnings per diluted share includes the incremental effects resulting from performance share units, restricted stock units, and forward sale agreements relating to common stock when the impact would be dilutive, as calculated using the treasury stock method. For information regarding performance share units and restricted stock units, see Note 11 – Stock-based Compensation. For information regarding forward sale agreements, see Note 5 – Long-term Debt and Equity Financings.
The following table reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 |
| | | | | |
| | | | | |
| Weighted-average Common Shares Outstanding – Basic | 262.8 | | | 258.4 | | | 256.3 | |
| Assumed settlement of performance share units and restricted stock units | 0.6 | | | 1.0 | | | 1.3 | |
| Dilutive effect of forward sale agreements | — | | | 0.1 | | | — | |
Weighted-average Common Shares Outstanding – Diluted(a) | 263.4 | | | 259.5 | | | 257.6 | |
| | | | | |
| | | | | |
| | | | | |
(a)There was an immaterial number of anti-dilutive securities excluded from the earnings per diluted share calculations for the years ended December 31, 2023, 2022, and 2021 related to performance share units and restricted stock units. The outstanding forward sale agreements as of December 31, 2023, were anti-dilutive for the year ended December 31, 2023, and excluded from the earnings per diluted share calculation as calculated using the treasury stock method.
Supplemental Cash Flow Information
The following table provides noncash financing and investing activity excluded from the statements of cash flows for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2023 | | December 31, 2022 | | December 31, 2021 |
| Ameren | Ameren
Missouri | | Ameren
Illinois | | Ameren | Ameren
Missouri | Ameren
Illinois | | Ameren | Ameren
Missouri | Ameren
Illinois |
| Investing | | | | | | | | | | | | |
Accrued capital expenditures, including nuclear fuel expenditures | $ | 518 | | $ | 270 | | | $ | 212 | | | $ | 441 | | $ | 243 | | $ | 181 | | | $ | 524 | | $ | 301 | | $ | 215 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Net realized and unrealized gain (loss) – nuclear decommissioning trust fund | 167 | | 167 | | | — | | | (218) | | (218) | | — | | | 163 | | 163 | | — | |
Return of investment in industrial development revenue bonds(a) | 240 | | 240 | | | — | | | — | | — | | — | | | — | | — | | — | |
| Financing | | | | | | | | | | | | |
| Issuance of common stock for stock-based compensation | $ | 40 | | $ | — | | | $ | — | | | $ | 31 | | $ | — | | $ | — | | | $ | 33 | | $ | — | | $ | — | |
| Issuance of common stock under the DRPlus | 7 | | — | | | — | | | 8 | | — | | — | | | — | | — | | — | |
Termination of a financing agreement(a) | 240 | | 240 | | | — | | | — | | — | | — | | | — | | — | | — | |
(a)In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments made in February 2018 under the settlement agreement.due to Ameren Missouri.
NOTE 15 16 – SEGMENT INFORMATION
Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission is primarily composedconsists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. The category called Other primarily includes Ameren parent company(parent) activities and Ameren Services.
Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri, Ameren Illinois, and ATXI.
Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution, other retail electric suppliers, and wholesale customers. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected in Ameren Transmission’s and Ameren Illinois Transmission’s operating revenues. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.
The following tables present revenues,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, 2017, 2016,2023, 2022, and 2015.2021. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.
Ameren
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren | | |
| 2023 | | | | | | | | | | | | | | | |
| External revenues | $ | 3,825 | | | $ | 2,217 | | | $ | 897 | | | $ | 561 | | | $ | — | | | $ | — | | | $ | 7,500 | | | |
| Intersegment revenues | 34 | | | 1 | | | — | | | 116 | | | — | | | (151) | | | — | | | |
| Depreciation and amortization | 783 | | | 351 | | | 108 | | | 138 | | | 7 | | | — | | | 1,387 | | | |
| Interest income | 11 | | | 19 | | | 1 | | | 2 | | | 5 | | | (5) | | | 33 | | | |
| Interest charges | 227 | | | 89 | | | 55 | | | 96 | | (a) | 104 | | | (5) | | | 566 | | | |
| Income taxes (benefit) | (8) | | | 82 | | | 50 | | | 106 | | | (47) | | | — | | | 183 | | | |
| Net income (loss) attributable to Ameren common shareholders | 545 | | | 258 | | | 134 | | | 296 | | | (81) | | | — | | | 1,152 | | | |
| Capital expenditures | 1,760 | | | 752 | | | 299 | | | 804 | | | 9 | | | (27) | | | 3,597 | | | |
| | | | | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | | | | |
| External revenues | $ | 4,012 | | | $ | 2,255 | | | $ | 1,180 | | | $ | 510 | | | $ | — | | | $ | — | | | $ | 7,957 | | | |
| Intersegment revenues | 34 | | | 1 | | | — | | | 105 | | | — | | | (140) | | | — | | | |
| Depreciation and amortization | 732 | | | 332 | | | 98 | | | 123 | | | 4 | | | — | | | 1,289 | | | |
| Interest income | 28 | | | 7 | | | — | | | — | | | 1 | | | (1) | | | 35 | | | |
| Interest charges | 213 | | | 74 | | | 44 | | | 84 | | (a) | 72 | | | (1) | | | 486 | | | |
| Income taxes (benefit) | (10) | | | 68 | | | 46 | | | 92 | | | (20) | | | — | | | 176 | | | |
| Net income (loss) attributable to Ameren common shareholders | 562 | | | 202 | | | 123 | | | 263 | | | (76) | | | — | | | 1,074 | | | |
| Capital expenditures | 1,690 | | | 621 | | | 308 | | | 741 | | | 7 | | | (16) | | | 3,351 | | | |
| | | | | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | | | | |
| External revenues | $ | 3,311 | | | $ | 1,635 | | | $ | 957 | | | $ | 491 | | | $ | — | | | $ | — | | | $ | 6,394 | | | |
| Intersegment revenues | 42 | | | 4 | | | — | | | 71 | | | — | | | (117) | | | — | | | |
| Depreciation and amortization | 632 | | | 309 | | | 90 | | | 111 | | | 4 | | | — | | | 1,146 | | | |
| Interest income | 26 | | | 1 | | | — | | | — | | | 3 | | | (3) | | | 27 | | | |
| Interest charges | 137 | | | 74 | | | 42 | | | 83 | | (a) | 50 | | | (3) | | | 383 | | | |
| Income taxes (benefit) | 3 | | | 53 | | | 39 | | | 82 | | | (20) | | | — | | | 157 | | | |
| Net income (loss) attributable to Ameren common shareholders | 518 | | | 165 | | | 108 | | | 230 | | | (31) | | | — | | | 990 | | | |
| Capital expenditures | 2,015 | | | 579 | | | 278 | | | 616 | | | 4 | | | (13) | | | 3,479 | | | |
| | | | | | | | | | | | | | | |
(a)Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Consolidated |
| 2017 | | | | | | | | | | | | | |
| External revenues | $ | 3,490 |
| | $ | 1,565 |
| | $ | 742 |
| | $ | 382 |
| | $ | (2 | ) | | $ | — |
| | $ | 6,177 |
|
| 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 from continuing operations | 323 |
| | 131 |
| | 60 |
| | 140 |
| | (131 | ) | | — |
| | 523 |
|
| Capital expenditures | 773 |
| | 476 |
| | 245 |
| | 644 |
| | 1 |
| | (7 | ) | | 2,132 |
|
| 2016 | | | | | | | | | | | | | |
| External revenues | $ | 3,469 |
| | $ | 1,545 |
| | $ | 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 from continuing operations | 357 |
| | 126 |
| | 59 |
| | 117 |
| | (6 | ) | | — |
| | 653 |
|
| Capital expenditures | 738 |
| | 470 |
| | 181 |
| | 689 |
| | 4 |
| | (6 | ) | | 2,076 |
|
| 2015 | | | | | | | | | | | | | |
| External revenues | $ | 3,566 |
| | $ | 1,529 |
| | $ | 782 |
| | $ | 219 |
| | $ | 2 |
| | $ | — |
| | $ | 6,098 |
|
| Intersegment revenues | 43 |
| | 3 |
| | 1 |
| | 40 |
| (a) | — |
| | (87 | ) | | — |
|
| Depreciation and amortization | 492 |
| | 212 |
| | 52 |
| | 33 |
| | 7 |
| | — |
| | 796 |
|
| Interest income | 28 |
| | 12 |
| | — |
| | — |
| | 7 |
| | (6 | ) | | 41 |
|
| Interest charges | 219 |
| | 71 |
| | 35 |
| | 35 |
| (b) | 1 |
| | (6 | ) | | 355 |
|
| Income taxes | 209 |
| | 71 |
| | 24 |
| | 51 |
| | 8 |
| | — |
| | 363 |
|
| Net income (loss) attributable to Ameren common shareholders from continuing operations | 352 |
| | 123 |
| | 37 |
| | 83 |
| | (16 | ) | | — |
| | 579 |
|
| Capital expenditures | 622 |
| | 491 |
| | 133 |
| | 669 |
| | 2 |
| | — |
| | 1,917 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| 2023 | | | | | | | | | | |
| External revenues | $ | 2,218 | | | $ | 897 | | | $ | 367 | | | $ | — | | | $ | 3,482 | | |
| Intersegment revenues | — | | | — | | | 113 | | | (113) | | | — | | |
| Depreciation and amortization | 351 | | | 108 | | | 97 | | | — | | | 556 | | |
| Interest income | 19 | | | 1 | | | 1 | | | — | | | 21 | | |
| Interest charges | 89 | | | 55 | | | 60 | | | — | | | 204 | | |
| Income taxes | 82 | | | 50 | | | 77 | | | — | | | 209 | | |
| Net income available to common shareholder | 258 | | | 134 | | | 215 | | | — | | | 607 | | |
| Capital expenditures | 752 | | | 299 | | | 680 | | | — | | | 1,731 | | |
| | | | | | | | | | |
| 2022 | | | | | | | | | | |
| External revenues | $ | 2,256 | | | $ | 1,180 | | | $ | 320 | | | $ | — | | | $ | 3,756 | | |
| Intersegment revenues | — | | | — | | | 104 | | | (104) | | | — | | |
| Depreciation and amortization | 332 | | | 98 | | | 84 | | | — | | | 514 | | |
| Interest income | 7 | | | — | | | — | | | — | | | 7 | | |
| Interest charges | 74 | | | 44 | | | 50 | | | — | | | 168 | | |
| Income taxes | 68 | | | 46 | | | 65 | | | — | | | 179 | | |
| Net income available to common shareholder | 202 | | | 123 | | | 188 | | | — | | | 513 | | |
| Capital expenditures | 621 | | | 308 | | | 672 | | | — | | | 1,601 | | |
| | | | | | | | | | |
| 2021 | | | | | | | | | | |
| External revenues | $ | 1,639 | | | $ | 957 | | | $ | 299 | | | $ | — | | | $ | 2,895 | | |
| Intersegment revenues | — | | | — | | | 66 | | | (66) | | | — | | |
| Depreciation and amortization | 309 | | | 90 | | | 73 | | | — | | | 472 | | |
| Interest income | 1 | | | — | | | — | | | — | | | 1 | | |
| Interest charges | 74 | | | 42 | | | 48 | | | — | | | 164 | | |
| Income taxes | 53 | | | 39 | | | 51 | | | — | | | 143 | | |
| Net income available to common shareholder | 165 | | | 108 | | | 152 | | | — | | | 425 | | |
| Capital expenditures | 579 | | | 278 | | | 575 | | | — | | | 1,432 | | |
| | | | | | | | | | |
| |
(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). |
The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the years ended December 31, 2023, 2022, and 2021. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system sales and capacity revenues.
Ameren
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | | | Intersegment Eliminations | | Ameren | |
| 2023 | | | | | | | | | | | | | | |
| Residential | $ | 1,577 | | | $ | 1,344 | | | $ | — | | | $ | — | | | | | $ | — | | | $ | 2,921 | | |
| Commercial | 1,280 | | | 747 | | | — | | | — | | | | | — | | | 2,027 | | |
| Industrial | 306 | | | 186 | | | — | | | — | | | | | — | | | 492 | | |
| Other | 531 | | | (59) | | | — | | | 677 | | | | | (150) | | | 999 | | |
| Total electric revenues | $ | 3,694 | | | $ | 2,218 | | | $ | — | | | $ | 677 | | | | | $ | (150) | | | $ | 6,439 | | |
| Residential | $ | 100 | | | $ | — | | | $ | 657 | | | $ | — | | | | | $ | — | | | $ | 757 | | |
| Commercial | 46 | | | — | | | 164 | | | — | | | | | — | | | 210 | | |
| Industrial | 5 | | | — | | | 14 | | | — | | | | | — | | | 19 | | |
| Other | 14 | | | — | | | 62 | | | — | | | | | (1) | | | 75 | | |
| Total gas revenues | $ | 165 | | | $ | — | | | $ | 897 | | | $ | — | | | | | $ | (1) | | | $ | 1,061 | | |
Total revenues(a) | $ | 3,859 | | | $ | 2,218 | | | $ | 897 | | | $ | 677 | | | | | $ | (151) | | | $ | 7,500 | | |
| 2022 | | | | | | | | | | | | | | |
| Residential | $ | 1,578 | | | $ | 1,325 | | | $ | — | | | $ | — | | | | | $ | — | | | $ | 2,903 | | |
| Commercial | 1,219 | | | 768 | | | — | | | — | | | | | — | | | 1,987 | | |
| Industrial | 290 | | | 199 | | | — | | | — | | | | | — | | | 489 | | |
| Other | 762 | | | (36) | | | — | | | 615 | | | | | (139) | | | 1,202 | | |
| Total electric revenues | $ | 3,849 | | | $ | 2,256 | | | $ | — | | | $ | 615 | | | | | $ | (139) | | | $ | 6,581 | | |
| Residential | $ | 119 | | | $ | — | | | $ | 846 | | | $ | — | | | | | $ | — | | | $ | 965 | | |
| Commercial | 56 | | | — | | | 221 | | | — | | | | | — | | | 277 | | |
| Industrial | 7 | | | — | | | 41 | | | — | | | | | — | | | 48 | | |
| Other | 15 | | | — | | | 72 | | | — | | | | | (1) | | | 86 | | |
| Total gas revenues | $ | 197 | | | $ | — | | | $ | 1,180 | | | $ | — | | | | | $ | (1) | | | $ | 1,376 | | |
Total revenues(a) | $ | 4,046 | | | $ | 2,256 | | | $ | 1,180 | | | $ | 615 | | | | | $ | (140) | | | $ | 7,957 | | |
| 2021 | | | | | | | | | | | | | | |
| Residential | $ | 1,445 | | | $ | 933 | | | $ | — | | | $ | — | | | | | $ | — | | | $ | 2,378 | | |
| Commercial | 1,126 | | | 545 | | | — | | | — | | | | | — | | | 1,671 | | |
| Industrial | 280 | | | 135 | | | — | | | — | | | | | — | | | 415 | | |
| Other | 361 | | | 26 | | | — | | | 562 | | | | | (116) | | | 833 | | |
| Total electric revenues | $ | 3,212 | | | $ | 1,639 | | | $ | — | | | $ | 562 | | | | | $ | (116) | | | $ | 5,297 | | |
| Residential | $ | 79 | | | $ | — | | | $ | 657 | | | $ | — | | | | | $ | — | | | $ | 736 | | |
| Commercial | 34 | | | — | | | 172 | | | — | | | | | — | | | 206 | | |
| Industrial | 4 | | | — | | | 35 | | | — | | | | | — | | | 39 | | |
| Other | 24 | | | — | | | 93 | | | — | | | | | (1) | | | 116 | | |
| Total gas revenues | $ | 141 | | | $ | — | | | $ | 957 | | | $ | — | | | | | $ | (1) | | | $ | 1,097 | | |
Total revenues(a) | $ | 3,353 | | | $ | 1,639 | | | $ | 957 | | | $ | 562 | | | | | $ | (117) | | | $ | 6,394 | | |
(a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Ameren | |
| 2023 | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (5) | | | $ | 116 | | | $ | 49 | | | $ | 19 | | | $ | 179 | | |
| Other revenues not from contracts with customers | (9) | | (a) | 7 | | | 2 | | | — | | | — | | (a) |
| 2022 | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | 17 | | | $ | 89 | | | $ | (19) | | | $ | (9) | | | $ | 78 | | |
| Other revenues not from contracts with customers | (103) | | (a)(b) | 6 | | | 3 | | | — | | | (94) | | (a)(b) |
| 2021 | | | | | | | | | | |
| Revenues from alternative revenue programs | $ | (16) | | | $ | 77 | | | $ | 5 | | | $ | 11 | | | $ | 77 | | |
| Other revenues not from contracts with customers | 56 | | (a)(b) | 10 | | | 2 | | | — | | | 68 | | (a)(b) |
(a)Includes net realized gains and losses on derivative power contracts.
(b)Includes $10 million and $78 million for insurance recoveries related to lost sales associated with the Callaway Energy Center maintenance outage for the years ended December 31, 2022 and 2021, respectively.
Ameren Illinois
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| 2023 | | | | | | | | | | |
| Residential | $ | 1,344 | | | $ | 657 | | | $ | — | | | $ | — | | | $ | 2,001 | | |
| Commercial | 747 | | | 164 | | | — | | | — | | | 911 | | |
| Industrial | 186 | | | 14 | | | — | | | — | | | 200 | | |
| Other | (59) | | | 62 | | | 480 | | | (113) | | | 370 | | |
Total revenues(a) | $ | 2,218 | | | $ | 897 | | | $ | 480 | | | $ | (113) | | | $ | 3,482 | | |
| 2022 | | | | | | | | | | |
| Residential | $ | 1,325 | | | $ | 846 | | | $ | — | | | $ | — | | | $ | 2,171 | | |
| Commercial | 768 | | | 221 | | | — | | | — | | | 989 | | |
| Industrial | 199 | | | 41 | | | — | | | — | | | 240 | | |
| Other | (36) | | | 72 | | | 424 | | | (104) | | | 356 | | |
Total revenues(a) | $ | 2,256 | | | $ | 1,180 | | | $ | 424 | | | $ | (104) | | | $ | 3,756 | | |
| 2021 | | | | | | | | | | |
| Residential | $ | 933 | | | $ | 657 | | | $ | — | | | $ | — | | | $ | 1,590 | | |
| Commercial | 545 | | | 172 | | | — | | | — | | | 717 | | |
| Industrial | 135 | | | 35 | | | — | | | — | | | 170 | | |
| Other | 26 | | | 93 | | | 365 | | | (66) | | | 418 | | |
Total revenues(a) | $ | 1,639 | | | $ | 957 | | | $ | 365 | | | $ | (66) | | | $ | 2,895 | | |
(a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the years ended December 31, 2023, 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois |
| 2023 | | | | | | | |
| Revenues from alternative revenue programs | $ | 116 | | | $ | 49 | | | $ | 12 | | | $ | 177 | |
| Other revenues not from contracts with customers | 7 | | | 2 | | | — | | | 9 | |
| 2022 | | | | | | | |
| Revenues from alternative revenue programs | $ | 89 | | | $ | (19) | | | $ | (7) | | | $ | 63 | |
| Other revenues not from contracts with customers | 6 | | | 3 | | | — | | | 9 | |
| 2021 | | | | | | | |
| Revenues from alternative revenue programs | $ | 77 | | | $ | 5 | | | $ | 9 | | | $ | 91 | |
| Other revenues not from contracts with customers | 10 | | | 2 | | | — | | | 12 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Consolidated | |
| 2017 | | | | | | | | | | |
| External revenues | $ | 1,569 |
| | $ | 743 |
| | $ | 216 |
| | $ | — |
| | $ | 2,528 |
| |
| 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 | $ | 1,549 |
| | $ | 754 |
| | $ | 187 |
| | $ | — |
| | $ | 2,490 |
| |
| 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 |
| |
| 2015 | | | | | | | | | | |
| External revenues | $ | 1,532 |
| | $ | 783 |
| | $ | 151 |
| | $ | — |
| | $ | 2,466 |
| |
| Intersegment revenues | — |
| | — |
| | 38 |
| (a) | (38 | ) | | — |
| |
| Depreciation and amortization | 212 |
| | 52 |
| | 31 |
| | — |
| | 295 |
| |
| Interest income | 12 |
| | — |
| | — |
| | — |
| | 12 |
| |
| Interest charges | 71 |
| | 35 |
| | 25 |
| | — |
| | 131 |
| |
| Income taxes | 71 |
| | 24 |
| | 32 |
| | — |
| | 127 |
| |
| Net income available to common shareholder | 123 |
| | 37 |
| | 54 |
| | — |
| | 214 |
| |
| Capital expenditures | 491 |
| | 133 |
| | 294 |
| | — |
| | 918 |
| |
| |
(a) | Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above. |
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2017 | | | 2016 |
| Quarter ended | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 |
| Operating revenues | $ | 1,514 |
| | $ | 1,538 |
| | $ | 1,723 |
| | $ | 1,402 |
| | | $ | 1,434 |
| | $ | 1,427 |
| | $ | 1,859 |
| | $ | 1,356 |
|
| Operating income | 254 |
| | 398 |
| | 581 |
| | 225 |
| | | 220 |
| | 325 |
| | 691 |
| | 145 |
|
| Net income (loss) | 104 |
| | 194 |
| | 290 |
| | (59 | ) | (a) | | 107 |
| | 148 |
| | 371 |
| | 33 |
|
| Net income (loss) attributable to Ameren common shareholders | $ | 102 |
| | $ | 193 |
| | $ | 288 |
| | $ | (60 | ) | | | $ | 105 |
| | $ | 147 |
| | $ | 369 |
| | $ | 32 |
|
| Earnings (loss) per common share – basic | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.19 |
| | $ | (0.24 | ) | | | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
|
Earnings (loss) per common share – diluted(b) | $ | 0.42 |
| | $ | 0.79 |
| | $ | 1.18 |
| | $ | (0.24 | ) | | | $ | 0.43 |
| | $ | 0.61 |
| | $ | 1.52 |
| | $ | 0.13 |
|
| |
(a)
| Includes an increase to income tax expense of $154 million recorded in 2017 as a result of the TCJA. |
| |
(b) | 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 | | Operating Income | | Net Income (Loss) | | Net Income (Loss) Available to Common Shareholder |
| March 31, 2017 | | $ | 790 |
| | $ | 53 |
| | $ | 6 |
| | $ | 5 |
|
| March 31, 2016 | | 741 |
| | 63 |
| | 15 |
| | 14 |
|
| June 30, 2017 | | 935 |
| | 237 |
| | 121 |
| | 120 |
|
| June 30, 2016 | | 867 |
| | 197 |
| | 93 |
| | 92 |
|
| September 30, 2017 | | 1,115 |
| | 417 |
| | 235 |
| | 234 |
|
| September 30, 2016 | | 1,165 |
| | 431 |
| | 242 |
| | 241 |
|
| December 31, 2017 | | 699 |
| | 40 |
| | (36 | ) | (a) | (36 | ) |
| December 31, 2016 | | 750 |
| | 54 |
| | 10 |
| | 10 |
|
| |
(a) | Includes an increase to income tax expense of $32 million recorded in 2017 as a result of the TCJA. |
|
| | | | | | | | | | | | | | | | |
Ameren Illinois Quarter ended(a) | | Operating Revenues | | Operating Income | | Net Income | | Net Income Available to Common Shareholder |
| March 31, 2017 | | $ | 703 |
| | $ | 172 |
| | $ | 80 |
| | $ | 79 |
|
| March 31, 2016 | | 677 |
| | 133 |
| | 60 |
| | 59 |
|
| June 30, 2017 | | 576 |
| | 130 |
| | 58 |
| | 57 |
|
| June 30, 2016 | | 542 |
| | 107 |
| | 46 |
| | 45 |
|
| September 30, 2017 | | 575 |
| | 128 |
| | 55 |
| | 55 |
|
| September 30, 2016 | | 676 |
| | 230 |
| | 119 |
| | 119 |
|
| December 31, 2017 | | 674 |
| | 150 |
| | 78 |
| | 77 |
|
| December 31, 2016 | | 595 |
| | 74 |
| | 30 |
| | 29 |
|
| |
(a) | In 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed the method it used to recognize its interim-period revenue. Ameren Illinois now recognizes revenue consistent with the timing of incurred electric distribution recoverable costs, and it recognizes revenue associated with the expected return on its rate base ratably over the year. As a result of this change in recognition of the interim period revenue for the IEIMA formula rate framework, as modified by the FEJA, Ameren Illinois incurred quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first, second, and fourth quarters and a decrease to earnings in the third quarter. The change in interim period revenue recognition did not affect 2017 annual earnings. |
| |
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, 2017,2023, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and the principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of December 31, 2017,2023, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
| |
(b) | Management’s Report on Internal Control over Financial Reporting |
(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, 2017.2023. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2017,2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of Ameren Missouri’s or Ameren Illinois’ (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over
financial reporting. Management’s report for each of the Subsidiary Registrants is not subject to attestation by an independent registered public accounting firm.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that internal controls might become inadequate because of changes in conditions, and to the risk that the degree of compliance with the policies or procedures might deteriorate.
| |
(c) | Change in Internal Control |
(c)Change in Internal Control
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
| |
ITEM 9B. | OTHER INFORMATION |
The Ameren Companies have no information reportable under this item that was required to be disclosedITEM 9B.OTHER INFORMATION
Insider Adoption or Termination of Trading Arrangements
During the fiscal quarter ended December 31, 2023, none of our directors or officers informed us of the adoption or termination of a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in a report on SEC Form 8-K during the fourth quarter of 2017 that has not previously been reported on an SEC Form 8-K.Regulation S-K, Item 408.
ITEM 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not Applicable.
PART III
| |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE |
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 20182024 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 20182024 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,”Reports” and “Corporate Governance” and “Board Structure.Governance.”
Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “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 CatherineNoelle K. Eder, Rafael Flores, Richard J. Harshman, and Leo S. Brune, J. Edward Coleman, and Ellen M. FitzsimmonsMackay, Jr. serve as members. The board of directors of Ameren has determined that Walter J. Galvin and J. Edward Coleman and Richard J. Harshman each qualify as an audit committee financial expert and that each is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of Ameren Missouri and Ameren Illinois use the 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 itsAmeren’s Director Nomination 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 20182024 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 20182024 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”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, 2017,2023, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans.plans:
| | | | | | | | | | | | | | | | | | | | |
Plan
Category | | Column A Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights(a) | | Column B Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Column C Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in Column A)(b) |
| Equity compensation plans approved by security holders | | 1,376,597 | | | (c) | | 8,201,140 | |
| Equity compensation plans not approved by security holders | | — | | | — | | | — | |
| Total | | 1,376,597 | | | (c) | | 8,201,140 | |
|
| | | | | | | | | |
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) | | 1,834,043 |
| | (c) |
| | 4,893,953 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
|
| Total | | 1,834,043 |
| | (c) |
| | 4,893,953 |
|
| |
(a) | Pursuant to grants of performance share units (PSUs) under the 2014 Incentive Plan, 1,767,462 of the securities represent the target number of PSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 2017 (including outstanding awards under the 2014 Incentive Plan as of December 31, 2017). 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, including payout calculations, see “Compensation Discussion and Analysis – Long-Term Incentives: Performance Share Unit Program (“PSUP”)” in Ameren’s definitive proxy statement for its 2018 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. Also, 66,581 of the securities represent shares that may be issued as of December 31, 2017, 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) | Earned PSUs and deferred compensation stock units are paid in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs and deferred compensation stock units do not have a weighted-average exercise price. |
(b)Includes shares remaining available for issuance pursuant to awards under the Ameren Corporation 2022 Omnibus Incentive Compensation Plan.
(c)No cash consideration is received when shares are distributed for earned PSUs, RSUs, and director awards. Accordingly, there is no weighted-average exercise price.
Ameren Missouri and Ameren Illinois do not have separate equity compensation plans.
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 20182024 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 20182024 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:statements: “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 20182024 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 20182024 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: “Policy and Procedures With Respect to Related“Related Person Transactions”Transactions Policy” and “Director Independence.”
| |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of Ameren Missouri and Ameren Illinois for their 20182024 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: “Independentstatements: “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 – | |
| (PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238) | |
Consolidated Statement of Income – Years Ended December 31, 2017, 2016, and 2015 | |
Consolidated Statement of Comprehensive Income – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| |
Consolidated Balance Sheet – December 31, 20172023 and 20162022 | |
Consolidated Statement of Cash Flows – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| Ameren Missouri | |
| Report of Independent Registered Public Accounting Firm – | |
| (PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238) | |
Consolidated Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| Consolidated Balance Sheet – December 31, 2023 and 2022 | |
| Consolidated Statement of Cash Flows – Years Ended December 31, 2023, 2022, and 2021 | |
| Consolidated Statement of Shareholders’ Equity – Years Ended December 31, 2023, 2022, and 2021 | |
| Ameren Illinois | |
| Report of Independent Registered Public Accounting Firm – | |
| (PricewaterhouseCoopers LLP’s Public Company Accounting Oversight Board ID 238) | |
| Statement of Income – Years Ended December 31, 2023, 2022, and 2021 | |
Balance Sheet – December 31, 20172023 and 20162022 | |
Statement of Cash Flows – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| Ameren Illinois |
Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016, and 2015 | |
Balance Sheet – December 31, 2017 and 2016 | |
Statement of Cash Flows – Years Ended December 31, 2017, 2016, and 2015 | |
Statement of Shareholders’ Equity – Years Ended December 31, 2017, 2016, and 2015 | |
| |
| (a)(2) Financial Statement Schedules | |
| Schedule I | |
| Condensed Financial Information of Parent – Ameren: | |
Condensed Statement of Income and Comprehensive Income – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
Condensed Balance Sheet – December 31, 20172023 and 20162022 | |
Condensed Statement of Cash Flows – Years Ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| Schedule II | |
| Ameren | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| Ameren Missouri | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
| Ameren Illinois | |
Valuation and Qualifying Accounts for the years ended December 31, 2017, 2016,2023, 2022, and 20152021 | |
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.
| | | | | |
| | | |
| | | |
| (a)(3) | | Exhibits – reference is made to the Exhibit Index | |
| (b) | | Exhibit Index | |
| | | | | | | | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME For the Years Ended December 31, 2023, 2022, and 2021 |
| (In millions) | 2023 | | 2022 | | 2021 |
| Operating revenues | $ | — | | | $ | — | | | $ | — | |
| Operating expenses | 22 | | | 15 | | | 13 | |
| Operating loss | (22) | | | (15) | | | (13) | |
| Equity in earnings of subsidiaries | 1,245 | | | 1,161 | | | 1,039 | |
| Interest income from affiliates | 10 | | | 2 | | | 3 | |
| Total other expense, net | (11) | | | (13) | | | — | |
| Interest charges | (119) | | | (86) | | | (64) | |
| Income tax benefit | 49 | | | 25 | | | 25 | |
| | | | | |
| | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 1,152 | | | $ | 1,074 | | | $ | 990 | |
| | | | | |
| Net Income Attributable to Ameren Common Shareholders | $ | 1,152 | | | $ | 1,074 | | | $ | 990 | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(2), $(4), and $4, respectively | (5) | | | (14) | | | 14 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 1,147 | | | $ | 1,060 | | | $ | 1,004 | |
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015 |
| (In millions) | 2017 | | 2016 | | 2015 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
|
| Operating expenses | 13 |
| | 14 |
| | 14 |
|
| Operating loss | (13 | ) | | (14 | ) | | (14 | ) |
| Equity in earnings of subsidiaries | 659 |
| | 663 |
| | 600 |
|
| Interest income from affiliates | 9 |
| | 10 |
| | 6 |
|
| Total other expense, net | — |
| | (5 | ) | | (5 | ) |
| Interest charges | 31 |
| | 28 |
| | 3 |
|
| Income tax (benefit) | 101 |
| | (27 | ) | | 5 |
|
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | 523 |
| | 653 |
| | 579 |
|
| Net Income Attributable to Ameren Common Shareholders – Discontinued Operations | — |
| | — |
| | 51 |
|
| Net Income Attributable to Ameren Common Shareholders | $ | 523 |
| | $ | 653 |
| | $ | 630 |
|
| | | | | | |
| Net Income Attributable to Ameren Common Shareholders – Continuing Operations | $ | 523 |
| | $ | 653 |
| | $ | 579 |
|
| Other Comprehensive Income, Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $3, $(7), and $3, respectively | 5 |
| | (20 | ) | | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders | 528 |
| | 633 |
| | 585 |
|
| Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders | — |
| | — |
| | 51 |
|
| Comprehensive Income Attributable to Ameren Common Shareholders | $ | 528 |
| | $ | 633 |
| | $ | 636 |
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions, except per share amounts) | December 31, 2023 | | December 31, 2022 |
| Assets: | | | |
| Cash and cash equivalents | $ | 16 | | | $ | — | |
| Advances to money pool | 598 | | | 68 | |
| Accounts receivable – affiliates | 20 | | | 59 | |
| | | |
| Miscellaneous accounts and notes receivable | 31 | | | 11 | |
| | | |
| | | |
| Total current assets | 665 | | | 138 | |
| | | |
| Investments in subsidiaries | 14,573 | | | 13,394 | |
| | | |
| | | |
| Accumulated deferred income taxes, net | 44 | | | 46 | |
| Other assets | 149 | | | 137 | |
| Total assets | $ | 15,431 | | | $ | 13,715 | |
| Liabilities and Shareholders’ Equity: | | | |
| Current maturities of long-term debt | $ | 450 | | | $ | — | |
| Short-term debt | — | | | 477 | |
| | | |
| Accounts payable | 2 | | | — | |
| Taxes accrued | 10 | | | 5 | |
| Accounts payable – affiliates | 100 | | | 52 | |
| Other current liabilities | 45 | | | 41 | |
| Total current liabilities | 607 | | | 575 | |
| Long-term debt, net | 3,379 | | | 2,536 | |
| Pension and other postretirement benefits | 19 | | | 19 | |
| Other deferred credits and liabilities | 77 | | | 77 | |
| Total liabilities | 4,082 | | | 3,207 | |
| Commitments and Contingencies (Note 4) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 266.3 and 262.0, respectively | 3 | | | 3 | |
| Other paid-in capital, principally premium on common stock | 7,216 | | | 6,860 | |
| Retained earnings | 4,136 | | | 3,646 | |
| Accumulated other comprehensive income (loss) | (6) | | | (1) | |
| Total shareholders’ equity | 11,349 | | | 10,508 | |
| Total liabilities and shareholders’ equity | $ | 15,431 | | | $ | 13,715 | |
|
| | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions) | December 31, 2017 | | December 31, 2016 |
| Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | 1 |
|
| Advances to money pool | 13 |
| | 27 |
|
| Accounts receivable – affiliates | 46 |
| | 31 |
|
| Miscellaneous accounts and notes receivable | — |
| | 26 |
|
| Other current assets | 8 |
| | 8 |
|
| Total current assets | 67 |
| | 93 |
|
| Investments in subsidiaries | 7,944 |
| | 7,498 |
|
| Note receivable – ATXI | 75 |
| | 350 |
|
| Accumulated deferred income taxes, net | 222 |
| | 419 |
|
| Other assets | 140 |
| | 135 |
|
| Total assets | $ | 8,448 |
| | $ | 8,495 |
|
| Liabilities and Shareholders’ Equity: | | | |
| Short-term debt | 383 |
| | 507 |
|
| Borrowings from money pool | 28 |
| | 33 |
|
| Accounts payable – affiliates | 6 |
| | 13 |
|
| Other current liabilities | 27 |
| | 17 |
|
| Total current liabilities | 444 |
| | 570 |
|
| Long-term debt | 696 |
| | 694 |
|
| Pension and other postretirement benefits | 37 |
| | 45 |
|
| Other deferred credits and liabilities | 87 |
| | 83 |
|
| Total liabilities | 1,264 |
| | 1,392 |
|
| Commitments and Contingencies (Note 4) | | | |
| Shareholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,540 |
| | 5,556 |
|
| Retained earnings | 1,660 |
| | 1,568 |
|
| Accumulated other comprehensive loss | (18 | ) | | (23 | ) |
| Total shareholders’ equity | 7,184 |
| | 7,103 |
|
| Total liabilities and shareholders’ equity | $ | 8,448 |
| | $ | 8,495 |
|
| | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015 | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2023, 2022, and 2021 | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2023, 2022, and 2021 | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2023, 2022, and 2021 | |
| (In millions) | | 2017 | | 2016 | | 2015 | (In millions) | | 2023 | | 2022 | | 2021 |
| Net cash flows provided by operating activities | | $ | 454 |
| | $ | 483 |
| | $ | 551 |
|
| Cash flows from investing activities: | | | | | | |
| Money pool advances, net | | 14 |
| | (27 | ) | | 55 |
|
| Notes receivable – ATXI, net | | 275 |
| | (60 | ) | | (96 | ) |
| Money pool advances, net | |
| Money pool advances, net | |
| Notes receivable – ATXI | |
| Investments in subsidiaries | | (151 | ) | | (123 | ) | | (509 | ) |
| | Other | |
| | Other | |
| | Other | | 6 |
| | 2 |
| | (12 | ) |
| Net cash flows provided by (used in) investing activities | | 144 |
| | (208 | ) | | (562 | ) |
| Cash flows from financing activities: | | | | | | |
| Dividends on common stock | | (431 | ) | | (416 | ) | | (402 | ) |
| Dividends on common stock | |
| Dividends on common stock | |
| Short-term debt, net | | (124 | ) | | 206 |
| | (284 | ) |
| Money pool borrowings, net | | (5 | ) | | 19 |
| | 14 |
|
| | Issuances of long-term debt | | — |
| | — |
| | 700 |
|
| | Issuances of long-term debt | |
| | Issuances of long-term debt | |
| Issuances of common stock | |
| | Employee payroll taxes related to stock-based compensation | |
| Employee payroll taxes related to stock-based compensation | |
| Employee payroll taxes related to stock-based compensation | |
| Debt issuance costs | | — |
| | — |
| | (6 | ) |
| Share-based payments | | (39 | ) | | (83 | ) | | (12 | ) |
| | Net cash flows provided by (used in) financing activities | | (599 | ) | | (274 | ) | | 10 |
|
| Net change in cash and cash equivalents | | $ | (1 | ) | | $ | 1 |
| | $ | (1 | ) |
| Cash and cash equivalents at beginning of year | | 1 |
| | — |
| | 1 |
|
| Cash and cash equivalents at end of year | | $ | — |
| | $ | 1 |
| | $ | — |
|
| | | | | | | |
| Net cash flows provided by (used in) financing activities | |
| Net cash flows provided by (used in) financing activities | |
| Net change in cash, cash equivalents, and restricted cash | |
| Cash, cash equivalents, and restricted cash at beginning of year | |
| Cash, cash equivalents, and restricted cash at end of year | |
| Supplemental information: | |
| Cash dividends received from consolidated subsidiaries | |
| Cash dividends received from consolidated subsidiaries | |
| Cash dividends received from consolidated subsidiaries | | $ | 362 |
| | $ | 465 |
| | $ | 575 |
|
| | | | | | | |
| Noncash investing activity – investments in subsidiaries | | — |
| | — |
| | (38 | ) |
| | Noncash financing activity – Issuance of common stock for stock-based compensation | |
| | Noncash financing activity – Issuance of common stock for stock-based compensation | |
| | Noncash financing activity – Issuance of common stock for stock-based compensation | |
| Noncash financing activity – Issuance of common stock under the DRPlus | |
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 20172023
NOTE 1 – BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. Ameren Corporation (parent company only) has accounted for its subsidiaries using the equity method. These financial statements are presented on a condensed basis.
See Note 1 – Summary of Significant Accounting Policies and Note 15 – Supplemental Information under Part II, Item 8, of this report for additional information. 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 – SHORT-TERM DEBT AND LIQUIDITY
Ameren, Ameren Services, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. All participants may borrow from or lend to the non-state-regulated money pool. The total amount available to pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. Interest revenues related to non-state-regulated money pool advances were $10 million in 2023 and interestimmaterial in 2022 and 2021. Interest charges related to non-state-regulated money pool advances and borrowings were immaterial in 2015, 2016,2021, 2022, and 2017.
Ameren Corporation (parent company only) had a total of $46 million in guarantees outstanding, primarily for ATXI, that were not recorded on its December 31, 2017 balance sheet. The ATXI guarantees were issued to local governments as assurance for potential remediation of damage caused by ATXI construction.
2023.
See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).
NOTE 3 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on Ameren Corporation’s (parent company only) long-term debt, indenture provisions, forward sale agreements related to common stock, and restricted cash balance.ATM program.
NOTE 4 – COMMITMENTS AND CONTINGENCIES
See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies of Ameren Corporation (parent company only).
NOTE 5 – DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS TOTAL OTHER EXPENSE, NET
See Note 1 – SummaryThe following table presents the components of Significant Accounting Policies under Part II, Item 8,“Total Other Expense, Net” in the Condensed Statement of this reportIncome and Comprehensive Income for information regarding the divestiture transactionsyears ended December 31, 2023, 2022, and discontinued operations.2021:
NOTE 6 – INCOME TAXES
See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding the impacts of the TCJA on Ameren Corporation (parent company only).
| | | | | | | | | | | | | | | | | |
| (In millions) | 2023 | | 2022 | | 2021 |
| Total Other Expense, Net | | | | | |
| Non-service cost components of net periodic benefit income | $ | 8 | | | $ | 3 | | | $ | 1 | |
| Donations | (18) | | | (15) | | | — | |
| Other expense, net | (1) | | | (1) | | | (1) | |
| Total Other Expense, Net | $ | (11) | | | $ | (13) | | | $ | — | |
|
| | | | | | | | | | | | | | | | | | | |
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2017, 2016, AND 2015 |
| (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: | | | | | | | | | |
| 2017 | $ | 19 |
| | $ | 26 |
| | $ | 7 |
| | $ | 33 |
| | $ | 19 |
|
| 2016 | 19 |
| | 32 |
| | 3 |
| | 35 |
| | 19 |
|
| 2015 | 21 |
| | 33 |
| | 5 |
| | 40 |
| | 19 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2017 | $ | 11 |
| | $ | (6 | ) | (c) | $ | — |
| | $ | — |
| | $ | 5 |
|
| 2016 | 6 |
| | 7 |
| | (2 | ) | | — |
| | 11 |
|
| 2015 | 10 |
| | 4 |
| | (8 | ) | | — |
| | 6 |
|
| Ameren Missouri: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2017 | $ | 7 |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
| | $ | 7 |
|
| 2016 | 7 |
| | 10 |
| | — |
| | 10 |
| | 7 |
|
| 2015 | 8 |
| | 13 |
| | — |
| | 14 |
| | 7 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2017 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2016 | — |
| | — |
| | — |
| | — |
| | — |
|
| 2015 | 1 |
| | — |
| | (1 | ) | | — |
| | — |
|
| Ameren Illinois: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2017 | $ | 12 |
| | $ | 17 |
| | $ | 7 |
| | $ | 24 |
| | $ | 12 |
|
| 2016 | 12 |
| | 22 |
| | 3 |
| | 25 |
| | 12 |
|
| 2015 | 13 |
| | 20 |
| | 5 |
| | 26 |
| | 12 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2017 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| 2016 | — |
| | — |
| | — |
| | — |
| | — |
|
| 2015 | 1 |
| | — |
| | (1 | ) | | — |
| | — |
|
| |
(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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2023, 2022, AND 2021 |
| (In millions) | | | | | | | | | | |
| Column A | | Column B | | Column C | | Column D | | Column E |
| Description | | Balance at
Beginning
of Period | | (1)
Charged to Costs
and Expenses | | (2) Charged to Other Accounts(a) | | Deductions(b) | | Balance at End
of Period |
| Ameren: | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | |
| 2023 | | $ | 31 | | | $ | 51 | | | $ | 5 | | | $ | 57 | | | $ | 30 | |
| 2022 | | 29 | | | 34 | | | 4 | | | 36 | | | 31 | |
| 2021 | | 50 | | | 9 | | | — | | | 30 | | | 29 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | |
| 2023 | | $ | 13 | | | $ | 11 | | | $ | — | | | $ | 12 | | | $ | 12 | |
| 2022 | | 13 | | | 9 | | | — | | | 9 | | | 13 | |
| 2021 | | 16 | | | 5 | | | — | | | 8 | | | 13 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Ameren Illinois: | | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | | |
| 2023 | | $ | 18 | | | $ | 40 | | | $ | 5 | | | $ | 45 | | | $ | 18 | |
| 2022 | | 16 | | | 25 | | | 4 | | | 27 | | | 18 | |
| 2021 | | 34 | | | 4 | | | — | | | 22 | | | 16 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
(a)Amounts associated with the allowance for doubtful accounts relate to the uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.
(b)Uncollectible accounts charged off, less recoveries.
| |
ITEM 16. | FORM 10-K SUMMARY |
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, 2017October 12, 2021 Form 8-K, Exhibit 3,3.1,
File No. 1-14756 |
| 3.8(ii) | Ameren Missouri | | December 18, 20142020 Form 8-K,
10-K, Exhibit 3.1,3.8(ii), File No. 1-2967 |
| 3.9(ii) | Ameren Illinois | | December 18, 20142020 Form 8-K,
10-K, Exhibit 3.2,3.9(ii), File No. 1-3672 |
| Instruments Defining Rights of Security Holders, Including Indentures |
| 4.1 | Ameren | | Exhibit 4.5, File No. 333-81774 |
| 4.2 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756 |
| 4.3 | Ameren | | November 24, 2015 Form 8-K, Exhibits 4.3 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 | | March 5, 2021 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 |
| 4.7 | Ameren | | November 18, 2021 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 |
| 4.8 | Ameren | | November 20, 2023 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 |
| 4.9 | Ameren | | December 21, 2023 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 |
| 4.10 | Ameren | | June 26, 2017 Form 8-K, Exhibit 4.1, File No. 1-14756 |
| 4.11 | Ameren | | 2021 Form 10-K, Exhibit 4.9, File No. 1-14756 |
| 4.12 | Ameren
Ameren Missouri | Indenture of Mortgage and Deed of Trust, dated June 15, 1937 (Ameren Missouri Mortgage), from Ameren Missouri to The Bank of New York Mellon, as successor trustee, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941 | Exhibit B-1, File No. 2-4940 |
4.54.13 | Ameren
Ameren Missouri | Ameren
Ameren Missouri
| | Exhibit 4.22, File No. 333-222108 |
4.64.14 | Ameren Ameren Missouri | | Exhibit 4.23, File No. 333-222108 |
4.74.15 | Ameren Ameren Missouri | | Exhibit 4.24, File No. 333-222108 |
4.84.16 | Ameren Ameren Missouri | | Exhibit 4.25, File No. 333-222108 |
4.94.17 | Ameren Ameren Missouri | | 1993 Form 10-K, Exhibit 4.8,
File No. 1-2967
|
4.104.18 | Ameren Ameren Missouri | | 2000 Form 10-K, Exhibit 4.1, 99,
File No. 1-2967 |
| | | | | | | | | | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
4.114.19 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.3,
File No. 1-2967
|
4.124.20 | Ameren Ameren Missouri | | March 11, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.134.21 | Ameren Ameren Missouri | | August 4, 2003 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.14 | Ameren
Ameren Missouri
| | March 31, 2004 Form 10-Q, Exhibit 4.1,
File No. 1-2967
|
|
| | | |
4.154.22 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.2,
File No. 1-2967
|
4.164.23 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.3,
File No. 1-2967
|
4.174.24 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.8,
File No. 1-2967
|
4.184.25 | Ameren Ameren Missouri | | September 23, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.19 | Ameren
Ameren Missouri
| | January 27, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.20 | Ameren
Ameren Missouri
| | July 21, 2005 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.214.26 | Ameren Ameren Missouri | | April 8, 2008 Form 8-K, Exhibit 4.7,
File No. 1-2967
|
4.22 | Ameren
Ameren Missouri
| | June 19, 2008 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.23 | Ameren
Ameren Missouri
| | March 23, 2009 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.244.27 | Ameren Ameren Missouri | | Exhibit 4.45, File No. 333-182258 |
4.254.28 | Ameren Ameren Missouri | | September 11, 2012 Form 8-K, Exhibit 4.4,
File No. 1-2967
|
4.264.29 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibit 4.5,
File No. 1-2967
|
4.274.30 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibit 4.5, File No. 1-2967 |
4.284.31 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibit 4.5, File No. 1-2967 |
4.294.32 | Ameren Ameren Missouri | | April 6, 2018 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.33 | Ameren Ameren Missouri | | March 6, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.34 | Ameren Ameren Missouri | | October 1, 2019 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.35 | Ameren Ameren Missouri | | March 20, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.36 | Ameren Ameren Missouri | | October 9, 2020 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.37 | Ameren
Ameren Missouri | | June 22, 2021 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.38 | Ameren
Ameren Missouri | | April 1, 2022 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.39 | Ameren Ameren Missouri | | March 13, 2023 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.40 | Ameren Ameren Missouri | | January 9, 2024 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.41 | Ameren Ameren Missouri | Loan Agreement, dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri, together with Indenture of Trust dated as of December 1, 1992, between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N.A. | 1992 Form 10-K, Exhibit 4.38,
File No. 1-2967
|
4.304.42 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.10,
File No. 1-2967
|
4.314.43 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q,
Exhibit 4.28, File No. 1-2967
|
4.324.44 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.11,
File No. 1-2967
|
4.334.45 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q,
Exhibit 4.29, File No. 1-2967
|
| | | | | | | | | | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
4.344.46 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.12,
File No. 1-2967
|
4.354.47 | Ameren Ameren Missouri | | September 30, 1998 Form 10-Q,
Exhibit 4.30, File No. 1-2967
|
4.364.48 | Ameren Ameren Missouri | | March 31, 2004 Form 10-Q, Exhibit 4.13,
File No. 1-2967
|
4.374.49 | Ameren Ameren Missouri | | August 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-2967
|
4.384.50 | Ameren Ameren Missouri | | Exhibit 4.48, File No. 333-182258 |
|
| | | |
4.394.51 | Ameren Ameren Missouri | | March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.404.52 | Ameren Ameren Missouri | | August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.41 | Ameren
Ameren Missouri
| | September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.42 | Ameren
Ameren Missouri
| | January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.43 | Ameren
Ameren Missouri
| | July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.444.53 | Ameren Ameren Missouri | | April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967 |
4.45 | Ameren
Ameren Missouri
| | June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.46 | Ameren
Ameren Missouri
| | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.474.54 | Ameren Ameren Missouri | | September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967 |
4.484.55 | Ameren Ameren Missouri | | April 4, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.494.56 | Ameren Ameren Missouri | | April 6, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.504.57 | Ameren
Ameren Missouri | Ameren
Ameren Missouri
| | June 23, 2016 Form 8-K, Exhibits 4.3, and 4.4, File No. 1-2967 |
4.514.58 | Ameren Ameren Missouri | | June 15, 2017 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
4.524.59 | Ameren Ameren Illinois | | Exhibit 4.4, File No. 333-59438 |
4.534.60 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.544.61 | Ameren Ameren Illinois | | Exhibit 4.17, File No. 333-166095 |
4.554.62 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
4.564.63 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
4.574.64 | Ameren Ameren Illinois | | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
4.58 | 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 |
4.594.65 | Ameren Ameren Illinois | | |
4.60 | Ameren
Ameren Illinois
| | |
|
| | | |
4.61 | Ameren
Ameren Illinois
| | |
4.62 | Ameren
Ameren Illinois
| | |
4.63 | Ameren
Ameren Illinois
| | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
4.64 | Ameren
Ameren Illinois
| | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
4.65 | Ameren
Ameren Illinois
| | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-27321-14756 |
| 4.66 | Ameren Ameren Illinois | | October 7, 2010 Form 8 K,8-K, Exhibit 4.1, File No. 1-3672 |
| 4.67 | Ameren Ameren Illinois | | September 30, 2011 Form 10-Q, Exhibit 4.1,
File No. 1-3672
|
| 4.68 | Ameren Ameren Illinois | | September 30, 2019 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
| 4.69 | Ameren Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-27321-14756 |
4.694.70 | Ameren Ameren Illinois | General Mortgage Indenture and Deed of Trust, dated as of November 1, 1992 between Ameren Illinois (successor in interest to Illinois Power Company) and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Ameren Illinois Mortgage) | 1992 Form 10-K, Exhibit 4(cc), File No. 1-3004 |
4.704.71 | Ameren Ameren Illinois | | June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004 |
4.71 | Ameren
Ameren Illinois
| | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 |
| | | | | | | | | | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
| 4.72 | Ameren Ameren Illinois | | April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004 |
4.73 | Ameren
Ameren Illinois
| | October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.74 | Ameren
Ameren Illinois
| | October 7, 2010 Form 8 K,8-K, Exhibit 4.9, File No. 1-3672 |
4.754.73 | Ameren Ameren Illinois | | Exhibit 4.78, File No. 333-182258 |
4.764.74 | Ameren Ameren Illinois | | August 20, 2012 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.774.75 | Ameren Ameren Illinois | | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.784.76 | Ameren Ameren Illinois | | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.794.77 | Ameren Ameren Illinois | | December 10, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.804.78 | Ameren Ameren Illinois | | December 14, 2015 Form 8-K, Exhibit 4.5, File No. 1-3672 |
4.814.79 | Ameren Ameren Illinois | | September 30, 2017 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
4.824.80 | Ameren Ameren Illinois | | November 28, 2017 Form 8-K, Exhibit 4.2, File No. 1-3672 |
4.834.81 | Ameren Ameren Illinois | | May 22, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.82 | Ameren Ameren Illinois | | November 15, 2018 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.83 | Ameren Ameren Illinois | | September 30, 2019 Form 10-Q, Exhibit 4.3, File No. 1-3672 |
| 4.84 | Ameren
Ameren Illinois | | November 26, 2019 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.85 | Ameren
Ameren Illinois | | 2019 Form 10-K, Exhibit 4.79, File No. 1-3672 |
| 4.86 | Ameren
Ameren Illinois | | November 23, 2020 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.87 | Ameren
Ameren Illinois | | June 29, 2021 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.88 | Ameren
Ameren Illinois | | August 29, 2022 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.89 | Ameren
Ameren Illinois | | November 22, 2022 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.90 | Ameren Ameren Illinois | | May 31, 2023 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.91 | Ameren
Ameren Illinois | | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-30041-14756 |
4.844.92 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | October 7, 2010 Form 8 K,8-K, Exhibit 4.5, File No. 1-14756 |
4.854.93 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
4.864.94 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | Exhibit 4.83, File No. 333-182258 |
|
| 4.95 | | | |
4.87Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | April 8, 2008September 30, 2019 Form 8-K,10-Q, Exhibit 4.4, File No. 1-30041-3672 |
4.884.96 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.89 | Ameren
Ameren Illinois
| | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.90 | Ameren
Ameren Illinois
| | December 10, 2013 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.914.97 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | June 30, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.924.98 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 10, 2014 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
4.934.99 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 14, 2015 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
| | | | | | | | | | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
4.944.100 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 6, 2016 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3672 |
Material Contracts4.101 | Ameren
Ameren Illinois | | September 30, 2019 Form 10-Q, Exhibits 4.5 and 4.6, File No. 1-3672 |
10.14.102 | Ameren | | 2021 Form 10-K, Exhibit 4.98, File No. 1-14756 |
| 4.103 | Ameren Missouri | | 2021 Form 10-K, Exhibit 4.99, File No. 1-14756 |
| 4.104 | Ameren Illinois | | 2021 Form 10-K, Exhibit 4.100, File No. 1-14756 |
| Material Contracts |
| 10.1 | Ameren Companies | | June 30, 2015 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
| 10.2 | Ameren
Ameren Missouri | Ameren
Ameren Missouri
| | December 6, 2022 Form 8-K, Exhibit 10.1, File No. 1-2967 |
| 10.3 | Ameren Ameren Missouri | | December 8, 2016August 3, 2023 Form 8-K,10-Q, Exhibit 10.1, File No. 1-2967 |
10.310.4 | Ameren
Ameren Illinois | Ameren
Ameren Illinois
| | December 8, 20166, 2022 Form 8-K, Exhibit 10.2, File No. 1-3672 |
10.410.5 | Ameren Ameren Illinois | | August 3, 2023 Form 10-Q, Exhibit 10.2, File No. 1-3672 |
| 10.6 | Ameren | | 2021 Form 10-K, Exhibit 10.6, File No. 1-14756 |
10.510.7 | Ameren | | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
10.610.8 | Ameren | | 2009 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.710.9 | Ameren | | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.810.10 | Ameren | | | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.910.11 | Ameren Companies | | 20102019 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1010.12 | Ameren Companies | | 20142020 Form 10-K, Exhibit 10.13,10.16, File No. 1-14756 |
10.1110.13 | Ameren Companies | | 20152021 Form 10-K, Exhibit 10.13,10.16, File No., 1-14756 |
| 10.14 | Ameren Companies | | 2022 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1210.15 | Ameren Companies | | | 2016 Form 10-K, Exhibit 10.13, File No. 1-14756
10.1310.16 | Ameren Companies | | |
10.14 | Ameren Companies | | 20142020 Form 10-K, Exhibit 10.17,10.23, File No. 1-14756 |
10.1510.17 | Ameren Companies | | 20152021 Form 10-K, Exhibit 10.17,10.20, File No. 1-14756 |
10.1610.18 | Ameren Companies | | 20162022 Form 10-K, Exhibit 10.17,10.21, File No. 1-14756 |
10.1710.19 | Ameren Companies | | |
10.1810.20 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 |
10.1910.21 | Ameren Companies | | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.2010.22 | Ameren Companies | | |
|
| 10.23 | | | |
10.21 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.22 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.23 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.24 | Ameren Companies | | 2017 Form 10-K, Exhibit 10.24, File No. 1-14756 |
10.2510.24 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.27, File No. 1-14756 |
| 10.25 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.32, File No. 1-14756 |
| 10.26 | Ameren Companies | | 2020 Form 10-K, Exhibit 10.33, File No. 1-14756 |
| | | | | | | | | | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
| 10.27 | Ameren Companies | | 2021 Form 10-K, Exhibit 10.30, File No. 1-14756 |
| 10.28 | Ameren Companies | | 2022 Form 10-K, Exhibit 10.31, File No. 1-14756 |
| 10.29 | Ameren Companies | | |
| 10.30 | Ameren Companies | | Exhibit 99, File No. 333-196515 |
10.2610.31 | Ameren Companies | | 2014 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.27 | Ameren Companies | | 2015 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.28 | Ameren Companies | | 2016 Form 10-K, Exhibit 10.31, File No. 1-14756 |
10.29 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.3010.32 | Ameren Companies | | December 13, 2017 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.3110.33 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.34, File No. 1-14756 |
| 10.34 | Ameren Companies | | 2018 Form 10-K, Exhibit 10.35, File No. 1-14756 |
| 10.35 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.41, File No. 1-14756 |
| 10.36 | Ameren Companies | | 2019 Form 10-K, Exhibit 10.42, File No. 1-14756 |
| 10.37 | Ameren Companies | | 2020 Form 10-K, Exhibit 10.44, File No. 1-14756 |
| 10.38 | Ameren Companies | | 2020 Form 10-K, Exhibit 10.45, File No. 1-14756 |
| 10.39 | Ameren Companies | | 2021 Form 10-K, Exhibit 10.42, File No. 1-14756 |
| 10.40 | Ameren Companies | | 2021 Form 10-K, Exhibit 10.43, File No. 1-14756 |
| 10.41 | Ameren Companies | | May 13, 2022 Form 8-K, Exhibit 10.1, File No. 1-14756 |
| 10.42 | Ameren Companies | | 2022 Form 10-K, Exhibit 10.45, File No. 1-14756 |
| 10.43 | Ameren Companies | | 2022 Form 10-K, Exhibit 10.46, File No. 1-14756 |
| 10.44 | Ameren Companies | | 2022 Form 10-K, Exhibit 10.47, File No. 1-14756 |
| 10.45 | Ameren Companies | | |
| 10.46 | Ameren Companies | | |
| 10.47 | Ameren Companies | | |
| 10.48 | Ameren Companies | | |
| 10.49 | Ameren Companies | | December 13, 20172018 Form 8-K,10-K, Exhibit 10.3,10.36, File No. 1-14756 |
10.3210.50 | Ameren Companies | | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.3310.51 | Ameren Companies | | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 |
Statement re: Computation of Ratios10.52 | Ameren Companies | | |
12.110.53 | Ameren Companies | | |
12.210.54 | Ameren MissouriCompanies | | |
12.310.55 | Ameren IllinoisCompanies | | |
| Subsidiaries of the Registrant |
| 21.1 | Ameren Companies | | |
| Consent of Experts and Counsel |
| | | | | | | | | | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
| 23.1 | Ameren | | |
| 23.2 | Ameren Missouri | | |
| 23.3 | Ameren Illinois | | |
| Power of Attorney |
| 24.1 | Ameren | | |
| 24.2 | Ameren Missouri | | |
| 24.3 | Ameren Illinois | | |
| Rule 13a-14(a)/15d-14(a) Certifications |
| 31.1 | Ameren | | |
| 31.2 | Ameren | | |
| 31.3 | Ameren Missouri | | |
| 31.4 | Ameren Missouri | | |
|
| 31.5 | | | |
31.5 | Ameren Illinois | | |
| 31.6 | Ameren Illinois | | |
| Section 1350 Certifications |
| 32.1 | Ameren | | |
| 32.2 | Ameren Missouri | | |
| 32.3 | Ameren Illinois | | |
Additional ExhibitsPolicy Relating to Recovery of Erroneously Awarded Compensation |
99.197.1 | Ameren Companies | | |
| Additional Exhibits |
| 99.1 | Ameren Companies | | 20132022 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.
| | | | | | | | | | | | | | |
| | | | |
| | AMEREN CORPORATION (registrant) |
| | | |
| Date: | February 29, 2024 | By | | /s/ Martin J. Lyons, Jr. |
| Date: | February 28, 2018 | By | /s/ Warner L. Baxter |
| | | | Warner L. Baxter
Martin J. Lyons, Jr.
Chairman, President, and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. |
| | | | | |
/s/ Warner L. Baxter | | Chairman, President and Chief Executive Officer, and Director (Principal Executive Officer) | | February 28, 2018 |
Warner L. Baxter | | | | |
| | | |
/s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
| | February 28, 2018 |
Martin J. Lyons, Jr. | | | | |
| | | | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 2018 |
Bruce A. Steinke | | | | |
| | | | | |
* | | Director | | February 28, 2018 |
Catherine S. Brune | | | | |
| | | | | |
* | | Director | | February 28, 2018 |
J. Edward Coleman | | | | |
| | | |
* | | Director | | February 28, 2018 |
Ellen M. Fitzsimmons | | | | |
| | | |
* | | Director | | February 28, 2018 |
Rafael Flores | | | | |
| | | | | |
* | | Director | | February 28, 2018 |
Walter J. Galvin | | | | |
| | | |
* | | Director | | February 28, 2018 |
Richard J. Harshman | | | | |
| | | |
* | | Director | | February 28, 2018 |
Gayle P. W. Jackson | | | | |
| | | |
* | | Director | | February 28, 2018 |
James C. Johnson | | | | |
| | | |
* | | Director | | February 28, 2018 |
Steven H. Lipstein | | | | |
| | | |
* | | Director | | February 28, 2018 |
Stephen R. Wilson | | | | |
| | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
|
| | | | |
| | UNION ELECTRIC COMPANY (registrant)
|
| | | |
Date: | February 28, 2018 | 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/ Michael L. MoehnMartin J. Lyons, Jr. | | Chairman, President, and President,Chief Executive Officer, and Director (Principal Executive Officer) | | February 28, 201829, 2024 |
Michael L. Moehn | | | | |
| | | |
/s/ Martin J. Lyons, Jr.
| | | | |
| | | |
| /s/ Michael L. Moehn | | Senior Executive Vice President and Chief Financial Officer and Director (Principal
(Principal Financial Officer) | | February 28, 201829, 2024 |
Martin J. Lyons, Jr.Michael L. Moehn | | | | | | |
| | | | | |
/s/ BruceTheresa A. Steinke Shaw | | Senior Vice President, Finance, and Chief Accounting Officer (Principal Accounting Officer) | | February 28, 201829, 2024 |
BruceTheresa A. SteinkeShaw | | | | |
| | | | | |
| * | | Director | | February 29, 2024 |
| Cynthia J. Brinkley | | | | |
| | | | | |
| * | | Director | | | February 29, 2024 |
*Catherine S. Brune | | | | |
| | | | | |
| * | | Director | | February 28, 201829, 2024 |
| J. Edward Coleman | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Ward H. Dickson | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Noelle K. Eder | | | | |
| | | | | |
| * | | Director | | February 29, 2024 |
| Ellen M. Fitzsimmons | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Rafael Flores | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Kimberly J. Harris | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Richard J. Harshman | | | | |
| | | | | |
| * | | Director | | February 29, 2024 |
| Craig S. Ivey | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| James C. Johnson | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Steven H. Lipstein | | | | |
| | | | | |
| * | | Director | | February 29, 2024 |
| Leo S. Mackay, Jr. | | | | |
| | | | | |
| *By | /s/ Michael L. Moehn | | | | February 29, 2024 |
| Michael L. Moehn | | | | |
| Attorney-in-Fact | | | | |
| | | | | | | | | | | | | | |
| | UNION ELECTRIC COMPANY (registrant) |
| | | |
| Date: | February 29, 2024 | By | | /s/ Mark C. Birk | | | | |
| | | | Mark C. Birk
Chairman and President |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
| | | | | | | | | | | | | | | | | |
| /s/ Mark C. Birk | | Chairman and President, and Director
(Principal Executive Officer) | | February 29, 2024 |
*Mark C. Birk | | | | |
| | | |
/s/ Michael L. Moehn | | Senior Executive Vice President and Chief Financial Officer, and Director
(Principal Financial Officer) | | February 29, 2024 |
| Michael L. Moehn | | | | |
| | | |
| /s/ Theresa A. Shaw | | Senior Vice President, Finance, and Chief Accounting Officer
(Principal Accounting Officer) | | February 28, 201829, 2024 |
| Theresa A. Shaw | | | | |
| | | | | |
| * | | Director | | February 29, 2024 |
| Bhavani Amirthalingam | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Fadi M. Diya | | | | |
| | | |
| * | | Director | | February 29, 2024 |
| Chonda J. Nwamu | | | | |
| | | |
| *By | /s/ Michael L. Moehn | | | | February 29, 2024 |
| *Michael L. Moehn | | | Director | | February 28, 2018
| Gregory L. NelsonAttorney-in-Fact | | | | |
| | | |
* | | Director | | February 28, 2018 |
David N. Wakeman | | | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
| | | | | | | | | | | | | | |
| | | | |
| | AMEREN ILLINOIS COMPANY (registrant) |
| | | | |
| Date: | February 29, 2024 | By | | /s/ Leonard P. Singh |
| Date: | February 28, 2018 | By | /s/ Richard J. Mark |
| | | | Richard J. Mark
Leonard P. Singh
Chairman and President |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
| | | | | | | | | | | | | | | | | |
| | | | | |
/s/ Richard J. MarkLeonard P. Singh | | Chairman and President, and Director (Principal
(Principal Executive Officer) | | February 28, 201829, 2024 |
Richard J. MarkLeonard P. Singh | | | | |
| | | |
/s/ Martin J. Lyons, Jr.Michael L. Moehn | | Senior Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | February 28, 201829, 2024 |
Martin J. Lyons, Jr.Michael L. Moehn | | | | |
| | | |
/s/ BruceTheresa A. SteinkeShaw | | Senior Vice President, Finance, and Chief Accounting Officer, and Director (Principal Accounting Officer) | | February 28, 201829, 2024 |
BruceTheresa A. SteinkeShaw | | | | |
| | | | | |
| * | | Director | | February 29, 2024 |
| Chonda J. Nwamu | | | | |
| | | |
| * | | Director | | | February 29, 2024 |
*Patrick E. Smith | | | | |
| | | | | |
| | | | |
| | | | |
| | | |
| *By | Director/s/ Michael L. Moehn | | | | February 28, 201829, 2024 |
| Craig D. NelsonMichael L. Moehn | | | | |
| Attorney-in-Fact | | | |
| * | Director | | February 28, 2018 |
Gregory L. Nelson | | | | |
| | | | | |
* | | Director | | February 28, 2018 |
David N. Wakeman | | | | |
| | | |
*By | /s/ Martin J. Lyons, Jr. | | | | February 28, 2018 |
| Martin J. Lyons, Jr. | | | | |
| Attorney-in-Fact | | | | |
