AMEREN CORP - Annual Report: 2019 (Form 10-K)

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regulatory, judicial, or legislative actions, and any changes in regulatory policies and ratemaking determinations, that may change regulatory recovery mechanisms, such as those that may result from a rehearing of the November 2019 FERC order determining the allowed base ROE under the MISO tariff, the Notices of Inquiry issued by the FERC in March 2019, Ameren Missouri’s electric service regulatory rate review filed with the MoPSC in July 2019, and Ameren Illinois’ natural gas delivery service regulatory rate review filed with the ICC in February 2020;

•	the effect and continuation of Ameren Illinois’ election to participate in performance-based formula ratemaking frameworks for its electric distribution service and its participation in electric energy-efficiency programs, including the direct relationship between Ameren Illinois’ ROE and the 30-year United States Treasury bond yields;

•	the effect on Ameren Missouri of any customer rate caps pursuant to Ameren Missouri’s election to use the PISA, including an extension of use beyond 2023, if requested by Ameren Missouri and approved by the MoPSC;

•	the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, and energy policies;

•	the effects of changes in federal, state, or local tax laws, regulations, interpretations, or rates, including as a result of amendments or technical corrections to the TCJA, and challenges to the tax positions taken by the Ameren Companies, if any;

•	the effects on demand for our services resulting from technological advances, including advances in customer energy efficiency, energy storage, and private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;

•	the effectiveness of Ameren Missouri’s customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA programs;

•	Ameren Illinois’ ability to achieve the performance standards applicable to its electric distribution business and the FEJA electric customer energy-efficiency goals and the resulting impact on its allowed ROE;

•	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 ROEs;

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the cost and availability of fuel, such as low-sulfur coal, natural gas, and enriched uranium, used to produce electricity; the cost and availability of purchased power, zero emission credits, renewable energy credits, and natural gas for distribution; and the level and volatility of future market prices for such commodities and credits, including our ability to recover the costs for such commodities and credits and our customers’ tolerance for any related price increases;

•	disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from the one NRC-licensed supplier of Ameren Missouri’s Callaway Energy Center’s assemblies;

•	the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy Ameren Missouri’s energy sales;

•	the effectiveness of our risk management strategies and our use of financial and derivative instruments;

•	the ability to obtain sufficient insurance, including insurance for Ameren Missouri’s nuclear and coal-fired energy centers, or, in the absence of insurance, the ability to recover uninsured losses from our customers;

•	the impact of cyberattacks on us or our suppliers, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information;

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•	business and economic conditions, including their impact on interest rates, collection of our receivable balances, and demand for our products;

•	disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;

•	the actions of credit rating agencies and the effects of such actions;

•	the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments;

•	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 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, and decommissioning costs;

•	Ameren Missouri’s ability to recover the remaining investment, if any, and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs;

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the impact of current environmental laws and new, more stringent, or changing requirements, including those related to NSR, CO2 and the implementation of the Affordable Clean Energy Rule, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our operating costs or investment requirements, result in an impairment of our assets, cause us to sell our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;

•	the impact of complying with renewable energy standards in Missouri and Illinois and with the zero emission standard in Illinois;

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Ameren Missouri’s ability to acquire wind and other renewable energy generation facilities and recover its cost of investment and related return in a timely manner, which is affected by the ability to obtain all necessary project approvals; the ability of developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary materials and equipment, among other things; the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind and solar generation technologies; and Ameren Missouri’s ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost for each facility;

•	the effect of a possible cash or net share settlement of the forward sale agreement relating to common stock in the event of changes to Ameren’s expected cash requirements;

•	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;

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the impact of negative opinions of us or our utility services that our customers, investors, legislators, or regulators may have or develop, which could result from a variety of factors, including failures in system reliability, failure to implement our investment plans or to protect sensitive customer information, increases in rates, negative media coverage, or concerns about environmental, social, and/or governance practices;

•	the impact of adopting new accounting guidance;

•	the effects of strategic initiatives, including mergers, acquisitions, and divestitures;

•	legal and administrative proceedings; and

•	acts of sabotage, war, terrorism, or other intentionally disruptive acts.

ITEM 1.	BUSINESS

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•	Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.

•	Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.

•	ATXI operates a FERC rate-regulated electric transmission business in the MISO.

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(a)	The Ameren Transmission segment also includes allocated Ameren (parent) interest charges, Ameren Transmission Company, LLC, ATX East, LLC, and ATX Southwest, LLC.

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(a)	Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and natural gas purchased for resale for natural gas delivery service, and intercompany eliminations.

(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. Ameren Missouri has a pending electric service regulatory rate review it filed with the MoPSC in July 2019. For additional information regarding this regulatory rate review, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(c)	This rate order specified that an implicit ROE was within a range of 9.2% to 9.7%. This rate order did not specify a percent of common equity or rate base. The ROE used for allowance for equity funds used during construction is 9.53%.

(d)	This rate order specified that an implicit ROE was within a range of 9.4% to 9.95%. This rate order did not specify rate base.

(e)

Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. This rate order was based on 2018 actual costs, expected net plant additions for 2019, and the annual average of the monthly yields during 2018 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ 2020 electric distribution delivery service revenues will be based on its 2020 actual recoverable costs, rate base, common equity percentage, and an allowed ROE, as calculated under the IEIMA’s performance-based formula ratemaking framework.

(f)	This rate order was based on a 2019 future test year. Ameren Illinois has a pending natural gas delivery service regulatory rate review it filed with the ICC in February 2020. For additional information regarding this regulatory rate review, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(g)

Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking framework based on each year’s forecasted information. The 10.38% return, which includes a 50 basis points incentive adder for participation in an RTO, is based on the FERC’s November 2019 order. For additional information regarding this order and related requests for rehearing, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report. The ROE applicable to investments in ATXI’s Mark Twain project includes an additional 50 basis point incentive adder related to the unique nature of risks involved in completing the project.

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•	the potential for changes in laws, regulations, enforcement efforts, and policies at the state and federal levels;

•	corporate tax law changes, as well as additional interpretations, regulations, amendments, or technical corrections that affect the amount and timing of income tax payments, reduce or limit the ability to claim certain deductions and use carryforward tax benefits, or result in rate base reductions;

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•	cybersecurity risks, including the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the theft or inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information;

•	political, regulatory, and customer resistance to higher rates;

•	the potential for more intense competition in generation, supply, and distribution, including new technologies and their declining costs;

•	the impact and effectiveness of vegetation management programs;

•	net metering rules and other changes in existing regulatory frameworks and recovery mechanisms to address the allocation of costs to customers who own generation resources that enable them both to sell power to us and to purchase power from us through the use of our transmission and distribution assets;

•	legislation or programs to encourage or mandate energy efficiency, energy conservation, and renewable sources of power, and the lack of consensus as to how those programs should be paid for;

•	pressure on customer growth and usage in light of economic conditions, distributed generation, energy storage, technological advances, and energy-efficiency or conservation initiatives;

•	changes in the structure of the industry as a result of changes in federal and state laws, including the formation and growth of independent transmission entities;

•	changes in the allowed ROE on FERC-regulated electric transmission assets;

•	the availability of fuel and fluctuations in fuel prices;

•	the availability of materials and equipment, and the potential disruptions in supply chains resulting from the international public health emergency associated with the novel coronavirus (COVID-19);

•	the availability of a skilled work force, including retaining the specialized skills of those who are nearing retirement;

•	regulatory lag;

•	the influence of macroeconomic factors on yields of United States Treasury securities and on the allowed ROE provided by regulators;

•	higher levels of infrastructure and technology investments and adjustments to customer rates associated with the TCJA that are expected to result in negative or decreased free cash flow, which is defined as cash flows from operating activities less cash flows from investing activities and dividends paid;

•	the demand for access to renewable energy generation at rates acceptable to customers;

•	public concerns about the siting of new facilities, and challenges that members of the public can assert against applications for governmental permits and other approvals required to site and build new facilities that can result in significant cost increases, delays and denial of the permits and approvals by the regulators;

•	complex new and proposed environmental laws including statutes, regulations, and requirements, such as air and water quality standards, mercury emissions standards, CCR management requirements, and potential CO2 limitations, which may reduce the frequency at which electric generating units are dispatched based upon their CO2 emissions;

•	public concerns about the potential environmental impacts from the combustion of fossil fuels and the use of natural gas;

•	certain investors’ concerns about investing in utility companies that have coal-fired generation assets and increasing scrutiny of environmental, social, and governance practices;

•	aging infrastructure and the need to construct new power generation, transmission, and distribution facilities, which have long time frames for completion, with limited long-term ability to predict power and commodity prices and regulatory requirements;

•	public concerns about nuclear generation, decommissioning, and the disposal of nuclear waste; and

•	consolidation of electric and natural gas utility companies.

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(a)	Sales for which power was supplied by Ameren Illinois as well as alternative retail electric suppliers. In 2019, 2018, and 2017, Ameren Illinois procured power on behalf of its customers for 22%, 23%, and 23%, respectively, of its total kilowatthour sales.

(b)	Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information.

(c)	Includes $62 million, $53 million, and $42 million in 2019, 2018, and 2017, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution.

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ITEM 1A.	RISK FACTORS

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•	facility shutdowns due to operator error, or a failure of equipment or processes;

•	longer-than-anticipated maintenance outages;

•	failures of equipment that can result in unanticipated liabilities or unplanned outages;

•	aging infrastructure that may require significant expenditures to operate and maintain;

•	lack of adequate water required for cooling plant operations;

•	labor disputes;

•	disruptions in the delivery of electricity to our customers;

•	suppliers and contractors who do not perform as required under their contracts;

•	failure of other operators’ facilities and the effect of that failure on our electric system and customers;

•	inability to comply with regulatory or permit requirements, including those relating to environmental laws;

•	handling, storage, and disposition of CCR;

•	unusual or adverse weather conditions or other natural disasters, including severe storms, droughts, floods, tornadoes, earthquakes, sustained high temperatures, solar flares, and electromagnetic pulses;

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•	the occurrence of catastrophic events such as fires, explosions, acts of sabotage or terrorism, pandemic health events, or other similar events;

•	accidents that might result in injury or loss of life, extensive property damage, or environmental damage;

•	ineffective vegetation management programs;

•	cybersecurity risks, including loss of operational control of Ameren Missouri’s energy centers and our transmission and distribution systems and loss of data, including sensitive customer, employee, financial, and operating system information, through insider or outsider actions;

•	limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities;

•	inability to implement or maintain information systems;

•	failure to keep pace with and the ability to adapt to rapid technological change; and

•	other unanticipated operations and maintenance expenses and liabilities.

•	potential harmful effects on the environment and human health resulting from radiological releases associated with the operation of nuclear facilities and the storage, handling, and disposal of radioactive materials;

•	continued uncertainty regarding the federal government’s plan to permanently store spent nuclear fuel and, as a result, the need to provide for long-term storage of spent nuclear fuel at the Callaway Energy Center;

•	limitations on the amounts and types of insurance available to cover losses that might arise in connection with the Callaway Energy Center or other United States nuclear facilities;

•	uncertainties about contingencies and retrospective premium assessments relating to claims at the Callaway Energy Center or any other United States nuclear facilities;

•	public and governmental concerns about the safety and adequacy of security at nuclear facilities;

•	limited availability of fuel supply and our reliance on licensed fuel assemblies from the one NRC-licensed supplier of Callaway Energy Center’s assemblies;

•	costly and extended outages for scheduled or unscheduled maintenance and refueling;

•	uncertainties about the technological and financial aspects of decommissioning nuclear facilities at the end of their licensed lives;

•	the adverse effect of poor market performance and other economic factors on the asset values of nuclear decommissioning trust funds and the corresponding increase, upon MoPSC approval, in customer rates to fund the estimated decommissioning costs; and

•	potential adverse effects of a natural disaster, acts of sabotage or terrorism, including a cyber attack, or any accident leading to a radiological release.

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•	Conservation and energy-efficiency programs. Missouri allows for conservation and energy-efficiency programs that are designed to reduce energy demand.

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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. 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 growth or contraction within Ameren Missouri’s service territories could reduce energy demand.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

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ITEM 2.	PROPERTIES

(a)	Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid.

(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 all generating capacity by 2045.

(d)	The Sioux Energy Center is scheduled to retire all generating capacity by 2033.

(e)	The Meramec Energy Center is scheduled for retirement by 2022.

(f)	The operating licenses for the Callaway, Osage, and Taum Sauk energy centers expire in 2044, 2047, and 2044, respectively.

(g)	There are economic development arrangements applicable to these CTs, as discussed below.

(h)	These CTs have the capability to operate on either oil or natural gas (dual fuel).

(i)	Two of its three units are steam-powered.

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(a)	ATXI owns 505 miles of transmission lines not reflected in this table.

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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, Ameren Missouri’s Lambert and BJC energy centers, certain substations, and most transmission and distribution lines and natural gas mains are situated on lands occupied under leases, easements, franchises, licenses, or permits. The United States or the state of Missouri may own or may have paramount rights with respect to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which certain of Ameren Missouri’s energy centers and other properties are located.

•	The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of Ameren Missouri’s Keokuk Energy Center is located.

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ITEM 3.	LEGAL PROCEEDINGS

•	Ameren Missouri’s electric service regulatory rate review filed with the MoPSC in July 2019;

•	Ameren Illinois’ natural gas delivery service regulatory rate review filed with the ICC in February 2020;

•	the ICC’s QIP prudence review requested by Ameren Illinois in March 2019;

•	Ameren and the MISO transmission owner’s request for a rehearing of the November 2019 FERC order related to the November 2013 complaint case;

•	the March 2019 FERC separate Notices of Inquiry regarding its allowed ROE policy and its transmission incentives policy;

•	litigation against Ameren Missouri with respect to NSR and the Clean Air Act; and

•	remediation matters associated with former MGP sites of Ameren Illinois.

ITEM 4.	MINE SAFETY DISCLOSURES

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ITEM 5.	MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES

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ITEM 6.	SELECTED FINANCIAL DATA

(a)

Amounts have not been revised to reflect the adoption of accounting guidance on revenue from contracts with customers, effective for the Ameren Companies as of January 1, 2018, and are not comparative. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of our Form 10-K for the year ended December 31, 2018, filed with the SEC on February 26, 2019, for additional information.

(b)	Includes a $69 million provision recorded for all of the previously capitalized construction and operating license costs relating to the cancelled second nuclear unit at Ameren Missouri’s Callaway Energy Center.

(c)	Includes an increase to income tax expense of $154 million and $32 million as a result of the TCJA at Ameren and Ameren Missouri, respectively. See Note 12 – Income Taxes under Part II, Item 8, of this report for additional information.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

•	Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.

•	Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.

•	ATXI operates a FERC rate-regulated electric transmission business in the MISO.

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•	increased Ameren Transmission and Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily as a result of additional rate base investment and Ameren Illinois Electric Distribution energy-efficiency investments (14 cents per share);

•	decreased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, excluding the Callaway Energy Center’s scheduled refueling and maintenance outage costs, primarily because of changes in the cash surrender value of company-owned life insurance (10 cents per share);

•	increased other income, net, primarily because charitable donations returned to more normal levels at Ameren Missouri and Ameren (parent), and increased non-service cost components of net periodic benefit income (9 cents per share);

•	the recognition of MEEIA 2013 and MEEIA 2016 performance incentives (8 cents per share);

•	the absence of a noncash charge to earnings for the revaluation of deferred taxes recorded in 2018 related to the TCJA (5 cents per share);

•	a decrease in the effective income tax rate at Ameren (parent), primarily because of an increase in the income tax benefit related to stock-based compensation (5 cents per share);

•	an increase in base rates at Ameren Illinois Natural Gas pursuant to the ICC’s November 2018 natural gas rate order (2 cents per share);

•	decreased net financing costs at Ameren Missouri, primarily as a result of the regulatory deferral of interest expense pursuant to the PISA and lower interest rates, partially offset by lower levels of the allowance for funds used during construction (2 cents per share);

•	increased Ameren Transmission earnings resulting from the net impact of the November 2019 FERC order addressing the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff (2 cents per share); and

•	increased Ameren Illinois Natural Gas earnings under the QIP rider resulting from investments in qualifying infrastructure (1 cent per share).

•	decreased electric retail sales at Ameren Missouri, primarily because of milder summer temperatures experienced in 2019 (estimated at 26 cents per share);

•	increased other operation and maintenance expenses related to the Callaway Energy Center’s scheduled refueling and maintenance outage that was completed in May 2019, as compared with no refueling and maintenance outage in 2018 (9 cents per share);

•	increased taxes other than income taxes at Ameren Missouri due to higher property taxes (5 cents per share);

•	increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Illinois Natural Gas and Ameren Missouri, primarily because of additional property, plant, and equipment (5 cents per share);

•	decreased Ameren Illinois Electric Distribution earnings under formula ratemaking because of a lower recognized ROE (4 cents per share);

•	increased transmission services charges at Ameren Missouri (3 cents per share); and

•	increased weighted-average basic common shares outstanding (3 cents per share).

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(a)	Includes other/intersegment eliminations of $(29) million and $(27) million in 2019 and 2018, respectively.

(a)	Includes other/intersegment eliminations of $(2) million and $(1) million in 2019 and 2018, respectively.

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(a)	Includes an increase in transmission margins of $21 million in 2019, compared with 2018, at Ameren Illinois.

(b)	Represents the estimated variation resulting primarily from changes in cooling and heating degree days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.

(c)	For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates.

(d)	Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of income, resulting in no change to electric and natural gas margins.

(e)	Offsetting expense increases or decreases are reflected in “Other operations and maintenance,” “Depreciation and amortization,” or in “Taxes other than income taxes,” within the “Operating Expenses” section of the statement of income. These items have no overall impact on earnings.

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Summer temperatures were milder as cooling degree days decreased 13%, and winter temperatures were warmer as heating degree days decreased 4%. The aggregate effect of weather decreased margins by an estimated $97 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$118 million) and the effect of weather (estimate) on fuel and purchased power (+$21 million) in the table above.

•	The reduction of customer rates in accordance with the TCJA provisions in Missouri law, which decreased revenues an estimated $39 million.

•	Revenues from other cost recovery mechanisms due primarily to gross receipts taxes, which decreased margins $16 million. See Taxes Other Than Income Taxes in this section for the related offsetting decrease in gross receipts tax.

•	A reduction in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which decreased revenues $11 million.

•	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 $9 million.

•	The MEEIA 2013 and 2016 performance incentives, which increased revenues $26 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 and MEEIA 2016 performance incentives.

•	Net energy costs increased margins $6 million as a result of lower energy costs (+$146 million), largely offset by a reduction in off-system sales revenue (-$140 million). The decrease in energy costs is the result of lower fuel costs and decreased generation volumes, while the reduction in off-system sales revenue is primarily due to generation facility outages.

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Excluding the estimated effects of weather and MEEIA customer energy-efficiency programs, electric revenues increased an estimated $5 million, primarily due to an increase in the average retail price per kilowatthour due to changes in customer usage patterns. While the MEEIA customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins ensured that electric margins were not affected.

•	Revenues increased $12 million due to return on increased energy-efficiency program investments (+$2 million) and recovery of associated expenses (+$10 million) under formula ratemaking.

•	Increased margins due to higher rate base (+$10 million) and higher recoverable expenses (+$5 million), partially offset by lower recognized ROE (-$10 million) due to a 53 basis point decrease in the annual average of the monthly 30-year United States Treasury bond yields under formula ratemaking. The sum of these changes collectively increased margins $5 million.

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•	Higher natural gas base rates as a result of the November 2018 natural gas rate order, which increased revenues $8 million.

•	Revenues from QIP recoveries due to additional investment in qualified natural gas infrastructure, which increased margins $7 million.

•	A software licensing agreement with Ameren Missouri, which increased revenues $5 million. See Note 13 – Related-party Transactions under Software Licensing Agreement for information regarding this transaction.

(a)	Includes other/intersegment eliminations of $(6) million and $(10) million in 2019 and 2018, respectively.

•	The cash surrender value of company-owned life insurance increased $19 million, primarily because of favorable market conditions.

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•	Nonnuclear energy center operations and maintenance costs decreased $15 million, primarily because of higher-than-normal scheduled outages and increased routine maintenance work in 2018.

•	Power restoration assistance provided to other utilities decreased $11 million.

•	Callaway Energy Center operations and maintenance costs increased $28 million, primarily because of the refueling and maintenance outage that was completed in May 2019. The previous Callaway Energy Center refueling and maintenance outage took place in the fourth quarter of 2017.

•	Employee benefit costs increased $3 million because of higher medical costs.

•	Power restoration assistance provided to other utilities decreased $9 million.

•	The cash surrender value of company-owned life insurance increased $8 million, primarily because of favorable market conditions.

•	Bad debt costs, which are recoverable through a rider, decreased $6 million, primarily because of improved collections experience.

•	Meter reading costs decreased $4 million, primarily because of increased automated meter deployment.

•	Amortization of regulatory assets associated with energy-efficiency program investments increased $8 million.

•	Environmental remediation costs, which are recoverable through a rider, increased $6 million, primarily because of increased remediation efforts.

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(a)	Includes other/intersegment eliminations of $4 million and $4 million in 2019 and 2018, respectively.

(a)	Includes $4 million and $4 million at Ameren Transmission in 2019 and 2018, respectively, and other/intersegment eliminations of $8 million and $9 million in 2019 and 2018, respectively.

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•	A $36 million decrease in pension and postretirement benefit plan contributions.

•	A net $15 million increase in collateral received from counterparties, primarily resulting from changes in the market prices of power and natural gas, changes in contracted commodity volumes, and increases resulting from Ameren Illinois’ renewable energy contracts entered into pursuant to the FEJA.

•	A $14 million decrease in payments to contractors for electric distribution maintenance costs, primarily due to decreased vegetation management costs at Ameren Illinois.

•	A $13 million decrease in payments related to charitable donations.

•	An $11 million decrease in property tax payments at Ameren Missouri due to lower property tax values.

•	A $33 million decrease resulting from decreased customer collections, primarily due to a decrease in weather-related sales volumes at Ameren Missouri, and a net decrease attributable to regulatory recovery mechanisms, partially offset by decreased fuel costs and generation volumes at Ameren Missouri and decreased purchase power costs and volumes and natural gas costs at Ameren Illinois.

•	A $28 million increase in payments for nuclear refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. There was no refueling and maintenance outage in 2018.

•	A $14 million decrease resulting from increased Ameren Missouri purchases to maintain coal inventory at near targeted levels.

•	A $236 million decrease resulting from decreased customer collections, primarily due to a decrease in weather-related sales volumes, and a net decrease attributable to regulatory recovery mechanisms, partially offset by decreased fuel costs and generation volumes.

•	A $28 million increase in payments for nuclear refueling and maintenance outages at the Callaway Energy Center. There was no refueling and maintenance outage in 2018.

•	A $14 million decrease resulting from increased purchases to maintain coal inventory at near targeted levels.

•	A $27 million decrease in income tax payments to Ameren (parent) pursuant to the tax allocation agreement, primarily due to lower taxable income in 2019.

•	A $15 million decrease in pension and postretirement benefit plan contributions.

•	A net $11 million increase in collateral received from counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes.

•	An $11 million decrease in property tax payments due to lower property tax values.

•	A $200 million increase primarily resulting from decreased purchased power costs and volumes, decreased natural gas costs, and a net increase attributable to regulatory recovery mechanisms.

•	A $24 million decrease in income tax payments to Ameren (parent) pursuant to the tax allocation agreement, primarily due to the timing of payments.

•	A $16 million decrease in pension and postretirement benefit plan contributions.

•	A $14 million decrease in payments to contractors for electric distribution maintenance costs, primarily due to decreased vegetation management costs.

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•	A net $4 million increase in collateral received from counterparties, primarily resulting from changes in the market prices of power and natural gas, changes in contracted commodity volumes, and increases resulting from renewable energy contracts entered into pursuant to the FEJA.

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(a)	Includes Other capital expenditures of $(29) million and $(4) million for the years ended December 31, 2019 and 2018, respectively, which includes amounts for the elimination of intercompany transfers.

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(a)	The maximum aggregate amount available to Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $900 million and $850 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.

(b)	The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the Illinois Credit Agreement is $500 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.

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(a)	Ameren issued a total of 0.9 million and 1.2 million shares of common stock under its DRPlus and 401(k) plan in 2019 and 2018, respectively.

(b)	Excludes 0.8 million and 0.7 million shares of common stock valued at $54 million and $35 million issued for no cash consideration in connection with stock-based compensation in 2019 and 2018, respectively.

(c)	Amount less than $1 million.

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(a)	Excludes unamortized discount and premium and debt issuance costs of $85 million, $39 million, and $38 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of this report, for discussion of items included herein.

(b)	See Other Obligations in Note 14 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein.

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In 2018, Missouri Senate Bill 564 was enacted and Ameren Missouri elected the PISA in accordance with the provisions of the law. Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a return at the applicable WACC on investments in certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC, with all approved PISA deferrals added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense and a return at the applicable WACC for investments in renewable generation plant placed in service and not recovered under the PISA. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Ameren Missouri recognizes the cost of debt on PISA deferrals in revenue, instead of using the applicable WACC, with the difference recognized in revenues when recovery of such deferrals is reflected in customer rates. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. Both the rate increase limitation and PISA are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028.

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In February 2020, 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 2020. 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 $7.6 billion over the five-year period from 2020 through 2024, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028. As a part of its Smart Energy Plan, Ameren Missouri expects to build solar generation facilities, including utility scale facilities and nonresidential customer site facilities. In September 2019, Ameren Missouri filed for certificates of convenience and necessity with the MoPSC to build three solar facilities in its service territory. Each 10-megawatt solar energy generation facility will connect to battery storage in order to improve system reliability. All three facilities are expected to be completed by 2022. Also in 2019, the MoPSC approved Ameren Missouri’s Charge Ahead program, which provides incentives for the development of over 1,000 electric vehicle charging stations along highways and at various locations in communities throughout Ameren Missouri’s service territory. The purpose of the program is to promote the development of electric vehicle charging infrastructure that will enable long-distance electric vehicle travel and encourage electrification of the transportation sector.

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In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a rate-adjustment mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65 million per year through 2021. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals. If the target goals are achieved for 2019, 2020, and 2021, additional revenues of $7 million, $10 million, and $13 million would be recognized in late 2020, 2021, and 2022, respectively. Incremental additional revenues of $1 million, $3 million, and $3 million may be earned for 2019, 2020, and 2021, respectively, and would be recognized in the respective following year, if Ameren Missouri exceeds its targeted energy savings goals. Ameren Missouri recognized $28 million, $11 million, and $37 million in revenues related to MEEIA performance incentives in 2016, 2018, and 2019, respectively.

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In June 2018, the MoPSC approved Ameren Missouri’s Renewable Choice Program, which allows large commercial and industrial customers and municipalities to elect to receive up to 100% of their energy from renewable resources. The tariff-based program is designed to recover the costs of the election. Ameren Missouri is working to meet its customers’ top priorities for this program, including prices competitive with existing rates, long-term price predictability, and the preference for renewable power generated in Missouri. Ameren Missouri has not yet developed a project that effectively meets the needs of those customers who have expressed an interest in the program. Ameren Missouri will remain focused on finding solutions to best meet customer needs and expectations.

•

In July 2019, Ameren Missouri filed a request with the MoPSC seeking approval to decrease its annual revenues for electric service by $1 million. In February 2020, Ameren Missouri, the MoPSC staff, the MoOPC, and certain intervenors filed a nonunanimous stipulation and agreement with the MoPSC to decrease Ameren Missouri’s annual revenues for electric service by $32 million. The remaining intervenor did not object to the agreement. The stipulation and agreement, which is subject to MoPSC approval, specified an allowed ROE range of 9.4% to 9.8%, but did not specify the common equity percentage or rate base. The stipulation and agreement includes 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. Ameren Missouri cannot predict whether the MoPSC will approve the stipulation and agreement or, if approved, whether any application for rehearing or appeal will be filed, or the outcome if so filed. A decision by the MoPSC is expected by March 2020, with new rates effective as early as April 1, 2020.The percentage of net energy cost variances from the amount set in base rates allowed to be recovered or refunded under the FAC and costs from services provided by affiliates are still being challenged by the MoOPC, and are expected to be addressed in a proceeding that would begin in March 2020. A MoPSC decision would be expected in the proceeding by the end of May 2020.

•

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 10.38% ROE, the revenue requirements that will be included in 2020 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $311 million and $190 million, respectively. These revenue requirements represent an increase in Ameren Illinois’ and ATXI’s revenue requirements of $14 million and $13 million, respectively, from the revenue requirements reflected in 2019 rates, primarily due to the expected rate base growth. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2020, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2020 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the FERC formula ratemaking framework.

•

The ROE for MISO transmission owners, including Ameren Illinois and ATXI, is the subject of FERC complaint cases filed in November 2013 and February 2015 challenging the allowed base ROE. In November 2019, the FERC issued an order addressing the November 2013 complaint case, which set the allowed base ROE at 9.88% and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. The order also dismissed the February 2015 complaint case. As a result of this

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•

Ameren Illinois’ electric distribution service performance-based formula ratemaking framework allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the year. Unless extended, the formula ratemaking framework expires at the end of 2022. If not extended, Ameren Illinois would then be required to establish future rates through a traditional regulatory rate review with the ICC. The decoupling provisions extend beyond the end of the formula ratemaking by law, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes.

•

In December 2019, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $7 million decrease in Ameren Illinois’ electric distribution service rates beginning in January 2020. Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and a return at the applicable WACC on year-end rate base in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois’ 2020 electric distribution service revenues will be based on its 2020 actual recoverable costs, 2020 year-end rate base, and return at the applicable WACC as calculated under the Illinois performance-based formula ratemaking framework. The 2020 revenue requirement is expected to be higher than the 2019 revenue requirement because of an expected increase in recoverable costs and expected rate base growth of approximately 7%, partially offset by the impact of an expected decrease in the annual average of the monthly yields of the 30-year United States Treasury bonds. The 2020 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2022. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $9 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2020 projected year-end rate base.

•

In February 2020, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $102 million, which included an estimated $46 million of annual revenues that would otherwise be recovered under the QIP and other riders. The request is based on a 10.5% allowed ROE, a capital structure composed of 54.1% common equity, and a rate base of $2.1 billion.

•

Ameren Illinois earns a return at the applicable WACC on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the applicable WACC, with the ROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The allowed ROE on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. Pursuant to the FEJA, Ameren Illinois plans to invest up to approximately $100 million per year in electric energy-efficiency programs through 2024, and will earn a return on those investments. While the ICC has approved a plan consistent with this spending level through 2021, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not included in the electric distribution formula ratemaking framework.

•

In February 2020, the MoPSC issued an order approving a stipulation and agreement allowing Ameren Missouri to defer and amortize maintenance expenses related to scheduled refueling and maintenance outages at its Callaway Energy Center. Beginning with the fall 2020 refueling and maintenance outage, Ameren Missouri will defer the maintenance expenses incurred related to a refueling and maintenance outage as a regulatory asset and amortize those expenses after completion of the outage. Maintenance expenses will be amortized over the period between refueling and maintenance outages, which is approximately 18 months. Ameren Missouri expects to incur approximately $40 million in maintenance expenses related to the fall 2020 outage. During a scheduled 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

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Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek increases to electric and natural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, legislative solutions to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective technological advances, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy for efficiencies and as a means to address economywide CO2 emission concerns. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, result in rate base and revenue growth but also higher depreciation and financing costs.

•

Ameren Missouri’s 2017 IRP 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 700 megawatts of wind generation by the end of 2020 in Missouri and adding 100 megawatts of solar generation by 2027. 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. Based on current and projected market prices for energy and for wind and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost option for customers. 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 production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind and solar generation technologies; energy prices; Ameren Missouri’s ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC, and any other required project approvals. Ameren Missouri expects to file its next integrated resource plan in September 2020. Ameren Missouri will seek stakeholder feedback and assess different scenarios to meet future energy needs, which will be used to create an updated plan for its current generation portfolio and ongoing transition to cleaner sources of energy.

•

In connection with the 2017 IRP filing, Ameren Missouri established a goal of reducing CO2 emissions 80% by 2050 from a 2005 base level. Ameren Missouri is also targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level. In order to meet these goals, among other things, Ameren Missouri expects to retire its coal-fired generation at the end of each energy center’s useful life. The Meramec, Sioux, Labadie, and Rush Island energy centers are expected to be retired in 2022, 2033, 2042, and 2045, respectively.

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Consistent with its 2017 IRP filing, in May 2019, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 300-megawatt wind generation facility. In 2018, Ameren Missouri entered into a build-transfer agreement to acquire, after construction, an up-to 400-megawatt wind generation facility. These two agreements are subject to customary contract terms and conditions. The two build-transfer acquisitions collectively represent $1.2 billion of capital expenditures, are expected to be completed by the end of 2020, and would support Ameren Missouri’s compliance with the Missouri renewable energy standard. Both acquisitions have received all regulatory approvals, and both projects have received all applicable zoning approvals, have entered into RTO interconnection agreements, and have begun construction activities.

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Through 2024, 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 $16.6 billion (Ameren Missouri – up to $8.4 billion; Ameren Illinois – up to $8.0 billion; ATXI – up to $0.2 billion) of capital expenditures during the period from 2020 through 2024. Ameren’s and Ameren Missouri’s estimates exclude any capital expenditures related to pollution control equipment that may be required as a result of the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

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Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. Certain of these regulations are being challenged through litigation, or reviewed or recommended for repeal by the EPA, or new replacement or alternative regulations are being contemplated, proposed, or adopted by the EPA and state regulators. The ultimate implementation of any of these regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital

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The Ameren Companies have multiyear credit agreements that cumulatively provide $2.3 billion of credit through December 2024, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $2.7 billion. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

•

Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its plan to fund these cash flow requirements, Ameren is using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2024. Ameren expects these issuances to provide equity funding of about $100 million annually. Ameren also plans to issue incremental common equity to fund a portion of Ameren Missouri’s wind generation investments through the settlement of the forward sale agreement discussed below. Additionally, Ameren plans to issue incremental equity of about $150 million annually from 2021 to 2024. Ameren expects its equity to total capitalization to be about 45% through the period ending December 2024, with the long-term intent to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent).

•

In August 2019, Ameren entered into a forward sale agreement with a counterparty relating to 7.5 million shares of common stock. The forward sale agreement can be settled at Ameren’s discretion on or prior to March 31, 2021. On a settlement date or dates, if Ameren elects to physically settle the forward sale agreement, Ameren will issue shares of common stock to the counterparty at the then-applicable forward sale price. The forward sale agreement will be physically settled unless Ameren elects to settle in cash or to net share settle. If physically settled, Ameren expects to receive between $540 million and $550 million upon settlement. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.

•

Federal income tax legislation enacted under the TCJA will continue to have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA, among other things, reduced the federal statutory corporate income tax rate from 35% to 21%, effective January 1, 2018. Customer rates were reduced to reflect the lower income tax rate, without a corresponding reduction in income tax payments because of our use of net operating losses and tax credit carryforwards until about 2020. Customer rates were also reduced to reflect the return of excess deferred income taxes. The result of these customer rate reductions is a decrease in operating cash flows in the near term. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts resulting from lower accumulated deferred income tax liabilities.

•	The following table presents the net regulatory liabilities/(assets) associated with excess deferred income taxes as of December 31, 2019, and the related amortization periods:

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As of December 31, 2019, Ameren had $98 million in tax benefits related to federal and state income tax credit carryforwards. Ameren has utilized all tax benefits from net operating loss carryforwards. Future expected income tax payments and refunds are based on planned capital expenditures and any related income tax credits and, in the case of Ameren Missouri and Ameren Illinois, are consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries. Ameren expects to make income tax payments between $5 million and $75 million in each year from 2020 to 2024, totaling $150 million to $200 million for the five-year period. Ameren Missouri expects to make income tax payments to Ameren (parent) between $35 million and $45 million in 2020. Additionally, Ameren Missouri expects to receive refunds from Ameren (parent) in each year from 2021 to 2024, totaling $60 million to $100 million for the four-year period. Ameren Illinois expects to make income tax payments to Ameren (parent) between $20 million and $30 million in 2020 and between $50 million and $90 million in each year from 2021 to 2024, totaling $260 million to $310 million for the five-year period.

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Ameren Missouri expects its 2020 wind generation acquisitions to generate federal production tax credits between $65 million and $70 million in each year from 2021 to 2030. Ameren expects to utilize approximately $140 million of these federal production tax credits from 2021 to 2024. Delays in the timely completion of the wind generation facilities may affect the ability to realize some or all of the anticipated federal production tax credits. If these facilities are not completed in 2020, Ameren Missouri will need to satisfy additional IRS requirements in order to qualify for some or all of the anticipated federal production tax credits.

•

In 2018, legislation modifying Missouri tax law was enacted to decrease the state’s corporate income tax rate from 6.25% to 4%, effective January 1, 2020. Ameren Missouri anticipates that the effect of this tax decrease will be reflected in customer rates upon completion of its current electric service regulatory rate review. Ameren (parent) and nonregistrant subsidiaries do not expect this income tax decrease to have a material impact on net income.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

•	short-term variable-rate debt;

•	fixed-rate debt;

•	United States Treasury bonds; and

•	the discount rate applicable to asset retirement obligations, goodwill, and defined pension and postretirement benefit plans.

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(a)	The Callaway Energy Center requires refueling at 18-month intervals. The next refueling is scheduled for the fall of 2020. As there are no refuelings scheduled to occur during 2021 or 2024, there are also no nuclear fuel deliveries anticipated to occur in these years.

(b)	Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2020 represents January 2020 through March 2020. The year 2021 represents November 2020 through March 2021. This continues each successive year through March 2024.

(c)	Represents the percentage of purchased power price-hedged for fixed-price residential and nonresidential customers with less than 150 kilowatts of demand.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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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.

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Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois. Ameren Illinois was incorporated in Illinois in 1923 and is the successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to a 43,700 square mile area in central and southern Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 0.8 million customers.

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Ameren Transmission Company of Illinois, doing business as ATXI, operates a FERC rate-regulated electric transmission business in the MISO. ATXI was incorporated in Illinois in 2006. ATXI is constructing the Illinois Rivers project, a MISO-approved electric transmission project, and eight of its nine line segments have been completed and placed in service as of December 31, 2018. ATXI operates the Spoon River project and the Mark Twain project, which were placed in service in February 2018 and December 2019, respectively.

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(a)	Under-recovered or over-recovered costs from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.

(b)	Deferral of commodity-related derivative MTM losses or gains. See Note 7 – Derivative Financial Instruments for additional information.

(c)	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.

(d)	These assets earn a return at the applicable WACC.

(e)	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.

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(f)	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.

(g)

The regulatory assets represent amounts that will be recovered from customers for deferred income taxes related to the equity component of allowance for funds used during construction and the effects of tax rate changes. The regulatory liabilities represent amounts that will be refunded to customers for deferred income taxes related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. For net regulatory liabilities related to deferred income taxes recorded at rates other than the current statutory rate, the weighted-average remaining amortization periods at Ameren, Ameren Missouri, and Ameren Illinois are 34, 26, and 43 years.

(h)	Ameren Missouri’s Callaway Energy Center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the original remaining life of the energy center.

(i)	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.

(j)	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.

(k)	Storm costs from 2016 and 2018 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred.

(l)	The period of recovery will depend on the timing of actual expenditures.

(m)	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.

(n)	Costs associated with Ameren Missouri’s solar rebate program. The amortization period for these assets will be determined in a future electric service regulatory rate review.

(o)	Under the PISA, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Accumulated PISA deferrals are added to rate base prospectively and amortized over a period of 20 years following a regulatory rate review.

(p)	Costs associated with Ameren Missouri’s compliance with the state of Missouri’s renewable energy standard. Costs incurred over a twelve-month period beginning each August are amortized over a twelve-month period beginning February the following year.

(q)	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 7 to 12 years.

(r)	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.

(s)	Under-recovered or over-recovered natural gas revenue caused by sales volume deviations from weather normalized sales approved by the ICC in rate regulatory reviews. Each year’s amount will be recovered from or refunded to customers from April through December of the following year.

(t)

The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs, lost electric margins, and the performance incentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, and lost electric margins are incurred or any performance incentive are earned.

(u)	The 2019 balances represent the estimated refunds to transmission customers related to the November 2019 FERC order in the November 2013 FERC complaint case. The 2018 balances represent the estimated refunds to transmission customers related to the February 2015 FERC complaint case, which was dismissed in the November 2019 order. See further discussion of the FERC ROE complaint cases above.

(v)	Estimated funds collected from customers to pay for the future removal cost of property, plant, and equipment retired from service, net of salvage.

(w)	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.

(x)

A regulatory recovery mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. The period of refund varies based on MoPSC approval in a regulatory rate review. For costs incurred prior to December 2016, the weighted-average remaining amortization period is three years. For costs incurred after December 2016, the amortization period will be determined in the current electric service regulatory rate review.

(y)	Funds collected for the purchase of renewable energy credits and zero emission credits through IPA procurements. The balance will be amortized as the credits are purchased.

(z)	The excess amount collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the current electric service regulatory rate review.

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(a)

Amounts include two CTs that have related financing obligations. The gross cumulative asset value of those agreements was $236 million and $235 million at December 31, 2019 and 2018, respectively. The total accumulated depreciation associated with the two CTs was $95 million and $89 million at December 31, 2019 and 2018, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.

(b)	The estimated lives for each asset group are as follows: 5 to 72 years for electric generation, excluding Ameren Missouri’s hydro generating assets which have useful lives of up to 150 years, 20 to 80 years for electric distribution, 50 to 75 years for electric transmission, 20 to 80 years for natural gas, and 5 to 55 years for other.

(c)	Other property, plant, and equipment includes assets used to support electric and natural gas services.

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(a)	Not applicable.

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(a)	The timing of peak outstanding commercial paper issuances varies by company. Therefore, the sum of the peak amounts presented by the companies may not equal the Ameren consolidated peak amount for the period.

(b)	In 2019, the peak interest rate was affected by temporary disruptions in the commercial paper market.

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(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 2049 maturity of the 3.25% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (e) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.

(b)	These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes.

(c)

Prior to the change in the method of determining the interest rates applicable to the Ameren Missouri bonds and the extinguishment of Ameren Illinois’ senior unsecured notes, the interest rates and the periods during which such rates apply varied depending on our selection of defined rate modes. The average interest rates for the respective applicable period in 2019 and the year ended December 31, 2018 were as follows:

(d)	Amount less than $1 million.

(e)	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.

(f)	These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri bond indenture. They are secured by substantially all Ameren Missouri property and franchises.

(g)

Payments due related to these financing obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the city/county and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the financing obligations and the related investments in debt securities, recorded in “Other Assets,” was $263 million and $270 million, respectively, as of December 31, 2019 and 2018.

(h)

These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises. 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 mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2050 maturity date of the 3.25% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these notes to fall away.

(i)	Ameren Illinois has agreed that so long as any of the 2.70% senior secured notes due 2022 are outstanding, Ameren Illinois will not permit a release date to occur.

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(j)	These bonds are first mortgage bonds issued by Ameren Illinois under its mortgage indenture. They are secured by substantially all Ameren Illinois property and franchises.

(k)	The following table presents the principal maturities schedule for the 3.43% senior notes due 2050:

(a)	Excludes unamortized discount, unamortized premium, and debt issuance costs of $6 million, $39 million, $38 million and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois and ATXI, respectively.

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(a)	In the event of voluntary liquidation, $105.50.

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(a)	Represents the variable interest rate of the bonds effective prior to the change in method of determining the interest rate.

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(a)	Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.

(b)	Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $2,358 million and $643 million at Ameren Missouri and Ameren Illinois, respectively.

(c)	Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.

(d)	Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.

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(a)	For the years ended December 31, 2019, and 2018, the non-service cost components of net periodic benefit income were partially offset by a deferral of $29 million and $17 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.

•	an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

•	market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory;

•	actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays; and

•	actual off-system sales revenues that differ from anticipated revenues.

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(a)	Balance excludes $5 million and $5 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2019 and 2018, respectively.

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(a)	Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.

(b)	Unobservable inputs were weighted by relative fair value.

(c)	Valuations through 2028 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2028 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.

(d)	Valuations through 2022 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2022 use a fundamental energy production model incorporating estimated future natural gas prices.

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(a)

Ameren and Ameren Missouri have investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the finance obligations for the Peno Creek and Audrain CT energy centers. As of December 31, 2019 and 2018, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value.

(b)

Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $72 million, $30 million, and $34 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2019. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $58 million, $22 million, and $31 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2018.

(c)	The Level 3 fair value amount consists of ATXI’s senior unsecured notes.

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(a)	Represents net receivables and payables relating to pending securities sales, interest, and securities purchases.

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(a)	Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.

(b)	Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $21 million per year.

(c)	Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors.

(d)	NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events.

(e)	All NEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.

(f)	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.

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(a)	Assets associated with other postretirement benefits are recorded in “Other assets” on the balance sheet.

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(a)	Not applicable.

(b)	Included in “Other assets” on Ameren’s consolidated balance sheet.

(c)	Included in “Other current liabilities” on Ameren’s consolidated balance sheet.

(a)	Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%.

(b)	Not applicable.

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(a)	Less than 1% of plan assets.

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(a)	Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation.

(b)	Receivables related to pending securities sales, offset by payables related to pending securities purchases.

(a)	Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.

(b)	Payables related to pending securities purchases, offset by interest receivables and receivables related to pending securities sales.

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(b)	2019 and 2018 amounts and the non-capitalized portion of 2017 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.

(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.

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(a)	Initial and ultimate medical cost trend rate for certain Medicare-eligible participants is 3.00%.

(b)	Not applicable.

(a)	Does not include 619,783 performance share units and 26,557 restricted stock units that were vested and undistributed.

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(b)	Vested and undistributed units are awards that vest on a pro-rata basis due to attainment of retirement eligibility by certain employees, but have not yet been distributed. For vested and undistributed performance share units, the number of shares issued for retirement-eligible employees will vary depending on actual performance over the three-year performance period.

(c)	Does not include 503,283 of performance share units and 79,854 of restricted stock units that were vested and undistributed.

(a)	Based on a historical period that is equal to the remaining term of the performance period as of the grant date.

(a)	Represents compensation expense for employees of Ameren Services. These amounts are not included in the Ameren Missouri and Ameren Illinois amounts above.

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(a)	Will expire between 2029 and 2039.

(b)	Will expire between 2022 and 2024.

(c)	See Schedule II under Part IV, Item 15, in this report for information on changes in the valuation allowance.

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(a)	Included in “Accounts payable – affiliates” on the balance sheet.

(b)	Included in “Accounts receivable – affiliates” on the balance sheet.

(a)	As a result of the tax allocation agreement.

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(a)	Not applicable.

(b)	Amount less than $1 million.

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(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 2035 with various renewable energy suppliers due to the contingent nature of the payment amounts, with the exception of expected payments of $13 million through 2024.

(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)

In January 2018, as required by the FEJA, Ameren Illinois entered into agreements to acquire zero emission credits, through 2026. Annual zero emission credit commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. The amounts above reflect Ameren Illinois’ commitment to acquire approximately $27 million of zero emission credits through May 2020.

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(a)	Consists of coal, oil, and propane.

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(a)	As an implicit rate is not readily determinable under most of our lease agreements, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. We use an implicit rate when readily determinable.

(a)

The amount of remaining maturities of operating lease liabilities under previous authoritative accounting guidance as of December 31, 2018, is materially consistent with the amount as of December 31, 2019. Maturities of certain financing arrangements, including the Peno Creek and Audrain energy centers' long-term agreements, are no longer required to be disclosed as lease-related maturities. See Note 5 – Long-Term Debt and Equity Financings, for further information on financing arrangements.

(a)	Balance included $53 million and $23 million in “Other current liabilities” on the balance sheet as of December 31, 2019 and 2018, respectively.

(b)	Included in “Other deferred credits and liabilities” on the balance sheet.

(c)	Ameren Missouri’s accretion expense was deferred as a decrease to regulatory liabilities.

(d)	Ameren Missouri changed its fair value estimate primarily due to an increase in the cost estimate for closure of certain CCR storage facilities.

(e)	Ameren Missouri changed its fair value estimate primarily due to a reduction in the cost estimate for closure of certain CCR storage facilities.

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(a)	There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the years ended December 31, 2019, 2018, and 2017.

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(a)	See Note 4 – Long-term Debt and Equity Financings for additional information.

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(a)	Ameren Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

(b)

Intersegment revenues at Ameren include $14 million and $5 million of revenue from Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. Under authoritative accounting guidance for rate-regulated entities, the revenue recognized by Ameren Illinois was not eliminated upon consolidation. See Note 13 – Related-party Transactions for additional information.

(c)	Ameren Transmission interest charges include an allocation of financing costs from Ameren (parent).

(d)	Intersegment capital expenditure eliminations include $24 million of eliminations for the year ended December 31, 2019 for a software licensing agreement between Ameren Illinois and Ameren Missouri. See Note 13 – Related-party Transactions for additional information.

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(a)	Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. See discussion of transactions above.

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(a)	Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information.

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(c)	Includes $60 million for the year ended December 31, 2018, for the reduction to revenue for the excess amounts collected in rates to be refunded related to the TCJA from January 1, 2018, through July 31, 2018. See Note 2 – Rate and Regulatory Matters for additional information.

(a)	Includes $14 million and $5 million for Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively, for the year ended December 31, 2019, for a software licensing agreement with Ameren Missouri. See Note 13 – Related-party Transactions for additional information.

(b)	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, 2019, 2018, and 2017:

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

ITEM 9A.	CONTROLS AND PROCEDURES

(a)	Evaluation of Disclosure Controls and Procedures

(b)	Management’s Report on Internal Control over Financial Reporting

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(c)	Change in Internal Control

ITEM 9B.	OTHER INFORMATION

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

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ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

(a)

Of the securities to be issued, 1,108,794 of the securities represent the target number of outstanding performance share units (PSUs) and 313,396 of the securities represent the number of outstanding restricted stock units (RSUs), both including accrued and reinvested dividends. The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level, depending upon the achievement of TSR objectives established for such awards. For additional information about the PSUs and RSUs, including payout calculations, see “Compensation Discussion and Analysis – Long-Term Incentive Compensation” in Ameren’s definitive proxy statement for its 2020 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. The remaining 78,613 of the securities represent shares that may be issued to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for Members of the Board of Directors.

(b)	Consists of the 2014 Omnibus Incentive Compensation Plan.

(c)	No cash consideration is received when shares are distributed for earned PSUs, RSUs, and director awards. Accordingly, there is no weighted-average exercise price.

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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(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.

(c)	Includes an adjustment of $3 million to Ameren (parent)’s valuation allowance for certain deferred tax assets existing at December 31, 2017, for the reduction in the income tax rate.

ITEM 16.	FORM 10-K SUMMARY

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