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regulatory, judicial, or legislative actions, and any changes in regulatory policies and ratemaking determinations, such as those that may result from a potential change in the allowed base return on common equity under the MISO tariff from either the complaint case filed in February 2015 with the FERC or a new methodology proposed by the FERC in November 2018, Ameren Missouri’s requested certificate of convenience and necessity for a wind generation facility filed with the MoPSC in October 2018, Ameren Missouri’s natural gas regulatory rate review filed with the MoPSC in December 2018, an appeal filed by the MoOPC in January 2019 in Ameren Missouri’s RESRAM case, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;

•	the effect of Ameren Illinois’ participation in performance-based formula ratemaking frameworks under the IEIMA and the FEJA, including the direct relationship between Ameren Illinois' return on common equity and the 30-year United States Treasury bond yields, and the related financial commitments;

•	the effect of Missouri Senate Bill 564 on Ameren Missouri, including as a result of Ameren Missouri’s election to use PISA and the resulting customer rate caps;

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

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

•	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 FEJA electric customer energy-efficiency goals and the resulting impact on its allowed return on program investments;

•	our ability to align overall spending, both operating and capital, with frameworks established by our regulators and to recover these costs in a timely manner in our attempt to earn our allowed returns on equity;

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the cost and availability of fuel, such as ultra-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;

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•	the ability to obtain sufficient insurance, including insurance for Ameren Missouri’s Callaway energy center, or, in the absence of insurance, the ability to recover uninsured losses from our customers;

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

•	business and economic conditions, 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, including as a result of the implementation of the TCJA, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;

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

•	the 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 breakdowns or failures of equipment in the operation of natural gas transmission and distribution systems and storage facilities, such as leaks, explosions, and mechanical problems, and compliance with natural gas safety regulations;

•	the effects of breakdowns or failures of electric generation, transmission, or distribution equipment or facilities, 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;

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

•	the impact of complying with renewable energy requirements 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 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 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 MISO or other RTOs, including the costs of such interconnections;

•	labor disputes, work force reductions, changes in future wage and employee benefits costs, including those resulting from changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;

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

•	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. ATXI is constructing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and operates the Spoon River project, which was placed in service in February 2018. Ameren also evaluates competitive electric transmission investment opportunities as they arise.

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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.

(c)	Based on the MoPSC’s March 2017 rate order. This rate order specified that an implicit return on equity was within a range of 9.2% to 9.7%. The rate order did not specify a percent of common equity or rate base. The return on equity used for allowance for equity funds used during construction is 9.53%.

(d)	Based on the MoPSC’s January 2011 rate order. This rate order did not specify the allowed return on equity, the percent of common equity, or rate base.

(e)

Based on the ICC’s November 2018 rate order. Ameren Illinois electric distribution delivery service rates are updated annually and become effective each January. The November 2018 rate order was based on 2017 recoverable costs, expected net plant additions for 2018, and the annual average of the monthly yields during 2017 of the 30-year United States Treasury bonds plus 580 basis points. Ameren Illinois’ 2019 electric distribution delivery service revenues will be based on its 2019 actual recoverable costs, rate base, common equity percentage, and return on common equity, as calculated under the IEIMA’s performance-based formula ratemaking framework.

(f)	Based on the ICC’s November 2018 rate order. The rate order was based on a 2019 future test year.

(g)

Transmission rates are updated annually and become effective each January. They are determined by a company-specific, forward-looking formula ratemaking based on each year’s forecasted information. The 10.82% return, which includes a 50 basis points incentive adder for participation in an RTO, could be lowered as a result of a FERC complaint proceeding filed in February 2015 that challenged the allowed return on common equity for MISO transmission owners and will require customer refunds if the FERC approves a return on equity lower than that previously collected through rates. The return on equity applicable to investments in ATXI’s Mark Twain project includes an additional 50 basis points incentive adder related to the unique nature of risks involved in completing the project.

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

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

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

•	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;

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

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•	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 and renewable sources of power and the lack of consensus as to who should pay for those programs;

•	pressure on customer growth and usage in light of economic conditions, distributed generation, technological advances, and energy-efficiency 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 return on common equity on FERC-regulated electric transmission assets;

•	the availability of fuel and fluctuations in fuel prices;

•	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 allowed rates of return on equity 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;

•	public concerns about the siting of new facilities;

•	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 some investors’ concerns about investing in energy companies that have fossil fuel-fired generation assets;

•	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 2018, 2017, and 2016, Ameren Illinois procured power on behalf of its customers for 23% of its total kilowatthour sales.

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

(c)	Includes $53 million, $42 million, and $45 million in 2018, 2017, and 2016, respectively, of electric operating revenues from transmission services provided to Ameren Illinois Electric Distribution.

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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;

•	disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including ultra-low-sulfur coal used by Ameren Missouri to comply with environmental regulations;

•	lack of adequate water required for cooling plant operations;

•	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, solar flares, and electromagnetic pulses;

•	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

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•	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 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 and to produce power at a competitive cost. Some distributed generation technologies have become more cost-competitive, with decreasing costs expected in the future. The costs of these distributed generation technologies may decline over time to a level that is competitive with that of Ameren Missouri’s energy centers. Additionally, technological advances in energy storage may be coupled with distributed generation to reduce the demand for our electric utility services. Increased adoption of these technologies by customers could decrease our revenues if customers cease to use our generation, transmission, and distribution services at current levels. Ameren Missouri might incur stranded costs, which ultimately might not be recovered through rates.

•	Macroeconomic factors. Macroeconomic factors resulting in low economic 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)	All coal-fueled kilowatts and 236,000 natural-gas-fueled kilowatts at the Meramec energy center are scheduled for retirement in 2022.

(c)	There are economic development arrangements applicable to these CTs.

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

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

(a)	ATXI owns 408 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, 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.

ITEM 3.	LEGAL PROCEEDINGS

•	the February 2015 complaint case filed with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff;

•	the November 2018 FERC order requesting briefs regarding a new methodology for determining the base return on common equity under the MISO tariff and how to apply the new methodology to the February 2015 complaint case and the September 2016 order related to the November 2015 complaint case;

•	the January 2019 appeal filed by the MoOPC challenging the MoPSC’s December 2018 order in the RESRAM case;

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

•	remediation matters associated with former MGP and waste disposal sites of the Ameren Companies.

ITEM 4.	MINE SAFETY DISCLOSURES

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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 for 2017 and 2016 have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information. The 2015 and 2014 balances are not revised for this guidance and are not comparative.

(b)	Amounts have been revised to reflect the adoption of accounting guidance on the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.

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

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

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

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

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

•	ATXI operates a FERC rate-regulated electric transmission business. ATXI is constructing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and operates the Spoon River project, which was placed in service in February 2018. Ameren also evaluates competitive electric transmission investment opportunities as they arise.

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•	the absence of a noncash charge to earnings, primarily at Ameren (parent), for the revaluation of deferred taxes recorded in 2017, as a

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•	increased demand in 2018 at Ameren Missouri, primarily due to warmer summer and colder winter temperatures in 2018 (estimated at 42 cents per share);

•	increased base rates and reduced operating expenses for net energy costs and other expenses subject to regulatory tracking mechanisms at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order (9 cents per share);

•	the absence of a Callaway energy center scheduled refueling and maintenance outage in 2018, which last occurred in the fourth quarter of 2017, partially offset by preparation costs incurred in 2018 for the 2019 scheduled refueling outage (9 cents per share);

•	increased Ameren Transmission earnings under formula ratemaking, primarily due to additional investment (8 cents per share);

•	increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional investment and a higher return on equity (5 cents per share);

•	increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP rider and increased base rates pursuant to the ICC’s November 2018 gas rate order (5 cents per share);

•	decreased property taxes at Ameren Missouri due to lower assessed property values (5 cents per share);

•	decreased financing costs, primarily at Ameren Missouri, due to lower interest rates and higher levels of the allowance for funds used during construction (3 cents per share); and

•	the recognition of a MEEIA 2016 performance incentive in 2018 at Ameren Missouri (3 cents per share).

•	increased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily due to higher-than-normal energy center scheduled outage and electric distribution maintenance costs at Ameren Missouri (19 cents per share) and due to changes in the market value of company-owned life insurance (7 cents per share);

•	increased donations at Ameren (parent) and Ameren Missouri (8 cents per share);

•	increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms, primarily at Ameren Missouri, resulting from additional electric property, plant, and equipment (7 cents per share); and

•	the dilutive effect of issuing common stock (2 cents per share).

•	an increase in income tax expense, primarily at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decrease in the federal statutory corporate income tax rate due to enactment of the TCJA (63 cents per share) and an increase in the Illinois corporate income tax rate (6 cents per share);

•	decreased demand primarily at Ameren Missouri due to milder winter and summer temperatures in 2017 (estimated at 15 cents per share);

•	the absence in 2017 of a MEEIA 2013 performance incentive at Ameren Missouri recognized in 2016 (7 cents per share);

•	increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri resulting from additional electric property, plant, and equipment (6 cents per share); and

•	increased transmission services charges at Ameren Missouri resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities (2 cents per share).

•	an increase in base rates, net of increased revenues in 2016 from the suspension of operations at the New Madrid Smelter, and reduced operating expenses for net energy costs and other expenses subject to regulatory tracking mechanisms at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order (32 cents per share);

•	increased Ameren Transmission earnings under formula ratemaking, primarily due to additional investment, partially offset by a lower recognized return on equity (9 cents per share);

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•	increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional investment and a higher recognized return on equity (4 cents per share); and

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decreased income tax expense, excluding the effect of corporate income tax rate changes discussed above, primarily at Ameren (parent) resulting from changes in the valuation allowance for charitable contributions, tax benefits related to company-owned life insurance, and tax credits in 2017, partially offset by a lower income tax benefit in 2017 related to stock-based compensation compared with 2016 (1 cent per share).

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(a)	Includes an increase in transmission margins of $9 million and $26 million in 2018 and 2017, respectively, 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 increases or decreases to expenses are reflected in “Operating Expenses – Other operations and maintenance” or in “Operating Expenses – Taxes other than income taxes” on the statement of income. These items have no overall impact on earnings.

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Summer temperatures were warmer as cooling degree days increased 11% in 2018 compared with 2017 and winter temperatures were colder as heating degree days increased 34% in 2018 compared with 2017. The effect of weather increased margins by an estimated $123 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$157 million) and the effect of weather (estimate) on fuel and purchased power (-$34 million) in the table above.

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Revenues from other cost recovery mechanisms due to MEEIA customer energy-efficiency program costs and gross receipts taxes, which increased margins $30 million. See Other Operations and Maintenance Expenses in this section for the related offsetting increase in MEEIA customer energy-efficiency program costs and Taxes Other Than Income Taxes in this section for the related offsetting increase in gross receipts taxes.

•	Excluding the estimated effects of weather and the MEEIA 2016 customer energy-efficiency programs, total retail sales volumes increased 1%, which increased revenues by an estimated $21 million, primarily due to growth. While MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins ensured that electric margins were not affected.

•	The MEEIA 2016 performance incentive, which increased revenues $11 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2016 performance incentive.

•	An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $5 million.

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Lower electric base rates in accordance with the TCJA provisions in Missouri Senate Bill 564, partially offset by higher electric base rates, as a result of the March 2017 electric rate order. These items collectively decreased margins by an estimated $104 million in 2018 compared with 2017. The net change in electric base rates is the sum of the change in base rates (estimate) (-$113 million) and the effect of lower net energy costs included in base rates (+$9 million) in the table above.

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An increase in net energy costs as a result of increased sales volumes discussed above, partially offset by the 5% Ameren Missouri retains for the variance in net energy costs from the amount set in base rates, primarily as a result of lower fuel costs in 2018 compared with 2017, which collectively decreased margins $1 million. The change in net energy costs is the sum of the effect of revenue change in off-system sales and capacity revenues (-$110 million) and the effect of the change in energy costs (excluding the estimated effect of weather) (+$109 million) in the table above.

•	Revenues from other cost recovery mechanisms, primarily due to a decrease in recoverable customer energy-efficiency program costs prior to the FEJA, which decreased margins $40 million. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency program costs prior to the FEJA.

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Revenues decreased due to lower recoverable expenses in 2018 compared with 2017 under formula ratemaking, partially offset by an increase in rate base of 8% and a higher recognized return on common equity due to an increase in the 30-year United States Treasury bond yields of 22 basis points, which collectively decreased margins $23 million. The reduction in the federal statutory corporate income tax rate decreased recoverable expenses $52 million.

•	Revenues increased $13 million due to energy-efficiency program investments pursuant to the FEJA.

•	An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $8 million.

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•	Revenues from QIP recoveries, which increased margins $13 million due to additional investment in qualified natural gas infrastructure.

•	Revenues from other cost recovery mechanisms, which increased margins $9 million.

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Higher electric base rates, effective April 1, 2017, as a result of the March 2017 MoPSC electric rate order, which increased margins by an estimated $100 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$61 million) and the effect of lower net energy costs included in base rates (+$39 million) in the table above. Higher electric base rates incorporated the effect of the suspension of operations at the New Madrid Smelter.

•	Revenues from other cost recovery mechanisms, primarily due to MEEIA customer energy-efficiency program costs, which increased margins $24 million. See Other Operations and Maintenance Expenses in this section for the related offsetting increase in MEEIA customer energy-efficiency program costs.

•	Increased transmission services revenues due to additional rate base investment, which increased margins $11 million.

•	An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $7 million.

•	Summer temperatures were milder in 2017 compared with 2016, as cooling degree days decreased 10%. The effect of weather decreased margins by an estimated $52 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$65 million) and the effect of weather (estimate) on fuel and purchased power (+$13 million) in the table above.

•	The absence of the MEEIA 2013 performance incentive, which decreased margins $28 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2013 performance incentive.

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•	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 $16 million.

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Excluding the estimated effects of weather and the MEEIA 2016 customer energy-efficiency programs, total retail sales volumes decreased less than 1%, which decreased revenues by an estimated $6 million. Lower sales volumes were due, in part, to the absence of the leap year benefit experienced in 2016, partially offset by growth. While MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins ensured that electric margins were not affected.

•	Revenues from other cost recovery mechanisms, primarily due to a decrease in recoverable customer energy-efficiency program costs prior to the FEJA, which decreased margins $36 million. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency program costs prior to the FEJA.

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The absence of the impact of warmer-than-normal summer temperatures experienced in 2016, which decreased margins by an estimated $6 million. Ameren Illinois Electric Distribution revenues were decoupled from sales volumes beginning in 2017. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$5 million) and the effect of weather (estimate) on fuel and purchased power (-$1 million) in the table above.

•	Nonnuclear energy center operations and maintenance costs increased $31 million, primarily because of higher-than-normal scheduled outage costs and an increase in routine maintenance work.

•	MEEIA customer energy-efficiency program costs increased $20 million.

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•	Distribution maintenance expenditures increased $20 million, primarily due to increased reliability work, including vegetation management work and inspections, and increased system repairs and maintenance costs.

•	Labor and employee benefit costs increased $14 million, primarily because of an unrealized MTM loss in 2018 compared with a MTM gain in 2017 resulting from changes in the market value of company-owned life insurance and an increase in power restoration assistance provided to other utilities.

•	MEEIA customer energy-efficiency program costs increased $22 million.

•	Nonnuclear energy center operations and maintenance costs increased $3 million, primarily due to higher coal handling charges.

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Labor and employee benefit costs decreased $6 million, primarily due to a reduction in the base level of pension and postretirement expenses allowed in rates as a result of the March 2017 MoPSC electric rate order along with changes in the market value of company-owned life insurance, partially offset by higher labor costs resulting from increased power restoration assistance provided to other utilities and higher wages.

•	Solar rebate costs decreased $8 million, primarily as a result of the March 2017 MoPSC electric rate order.

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(a)	The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate increased the effective income tax rate for 2017 by 15 percentage points.

(b)	The impact of the revaluation of deferred income taxes as a result of the TCJA increased the effective income tax rate for 2017 by 6 percentage points.

(c)	The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate had no material effect on the effective income tax rate.

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•	A $220 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	A $27 million decrease in payments for nuclear refueling and maintenance outages at Ameren Missouri’s Callaway energy center. There was no refueling and maintenance outage in 2018; however, there were cash expenditures related to the 2019 scheduled outage paid in 2018.

•	The absence of $21 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

•	A net $88 million decrease resulting from costs and associated collections under various cost recovery mechanisms from Ameren Missouri and Ameren Illinois customers.

•	A $40 million decrease resulting from income tax payments of $21 million in 2018, compared with income tax refunds of $19 million in 2017, primarily due to state income tax refunds and the sale of state tax credits.

•	A $25 million increase in energy center maintenance costs at Ameren Missouri, primarily due to higher-than-normal, non-nuclear scheduled outage costs, and an increase in routine maintenance work.

•	A $19 million increase in payments related to donations.

•	A $17 million increase in interest payments, primarily due to an increase in the average outstanding debt balance at ATXI.

•	A $136 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	A net $95 million increase resulting from net energy costs and associated collections from customers under the FAC.

•	A decrease in income tax payments of $49 million to Ameren (parent) pursuant to the tax allocation agreement, primarily due to the lower federal income tax rate and lower property-related deductions.

•	A $27 million decrease in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center. There was no refueling and maintenance outage in 2018; however, there were cash expenditures related to the 2019 scheduled outage paid in 2018.

•	A net $183 million decrease resulting from costs and associated collections under various cost recovery mechanisms from customers.

•	A $50 million decrease resulting from income tax payments of $28 million, compared with income tax refunds of $22 million in 2017, to Ameren (parent) pursuant to the tax allocation agreement resulting primarily from the lower federal income tax rate and lower property-related deductions.

•	A $75 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	The absence of $17 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

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•	A $167 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	A $14 million decrease in coal inventory because of decreased market prices and decreased purchases at Ameren Missouri as a result of inventory reductions at its energy centers.

•	A net $83 million decrease resulting from costs and associated collections under various cost recovery mechanisms from Ameren Missouri and Ameren Illinois customers.

•	The absence of a $42 million insurance receipt received in 2016 at Ameren Missouri related to the Taum Sauk breach that occurred in December 2005.

•	Refunds paid in 2017 of $21 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

•	A $14 million increase in the cost of natural gas held in storage at Ameren Illinois, caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.

•	A $13 million increase in interest payments, primarily due to an increase in the average outstanding debt at Ameren Illinois.

•	An increase in income tax payments of $151 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to higher taxable income in 2017, because of significantly lower property-related deductions.

•	The absence of a $42 million insurance receipt received in 2016 related to the Taum Sauk breach that occurred in December 2005.

•	A net $47 million decrease resulting from costs and associated collections under various cost recovery mechanisms from customers.

•	A $70 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	A $14 million decrease in coal inventory as a result of decreased market prices and decreased purchases as a result of inventory reductions at the energy centers.

•	A $75 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	A $30 million increase resulting from income tax refunds of $22 million in 2017, compared with income tax payments of $8 million in 2016, pursuant to the tax allocation agreement with Ameren (parent), primarily related to tax losses in 2017 as a result of higher property-related deductions and use of net operating losses.

•	A net $36 million decrease resulting from costs and associated collections under various cost recovery mechanisms from customers.

•	Refunds paid in 2017 of $17 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

•	A $14 million increase in the cost of natural gas held in storage, caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.

•	A $13 million increase in interest payments, primarily due to an increase in the average outstanding debt.

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(a)	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 $700 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.

(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)	Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.

(b)	Excludes unamortized discount and premium and debt issuance costs of $70 million, $31 million, and $34 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of this report, for discussion of items included herein.

(c)	The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2018.

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

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•

On June 1, 2018, Missouri Senate Bill 564 was enacted. The provision of the law applicable to the TCJA was effective immediately; the remaining provisions, including the ability to elect PISA, became effective August 28, 2018. The law required the MoPSC to authorize a reduction in Ameren Missouri’s rates to pass through the effect of the TCJA within 90 days of the law’s effective date. In July 2018, the MoPSC authorized Ameren Missouri to reduce its annual revenue requirement by $167 million and reflect that reduction in rates beginning August 1, 2018. The reduction included $74 million for the amortization of excess accumulated deferred income taxes. In addition, Ameren Missouri recorded a reduction to revenue and a corresponding regulatory liability of $60 million for the excess amounts collected in rates related to the TCJA from January 1, 2018, through July 31, 2018. The regulatory liability will be reflected in customer rates over a period of time to be determined by the MoPSC in the next regulatory rate review. Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Accumulated PISA deferrals earn carrying costs at the weighted-average cost of capital, and all approved PISA deferrals will be added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. PISA mitigates the impacts of regulatory lag between regulatory rate reviews. The remaining 15% of certain property, plant, and equipment placed in service and not eligible for recovery under PISA, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. As a result of the PISA election, additional provisions of the new law apply to Ameren Missouri, including limitations on electric customer rate increases and an electric base rate freeze until April 2020. Both the rate increase limitation and PISA are effective through December 2023, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2028. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Missouri Senate Bill 564.

•

In February 2019, Ameren Missouri announced its Smart Energy Plan, which includes a five-year capital investment overview with a detailed one-year plan for 2019, designed to upgrade Ameren Missouri's electric infrastructure. The plan includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $6.3 billion over the five-year period from 2019 through 2023, with costs largely recoverable under PISA and, for the portion of wind and other renewable generation investments that are not recoverable under PISA, recoverable under the RESRAM.

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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, net of changes in the market price of such energy. Based on customer contracts, the program enables Ameren Missouri to supply up to 400 megawatts of renewable wind energy generation, up to 200 megawatts of which it could own. As applicable, the addition of generation by Ameren Missouri would be subject to the issuance of a certificate of convenience and necessity by the MoPSC, obtaining transmission interconnection agreements with MISO or other RTOs, and FERC approval. This generation would be incremental to estimated capital expenditures through 2023 discussed below. Ameren Missouri anticipates finalizing customer interest and pursuing renewable energy projects to fulfill requirements in 2019. Without extension, the option to elect into the program will terminate in the third quarter of 2023.

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In December 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2021 and low-income customer energy-efficiency programs through December 2024, along with a regulatory recovery mechanism. Ameren Missouri intends to invest $226 million over the life of the plan, including $65 million per year through 2021. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals, including $30 million if 100% of the goals are achieved during the period ended December 2021. Additional revenues may be earned if Ameren Missouri exceeds 100% of its energy savings goals.

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Ameren continues to make significant investments in FERC regulated electric transmission businesses. Ameren Illinois expects to invest $2.2 billion in electric transmission assets from 2019 through 2023, to replace aging infrastructure and improve reliability. ATXI has three MISO-approved multi-value projects: the Spoon River, Illinois Rivers, and Mark Twain projects. The Spoon River project, located in northwest Illinois, was placed in service in February 2018. The Illinois Rivers project involves the construction of a transmission line from eastern Missouri across Illinois to western Indiana. Construction of the Illinois Rivers project is substantially complete, with the last section awaiting the outcome of certain legal proceedings, which will delay the expected completion date to 2020. This delay is not expected to materially affect 2019 rate base or earnings. The Mark Twain project involves the construction of a transmission line from northeast Missouri, connecting the Illinois Rivers project to Iowa. Construction of the Mark Twain project began in the second quarter of 2018, and is expected to be completed by the end of 2019. ATXI’s expected remaining investment in its multi-value projects is approximately $150 million in 2019, with the total investment expected to be more than $1.6 billion.

•	Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base growth and the currently allowed 10.82% return on common equity, the

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The return on common equity for MISO transmission owners, including Ameren Illinois and ATXI, is the subject of a FERC complaint case filed in February 2015 challenging the allowed base return on common equity. Ameren Illinois and ATXI currently use the FERC authorized total allowed return on common equity of 10.82% in customer rates. A final FERC order would establish the allowed return on common equity to be applied to the 15-month period from February 2015 to May 2016 and also establish the return on common equity to be included in customer rates prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. In October 2018, the FERC issued an order addressing the remanded issues in an unrelated case. That order proposed a new methodology for determining the base return on equity and required further briefs from the participants. In November 2018, the FERC issued an order related to the February 2015 complaint case and the September 2016 final order, which required briefs from the participants to be filed in February 2019 regarding a new methodology for determining the base return on common equity and whether and how to apply the new methodology to the two MISO complaint cases. Ameren is unable to predict the ultimate impact of the proposed methodology on these complaint cases at this time. As the FERC is under no deadline to issue a final order, the timing of the issuance of the final order in the February 2015 complaint case, or any potential impact to the amounts refunded as a result of the September 2016 final order, is uncertain. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding FERC complaint cases. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren’s and Ameren Illinois’ net income by an estimated $9 million and $5 million, respectively, based on each company’s 2019 projected rate base.

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In November 2018, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $72 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2019. However, Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and investment return in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois’ 2019 electric distribution service revenues will be based on its 2019 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. The 2019 revenue requirement is expected to be higher than the 2018 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of approximately 8%, and an expected increase in the annual average of the monthly yields of the 30-year United States Treasury bonds. The 2019 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2021. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $8 million change in Ameren’s and Ameren Illinois’ net income, based on Ameren Illinois’ 2019 projected year-end rate base.

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Ameren Illinois is allowed to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at its weighted-average cost of capital, with the equity return based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return 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 $100 million per year in electric energy-efficiency programs through 2023 and will earn a return on those investments. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not included in the electric distribution formula ratemaking framework. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ energy-efficiency program.

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In November 2018, the ICC issued an order approving a stipulation and agreement that resulted in an annual natural gas rate increase of $32 million, based on a 9.87% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. This increase reflects the reduction in the federal statutory corporate income tax rate enacted under the TCJA, as well as the increase in the Illinois corporate income tax rate that became effective in July 2017, which collectively decreased annual rates by approximately $17 million. The new customer rates were effective in November 2018. As a result of this order, the rate base under the QIP rider was reset to zero. Ameren Illinois used a 2019 future test year in this proceeding.

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Ameren Missouri’s next scheduled refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2019. During the 2017 refueling, Ameren Missouri incurred maintenance expenses of $35 million. During a scheduled refueling, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, 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

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•	Ameren Missouri expects to realize lower costs of fuel for generation through 2023, compared to 2018 levels, based on coal and related transportation contracts and management’s outlook for future prices. Substantially all the benefit of these lower costs would be passed through to customers through the FAC.

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Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek regular electric and natural gas rate increases to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy-efficiency programs, 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 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.

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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 at least 700 megawatts of wind generation by the end of 2020 in Missouri and neighboring states 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 MISO or other RTOs, as well as the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC, and any other required project approvals.

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In connection with the 2017 IRP filing, Ameren Missouri established a goal of reducing CO2 emissions 80% by 2050 from a 2005 base level. Ameren Missouri is also targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level. In order to meet these goals, among other things, Ameren Missouri expects to retire its coal-fired generation at the end of each energy center’s useful life.

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In the second quarter of 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Terra-Gen, LLC to acquire, after construction, a 400-megawatt wind generation facility, which is expected to be located in northeastern Missouri. In October 2018, the MoPSC issued an order approving a unanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. In December 2018, Ameren Missouri received FERC approval to acquire the facility after construction. A transmission interconnection agreement with the MISO for this facility is expected in the fall of 2019. Also, in October 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of EDF Renewables, Inc. to acquire, after construction, a wind generation facility of up to 157 megawatts. In February 2019, Ameren Missouri filed with the MoPSC a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. The up to 157-megawatt facility is expected to be located in northwestern Missouri. A transmission interconnection agreement with the MISO for this facility is expected in early 2020. Both facilities are expected to be completed by the end of 2020 and would help Ameren Missouri comply with the Missouri renewable energy standard. Each acquisition is subject to certain conditions, including entering into a MISO transmission interconnection agreement at an acceptable cost for each facility and obtaining FERC approval and the issuance of a certificate of convenience and necessity by the MoPSC for the up to 157-megawatt facility, as well as other customary contract terms and conditions. These agreements collectively represent approximately $1 billion in capital expenditures expected in 2020, which is included in Ameren Missouri’s Smart Energy Plan. In October and December 2018, the MoPSC issued orders approving a RESRAM that allows Ameren Missouri to adjust customer rates on an annual basis without a traditional regulatory rate review. The RESRAM is designed to mitigate the impacts of regulatory lag for the cost of compliance with renewable energy standards, including recovery of investments in wind and

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Through 2023, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest up to $13.9 billion (Ameren Missouri – up to $7.1 billion; Ameren Illinois – up to $6.6 billion; ATXI – up to $0.2 billion) of capital expenditures during the period from 2019 through 2023. Any additional wind generation investments by Ameren Missouri beyond the two facilities that Ameren Missouri has agreed to acquire after construction would be incremental to these estimates.

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Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. Certain of these regulations are being challenged through litigation, are being reviewed or recommended for repeal by the EPA or new replacement or alternative regulations are being contemplated or proposed by the EPA and state regulators; therefore, the ultimate implementation of any of these regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.

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The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through December 2022, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $2.5 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.

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

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Ameren Missouri expects a decrease in operating cash flows of approximately $100 million in 2019 compared with 2018, as a result of the TCJA. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts, once approved by the MoPSC, resulting from lower accumulated deferred income tax liabilities.

•	The following table presents the net regulatory liabilities associated with excess deferred taxes as of December 31, 2018, and the related amortization periods:

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In 2018, our rate-regulated businesses began to amortize excess deferred taxes. Ameren Illinois and ATXI's 2018 income tax expense reflect a full year of amortization, while Ameren Missouri's 2018 income tax expense reflects five months of amortization related to its electric business, in accordance with a MoPSC order received in July 2018. The amortization of such balances related to Ameren Missouri’s gas business started in January 2019, in accordance with a MoPSC order received in December 2018. These amortizations reduce our income tax expense and effective tax rates. Due to formula ratemaking, Ameren Illinois Electric Distribution and Ameren Transmission have an offsetting reduction in revenue from customers, with no overall impact on earnings. Ameren Missouri and Ameren

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As of December 31, 2018, Ameren had $91 million in tax benefits from federal and state net operating loss carryforwards and $127 million in federal and state income tax credit carryforwards. These carryforwards are expected to largely offset income tax obligations in 2019. Ameren does not expect to make material federal or state income tax payments over the next five years based on planned capital expenditures and related income tax credits. Consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries, Ameren Missouri expects to make material income tax payments to Ameren (parent) in 2019 and 2020 and immaterial payments in 2021 through 2023 based on planned capital expenditures and related income tax credits, while Ameren Illinois expects to make material income tax payments to Ameren (parent) in 2020 through 2023.

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Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. To fund a portion of these cash requirements, beginning in the first quarter of 2018, Ameren began using newly issued shares, rather than market-purchased shares, to satisfy requirements under its DRPlus and employee benefit plans and expects to continue to do so over the next five years. Ameren also plans to issue incremental common equity to fund a portion of Ameren Missouri’s wind generation investments. Ameren, Ameren Missouri, and Ameren Illinois expect their respective equity to total capitalization levels over the period ending December 2023 to remain in-line with their respective equity to total capitalization levels as of December 31, 2018. 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).

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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•	long-term and short-term variable-rate debt;

•	fixed-rate debt;

•	United States Treasury bonds; and

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

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(a)	Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2019 represents January 2019 through March 2019. The year 2020 represents November 2019 through March 2020. This continues each successive year through March 2023.

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

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(a)	Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps.

(b)	Principally power forward contract values based on information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on an option valuation model.

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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 40,000 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. ATXI was incorporated in Illinois in 2006. ATXI is constructing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and operates the Spoon River project, which was placed in service in February 2018. Ameren also evaluates competitive electric transmission investment opportunities as they arise.

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

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•	macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;

•	pending regulatory rate review outcomes and projections of future regulatory rate review outcomes;

•	changes in laws and potential law changes;

•	observable industry market multiples;

•	achievement of IEIMA and FEJA performance metrics and the yield of the 30-year United States Treasury bonds;

•	changes in the FERC-allowed return on equity with respect to transmission services; and

•	projected operating results and cash flows.

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

(b)	Ameren Missouri changed its fair value estimate primarily because of an extension of the remediation period of certain CCR storage facilities, an update to the decommissioning of the Callaway energy center to reflect the cost study and funding analysis filed with the MoPSC in 2017, and an increase in the assumed discount rate.

(c)	Balance included $23 million and $6 million in “Other current liabilities” on the balance sheet as of December 31, 2018 and 2017, respectively.

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

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

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(a)	Amounts have been adjusted from those previously reported to reflect additional excise taxes for the years ended December 31, 2017 and 2016.

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(a)	Under-recovered or over-recovered fuel costs to be recovered or refunded through the FAC. Specific accumulation periods aggregate the under-recovered or over-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from, or refund to, customers that occurs over the next eight months.

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

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

(d)	The difference between Ameren Illinois’ electric distribution service annual revenue requirement calculated under the performance-based formula ratemaking framework and the revenue requirement included in customer rates for that year. Any under-recovery or over-recovery will be recovered from, or refunded to, customers with interest within two years.

(e)	These assets earn a return.

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(f)	Ameren Illinois’ and ATXI’s annual revenue requirement reconciliation calculated pursuant to the FERC’s electric transmission formula ratemaking framework. Any under-recovery or over-recovery will be recovered from, or refunded to, customers within two years.

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

(h)	These costs are being amortized in proportion to the recognition of prior service costs (credits) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 10 – Retirement Benefits for additional information.

(i)

The regulatory assets represent deferred income taxes that will be recovered from customers related to the equity component of allowance for funds used during construction and the effects of tax rate changes from the TCJA and the increased income tax rate in Illinois. The regulatory liabilities represent deferred income taxes that will be refunded to customers related to depreciation differences, other tax liabilities, and the unamortized portion of investment tax credits recorded at rates in excess of current statutory rates. Amounts associated with the equity component of allowance for funds used during construction, and the unamortized portion of investment tax credits will be amortized over the expected life of the related assets. The amortization periods for depreciation differences are determined in rate orders by the applicable regulators and range from 7 to 60 years. See Note 12 – Income Taxes for amounts related to the revaluation of deferred income taxes under the TCJA.

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

(k)	Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the original lives of the old debt issuances if no new debt was issued.

(l)	The recoverable portion of accrued environmental site liabilities that will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of remediation expenditures. See Note 14 – Commitments and Contingencies for additional information.

(m)	Storm costs from 2015, 2016, and 2018 deferred in accordance with the IEIMA. These costs are being amortized over five-year periods beginning in the year the storm occurred.

(n)

Demand-side costs incurred prior to implementation of the MEEIA in 2013, including the costs of developing, implementing, and evaluating customer energy-efficiency and demand response programs. The MoPSC’s March 2017 electric rate order modified certain amortization periods for these costs. Costs incurred from May 2008 through September 2008, and from January 2010 through July 2012, are being amortized over a two-year period that began in April 2017. Costs incurred from October 2008 through December 2009 are no longer being amortized as of April 2017, and a new amortization period for these costs will be determined in a future regulatory rate review. Costs incurred from August 2012 through December 2012 are being amortized over a six-year period that began in June 2015.

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

(p)	The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was included in customer rates beginning in 2011. These costs are being amortized over the expected life of the Sioux energy center, currently through 2033.

(q)	Costs associated with Ameren Missouri’s solar rebate program to fulfill its renewable energy requirements. Costs incurred from 2010 to 2014 are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. Costs incurred from 2015 to 2016 are being amortized over a three-year period that began in April 2017.

(r)

Electric energy-efficiency program investment deferrals which earn a return at Ameren Illinois’ weighted-average cost of capital with the equity return based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The investments are being amortized over their weighted-average useful lives beginning in the period in which they were made, with current remaining amortization periods ranging from 8 to 12 years.

(s)

The Ameren Missouri balance relates to the MEEIA. The MEEIA rider allows Ameren Missouri to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers for the MEEIA program costs, lost electric margins, and the performance incentive. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs, and lost electric margins are incurred or any performance incentive are earned. The Ameren Illinois balance relates to a regulatory tracking mechanism to recover its electric pre-FEJA costs and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. Any under-recovery or over-recovery will be collected from, or refunded to, customers over the year following the plan year.

(t)	Estimated refunds to transmission customers related to the February 2015 FERC complaint case discussed above.

(u)	Estimated funds collected for the eventual dismantling and removal of plant retired from service, net of salvage value.

(v)	Recoverable or refundable removal costs for AROs, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.

(w)

A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri and the level of such costs included in customer rates. For costs incurred prior to August 2012, the amounts are being amortized over a two-year period that began in April 2017 as modified per the MoPSC’s March 2017 electric rate order. For costs incurred between August 2012 and December 2014, the MoPSC’s May 2015 electric rate order directed the amortization period to occur over a five-year period that began in June 2015. For costs incurred between January 2015 and December 2016, the MoPSC’s March 2017 electric rate order directed the amortization period to occur over a five-year period that began in April 2017. For costs incurred after December 2016, the amortization period will be determined in a future electric regulatory rate review.

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

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

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(a)

Amounts in Ameren and Ameren Missouri include two CTs under separate agreements. The gross cumulative asset value of those agreements was $235 million and $233 million at December 31, 2018 and 2017, respectively. The total accumulated depreciation associated with the two CTs was $89 million and $83 million at December 31, 2018 and 2017, respectively. See Note 5 – Long-term Debt and Equity Financings for additional information on these agreements.

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

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

(a)	As of December 31, 2018, the estimated amortization expense of capitalized software for each of the five succeeding years is not expected to differ materially from the current year expense.

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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.

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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 2048 maturity of the 4.00% first mortgage bonds and the restrictions preventing a release date to occur that are attached to certain senior secured notes described in footnote (b) below, Ameren Missouri does not expect the first mortgage lien protection associated with these notes to fall away.

(b)

Ameren Missouri has agreed that so long as any of the 3.90% senior secured notes due 2042 are outstanding, Ameren Missouri will not permit a release date to occur, and so long as any of the 6.70% senior secured notes due 2019 and 8.45% senior secured notes due 2039 are outstanding, Ameren Missouri will not optionally redeem, purchase, or otherwise retire in full the outstanding first mortgage bonds not subject to release provisions.

(c)	These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri’s senior secured notes. The bonds are also backed by an insurance guarantee policy.

(d)	The interest rates and the periods during which such rates apply vary depending on our selection of defined rate modes. Maximum interest rates could reach 18%, depending on the series of bonds. The average interest rates for 2018 and 2017 were as follows:

(e)	These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture. They are secured by substantially all Ameren Missouri property and franchises. Less than $1 million principal amount of the bonds remain outstanding.

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

(g)

Payments due related to these financing obligations are paid to a trustee, which is authorized to utilize the cash only to pay equal amounts due to Ameren Missouri under related bonds issued by the city/county and held by Ameren Missouri. The timing and amounts of payments due from Ameren Missouri under the agreements are equal to the timing and amount of bond service payments due to Ameren Missouri, resulting in no net cash flow. The balance of both the financing obligations and the related investments in debt securities, recorded in "Other Assets," was $270 million and $276 million, respectively, as of December 31, 2018 and 2017.

(h)

These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under its 1992 mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the 2049 maturity date of the 4.50% first mortgage bonds, Ameren Illinois does not expect the first mortgage lien protection associated with these

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

(j)	These bonds are first mortgage bonds issued by Ameren Illinois under its 1933 mortgage indenture. They are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value. Less than $1 million principal amount of the bonds remain outstanding.

(k)	These bonds are first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS. The bonds are also backed by an insurance guarantee policy. Less than $1 million principal amount of the bonds remains outstanding.

(l)	These bonds are first mortgage bonds issued by Ameren Illinois under its 1992 mortgage indenture. They are secured by substantially all property of the former IP and CIPS.

(m)

These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under its 1933 mortgage indenture. They are secured by substantially all property of the former CILCO. The notes have a fall-away lien provision, and Ameren Illinois could cause these notes to become unsecured at any time by redeeming the 5.90% first mortgage bonds due 2023 (of which less than $1 million principal amount remains outstanding).

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

(a)	Excludes unamortized discount, unamortized premium, and debt issuance costs of $3 million, $31 million, $34 million and $2 million at Ameren (parent), Ameren Missouri, Ameren Illinois and ATXI, respectively.

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

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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.

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(b)	Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $2,006 million and $985 million at Ameren Missouri and Ameren Illinois, respectively.

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

(d)	Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under its 1992 mortgage indenture.

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

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(a)	For the year ended December 31, 2018, the non-service cost components of net periodic benefit income were partially offset by a $17 million deferral due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.

•	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 inventories that differ from the cost of those commodities in inventory; and

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

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(a)	Consists of ultra-low-sulfur diesel products.

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(a)	Before consideration of master netting arrangements or similar agreements and including NPNS and other accrual contract exposures.

(b)	As collateral requirements with certain counterparties are based on master netting arrangements or similar agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such arrangements.

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(a)	The derivative asset and liability balances are presented net of registrant and counterparty credit considerations.

(b)	Balance excludes $5 million and $4 million of cash and cash equivalents, receivables, payables, and accrued income, net for December 31, 2018 and 2017, respectively.

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(b)	Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2022 and 2021 for December 31, 2018 and 2017, respectively. Valuations beyond 2022 and 2021 for December 31, 2018 and 2017, respectively, use fundamentally modeled pricing by month for peak and off-peak demand.

(c)	Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.

(d)	Escalation rate applies to power prices in 2031 and beyond.

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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, 2018 and 2017, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value.

(b)

Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $58 million, $22 million, and $31 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2018. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $50 million, $20 million, and $24 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2017.

(c)	The Level 3 fair value amount consists of ATXI’s senior unsecured notes. In the first quarter of 2018, the amount was transferred to Level 3 because inputs to the valuation model became unobservable during the period.

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(a)	Represents net receivables and payables relating to pending security sales, interest, and security 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 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 security sales, offset by payables related to pending security 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.

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

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

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

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

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

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(b)	2018 amounts and the non-capitalized portion of 2017 and 2016’s non-service cost components, as discussed above, are reflected in “Other Income, Net” on Ameren’s statement of income. See Note 5 - Other Income, Net for additional information.

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(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.

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

(b)	Not applicable.

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(a)	Does not include 712,572 undistributed vested performance share units.

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

(c)	Does not include 619,783 of vested and undistributed performance share units and 26,557 of vested and undistributed restricted stock units.

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

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

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(a)	Reflects the adoption of authoritative accounting guidance related to stock-based compensation, which resulted in the recognition of a $21 million income tax benefit in 2016.

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(a)	Will expire between 2034 and 2037. Any net operating loss carryforward generated after January 1, 2018, will not have an expiration date as a result of the TCJA.

(b)	Will expire between 2029 and 2037.

(c)	Will expire between 2019 and 2022.

(d)	Will expire between 2019 and 2023.

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

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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.

(b)	Included a $38 million accrued capital contribution from 2015.

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(a)	Not applicable.

(b)	Amount less than $1 million.

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(a)	See Note 3 – Property, Plant, and Equipment, Net for additional information.

(b)	See Note 5 – Long-term Debt and Equity Financings for additional information on Ameren’s and Ameren Missouri’s capital lease agreements.

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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 2034 with various renewable energy suppliers due to the contingent nature of the payment amounts.

(c)	The purchased power amounts for Ameren and Ameren Missouri exclude a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024, due to the contingent nature of the payment amounts.

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

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

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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 $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.

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(b)	The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the years ended December 31, 2018, 2017, and 2016:

(a)	The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the years ended December 31, 2018, 2017, and 2016:

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(a)

2017 amounts have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers and the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.

(b)	Includes an increase to income tax expense of $154 million recorded in 2017 as a result of the TCJA.

(c)	The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is because of the effects of rounding and the changes in the number of weighted-average diluted shares outstanding each period.

(a)

2017 amounts have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers and the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.

(b)	Includes an increase to income tax expense of $32 million recorded in 2017 as a result of the TCJA.

(a)

2017 amounts have been revised to reflect the adoption of accounting guidance on revenue from contracts with customers and the presentation of net periodic pension and postretirement benefit cost, effective for the Ameren Companies as of January 1, 2018. See Note 1 – Summary of Significant Accounting Policies and Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.

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

ITEM 9A.	CONTROLS AND PROCEDURES

(a)	Evaluation of Disclosure Controls and Procedures

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

(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)

Pursuant to grants of performance share units (PSUs) and restricted stock units (RSUs) under the 2014 Incentive Plan, 1,393,223 of the securities represent the target number of PSUs granted but not vested and 187,314 of the securities represent the number of RSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 2018 (including outstanding awards under the 2014 Incentive Plan as of December 31, 2018). The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level, depending upon the achievement of total shareholder return objectives established for such awards. For additional information about the PSUs and RSUs, including payout calculations, see “Compensation Discussion and Analysis – Long-Term Incentive Compensation” in Ameren’s definitive proxy statement for its 2019 annual meeting of shareholders, which will be filed pursuant to SEC Regulation 14A. Also, 70,028 of the securities represent shares that may be issued as of December 31, 2018, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for members of the board of directors.

(b)	Consists of the 2014 Incentive Plan.

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

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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. The amounts relating to the deferred tax valuation allowance are for items that have expired and were removed from both the underlying accumulated deferred income tax account as well as the offsetting valuation account.

(b)	Uncollectible accounts charged off, less recoveries.

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

ITEM 16.	FORM 10-K SUMMARY

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