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

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

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries.

Below is a summary description of Ameren’s principal subsidiaries, which includes Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as providing shared services. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

•Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.
•Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.
•ATXI operates a FERC rate-regulated electric transmission business. ATXI is constructing MISO-approved electric transmission projects, 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.

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission primarily consists of the aggregated electric transmission businesses of Ameren Illinois and ATXI. See Note 15 – Segment Information under Part II, Item 8, of this report for further discussion of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ Segments.

Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding for the relevant period.

OVERVIEW

Ameren’s strategic plan includes investing in, and operating its utilities in, a manner consistent with existing regulatory frameworks, enhancing those frameworks, and advocating for responsible energy and economic policies, as well as creating and capitalizing on opportunities for investment for the benefit of its customers and shareholders. Ameren remains focused on disciplined cost management and strategic capital allocation. As discussed below, Ameren successfully executed on its strategic plan in 2018, with constructive outcomes received in various regulatory proceedings. With the enactment of legislation in Missouri, we believe constructive regulatory frameworks for investment exist at all of Ameren's utility businesses. In February 2019, Ameren Missouri announced its Smart Energy Plan to upgrade the electric grid and accommodate more renewable energy. In addition, Ameren Missouri advanced its transition of generation to a cleaner, more diverse portfolio by entering into two build-transfer agreements for the acquisition of up to 557 megawatts of wind generation in Missouri.

In 2018, Ameren’s utility businesses each received orders to reduce customer rates to reflect the benefits of a lower federal tax rate and, over time, to reflect the return of excess deferred taxes of over $2 billion. The return of excess deferred taxes to customers reduces operating cash flows but is expected to increase the rate base on which customer rates are established.

In June 2018, legislation was enacted in Missouri that enhanced Ameren Missouri’s electric regulatory framework. 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. This Missouri law maintains strong MoPSC oversight and consumer protections while supporting Ameren Missouri’s ability to strengthen and modernize Missouri’s electric grid.

In the second quarter of 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of Terra-Gen, LLC to acquire, after construction, a 400-megawatt wind generation facility, which is expected to be located in northeastern Missouri. In October 2018, the MoPSC issued an order approving a unanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. In December 2018, Ameren Missouri received FERC approval to acquire the facility after construction. A transmission interconnection agreement with the MISO for this facility is expected in the fall of 2019. Also, in October 2018, Ameren Missouri entered into a build-transfer agreement with a subsidiary of EDF Renewables, Inc. to acquire, after construction, a wind generation facility of up to 157 megawatts. In February 2019, Ameren Missouri filed with the MoPSC a nonunanimous stipulation and agreement regarding a requested certificate of convenience and necessity for the facility. The up to 157-megawatt facility is expected to be located in northwestern Missouri. A transmission interconnection agreement with the MISO for this facility is expected in early 2020. Both facilities are expected to be completed by the end of 2020 and would help Ameren Missouri comply with the Missouri renewable energy standard. Each acquisition is subject to certain conditions, including entering into a MISO transmission interconnection agreement at an acceptable cost for each facility and obtaining FERC approval and the issuance of a certificate of convenience and necessity by the MoPSC for the up to 157-megawatt facility, as well as other customary contract terms and conditions. These agreements collectively represent approximately $1 billion in capital expenditures expected in 2020, which is included in Ameren Missouri’s Smart Energy Plan. As outlined in its 2017 IRP, Ameren Missouri is pursuing at least 700 megawatts of wind generation by the end of 2020. 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 other renewable generation, by providing more timely recovery of costs and a return on investments not already provided for in customer rates or recovered under PISA.

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.

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

In April 2018, Ameren Illinois filed its annual electric distribution service formula rate update to establish the revenue requirement to be used for 2019 rates with the ICC. In November 2018, 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.

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.

ATXI’s Spoon River project, located in northwest Illinois, was placed in service in February 2018. Construction of the Illinois Rivers project is substantially complete, with the last section awaiting the outcome of certain legal proceedings, which will delay the expected completion date to 2020. This delay is not expected to materially affect 2019 rate base or earnings. Construction activities for ATXI’s Mark Twain project began in the second quarter of 2018, and the project is expected to be completed by the end of 2019.

In October 2018, Ameren’s board of directors increased the quarterly common stock dividend to 47.5 cents per share, resulting in an annualized equivalent dividend rate of $1.90 per share.

Earnings

Net income attributable to Ameren common shareholders was $815 million, or $3.32 per diluted share, for 2018, and $523 million, or $2.14 per diluted share, for 2017. Net income was favorably affected in 2018 compared with 2017 by the absence of a noncash charge to earnings for the revaluation of deferred taxes, primarily at Ameren (parent) as a result of federal and Illinois tax law changes, and by increased demand at Ameren Missouri, primarily due to warmer summer and colder winter temperatures in 2018. Earnings were also

favorably affected in 2018 compared with 2017 by an increase in base rates and a reduction in operating expenses for net energy costs and other expenses subject to regulatory tracking mechanisms at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order, by the absence of a Callaway energy center scheduled refueling and maintenance outage at Ameren Missouri, and by increased investments in infrastructure at the Ameren Illinois Electric Distribution and Ameren Transmission segments. Net income was unfavorably affected in 2018, compared with 2017 by increased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily due to higher-than-normal energy center scheduled outage and electric distribution maintenance costs at Ameren Missouri, and by increased depreciation and amortization expenses at Ameren Missouri.

Liquidity

At December 31, 2018, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.5 billion. In December 2018, the Credit Agreements were extended and now mature in December 2022.

Capital Expenditures

In 2018, Ameren continued to make significant investment in its utility businesses by making capital expenditures of $0.9 billion, $0.6 billion, $0.5 billion, and $0.3 billion in Ameren Missouri, Ameren Transmission, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. For 2019 through 2023, Ameren’s cumulative capital expenditures are projected to range from $12.8 billion to $13.9 billion. The projected spending by segment includes up to $7.1 billion, $2.7 billion, $2.5 billion, and $1.6 billion for Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively, including approximately $1 billion to acquire two wind generation facilities in 2020 at Ameren Missouri.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, energy-efficiency investments by our customers and by us, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by nuclear refueling and other energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. Almost all of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the prices we charge for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, within the frameworks established by our regulators. Our 2018 revenues include a reduction from 2017 revenues for the pass-through to customers of reduced income taxes resulting from TCJA, which is substantially offset by a reduction in income tax expense.

Ameren Missouri principally uses coal and nuclear fuel for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, and many other factors. As described below, we have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution business, and a FAC for Ameren Missouri’s electric business.

Ameren Missouri’s electric service and natural gas distribution service rates are established in a traditional regulatory rate review based on a historical test year and an allowed return on equity. To mitigate the effects of regulatory lag, Ameren Missouri has recovery mechanisms in place for certain costs that allow customer rates to be adjusted without a traditional regulatory rate review. Ameren Missouri’s FAC cost recovery mechanism allows it to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional regulatory rate review, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the related lost electric margins, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional regulatory rate review. Ameren Missouri also has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a tracker on certain excess deferred taxes, a renewable energy standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability. The difference will be reflected in base rates in a subsequent MoPSC rate order. Pursuant to its PISA election, Ameren Missouri is permitted to defer and recover 85% of the depreciation expense and a weighted-average cost of capital return on rate base on certain property, plant, and equipment placed in service after September 1, 2018, and not included in base rates. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of renewable generation plant placed in service not recovered under PISA. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Missouri’s PISA election and the RESRAM.

Ameren Illinois’ electric distribution service rates are reconciled annually to its actual revenue requirement and allowed return on equity, under a formula ratemaking process effective through 2022. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years. In addition, Ameren Illinois’ electric customer energy-efficiency rider provides Ameren Illinois’ electric distribution service business with recovery of, and return on, energy-efficiency investments. Under formula ratemaking for both its electric distribution service and its electric energy-efficiency investments, the revenue requirements are based on recoverable costs, year-end rate base, a capital structure of 50% common equity, and a return on equity. The return on equity component is equal to the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity for its electric distribution business is directly correlated to the yields on such bonds.

Ameren Illinois’ natural gas distribution service rates are established in a traditional regulatory rate review based on a future test year and allowed return on equity. Ameren Illinois employs a VBA to ensure recoverability of the natural gas distribution service revenue requirement for residential and small nonresidential customers that is dependent on sales volumes. For these rate classes, the VBA allows Ameren Illinois to adjust natural gas distribution service rates without a traditional regulatory rate review when changes occur in sales volumes from normalized sales volumes approved by the ICC in a previous regulatory rate review. In addition, the QIP rider provides Ameren Illinois’ natural gas business with recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews.

Ameren Illinois also has recovery mechanisms in place for certain costs that allow customer rates to be adjusted without a traditional regulatory rate review. Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers, renewable energy credit compliance, and zero emission credits. Ameren Illinois’ natural gas business has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through costs do not affect Ameren Illinois’ electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expenses and costs of certain asbestos-related claims not recovered in base rates.

FERC’s electric transmission formula rate framework provides for an annual reconciliation of the electric transmission service revenue requirement, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed return on equity. Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These rates are updated each January with forecasted information. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is collected from, or refunded to, customers within two years. The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.

We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of Ameren Missouri's energy centers and our transmission and distribution systems and the level and timing of operations and maintenance costs and capital investment are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.

Earnings Summary

The following table presents a summary of Ameren’s earnings for the years ended December 31, 2018, 2017, and 2016:

201820172016
Net income attributable to Ameren common shareholders$815$523$653
Earnings per common share – diluted3.322.142.68

2018 versus 2017

Net income attributable to Ameren common shareholders in 2018 increased $292 million, or $1.18 per diluted share, from 2017. The increase was due to net income increases of $155 million, $24 million, $10 million, and $5 million at Ameren Missouri, Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Illinois Electric Distribution, respectively. Additionally, the net loss for activity not reported as part of a segment, primarily at Ameren (parent), decreased $98 million.

Compared with 2017, 2018 earnings per share were favorably affected by:

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

result of a decrease in the federal statutory corporate income tax rate under the TCJA and an increase in the Illinois corporate income tax rate, partially offset by a noncash charge for updates to the revaluation of deferred taxes recorded in 2018 (64 cents per share);

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

Compared with 2017, 2018 earnings per share were unfavorably affected by:

•increased other operation and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily due to higher-than-normal energy center scheduled outage and electric distribution maintenance costs 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).

The cents per share information presented is based on the weighted-average basic shares outstanding in 2017 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 2018 statutory tax rate of 27%.

2017 versus 2016

Net income attributable to Ameren common shareholders in 2017 decreased $130 million, or $0.54 per diluted share, from 2016. The decrease was due to an increase in net loss of $125 million for activity not reported as part of a segment, primarily at Ameren (parent), and a net income decrease of $34 million at Ameren Missouri, both of which were primarily due to the enactment of the TCJA. The decrease was partially offset by a $23 million and a $5 million increase in net income from Ameren Transmission and Ameren Illinois Electric Distribution, respectively.

Compared with 2016, 2017 earnings per share were unfavorably affected by:

•an increase in income tax expense, primarily at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decrease in the federal statutory corporate income tax rate due to enactment of the TCJA (63 cents per share) and an increase in the Illinois corporate income tax rate (6 cents per share);
•decreased demand primarily at Ameren Missouri due to milder winter and summer temperatures in 2017 (estimated at 15 cents per share);
•the absence in 2017 of a MEEIA 2013 performance incentive at Ameren Missouri recognized in 2016 (7 cents per share);
•increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri resulting from additional electric property, plant, and equipment (6 cents per share); and
•increased transmission services charges at Ameren Missouri resulting from cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities (2 cents per share).

Compared with 2016, 2017 earnings per share were favorably affected by:

•an increase in base rates, net of increased revenues in 2016 from the suspension of operations at the New Madrid Smelter, and reduced operating expenses for net energy costs and other expenses subject to regulatory tracking mechanisms at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order (32 cents per share);
•increased Ameren Transmission earnings under formula ratemaking, primarily due to additional investment, partially offset by a lower recognized return on equity (9 cents per share);
•increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional investment and a higher recognized return on equity (4 cents per share); and
•decreased income tax expense, excluding the effect of corporate income tax rate changes discussed above, primarily at Ameren (parent) resulting from changes in the valuation allowance for charitable contributions, tax benefits related to company-owned life insurance, and tax credits in 2017, partially offset by a lower income tax benefit in 2017 related to stock-based compensation compared with 2016 (1 cent per share).

The cents per share information presented is based on the weighted-average basic shares outstanding in 2016 and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s 2017 statutory tax rate of 39%.

For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income, Net, Interest Charges, and Income Taxes, see the major headings below.

Below is Ameren’s table of income statement components by segment for the years ended December 31, 2018, 2017, and 2016:

2018Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren TransmissionOther / Intersegment EliminationsAmeren
Electric margins$2,518$1,065$—$433$(27)$3,989
Natural gas margins82—497—(1)578
Other operations and maintenance(972)(506)(241)(63)10(1,772)
Depreciation and amortization(550)(259)(65)(77)(4)(955)
Taxes other than income taxes(329)(75)(66)(4)(9)(483)
Other income, net5626974102
Interest charges(200)(73)(38)(75)(15)(401)
Income taxes(124)(41)(25)(56)9(237)
Net income (loss)48113771165(33)821
Noncontrolling interests – preferred stock dividends(3)(1)(1)(1)—(6)
Net income (loss) attributable to Ameren common shareholders$478$136$70$164$(33)$815
2017
Electric margins$2,429$1,109$—$426$(32)$3,932
Natural gas margins79—479—(2)556
Other operations and maintenance(925)(519)(227)(64)30(1,705)
Depreciation and amortization(533)(239)(59)(60)(5)(896)
Taxes other than income taxes(328)(74)(60)(6)(9)(477)
Other income, net6511—2886
Interest charges(207)(73)(36)(67)(8)(391)
Income taxes(254)(83)(36)(90)(113)(576)
Net income (loss)32613261141(131)529
Noncontrolling interests – preferred stock dividends(3)(1)(1)(1)—(6)
Net income (loss) attributable to Ameren common shareholders$323$131$60$140$(131)$523
2016
Electric margins$2,397$1,104$—$355$(28)$3,828
Natural gas margins79—462—(2)539
Other operations and maintenance(912)(551)(223)(63)16(1,733)
Depreciation and amortization(514)(226)(55)(43)(7)(845)
Taxes other than income taxes(325)(72)(58)(4)(8)(467)
Other income, net6222755101
Interest charges(211)(72)(34)(58)(7)(382)
Income taxes(216)(78)(39)(74)25(382)
Net income (loss)36012760118(6)659
Noncontrolling interests – preferred stock dividends(3)(1)(1)(1)—(6)
Net income (loss) attributable to Ameren common shareholders$357$126$59$117$(6)$653

Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2018, 2017, and 2016:

2018Ameren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Illinois TransmissionAmeren Illinois
Electric margins$1,065$—$267$1,332
Natural gas margins—497—497
Other operations and maintenance(506)(241)(52)(799)
Depreciation and amortization(259)(65)(50)(374)
Taxes other than income taxes(75)(66)(3)(144)
Other income, net269742
Interest charges(73)(38)(38)(149)
Income taxes(41)(25)(32)(98)
Net income1377199307
Preferred stock dividends(1)(1)(1)(3)
Net income attributable to common shareholder$136$70$98$304
2017
Electric margins$1,109$—$258$1,367
Natural gas margins—479—479
Other operations and maintenance(519)(227)(53)(799)
Depreciation and amortization(239)(59)(43)(341)
Taxes other than income taxes(74)(60)(3)(137)
Other income, net11—112
Interest charges(73)(36)(35)(144)
Income taxes(83)(36)(47)(166)
Net income1326178271
Preferred stock dividends(1)(1)(1)(3)
Net income attributable to common shareholder$131$60$77$268
2016
Electric margins$1,104$—$232$1,336
Natural gas margins—462—462
Other operations and maintenance(551)(223)(54)(828)
Depreciation and amortization(226)(55)(38)(319)
Taxes other than income taxes(72)(58)(2)(132)
Other income, net227534
Interest charges(72)(34)(34)(140)
Income taxes(78)(39)(41)(158)
Net income1276068255
Preferred stock dividends(1)(1)(1)(3)
Net income attributable to common shareholder$126$59$67$252

Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2018 compared with 2017, as well as 2017 compared with 2016. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Electric and Natural Gas Margins
2018 versus 2017Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Transmission(a)Other / Intersegment EliminationsAmeren
Electric revenue change:
Effect of weather (estimate)(b)$157$—$—$—$—$157
Base rates, including effects of TCJA (estimate)(c)(113)(23)—7—(129)
Recovery of power restoration efforts provided to other utilities58———13
Sales volume (excluding the estimated effects of weather and MEEIA)21————21
Off-system sales and capacity revenues(110)————(110)
MEEIA 2016 performance incentive11————11
Energy-efficiency program investments—13———13
Other62——614
Cost recovery mechanisms – offset in fuel and purchased power(d)3319———52
Other cost recovery mechanisms(e)30(40)———(10)
Total electric revenue change$40$(21)$—$7$6$32
Fuel and purchased power change:
Energy costs (excluding the estimated effect of weather)$109$—$—$—$—$109
Effect of weather (estimate)(b)(34)————(34)
Effect of lower net energy costs included in base rates9————9
Other(2)(4)——(1)(7)
Cost recovery mechanisms – offset in electric revenue(d)(33)(19)———(52)
Total fuel and purchased power change$49$(23)$—$—$(1)$25
Net change in electric margins$89$(44)$—$7$5$57
Natural gas revenue change:
Effect of weather (estimate)(b)$19$—$—$—$—$19
Base rates, including effects of TCJA (estimate)——(6)——(6)
QIP rider——13——13
Other——2—13
Cost recovery mechanisms – offset in natural gas purchased for resale(d)(7)—54——47
Other cost recovery mechanisms(e)——9——9
Total natural gas revenue change$12$—$72$—$1$85
Natural gas purchased for resale change:
Effect of weather (estimate)(b)$(16)$—$—$—$—$(16)
Cost recovery mechanisms – offset in natural gas revenue(d)7—(54)——(47)
Total natural gas purchased for resale change$(9)$—$(54)$—$—$(63)
Net change in natural gas margins$3$—$18$—$1$22
2017 versus 2016Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Transmission(a)Other / Intersegment EliminationsAmeren
Electric revenue change:
Effect of weather (estimate)(b)$(65)$(5)$—$—$—$(70)
Base rates (estimate)(c)6142—71—174
Recovery of power restoration efforts provided to other utilities71———8
Sales volume (excluding the estimated effects of weather and MEEIA)(6)————(6)
Off-system sales and capacity revenues22————22
MEEIA 2013 performance incentive(28)————(28)
Transmission services revenues11————11
Other————55
Cost recovery mechanisms – offset in fuel and purchased power(d)(11)18———7
Other cost recovery mechanisms(e)24(36)———(12)
Total electric revenue change$15$20$—$71$5$111
Fuel and purchased power change:
Energy costs (excluding the estimated effect of weather)$(22)$—$—$—$—$(22)
Effect of weather (estimate)(b)13(1)———12
Effect of lower net energy costs included in base rates39————39
Transmission services charges(16)————(16)
Other(8)4——(9)(13)
Cost recovery mechanisms – offset in electric revenue(d)11(18)———(7)
Total fuel and purchased power change$17$(15)$—$—$(9)$(7)
Net change in electric margins$32$5$—$71$(4)$104
Natural gas revenue change:
Effect of weather (estimate)(b)$(4)$—$—$—$—$(4)
QIP rider——12——12
Other——(3)——(3)
Cost recovery mechanisms – offset in natural gas purchased for resale(d)2—(28)——(26)
Other cost recovery mechanisms(e)——8——8
Total natural gas revenue change$(2)$—$(11)$—$—$(13)
Natural gas purchased for resale change:
Effect of weather (estimate)(b)$4$—$—$—$—$4
Cost recovery mechanisms – offset in natural gas revenue(d)(2)—28——26
Total natural gas purchased for resale change$2$—$28$—$—$30
Net change in natural gas margins$—$—$17$—$—$17
(a)Includes an increase in transmission 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.

2018 versus 2017

Ameren

Ameren’s electric margins increased $57 million, or 1%, in 2018 compared with 2017, primarily because of increased margins at Ameren Missouri partially offset by decreased margins at Ameren Illinois Electric Distribution. Ameren’s natural gas margins increased $22 million, or 4%, in 2018 compared with 2017, primarily because of increased margins at Ameren Illinois Natural Gas.

Ameren Transmission

Ameren Transmission’s margins increased $7 million, or 2%, in 2018 compared with 2017. Margins were favorably affected by increased capital investment, as evidenced by a 13% increase in rate base used to calculate the revenue requirement in 2018 compared with 2017. Margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, which decreased revenues $54 million in 2018 compared with 2017.

Ameren Missouri

Ameren Missouri’s electric margins increased $89 million, or 4%, in 2018 compared with 2017. Ameren Missouri’s natural gas margins increased $3 million, or 4%, in 2018 compared with 2017 primarily due to colder winter temperatures, as discussed below.

The following items had a favorable effect on Ameren Missouri’s electric margins in 2018 compared with 2017:

•Summer temperatures were warmer as cooling degree days increased 11% in 2018 compared with 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.
•Revenues from other cost recovery mechanisms due to MEEIA customer energy-efficiency program costs and gross receipts taxes, which increased margins $30 million. See Other Operations and Maintenance Expenses in this section for the related offsetting increase in MEEIA customer energy-efficiency program costs and Taxes Other Than Income Taxes in this section for the related offsetting increase in gross receipts taxes.
•Excluding the estimated effects of weather and the MEEIA 2016 customer energy-efficiency programs, total retail sales volumes increased 1%, which increased revenues by an estimated $21 million, primarily due to growth. While MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins ensured that electric margins were not affected.
•The MEEIA 2016 performance incentive, which increased revenues $11 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the MEEIA 2016 performance incentive.
•An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $5 million.

The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2018 compared with 2017:

•Lower electric base rates in accordance with the TCJA provisions in Missouri Senate Bill 564, partially offset by higher electric base rates, as a result of the March 2017 electric rate order. These items collectively decreased margins by an estimated $104 million in 2018 compared with 2017. The net change in electric base rates is the sum of the change in base rates (estimate) (-$113 million) and the effect of lower net energy costs included in base rates (+$9 million) in the table above.
•An increase in net energy costs as a result of increased sales volumes discussed above, partially offset by the 5% Ameren Missouri retains for the variance in net energy costs from the amount set in base rates, primarily as a result of lower fuel costs in 2018 compared with 2017, which collectively decreased margins $1 million. The change in net energy costs is the sum of the effect of revenue change in off-system sales and capacity revenues (-$110 million) and the effect of the change in energy costs (excluding the estimated effect of weather) (+$109 million) in the table above.

Ameren Illinois

Ameren Illinois’ electric margins decreased $35 million, or 3%, in 2018 compared with 2017 driven by decreased margins at Ameren Illinois Electric Distribution (-$44 million), partially offset by increased margins at Ameren Illinois Transmission (+$9 million). Ameren Illinois Natural Gas’ margins increased $18 million, or 4%, in 2018 compared with 2017.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins decreased $44 million, or 4%, in 2018 compared with 2017. The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s margins in 2018 compared with 2017:

•Revenues from other cost recovery mechanisms, primarily due to a decrease in recoverable customer energy-efficiency program costs prior to the FEJA, which decreased margins $40 million. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency program costs prior to the FEJA.
•Revenues decreased due to lower recoverable expenses in 2018 compared with 2017 under formula ratemaking, partially offset by an increase in rate base of 8% and a higher recognized return on common equity due to an increase in the 30-year United States Treasury bond yields of 22 basis points, which collectively decreased margins $23 million. The reduction in the federal statutory corporate income tax rate decreased recoverable expenses $52 million.

The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in 2018 compared with 2017:

•Revenues increased $13 million due to energy-efficiency program investments pursuant to the FEJA.
•An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $8 million.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins increased $18 million, or 4%, in 2018 compared with 2017. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins:

•Revenues from QIP recoveries, which increased margins $13 million due to additional investment in qualified natural gas infrastructure.
•Revenues from other cost recovery mechanisms, which increased margins $9 million.

Ameren Illinois Natural Gas’ margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, partially offset by higher natural gas base rates, as a result of the November 2018 natural gas rate order. These items collectively decreased margins by an estimated $6 million, in 2018 compared with 2017.

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins increased $9 million, or 3%, in 2018 compared with 2017. Margins were favorably affected by increased capital investment, as evidenced by an 18% increase in rate base used to calculate the revenue requirement in 2018 compared with 2017. Margins were unfavorably affected by the reduction in the federal statutory corporate income tax rate, which decreased revenues $32 million, in 2018 compared with 2017.

2017 versus 2016

Ameren

Ameren’s electric margins increased $104 million, or 3%, in 2017 compared with 2016 primarily because of increased margins at Ameren Transmission and Ameren Missouri. Ameren’s natural gas margins increased $17 million, or 3%, in 2017 compared with 2016 because of increased margins at Ameren Illinois Natural Gas.

Ameren Transmission

Ameren Transmission’s margins increased $71 million, or 20%, in 2017 compared with 2016. Margins were favorably affected by increased capital investment, as evidenced by a 23% increase in rate base used to calculate the revenue requirement in 2017 compared with 2016, as well as higher recoverable costs in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the allowed return on common equity for FERC-regulated transmission rate base.

Ameren Missouri

Ameren Missouri’s electric margins increased $32 million, or 1%, in 2017 compared with 2016. Ameren Missouri’s natural gas margins were comparable between years.

The following items had a favorable effect on Ameren Missouri’s electric margins in 2017 compared with 2016:

•Higher electric base rates, effective April 1, 2017, as a result of the March 2017 MoPSC electric rate order, which increased margins by an estimated $100 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$61 million) and the effect of lower net energy costs included in base rates (+$39 million) in the table above. Higher electric base rates incorporated the effect of the suspension of operations at the New Madrid Smelter.
•Revenues from other cost recovery mechanisms, primarily due to MEEIA customer energy-efficiency program costs, which increased margins $24 million. See Other Operations and Maintenance Expenses in this section for the related offsetting increase in MEEIA customer energy-efficiency program costs.
•Increased transmission services revenues due to additional rate base investment, which increased margins $11 million.
•An increase in power restoration assistance provided to other utilities and the associated recovery of labor and benefit costs for crews supporting those efforts, which increased revenues $7 million.

The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2017 compared with 2016:

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

Ameren Illinois

Ameren Illinois’ electric margins increased $31 million, or 2%, in 2017 compared with 2016 driven by increases in Ameren Illinois Electric Distribution (+$5 million) and Ameren Illinois Transmission (+$26 million) margins. Ameren Illinois Natural Gas’ margins increased $17 million, or 4%, in 2017 compared with 2016 primarily due to increased QIP rider recoveries, which increased margins $12 million.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $5 million, or less than 1%, in 2017 compared with 2016. Ameren Illinois Electric Distribution’s margins were favorably affected by an increase in rate base of 6% in 2017 compared with 2016 and a higher return on common equity due to an increase in the 30-year United States Treasury bond yields of 29 basis points in 2017 compared with 2016, as well as higher recoverable expenses under formula ratemaking pursuant to the IEIMA, which collectively increased margins $42 million.

The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s margins in 2017 compared with 2016:

•Revenues from other cost recovery mechanisms, primarily due to a decrease in recoverable customer energy-efficiency program costs prior to the FEJA, which decreased margins $36 million. See Other Operations and Maintenance Expenses in this section for the related offsetting decrease in customer energy-efficiency program costs prior to the FEJA.
•The absence of the impact of warmer-than-normal summer temperatures experienced in 2016, which decreased margins by an estimated $6 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.

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins increased $26 million, or 11%, in 2017 compared with 2016. Margins were favorably affected by increased capital investment, as evidenced by a 16% increase in rate base used to calculate the revenue requirement and higher recoverable costs in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.

Other Operations and Maintenance Expenses

2018 versus 2017

Ameren

Other operations and maintenance expenses were $67 million higher in 2018 compared with 2017. In addition to changes by segment discussed below, other operations and maintenance expenses increased $20 million in 2018 for activity not reported as part of a segment, primarily because of a decrease in intersegment eliminations.

Ameren Transmission

Other operations and maintenance expenses were comparable between 2018 and 2017.

Ameren Missouri

Other operations and maintenance expenses were $47 million higher in 2018 compared with 2017. The following items increased other operations and maintenance expenses between years:

•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.
•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.

The above increases were partially offset by a $29 million reduction in Callaway energy center refueling and maintenance outage costs. There was no Callaway refueling and maintenance outage in 2018; however, $6 million in preparation costs were incurred in 2018 for the 2019 scheduled outage.

Ameren Illinois

Other operations and maintenance expenses were comparable at Ameren Illinois and Ameren Illinois Transmission between 2018 and 2017.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses were $13 million lower in 2018 compared with 2017, primarily because of a $36 million decrease in customer energy-efficiency costs prior to the FEJA and a $3 million decrease in environmental remediation costs. These decreases were partially offset by a $21 million increase in labor and employee benefit costs, primarily because of an unrealized MTM loss in 2018 compared with a MTM gain in 2017 resulting from changes in the market value of company-owned life insurance and an increase in power restoration assistance provided to other utilities. Additionally, amortization of regulatory assets associated with the FEJA energy-efficiency program increased $9 million.

Ameren Illinois Natural Gas

Other operations and maintenance expenses were $14 million higher in 2018 compared with 2017, primarily because of increased operations and compliance expenditures related to pipeline integrity, higher bad debt expense, and increased customer energy-efficiency program costs.

2017 versus 2016

Ameren

Other operations and maintenance expenses decreased $28 million in 2017 compared with 2016. In addition to changes by segment discussed below, other operations and maintenance expenses decreased $14 million in 2017 for activity not reported as part of a segment, primarily because of an increase in intersegment eliminations.

Ameren Transmission

Other operations and maintenance expenses were comparable between 2017 and 2016.

Ameren Missouri

Other operations and maintenance expenses were $13 million higher in 2017 compared with 2016. The following items increased other operations and maintenance expenses between years:

•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.

The following items decreased other operations and maintenance expenses between years:

•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.

Ameren Illinois

Other operations and maintenance expenses decreased $29 million in 2017 compared with 2016, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2017 and 2016.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses were $32 million lower in 2017 compared with 2016, primarily because of a $47 million decrease in customer energy-efficiency program costs and a $3 million decrease in labor and employee benefit costs, partially offset by an $11 million increase in environmental remediation costs.

Ameren Illinois Natural Gas

Other operations and maintenance expenses were $4 million higher in 2017 compared with 2016, primarily because of increases in bad debt expense, customer energy-efficiency program costs, and environmental remediation costs, partially offset by lower labor and employee benefit costs.

Depreciation and Amortization

2018 versus 2017

Depreciation and amortization expenses increased $59 million, $17 million, and $33 million in 2018 compared with 2017 at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment across their respective segments. Additionally, depreciation and amortization expenses were higher at Ameren Missouri and Ameren Illinois Electric Distribution due to increased software amortization expenses.

2017 versus 2016

Depreciation and amortization expenses increased $51 million, $19 million, and $22 million in 2017 compared with 2016 at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment across their respective segments.

Taxes Other Than Income Taxes

2018 versus 2017

Taxes other than income taxes increased $6 million in 2018 compared with 2017, primarily because of higher gross receipts taxes at Ameren Missouri and Ameren Illinois Natural Gas, partially offset by a decrease in property taxes at Ameren Missouri due to lower assessed property values. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.

2017 versus 2016

Taxes other than income taxes increased $10 million in 2017 compared with 2016, primarily because of higher gross receipts taxes at Ameren Missouri and higher property taxes at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, resulting from a refund for 2015 electric distribution taxes that was received in 2016.

Other Income, Net

2018 versus 2017

Other income, net, increased $16 million in 2018 compared with 2017, primarily because of an increase in the non-service cost components of net periodic benefit income at Ameren Transmission and each of the Ameren Illinois segments, along with an increase in allowance for equity funds used during construction at Ameren Missouri, Ameren Transmission, and each of the Ameren Illinois segments, resulting from increased capital projects. These increases were partially offset by a decrease in Ameren Missouri’s non-service cost components of net periodic benefit income and increased donations at Ameren Missouri.

In addition to the changes discussed above, Other income, net, decreased in 2018 compared with 2017, due to activity not reported as part of a segment, primarily as a result of increased donations at Ameren (parent), partially offset by an increase in the non-service cost components of net periodic benefit income.

See Note 6 – Other Income, Net under Part II, Item 8, of this report for additional information. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for more information on the non-service cost components of net periodic benefit income.

2017 versus 2016

Other income, net, decreased $15 million in 2017 compared with 2016, primarily because of a decrease in the non-service cost

components of net periodic benefit income at Ameren Transmission and each of the Ameren Illinois segments, lower interest income associated with a lower IEIMA revenue requirement reconciliation regulatory asset balance at Ameren Illinois Electric Distribution, and a decrease in allowance for equity funds used during construction, primarily at Ameren Missouri. These decreases were partially offset by an increase in Ameren Missouri’s non-service cost components of net periodic benefit income.

In addition to the changes discussed above, Other income, net, increased in 2017 compared with 2016, due to activity not reported as part of a segment, primarily as a result of decreased donations at Ameren (parent).

Interest Charges

2018 versus 2017

Ameren

Interest charges increased $10 million in 2018 compared with 2017. Along with the changes discussed below, interest charges increased $7 million for activity not reported as part of a segment, primarily because of a decrease in intersegment borrowings at Ameren Transmission.

Ameren Transmission

Interest charges increased $8 million, primarily because of higher average outstanding debt at Ameren Illinois Transmission and ATXI, partially offset by decreased affiliate borrowings at ATXI.

Ameren Missouri

Interest charges decreased $7 million, primarily because of a decrease in the average interest rate of long-term debt, partially offset by an increase in average outstanding debt.

Ameren Illinois

Interest charges increased $5 million across the Ameren Illinois segments, primarily because of an increase in average outstanding debt, partially offset by a decrease in the average interest rate of long-term debt.

2017 versus 2016

Ameren

Interest charges increased $9 million in 2017 compared with 2016, as discussed below.

Ameren Transmission

Interest charges increased $9 million, primarily because of an increase in average outstanding debt at Ameren Illinois Transmission and ATXI.

Ameren Missouri

Interest charges decreased $4 million, primarily because of a decrease in the average interest rate of long-term debt.

Ameren Illinois

Interest charges increased $4 million across the Ameren Illinois segments, primarily because of an increase in average outstanding debt, partially offset by a decrease in the average interest rate of long-term debt.

Income Taxes

The following table presents effective income tax rates for the years ended December 31, 2018, 2017, and 2016:

201820172016
Ameren22%52%(a)37%
Ameren Missouri20%44%(b)38%
Ameren Illinois24%38%(c)38%
Ameren Illinois Electric Distribution23%38%(c)38%
Ameren Illinois Natural Gas26%38%(c)39%
Ameren Illinois Transmission24%37%(c)38%
Ameren Transmission25%39%(c)39%
(a)The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate increased the effective income tax rate for 2017 by 15 percentage points.
(b)The impact of the revaluation of deferred income taxes as a result of the TCJA increased the effective income tax rate for 2017 by 6 percentage points.
(c)The net impact of the revaluation of deferred income taxes as a result of the TCJA and the increase in the Illinois corporate income tax rate had no material effect on the effective income tax rate.

See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois, as well as a discussion of the effect of the TCJA and the revaluation of deferred taxes in 2017. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding reductions in revenues related to the lower federal statutory corporate income tax rate enacted under the TCJA and the return of excess deferred taxes to customers.

2018 versus 2017

Ameren

The effective income tax rate was lower in 2018 compared with 2017, primarily because of the decrease in the federal statutory corporate income tax rate from 35% to 21%, beginning in 2018, and revaluation of deferred taxes in 2017, resulting from both the enactment of the TCJA in 2017 and an increase in the Illinois corporate income tax rate in mid-2017. Additionally, the effective tax rate was lower due to amortization of excess deferred taxes in 2018. These items were offset by higher state income tax expense, as the increase in the Illinois corporate income tax rate in 2017 applied to the full year in 2018, and lower tax benefits related to company-owned life insurance in 2018.

Ameren Transmission

The effective income tax rate was lower in 2018 compared with 2017, primarily because of the decrease in the federal statutory corporate income tax rate, along with amortization of excess deferred taxes in 2018, partially offset by the increase in the Illinois corporate income tax rate applied to the full year in 2018.

Ameren Missouri

The effective income tax rate was lower in 2018 compared with 2017, primarily because of the decrease in the federal statutory corporate income tax rate in 2018, amortization of excess deferred taxes in 2018, and revaluation of deferred taxes in 2017.

Ameren Illinois

The effective tax rate was lower in 2018 compared with 2017 at Ameren Illinois and its respective segments, primarily because of the decrease in the federal statutory corporate income tax rate and amortization of excess deferred taxes in 2018, partially offset by the increase in the Illinois corporate income tax rate applied to the full year in 2018.

2017 versus 2016

Ameren

The effective income tax rate was higher in 2017 compared with 2016, primarily because of revaluation of deferred taxes due to enactment of the TCJA in 2017. In addition, income tax expense increased due to the revaluation of deferred taxes as a result of an increase in the Illinois income tax rate in 2017 and due to a decrease in the recognition of tax benefits associated with share-based compensation, resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. These items were partially offset by a reduction in the valuation allowance related to charitable contributions, due to higher-than-expected current-year taxable income.

Ameren Transmission

The effective income tax rate was comparable between years.

Ameren Missouri

The effective income tax rate was higher, primarily because of revaluation of deferred taxes due to the reduction in the federal statutory corporate income tax rate described above.

Ameren Illinois

The effective tax rate was comparable between years at Ameren Illinois and its respective segments.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash provided by operating activities, we use available cash, borrowings under the Credit Agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, other short-term affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). In the near term, our operating cash flows will decrease due to the reduction in the federal statutory income tax rate enacted under the TCJA. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2020 because of our use of net operating losses and tax credit carryforwards. Additionally, operating cash flows will be further reduced by lower customer rates, resulting from the return of excess deferred taxes. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts resulting from lower accumulated deferred income tax liabilities. We expect to make significant capital expenditures over the next five years as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy requirements, environmental compliance, and other improvements. As part of its plan to fund these cash flow requirements, beginning in the first quarter of 2018, Ameren began using newly issued shares, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2023. 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.

The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2018, for the Ameren Companies. The working capital deficit as of December 31, 2018, was primarily the result of current maturities of long-term debt and our decision to finance our businesses with lower-cost commercial paper issuances. With the credit capacity available under the Credit Agreements, along with cash and cash equivalents, Ameren had net available liquidity of $1.5 billion at December 31, 2018. See Credit Facility Borrowings and Liquidity below for additional information.

The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2018, 2017, and 2016:

Net Cash Provided by Operating ActivitiesNet Cash Used in Investing ActivitiesNet Cash Provided by (Used in) Financing Activities
201820172016201820172016201820172016
Ameren$2,170$2,118$2,117$(2,336)$(2,204)$(2,158)$205$102$(258)
Ameren Missouri1,2601,0171,169(976)(684)(937)(283)(331)(434)
Ameren Illinois659828796(1,248)(1,070)(918)62825551

Cash Flows from Operating Activities

Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional rate proceeding. Similar regulatory mechanisms exist for certain operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by changes in customer demand due to weather, significantly affect the amount and timing of our cash provided by operating activities. See Part 1, Item 1, and Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our rate-adjustment mechanisms.

2018 versus 2017

Ameren

Ameren’s cash from operating activities increased $52 million in 2018 compared with 2017. The following items contributed to the increase:

•A $220 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
•A $27 million decrease in payments for nuclear refueling and maintenance outages 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.

The following items partially offset the increase in Ameren’s cash from operating activities between years:

•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.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased $243 million in 2018 compared with 2017. The following items contributed to the increase:

•A $136 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
•A net $95 million increase resulting from net energy costs and associated collections from customers under the FAC.
•A decrease in income tax payments of $49 million to Ameren (parent) pursuant to the tax allocation agreement, primarily due to the lower federal income tax rate and lower property-related deductions.
•A $27 million decrease in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center. There was no refueling and maintenance outage in 2018; however, there were cash expenditures related to the 2019 scheduled outage paid in 2018.

The increase was partially offset by a $25 million increase in energy center maintenance costs, primarily due to higher-than-normal nonnuclear scheduled outage costs, and an increase in routine maintenance work between periods.

Ameren Illinois

Ameren Illinois’ cash from operating activities decreased $169 million in 2018 compared with 2017. The following items contributed to the decrease:

•A net $183 million decrease resulting from costs and associated collections under various cost recovery mechanisms from customers.
•A $50 million decrease resulting from 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.

The following items partially offset the decrease in Ameren Illinois’ cash from operating activities between periods:

•A $75 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
•The absence of $17 million in refunds paid in 2017 associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

2017 versus 2016

Ameren

Ameren’s cash from operating activities were comparable between 2017 and 2016. The following items increased cash from operating activities:

•A $167 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
•A $14 million decrease in coal inventory because of decreased market prices and decreased purchases at Ameren Missouri as a result of inventory reductions at its energy centers.

The following items largely offset the increase in Ameren’s cash from operating activities during 2017, compared with 2016:

•A net $83 million decrease resulting from costs and associated collections under various cost recovery mechanisms from Ameren Missouri and Ameren Illinois customers.
•The absence of a $42 million insurance receipt received in 2016 at Ameren Missouri related to the Taum Sauk breach that occurred in December 2005.
•Refunds paid in 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.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased $152 million in 2017 compared with 2016. The following items contributed to the decrease:

•An increase in income tax payments of $151 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to higher taxable income in 2017, because of significantly lower property-related deductions.
•The absence of a $42 million insurance receipt received in 2016 related to the Taum Sauk breach that occurred in December 2005.
•A net $47 million decrease resulting from costs and associated collections under various cost recovery mechanisms from customers.

The following items partially offset the decrease in Ameren Missouri’s cash from operating activities between years:

•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.

Ameren Illinois

Ameren Illinois’ cash from operating activities increased $32 million in 2017 compared with 2016. The following items contributed to the increase:

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

The following items partially offset the increase in Ameren Illinois’ cash from operating activities between periods:

•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.

Pension Plans

Ameren’s pension plans are funded in compliance with income tax regulations, federal funding, and other regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on Ameren’s assumptions at December 31, 2018, its investment performance in 2018, and its pension funding policy, Ameren expects to make annual contributions of $20 million to $70 million in each of the next five years, with aggregate estimated contributions of $200 million. We estimate that Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements will be approximately 30% and 60%, respectively. These estimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In 2018, Ameren contributed $60 million to its pension plans. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.

Cash Flows from Investing Activities

2018 versus 2017

Ameren’s cash used in investing activities increased $132 million during 2018 compared with 2017, primarily as a result of increased capital expenditures of $154 million, partially offset by an $11 million decrease due to the timing of nuclear fuel expenditures. Increased capital expenditures at Ameren Missouri and Ameren Illinois, discussed below, were partially offset by a $171 million decrease in capital expenditures at ATXI. ATXI’s capital expenditures decreased as a result of decreased expenditures on the Illinois Rivers and Spoon River projects. The Spoon River project was placed in service in February 2018.

Ameren Missouri’s cash used in investing activities increased $292 million during 2018 compared with 2017, primarily due to money pool activity and increased capital expenditures. During 2018, Ameren Missouri had no money pool activity, compared with $161 million in returns of net money pool advances received during 2017. Additionally, capital expenditures increased $141 million between periods, primarily related to energy center projects and electric distribution system reliability projects. The increase in capital expenditures was partially offset by an $11 million decrease due to the timing of nuclear fuel expenditures.

Ameren Illinois’ cash used in investing activities increased $178 million during 2018 compared with 2017 due to an increase in capital expenditures of $182 million, primarily related to substation upgrades, upgrades to natural gas main infrastructure, and electric transmission system reliability projects.

2017 versus 2016

Ameren’s cash used in investing activities increased $46 million during 2017 compared with 2016, primarily as a result of increased capital expenditures of $56 million. Increased capital expenditures at Ameren Missouri and Ameren Illinois, discussed below, were partially offset by a $127 million decrease in capital expenditures at ATXI. Reduced spending on ATXI’s Illinois Rivers project was partially offset by an increase in spending on its Spoon River project.

Ameren Missouri’s cash used in investing activities decreased $253 million during 2017 compared with 2016, primarily because of net money pool advances. During 2017, Ameren Missouri received $161 million in returns of net money pool advances compared with investing $125 million in net money pool advances in 2016. This decrease was partially offset by a $35 million increase in capital expenditures, primarily related to electric distribution and transmission system reliability projects and energy center projects.

Ameren Illinois’ cash used in investing activities increased $152 million during 2017 compared with 2016 because of increased capital expenditures, primarily related to electric transmission system reliability projects and natural gas infrastructure projects.

Capital Expenditures

The following table presents our capital expenditures for the years ended December 31, 2018, 2017, and 2016:

201820172016
Ameren Missouri$914$773$738
Ameren Illinois Electric Distribution503476470
Ameren Illinois Natural Gas311245181
Ameren Illinois Transmission444355273
ATXI118289416
Other (a)(4)(6)(2)
Ameren$2,286$2,132$2,076
(a)Includes amounts for the elimination of intercompany transfers.

Ameren’s 2018 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $118 million primarily on the Illinois Rivers and Mark Twain projects. Ameren Illinois spent $444 million on transmission projects, $188 million on natural gas projects eligible for QIP recovery, and $89 million on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects.

Ameren’s 2017 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $289 million primarily on the Illinois Rivers and Spoon River projects. Ameren Illinois spent $355 million on transmission projects, $153 million on natural gas projects eligible for QIP recovery, and $123 million on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology. Additionally, the Ameren Companies invested in various software projects.

Ameren’s 2016 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $416 million primarily on the Illinois Rivers project. Ameren Illinois spent $273 million on transmission projects and $109 million on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.

The following table presents Ameren’s estimate of capital expenditures that will be incurred from 2019 through 2023, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations:

20192020-2023Total
Ameren Missouri$1,070$5,410–$5,980$6,480–$7,050
Ameren Illinois Electric Distribution4951,925–2,1252,420–2,620
Ameren Illinois Natural Gas3501,165–1,2901,515–1,640
Ameren Illinois Transmission3601,765–1,9502,125–2,310
ATXI15565–70220–225
Other55–510–10
Ameren$2,435$10,335–$11,420$12,770–$13,855

Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, as well as expenditures for compliance with environmental regulations. In addition, Ameren Missouri’s estimated capital expenditures include approximately $1 billion in wind generation investments expected in 2020. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, capital expenditures to modernize its distribution system pursuant to the IEIMA, and capital expenditures for qualified investments in natural gas infrastructure under the QIP rider. ATXI’s estimated capital expenditures include expenditures for the two MISO-approved multi-value transmission projects. For additional information regarding Ameren Missouri’s build-transfer wind agreements, IEIMA capital expenditure requirements, the QIP rider, and ATXI’s transmission projects, see Part I, Item 1, of this report.

Ameren Missouri continually reviews its generation portfolio and expected power needs. As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments within and outside our service territories. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, among other factors. Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.

Environmental Capital Expenditures

Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO2, NOx, and mercury emissions from its coal-fired energy centers. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws that affect, or may affect, our facilities and capital expenditures to comply with such laws.

Cash Flows from Financing Activities

Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the level of dividends, and our long-term debt maturities, among other things.

2018 versus 2017

Ameren’s cash provided by financing activities increased $103 million during 2018 compared with 2017. During 2018, Ameren utilized net proceeds from the issuance of $1,464 million of long-term indebtedness and net commercial paper issuances and cash on hand to repay $841 million of higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during 2017, Ameren utilized net proceeds from the issuance of $1,345 million of long-term indebtedness to repay $681 million of higher-cost long-term indebtedness, to repay $74 million of net commercial paper issuances, and to fund, in part, investing activities. During 2018, Ameren made $451 million in dividend payments to shareholders, compared with $431 million in dividend payments in 2017. Additionally, Ameren issued $74 million in common stock under its DRPlus and 401(k) plan during 2018. Ameren also issued $35 million of common stock related to stock-based compensation resulting in noncash financing activity during 2018, compared with $24 million paid for the repurchase of common stock for stock-based compensation in 2017. Ameren did not issue common stock in 2017.

Ameren Missouri’s cash used in financing activities decreased $48 million in 2018 compared with 2017. During 2018, Ameren Missouri utilized net proceeds from the issuance of $439 million of long-term indebtedness and net commercial paper issuances, along with cash on hand, to repay $384 million of higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during 2017, Ameren Missouri utilized net proceeds from the issuance of $438 million of long-term indebtedness and net commercial paper issuances, along with cash on hand, to repay $431 million of higher-cost long-term indebtedness. In 2018, Ameren Missouri paid $375 million in common stock dividends, compared with $362 million in dividend payments in 2017. Additionally, during 2018, Ameren Missouri received $45 million in capital contributions from Ameren (parent), associated with the tax allocation agreement, compared with $30 million received in 2017.

Ameren Illinois’ cash provided by financing activities increased $373 million in 2018, compared with 2017. During 2018, Ameren Illinois utilized net proceeds from the issuance of $939 million of long-term indebtedness and net commercial paper issuances to repay at maturity $457 million of higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during 2017, Ameren Illinois issued $507 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay $250 million of higher-cost long-term indebtedness, and to fund, in part, investing activities. Additionally, during 2018, Ameren Illinois received $160 million in capital contributions from Ameren (parent), compared with $8 million received in 2017.

2017 versus 2016

Ameren’s financing activities provided net cash of $102 million in 2017 compared with using net cash of $258 million in 2016. During 2017, Ameren utilized net proceeds from the issuance of $1,345 million of long-term indebtedness to repay $681 million of higher-cost long-term indebtedness, to repay $74 million of net commercial paper issuances, and to fund, in part, investing activities. In comparison, during 2016, Ameren utilized net proceeds from the issuance of $653 million of long-term indebtedness and net commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and to fund, in part, investing activities. Additionally, during 2017, Ameren made $431 million in dividend payments to shareholders, compared with $416 million in dividend payments in 2016.

Ameren Missouri’s cash used in financing activities decreased $103 million in 2017 compared with 2016. During 2017, Ameren Missouri utilized net proceeds from the issuance of $438 million of long-term indebtedness and net commercial paper issuances to repay $431 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In 2017, Ameren Missouri paid $362 million in dividends to Ameren (parent), compared with $355 million dividends paid in 2016. Additionally, during 2017, Ameren Missouri received $30 million in capital contributions from Ameren (parent) associated with the tax allocation agreement, compared with $44 million received in 2016.

Ameren Illinois’ cash provided by financing activities increased by $204 million in 2017, compared with 2016. During 2017, Ameren Illinois utilized net proceeds from the issuance of $507 million of long-term indebtedness and net commercial paper issuances to repay at maturity $250 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Illinois issued $298 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay at maturity $129 million of higher-cost long-term indebtedness. Additionally, in 2017, no dividends were paid to Ameren (parent), compared with $110 million paid in 2016.

Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, or proceeds from borrowings under the Credit Agreements, commercial paper issuances and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional

information on credit agreements, commercial paper issuances, borrowings under Ameren’s money pool arrangements, and relevant interest rates.

The following table presents Ameren’s consolidated net available liquidity as of December 31, 2018:

Available at December 31, 2018
Ameren (parent) and Ameren Missouri (a):
Missouri Credit Agreement – borrowing capacity$1,000
Less: Ameren (parent) commercial paper outstanding274
Less: Ameren Missouri commercial paper outstanding55
Less: Letters of credit7
Missouri Credit Agreement – subtotal664
Ameren (parent) and Ameren Illinois(b):
Illinois Credit Agreement – borrowing capacity1,100
Less: Ameren (parent) commercial paper outstanding196
Less: Ameren Illinois commercial paper outstanding72
Less: Letters of credit2
Illinois Credit Agreement – subtotal830
Subtotal$1,494
Cash and cash equivalents16
Net Available Liquidity$1,510
(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.

In December 2018, the Credit Agreements, which were scheduled to mature in December 2021, were extended and now mature in December 2022. The Credit Agreements provide $2.1 billion of credit cumulatively through maturity. The maturity date may be extended for an additional one-year period upon mutual consent of the borrowers and lenders. Borrowings by Ameren (parent) under either of the Credit Agreements are due and payable no later than the maturity date, while borrowings by Ameren Missouri and Ameren Illinois are due and payable no later than the earlier of the maturity date or 364 days after the date of such borrowing (subject to the right of each borrower to re-borrow in accordance with the terms of the applicable Credit Agreement). The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the credit agreements are available to Ameren (parent) to support issuances under Ameren (parent)’s commercial paper program, subject to available credit capacity under the agreements. The Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. The Illinois Credit Agreement is available to support issuances under Ameren Illinois’ commercial paper program. Issuances under the Ameren (parent), Ameren Missouri, and Ameren Illinois commercial paper programs were available at lower interest rates than the interest rates of borrowings under the Credit Agreements. Commercial paper issuances were thus preferred to credit facility borrowings as a source of third-party short-term debt.

Ameren has a money pool agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option has the lowest interest rates. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for a detailed explanation of the utility money pool arrangement.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval under the Federal Power Act. In 2018, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 2020 and September 2020, respectively. In June 2017, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2019.

The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements for changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or to other short-term borrowing arrangements.

Long-term Debt and Equity

The following table presents Ameren’s equity issuances, as well as issuances (net of issuance premiums or discounts), redemptions, repurchases, and maturities of long-term debt for the years ended December 31, 2018, 2017, and 2016. For additional information related to the terms and uses of these issuances and effective registration statements, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report. For information on capital contributions received by Ameren Missouri and Ameren Illinois from Ameren (parent), see Note 13 – Related-party Transactions under Part II, Item 8 of this report.

Month Issued, Redeemed, Repurchased, or Matured201820172016
Issuances of Long-term Debt
Ameren Missouri:
4.00% First mortgage bonds due 2048April$423$—$—
2.95% Senior secured notes due 2027June—399—
3.65% Senior secured notes due 2045June——149
Ameren Illinois:
3.80% First mortgage bonds due 2028May430——
4.50% First mortgage bonds due 2049November499——
3.70% First mortgage bonds due 2047November—496—
4.15% Senior secured notes due 2046December——247
ATXI:
3.43% Senior notes due 2050June—150—
3.43% Senior notes due 2050August—300—
Total long-term debt issuances$1,352$1,345$396
Issuances of Common Stock
Ameren:
DRPlus and 401(k)Various$74(a)(b)$—$—
Total common stock issuances$74$—$—
Total Ameren long-term debt and common stock issuances$1,426$1,345$396
Redemptions, Repurchases, and Maturities of Long-term Debt
Ameren Missouri:
6.00% Senior secured notes due 2018April179——
5.10% Senior secured notes due 2018August199——
6.40% Senior secured notes due 2017June—425—
5.40% Senior secured notes due 2016February——260
City of Bowling Green financing obligation (Peno Creek CT)December666
Ameren Illinois:
6.25% Senior secured notes due 2018April144——
9.75% Senior secured notes due 2018November313——
6.125% Senior secured notes due 2017November—250—
6.20% Senior secured notes due 2016June——54
6.25% Senior secured notes due 2016June——75
Total long-term debt redemptions, repurchases, and maturities$841$681$395

(a) Ameren issued a total of 1.2 million shares of common stock under its DRPlus and 401(k) plan.

(b) Excludes 0.7 million shares of common stock valued at $35 million issued in connection with stock-based compensation.

The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

At December 31, 2018, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreement.

We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in

the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

Ameren paid to its shareholders common stock dividends totaling $451 million, or $1.8475 per share, in 2018, $431 million, or $1.7775 per share, in 2017, and $416 million, or $1.715 per share, in 2016.

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On February 8, 2019, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 47.5 cents per share, payable on March 29, 2019, to shareholders of record on March 13, 2019.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances.

Ameren Illinois’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions with respect to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in the capital structure at Ameren Illinois.

Ameren Missouri and Ameren Illinois, as well as certain other nonregistrant Ameren subsidiaries, are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and from retained earnings. In addition, under Illinois law, Ameren Illinois and ATXI may not pay any dividend on their respective stock unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provisions are made for reasonable and proper reserves, or unless Ameren Illinois or ATXI has specific authorization from the ICC.

At December 31, 2018, the amount of restricted net assets of Ameren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $2.8 billion.

The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren subsidiaries to their parent, Ameren:

201820172016
Ameren$451$431$416
Ameren Missouri375362355
Ameren Illinois——110
ATXI75——

Ameren Missouri and Ameren Illinois each have issued preferred stock, which provides for cumulative preferred stock dividends. Each company’s board of directors considers the declaration of preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.

Contractual Obligations

The following table presents our contractual obligations as of December 31, 2018. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans, which are not included in the table below. In addition, routine short-term purchase order commitments are not included.

20192020 – 20212022 – 20232024 and ThereafterTotal
Ameren:(a)
Long-term debt and financing obligations(b)$580$450$745$6,734$8,509
Interest payments(c)3486536254,2815,907
Operating leases101511945
Other obligations(d)7997462211661,932
Total cash contractual obligations$1,737$1,864$1,602$11,190$16,393
Ameren Missouri:
Long-term debt and financing obligations(b)$580$100$295$3,054$4,029
Interest payments(c)1763223191,9342,751
Operating leases81310940
Other obligations(d)4674891951301,281
Total cash contractual obligations$1,231$924$819$5,127$8,101
Ameren Illinois:
Long-term debt(b)$—$—$400$2,930$3,330
Interest payments(c)1332662532,1402,792
Operating leases1———1
Other obligations(d)3222432620611
Total cash contractual obligations$456$509$679$5,090$6,734
(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.

Off-balance-sheet Arrangements

At December 31, 2018, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, variable interest entities, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for further detail concerning variable interest entities.

Credit Ratings

Our credit ratings affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.

The following table presents the principal credit ratings of the Ameren Companies by Moody’s and S&P effective on the date of this report:

Moody’sS&P
Ameren:
Issuer/corporate credit ratingBaa1BBB+
Senior unsecured debtBaa1BBB
Commercial paperP-2A-2
Ameren Missouri:
Issuer/corporate credit ratingBaa1BBB+
Secured debtA2A
Senior unsecured debtBaa1Not Rated
Commercial paperP-2A-2
Ameren Illinois:
Issuer/corporate credit ratingA3BBB+
Secured debtA1A
Senior unsecured debtA3BBB+
Commercial paperP-2A-2
ATXI:
Issuer credit ratingA2Not Rated
Senior unsecured debtA2Not Rated

A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

Collateral Postings

Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial at December 31, 2018. A sub-investment-grade issuer or senior unsecured debt rating (below “Baa3” from Moody’s or below “BBB-” from S&P) at December 31, 2018, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade obligations amounting to $94 million, $64 million, and $30 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2018, if market prices were 15% higher or lower than December 31, 2018, levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade obligations.

OUTLOOK

We seek to earn competitive returns on investments in our businesses. We seek to improve our regulatory frameworks and cost recovery mechanisms and are simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We align our overall spending, both operating and capital, with economic conditions and with the frameworks established by our regulators, to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity and allocating capital resources to business opportunities that we expect will offer the most attractive risk-adjusted return potential.

As part of Ameren’s strategic plan, we pursue projects to meet our customers’ energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories. Ameren also evaluates competitive electric transmission investment opportunities as they arise. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition to a more diverse energy generation portfolio, including investments in renewable energy resources and the retirement of its coal-fired generation at the end of each energy center’s useful life.

Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2019 and beyond.

Operations

•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.
•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.
•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.
•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

2019 revenue requirements included in rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $297 million and $177 million, respectively. These revenue requirements represent an increase in Ameren Illinois' and ATXI’s revenue requirements of $24 million and $3 million, respectively, primarily because of the rate base growth. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2019, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2019 actual recoverable costs, rate base, and return on common equity as calculated under the FERC formula ratemaking framework.

•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.
•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.
•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.
•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.
•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

power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri may incur increased nonnuclear energy center maintenance costs in non-outage years.

•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.
•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.

For additional information regarding recent rate orders, lawsuits, and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

Liquidity and Capital Resources

•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.
•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.
•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

other renewable generation, by providing more timely recovery of costs and a return on investments not already provided for in customer rates or recovered under PISA.

•Through 2023, 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.
•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.
•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.
•Federal income tax legislation enacted under the TCJA will continue to have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA, among other things, reduced the federal statutory corporate income tax rate from 35% to 21%, effective January 1, 2018. Customer rates were reduced to reflect the lower income tax rate, without a corresponding reduction in income tax payments because of our use of net operating losses and tax credit carryforwards until about 2020. Customer rates were also reduced to reflect the return of excess deferred taxes. The result of these customer rate reductions is a decrease in operating cash flows in the near term. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts resulting from lower accumulated deferred income tax liabilities.
•Ameren Missouri expects a decrease in operating cash flows of approximately $100 million in 2019 compared with 2018, as a result of the TCJA. Over time, the decrease in operating cash flows will be offset as temporary differences between book and taxable income reverse, and by increased customer rates due to higher rate base amounts, once approved by the MoPSC, resulting from lower accumulated deferred income tax liabilities.
•The following table presents the net regulatory liabilities associated with excess deferred taxes as of December 31, 2018, and the related amortization periods:
Amortization PeriodAmeren MissouriAmeren IllinoisATXITotal
30 – 60 years$947$796$84$1,827
7 – 10 years524(4)2522
Total$1,471$792$86$2,349
•In 2018, our rate-regulated businesses began to amortize excess deferred taxes. Ameren Illinois and ATXI's 2018 income tax expense reflect a full year of amortization, while Ameren Missouri's 2018 income tax expense reflects five months of amortization related to its electric business, in accordance with a MoPSC order received in July 2018. The amortization of such balances related to Ameren Missouri’s gas business started in January 2019, in accordance with a MoPSC order received in December 2018. These amortizations reduce our income tax expense and effective tax rates. Due to formula ratemaking, Ameren Illinois Electric Distribution and Ameren Transmission have an offsetting reduction in revenue from customers, with no overall impact on earnings. Ameren Missouri and Ameren

Illinois Natural Gas 2019 interim period earnings may be affected by timing differences between income tax expense and revenue reductions based on their revenue patterns; however, no material impact to year-over-year earnings is expected.

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

The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.

REGULATORY MATTERS

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

ACCOUNTING MATTERS

Critical Accounting Estimates

Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments regarding many factors that in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates that we believe are the most difficult, subjective, or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

Accounting EstimateUncertainties Affecting Application

Regulatory Mechanisms and Cost Recovery

We defer costs and recognize revenues that we intend to collect in future rates.

•Regulatory environment and external regulatory decisions and requirements
•Anticipated future regulatory decisions and our assessment of their impact
•The impact of prudence reviews, complaint cases, limitations on electric rate increases in Missouri, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments
•Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under performance-based formula ratemaking framework
•Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks
•Ameren Missouri’s estimate of revenue recovery under the MEEIA plans

Basis for Judgment

The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, legislation, or historical experience, as well as discussions with legal counsel. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers. We also recognize revenues for alternative revenue programs authorized by our regulators that allow for an automatic rate adjustment, are probable of recovery, and are collected within 24 months following the end of the annual period in which they are recognized. Ameren Illinois estimates its annual electric distribution revenue requirement under performance-based formula ratemaking for interim periods by using internal forecasted rate base and published forecasted data regarding the annual average of the monthly yields of the 30-year United States Treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31 of each year using that year’s actual operating results and assesses the probability of recovery from or refund to customers that the ICC will order at the end of the following year. Variations in investments made or orders by the ICC or courts can result in a subsequent change in Ameren Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates electric margins resulting from its MEEIA customer energy-efficiency programs. Ameren Missouri uses a MEEIA rider to collect from, or refund to, customers any annual difference in the actual amounts incurred and the amounts collected from customers. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for quantification of these assets or liabilities for each of the Ameren Companies. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for a listing of regulatory mechanisms used by Ameren Missouri and Ameren Illinois.

Benefit Plan Accounting

Based on actuarial calculations, we accrue costs of providing future employee benefits for the benefit plans we offer our employees. See Note 10 – Retirement Benefits under Part II, Item 8, of this report.

•Future rate of return on pension and other plan assets
•Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable
•Discount rate
•Future compensation increase assumption
•Health care cost trend rates
•Timing of employee retirements and mortality assumptions
•Ability to recover certain benefit plan costs from our customers
•Changing market conditions that may affect investment and interest rate environments

Basis for Judgment

Ameren has defined benefit pension and postretirement benefit plans covering substantially all of its union employees. Ameren has defined benefit pension plans covering substantially all of its non-union employees and postretirement benefit plans covering non-union employees hired before October 2015. Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable. We also make mortality assumptions to estimate our pension and other postretirement benefit obligations. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for these assumptions and the sensitivity of Ameren’s benefit plans to potential changes in these assumptions.

Accounting for Contingencies

We make judgments and estimates in the recording and the disclosing of liabilities for claims, litigation, environmental remediation, the actions of various regulatory agencies, or other matters that occur in the normal course of business. We record a loss contingency when it is probable that a liability has been incurred and that the amount of the loss can be reasonably estimated.

•Estimating financial impact of events
•Estimating likelihood of various potential outcomes
•Regulatory and political environments and requirements
•Outcome of legal proceedings, settlements, or other factors
•Changes in regulation, expected scope of work, technology or timing of environmental remediation

Basis for Judgment

The determination of a loss contingency requires significant judgment as to the expected outcome of the contingency in future periods. In making the determination as to the amount of potential loss and the probability of loss, we consider the nature of the litigation, the claim or assessment, opinions or views of legal counsel, and the expected outcome of potential litigation, among other things. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates. The amount recorded for any contingency may differ from actual costs incurred when the contingency is resolved. Contingencies are normally resolved over long periods of time. In our evaluation of legal matters, management consults with legal counsel and relies on analysis of relevant case law and legal precedents. See Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, and Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for information on the Ameren Companies’ contingencies.

Accounting for Income Taxes

We record a provision for income taxes, deferred tax assets and liabilities, and a valuation allowance against net deferred tax assets, if any. See Note 12 – Income Taxes under Part II, Item 8, of this report.

•Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations
•Estimates of the amount and character of future taxable income and forecasted use of our tax credit carryforwards
•Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled
•Effectiveness of implementing tax planning strategies
•Changes in income tax laws, including amounts subject to income tax, and the regulatory treatment of any tax reform changes
•Results of audits and examinations by taxing authorities

Basis for Judgment

The reporting of tax-related assets and liabilities requires the use of estimates and significant management judgment. Deferred tax assets and liabilities are recorded to represent future effects on income taxes for temporary differences between the basis of assets for financial reporting and tax purposes. Although management believes that current estimates for deferred tax assets and liabilities are reasonable, actual results could differ from these estimates for a variety of reasons, including: a change in forecasted financial condition and/or results of operations; changes in income tax laws, enacted tax rates or amounts subject to income tax; the form, structure, and timing of asset or stock sales or dispositions; changes in the regulatory treatment of any tax reform benefits; and changes resulting from audits and examinations by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority that has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At each period end, and as new developments occur, management reevaluates its tax positions. See Note 12 – Income Taxes under Part II, Item 8, of this report for the amount of deferred income taxes recorded at December 31, 2018.

Impact of New Accounting Pronouncements

See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

EFFECTS OF INFLATION AND CHANGING PRICES

Ameren’s rates for retail electric and natural gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by the FERC. Rate regulation is generally based on the recovery of historical or projected costs. As a result, revenue increases could lag behind changing prices. The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, customer rates designed to provide recovery of historical costs through depreciation might not be adequate to replace plant in future years.

Ameren Illinois participates in performance-based formula ratemaking for its electric distribution business and its electric energy-efficiency investments. Within Ameren Illinois’ formula ratemaking mechanisms, the annual average of the monthly yields of the 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the annual return on equity applicable to Ameren Illinois’ electric distribution business and electric energy-efficiency investments. Ameren Illinois’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates in a subsequent year.

Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. However, the FAC excludes substantially all transmission revenues and charges. Ameren Missouri is therefore exposed to transmission charges to the extent that they exceed transmission revenues. Ameren Illinois is required to purchase all of its expected power supply through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.

In our Missouri and Illinois retail natural gas utility jurisdictions, changes in natural gas costs are generally reflected in billings to natural gas customers through PGA clauses.

See Part I, Item 1, and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on our cost recovery mechanisms.

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