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 under PUHCA 2005. Ameren’s primary assets are its equity interests in its subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. 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. Ameren also has various other subsidiaries that conduct other activities, such as the provision of 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 distribution, electric transmission and natural gas distribution businesses in Illinois.
•ATXI operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers, Spoon River, and Mark Twain projects. ATXI is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.

Unless otherwise stated, the following sections of Management's Discussion and Analysis of Financial Condition and Results of Operations exclude discontinued operations for all periods presented. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information regarding that presentation.

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. In 2016, Ameren successfully executed its strategy. Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks. In 2016, Ameren invested $1.3 billion of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.

In 2016, Ameren continued to work to enhance its regulatory frameworks and advocate for responsible energy and economic policies and to create and capitalize on opportunities for investment for the benefit of its customers and shareholders. Ameren Illinois successfully advocated for the FEJA, which improved the constructive regulatory framework for Ameren Illinois' electric distribution business. The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking process through 2022. Also, beginning in 2017, the FEJA decouples electric distribution revenues established in a rate proceeding from actual sales volumes by providing that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes reflected in that year's rates will be collected from or refunded to customers within two years. This portion of the law extends beyond the end of the IEIMA in 2022. Further, beginning as early as June 2017, the FEJA will allow Ameren Illinois to capitalize as a regulatory asset and earn a return on its electric energy efficiency investments.

In July 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service. Relating to that request, in February 2017, Ameren Missouri, the MoPSC staff, the MoOPC, and all intervenors filed a unanimous stipulation and agreement with the MoPSC. The stipulation and agreement, which is subject to MoPSC approval, would result in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate order. The stipulation and agreement did not specify the common equity percentage, the rate base, or the allowed return on common equity. The new revenue requirement reflects the current actual sales volumes of the New Madrid Smelter, whose operations remain suspended, as well as other agreed upon sales volumes. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs under the stipulation and agreement would decrease by $54 million from the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, would reduce expenses by $26 million from the base levels established in the MoPSC's April 2015 electric rate order. The stipulation and agreement contemplates that new rates will become effective on or before March 20, 2017.

Related to ATXI's and Ameren Illinois' FERC rate-regulated transmission businesses, in September 2016, the FERC issued a final order in the November 2013 complaint case which lowered the total allowed return on common equity to 10.82%. The new

allowed return on common equity has been reflected in rates prospectively from the September 2016 effective date of the order. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. That final order will determine the allowed return on common equity for the 15-month period ended May 2016. That final order will also establish the allowed return on common equity that will apply prospectively from its expected second quarter 2017 effective date, replacing the current 10.82% total return on common equity, which became effective in September 2016.

In October 2016, Ameren’s board of directors increased the quarterly common stock dividend to 44 cents per share, resulting in an annualized equivalent dividend rate of $1.76 per share.

Earnings

Net income attributable to Ameren common shareholders from continuing operations was $653 million, or $2.68 per diluted share, for 2016, and $579 million, or $2.38 per diluted share, for 2015. These earnings were favorably affected in 2016, compared with 2015, by increased Ameren Transmission and Ameren Illinois Electric Distribution earnings, reflecting Ameren’s strategy to allocate incremental capital to those businesses, increased demand due to warmer summer temperatures, higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order, and decreased other operations and maintenance expenses. Net income was also favorably affected in 2016, compared with 2015, by an income tax benefit recorded in 2016 at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation, as well as the absence of a provision recognized in 2015 as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site. Net income was unfavorably affected in 2016, compared with 2015, by the absence in 2016 of MEEIA 2013 net shared benefits, partially offset by the recognition of a MEEIA 2013 performance incentive, decreased Ameren Missouri sales to the New Madrid Smelter resulting from a reduction in operations at that plant, and the cost of the Callaway energy center’s scheduled refueling and maintenance outage. Additionally, earnings were unfavorably affected in 2016, compared with 2015, by increased depreciation and amortization expenses at Ameren Missouri, the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism, and decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues.

Liquidity

At December 31, 2016, Ameren, on a consolidated basis, had available liquidity in the form of amounts available under credit agreements of $1.5 billion.

Capital Expenditures

In 2016, Ameren continued to make significant investment in its utility businesses by making capital expenditures of $0.7 billion, $0.5 billion, $0.2 billion, and $0.7 billion in Ameren

Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. For 2017 through 2021, Ameren's cumulative capital expenditures are projected to range from $10.4 billion to $11.2 billion. The projected spending by segment includes up to $4.2 billion, $2.6 billion, $1.5 billion, and $2.9 billion for Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Weather, economic conditions, energy efficiency investments by our customers and us, and the actions of key customers can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations in winter heating and summer cooling demands. Ameren and Ameren Missouri are also affected 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, with regulatory frameworks established by our regulators.

Ameren Missouri principally uses coal, nuclear fuel, and natural gas 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. We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution service businesses, a purchased power cost recovery mechanism for Ameren Illinois' electric distribution service business, and a FAC for Ameren Missouri's electric utility business.

Ameren Illinois' electric distribution service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement included in customer rates for that year. Recoveries from or refunds to customers occur in a subsequent year. Included in Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois' annual return on equity is directly correlated to yields on United States Treasury bonds. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula framework in setting their transmission rates. These rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and actual sales volumes, is used to adjust billing rates in a subsequent year.

Ameren Illinois’ and ATXI’s electric transmission service businesses and Ameren Illinois’ electric distribution service business operate under formula ratemaking designed to provide for the recovery of actual costs of service that are prudently incurred as well as a return on equity. Although rate-regulated, Ameren Illinois’ natural gas business and Ameren Missouri do not operate under formula ratemaking. Ameren (parent) is not rate-regulated.

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 of purchased power costs, 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.

During the fourth quarter of 2016, the Ameren Companies changed the manner in which performance is assessed and resources are allocated, driven by increasing investment in FERC-regulated electric transmission and Ameren Illinois electric distribution and natural gas distribution businesses, as well as the unique regulatory environment for each jurisdiction. Ameren now has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, which primarily includes Ameren Illinois Transmission and ATXI. Ameren Missouri has one segment, which includes all of the operations of Ameren Missouri. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission. Prior-period presentation has been adjusted for comparative purposes. See Note 16 – Segment Information under Part II, Item 8, of this report for further discussion of Ameren’s, Ameren Missouri's, and Ameren Illinois' segments.

Earnings Summary

The following table presents a summary of Ameren's earnings for the years ended December 31, 2016, 2015, and 2014:

201620152014
Net income attributable to Ameren common shareholders$653$630$586
Earnings per common share – diluted2.682.592.40
Net income attributable to Ameren common shareholders – continuing operations653579587
Earnings per common share – diluted – continuing operations2.682.382.40

2016 versus 2015

Net income attributable to Ameren common shareholders from continuing operations in 2016 increased $74 million, or $0.30 per diluted share, from 2015. The increase was due to net income increases of $34 million, $22 million, $5 million, and $3 million at Ameren Transmission, Ameren Illinois Natural Gas, Ameren Missouri, and Ameren Illinois Electric Distribution,

respectively. Additionally, the net loss from other businesses, primarily Ameren (parent), and intersegment eliminations decreased $10 million.

In 2015, net income attributable to Ameren common shareholders from discontinued operations was favorably affected by the recognition of a tax benefit resulting from the removal of a reserve for unrecognized tax benefits of $53 million recorded in 2013 related to the divestiture of New AER, based on the completion of the IRS audit of Ameren’s 2013 tax year.

Compared with 2015, 2016 earnings per share from continuing operations were favorably affected by:

•increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment. Ameren Transmission earnings also benefited from a temporarily higher allowed return on common equity, recognizing an allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 complaint case (19 cents per share);
•the absence of a provision recognized in the second quarter of 2015 as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site (18 cents per share);
•increased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures (estimated at 15 cents per share);
•higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order (11 cents per share);
•an income tax benefit recorded at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation (9 cents per share);
•decreased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri (7 cents per share). This was due, in part, to a reduction in energy center maintenance costs, excluding the cost of the Callaway energy center's scheduled refueling and maintenance outage (discussed below) and reduced electric distribution maintenance expenditures; and
•increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment partially offset by a lower return on equity resulting from a reduction in the 30-year United States Treasury bond yields (2 cents per share).

Compared with 2015, 2016 earnings per share from continuing operations were unfavorably affected by:

•the absence in 2016 of MEEIA net shared benefits due to the expiration of MEEIA 2013, partially offset by the recognition of a MEEIA 2013 performance incentive (15 cents per share);
•decreased Ameren Missouri sales to the New Madrid Smelter resulting from a reduction in operations at the smelter (15 cents per share);
•the cost of the Callaway energy center's scheduled refueling

and maintenance outage in 2016. There was no Callaway refueling and maintenance outage in 2015 (7 cents per share);

•increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri primarily because of electric system capital additions (4 cents per share);
•decreased Ameren Illinois Electric Distribution earnings resulting from the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share);
•decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues (3 cents per share); and
•increased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Illinois Natural Gas, primarily due to increased repairs and compliance expenditures (2 cents per share).

The cents per share information presented above is based on the diluted average shares outstanding in 2015. Pretax amounts have been presented net of income taxes, using Ameren's 2015 statutory tax rate of 39%.

2015 versus 2014

Net income attributable to Ameren common shareholders from continuing operations in 2015 decreased $8 million, or $0.02 per diluted share, from 2014. The decrease was due to a $38 million and a $13 million decrease in net income from Ameren Missouri and Ameren Illinois Natural Gas, respectively. The decrease was partially offset by a $32 million and a $10 million increase in net income from Ameren Transmission and Ameren Illinois Electric Distribution, respectively.

In 2015, net income attributable to Ameren common shareholders from discontinued operations was favorably affected by the recognition of a tax benefit resulting from the removal of a reserve for unrecognized tax benefits of $53 million recorded in 2013 related to the divestiture of New AER, based on the completion of the IRS audit of Ameren’s 2013 tax year.

Compared with 2014, 2015 earnings per share from continuing operations were unfavorably affected by:

•a provision recognized in the second quarter of 2015 as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site (18 cents per share);
•decreased electric and natural gas sales volumes, primarily due to warmer winter temperatures in 2015 (estimated at 6 cents per share);
•increased net financing costs at Ameren Missouri, primarily due to a reduction in allowance for funds used during construction as multiple significant electric capital projects were completed in 2014 (6 cents per share);
•increased depreciation and amortization expenses at Ameren Illinois Natural Gas, resulting from amortization of

capital additions, and at Ameren Missouri, primarily resulting from electric capital additions completed in 2014 which were not reflected in customer rates until May 30, 2015 (5 cents per share); and

•the absence in 2015 of a recovery of certain previously disallowed debt premium costs per the ICC's December 2014 order (3 cents per share).

Compared with 2014, 2015 earnings per share from continuing operations were favorably affected by:

•increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment (15 cents per share). These earnings were reduced by an estimate of the probable customer refunds as a result of the FERC complaint cases regarding the allowed return on common equity (3 cents per share);
•increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment as well as interest earned on the revenue requirement reconciliation adjustment regulatory assets (5 cents per share), partially offset by a lower return on equity due to a reduction in the 30-year United States Treasury bond yields (2 cents per share);
•the absence of a Callaway energy center scheduled refueling and maintenance outage in 2015, partially offset by preparation costs incurred in 2015 for the 2016 scheduled refueling outage (7 cents per share);
•increased Ameren Illinois Electric Distribution earnings resulting from a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share);
•excluding the scheduled refueling and maintenance outage, MEEIA program costs, and expenses with corresponding increases in electric revenues resulting from the April 2015 MoPSC electric rate order, decreased other operations and maintenance expenses at Ameren Missouri primarily because of decreased energy center costs and at other businesses (4 cents per share); and
•decreased interest expense attributable to other businesses, primarily due to Ameren's (parent) maturity of higher-cost debt in 2014 being replaced with lower-cost debt in 2015 (4 cents per share).

The cents per share information presented above is based on the diluted average shares outstanding in 2014. Pretax amounts have been presented net of income taxes, using Ameren's 2014 statutory tax rate of 39%.

For additional details regarding the Ameren Companies’ segment results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Provision for Callaway Construction and Operating License, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, Income Taxes, and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.

Below is Ameren's table of income statement components by segment for the years ended December 31, 2016, 2015, and 2014:

2016Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren TransmissionOther / Intersegment EliminationsTotal
Electric margins$2,397$1,105$—$355$(27)$3,830
Natural gas margins79—462—(2)539
Other revenues1———(1)—
Other operations and maintenance(893)(538)(215)(60)30(1,676)
Depreciation and amortization(514)(226)(55)(43)(7)(845)
Taxes other than income taxes(325)(72)(58)(4)(8)(467)
Other income and (expenses)428(1)2(9)42
Interest charges(211)(72)(34)(58)(7)(382)
Income taxes(216)(78)(39)(74)25(382)
Income (loss) from continuing operations36012760118(6)659
Income from discontinued operations, net of taxes——————
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
2015
Electric margins$2,481$1,074$—$259$(26)$3,788
Natural gas margins80—425—(2)503
Other revenues2———(2)—
Other operations and maintenance(925)(532)(219)(56)38(1,694)
Provision for Callaway construction and operating license(69)————(69)
Depreciation and amortization(492)(212)(52)(33)(7)(796)
Taxes other than income taxes(335)(72)(56)(2)(8)(473)
Other income and (expenses)418(1)2(6)44
Interest charges(219)(71)(35)(35)5(355)
Income taxes(209)(71)(24)(51)(8)(363)
Income (loss) from continuing operations3551243884(16)585
Income from discontinued operations, net of taxes————5151
Net income355124388435636
Noncontrolling interests – preferred stock dividends(3)(1)(1)(1)—(6)
Net income attributable to Ameren common shareholders$352$123$37$83$35$630
2014
Electric margins$2,436$1,025$—$187$(22)$3,626
Natural gas margins82—443——525
Other revenues1———(1)—
Other operations and maintenance(939)(507)(220)(49)31(1,684)
Depreciation and amortization(473)(197)(41)(26)(8)(745)
Taxes other than income taxes(322)(73)(63)(2)(8)(468)
Other income and (expenses)484(1)6—57
Interest charges(211)(63)(28)(26)(13)(341)
Income (taxes) benefit(229)(75)(39)(38)4(377)
Income (loss) from continuing operations3931145152(17)593
Loss from discontinued operations, net of taxes————(1)(1)
Net income (loss)3931145152(18)592
Noncontrolling interests – preferred stock dividends(3)(1)(1)(1)—(6)
Net income (loss) attributable to Ameren common shareholders$390$113$50$51$(18)$586

Below is Ameren Illinois' table of income statement components by segment for the years ended December 31, 2016, 2015, and 2014:

2016Electric DistributionNatural GasTransmissionTotal
Electric margins$1,105$—$232$1,337
Natural gas margins—462—462
Other operations and maintenance(538)(215)(51)(804)
Depreciation and amortization(226)(55)(38)(319)
Taxes other than income taxes(72)(58)(2)(132)
Other income and (expenses)8(1)29
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
2015
Electric margins$1,074$—$189$1,263
Natural gas margins—425—425
Other operations and maintenance(532)(219)(46)(797)
Depreciation and amortization(212)(52)(31)(295)
Taxes other than income taxes(72)(56)(2)(130)
Other income and (expenses)8(1)29
Interest charges(71)(35)(25)(131)
Income taxes(71)(24)(32)(127)
Net income1243855217
Preferred stock dividends(1)(1)(1)(3)
Net income attributable to common shareholder$123$37$54$214
2014
Electric margins$1,025$—$154$1,179
Natural gas margins—443—443
Other operations and maintenance(507)(220)(44)(771)
Depreciation and amortization(197)(41)(25)(263)
Taxes other than income taxes(73)(63)(2)(138)
Other income and (expenses)4(1)69
Interest charges(63)(28)(21)(112)
Income taxes(75)(39)(29)(143)
Net income1145139204
Preferred stock dividends(1)(1)(1)(3)
Net income attributable to common shareholder$113$50$38$201

Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2016 compared with 2015, as well as 2015 compared with 2014. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Electric and Natural Gas Margins
2016 versus 2015Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Transmission(a)Other / Intersegment EliminationsAmeren
Electric revenue change:
Effect of weather (estimate)(b)$57$15$—$—$—$72
Base rates (estimate)4838—102—188
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)7————7
New Madrid Smelter revenues(129)————(129)
Off-system sales and capacity revenues153————153
MEEIA 2013 net shared benefits(85)————(85)
MEEIA 2013 performance incentive28————28
Transmission services revenues3————3
Purchased power rider order in 2015—(15)———(15)
Other(1)(1)—(6)(21)(29)
Cost recovery mechanisms – offset in fuel and purchased power:(c)
Power supply costs—(28)———(28)
Transmission services recovery mechanism—6———6
Recovery of FAC under-recovery(118)————(118)
Other cost recovery mechanisms:(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders—2———2
Gross receipts tax(5)————(5)
MEEIA 2013 and 2016 program costs(34)————(34)
Total electric revenue change$(76)$17$—$96$(21)$16
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)$(145)$—$—$—$—$(145)
New Madrid Smelter energy costs72————72
Effect of weather (estimate)(b)(9)(8)———(17)
Effect of higher net energy costs included in base rates(34)————(34)
Transmission services charges(16)————(16)
Other6———2026
Cost recovery mechanisms – offset in electric revenue:(c)
Power supply costs—28———28
Transmission services recovery mechanism—(6)———(6)
Recovery of FAC under-recovery118————118
Total fuel and purchased power change$(8)$14$—$—$20$26
Net change in electric margins$(84)$31$—$96$(1)$42
Natural gas revenue change:
Effect of weather (estimate)(b)$(7)$—$13$—$—$6
Base rates (estimate)——42——42
Other——2——2
Cost recovery mechanism – offset in natural gas purchased for resale:(c)
Purchased natural gas costs(2)—(76)——(78)
Other cost recovery mechanisms:(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders——(10)——(10)
Total natural gas revenue change$(9)$—$(29)$—$—$(38)
Natural gas purchased for resale change:
Effect of weather (estimate)(b)$6$—$(10)$—$—$(4)
Cost recovery mechanism – offset in natural gas revenue:(c)
Purchased natural gas costs2—76——78
Total natural gas purchased for resale change$8$—$66$—$—$74
Net change in natural gas margins$(1)$—$37$—$—$36
2015 versus 2014Ameren MissouriAmeren Illinois Electric DistributionAmeren Illinois Natural GasAmeren Transmission(a)Other / Intersegment EliminationsAmeren
Electric revenue change:
Effect of weather (estimate)(b)$(20)$(10)$—$—$—$(30)
Base rates (estimate)8234—66—182
Sales volume (excluding the estimated effect of weather)(36)(1)———(37)
Off-system sales, transmission services revenues, and capacity revenues3————3
MEEIA 2013 net shared benefits33————33
Transmission services revenues(e)1————1
Purchased power rider order in 2015—15———15
Other2(10)—6(16)(18)
Cost recovery mechanisms – offset in fuel and purchased power:(c)
Power supply costs—81———81
Transmission services recovery mechanism—10———10
Recovery of FAC under-recovery(5)————(5)
Other cost recovery mechanisms:(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders—10———10
Gross receipts tax6————6
MEEIA 2013 program costs16————16
Total electric revenue change$82$129$—$72$(16)$267
Fuel and purchased power change:
Energy costs (excluding the estimated effect of weather)$21$—$—$—$—$21
Effect of weather (estimate)(b)1010———20
Effect of higher net energy costs included in base rates(65)————(65)
FAC exclusion of transmission services charges(e)(7)————(7)
Other(1)1——1212
Cost recovery mechanisms – offset in electric revenue:(c)
Power supply costs—(81)———(81)
Transmission services recovery mechanism—(10)———(10)
Recovery of FAC under-recovery5————5
Total fuel and purchased power change$(37)$(80)$—$—$12$(105)
Net change in electric margins$45$49$—$72$(4)$162
Natural gas revenue change:
Effect of weather (estimate)(b)$(17)$—$(72)$—$—$(89)
Other2—1—(2)1
Cost recovery mechanism – offset in natural gas purchased for resale:(c)
Purchased natural gas costs(11)—(113)——(124)
Other cost recovery mechanisms:(d)
Bad debt, energy efficiency programs, and environmental remediation cost riders——(2)——(2)
Gross receipts tax(1)—(7)——(8)
Total natural gas revenue change$(27)$—$(193)$—$(2)$(222)
Natural gas purchased for resale change:
Effect of weather (estimate)(b)$14$—$62$—$—$76
Cost recovery mechanism – offset in natural gas revenue:(c)
Purchased natural gas costs11—113——124
Total natural gas purchased for resale change$25$—$175$—$—$200
Net change in natural gas margins$(2)$—$(18)$—$(2)$(22)
(a)Includes an increase in transmission margins of $43 million and $35 million in 2016 and 2015, respectively, at Ameren Illinois. The increase in transmission margins at Ameren Illinois is the sum of the change in base rates (estimate) of $49 million and $29 million, respectively, and the change in Other of -$6 million and $6 million, respectively.
(b)Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.
(c)Electric and natural gas revenue changes are offset by corresponding changes in Fuel, Purchased power, and Natural gas purchased for resale, resulting in no change to electric and natural gas margins.
(d)See Other Operations and Maintenance Expenses or Taxes Other Than Income Taxes in this section for the related offsetting increase or decrease to expense. These items have no overall impact on earnings.
(e)Ameren Missouri amounts are subsequent to May 30, 2015, due to the exclusion of transmission revenues and substantially all transmission charges from the FAC as a result of the April 2015 MoPSC electric rate order.

2016 versus 2015

Ameren

Ameren's electric margins increased $42 million, or 1%, in 2016 compared with 2015, primarily because of increased margins at Ameren Transmission and Ameren Illinois Electric Distribution, partially offset by decreased margins at Ameren Missouri. Ameren's natural gas margins increased $36 million, or 7%, in 2016 compared with 2015, primarily because of increased margins at Ameren Illinois Natural Gas.

Ameren Missouri

Ameren Missouri has a FAC cost recovery mechanism that allows it to recover or refund, through customer rates, 95% of changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri.

Net energy costs, as defined in the FAC, include fuel and purchased power costs, including transportation, net of off-system sales. Since May 2015, when transmission revenues and substantially all transmission charges were excluded from net energy costs as a result of the April 2015 MoPSC electric rate order, electric margins have been unfavorably affected, as discussed below. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. Net recovery of these costs through customer rates does not affect Ameren Missouri's electric margins, as any change in revenue is offset by a corresponding change in fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins decreased $84 million, or 3%, in 2016 compared with 2015. The following items had an unfavorable effect on Ameren Missouri's electric margins:

•The suspension of the New Madrid Smelter operations in the first quarter of 2016, which decreased margins by $57 million. The change in margins due to lower sales to the New Madrid Smelter is the sum of New Madrid Smelter revenues (-$129 million) and New Madrid Smelter energy costs (+$72 million) in the Electric and Natural Gas Margins table above. New Madrid Smelter energy costs include the impact of a provision in the FAC tariff that, under certain circumstances, allows Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced sales to the New Madrid Smelter. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the New Madrid Smelter.
•The expiration of MEEIA 2013, which decreased margins by $57 million. The change in margins due to the expiration of MEEIA 2013 is the sum of MEEIA 2013 net shared benefits (-$85 million) and MEEIA 2013 performance incentive (+$28 million) in the Electric and Natural Gas Margins table above. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency-related volume reductions in current and future periods. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for

information regarding the MEEIA 2013 performance incentive.

•Increased transmission services charges resulting from additional MISO-approved electric transmission investments made by other entities and shared by all MISO participants, which decreased margins by $16 million.

The following items had a favorable effect on Ameren Missouri's electric margins in 2016 compared with 2015:

•Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 16%, while heating degree-days decreased 6%. The net effect of weather increased margins by an estimated $48 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$57 million) and the effect of weather (estimate) on fuel and purchased power (-$9 million) in the Electric and Natural Gas Margins table above.
•Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $14 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$48 million) and the change in effect of higher net energy costs included in base rates (-$34 million) in the Electric and Natural Gas Margins table above.
•Lower net energy costs as a result of the 5% of changes retained by Ameren Missouri through the FAC, primarily due to higher MISO capacity revenues, which increased margins by $8 million. The change in net energy costs is the sum of the change in off-system sales and capacity revenues (+$153 million) and the change in energy costs (excluding the New Madrid Smelter and estimated effect of weather) (-$145 million) in the Electric and Natural Gas Margins table above.
•Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effect of weather, total retail sales volumes increased by less than 1%, which increased revenues by $7 million, due to an additional day as a result of the leap year and growth, partially offset by the carryover effect of MEEIA 2013 on sales volumes and the effect of MEEIA 2016 customer energy efficiency programs. MEEIA 2016 customer energy efficiency programs reduced retail sales volumes but the throughput disincentive recovery ensured that electric margins were not affected.

Ameren Missouri's natural gas margins were comparable between years. Ameren Missouri has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased natural 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 Illinois

Ameren Illinois' electric margins increased by $74 million, or 6%, in 2016 compared with 2015, driven by increases in Ameren Illinois Electric Distribution ($31 million) and Ameren Illinois Transmission ($43 million) margins.

Ameren Illinois Electric Distribution

The IEIMA performance-based formula rate framework

provides an annual reconciliation of the electric delivery service revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If the current year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) in the Electric and Natural Gas Margins table above. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois Electric Distribution's revenue requirement reconciliation pursuant to the IEIMA.

Ameren Illinois Electric Distribution has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its customers. These pass-through costs do not affect Ameren Illinois Electric Distribution's margins, as any change in costs is offset by a corresponding change in revenues.

Ameren Illinois Electric Distribution's margins increased $31 million, or 3%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Electric Distribution's electric margins:

•Revenues increased by $38 million, primarily due to an increase in rate base of 8% and higher recoverable costs in 2016 compared with 2015, under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity due to a reduction in 30-year United States Treasury bond yields, which decreased 24 basis points in 2016 compared with 2015.
•Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 13%, while heating degree-days decreased 5%. The net effect of weather increased margins by an estimated $7 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$15 million) and the effect of weather (estimate) on fuel and purchased power (-$8 million) in the Electric and Natural Gas Margins table above.

Ameren Illinois Electric Distribution's margins were unfavorably affected by the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois' cumulative power usage cost and its purchased power rider mechanism, which increased margins by $15 million in 2015.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased natural gas costs do not affect Ameren Illinois

Natural Gas' margins, as any change in costs is offset by a corresponding change in revenues.

Ameren Illinois Natural Gas' margins increased $37 million, or 9%, in 2016 compared with 2015. The following items had a favorable effect on Ameren Illinois Natural Gas' margins:

•Higher natural gas base rates in 2016, which increased margins by an estimated $42 million.
•The absence of warmer-than-normal 2015 winter temperatures and the application of the VBA in 2016, which increased margins by $3 million. The VBA, which was approved by the ICC in December 2015, eliminated the impact of weather on natural gas margins for residential and small nonresidential customers in 2016. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (+$13 million) and the effect of weather (estimate) on natural gas purchased for resale (-$10 million) in the Electric and Natural Gas Margins table above.

Ameren Illinois Transmission

Ameren Illinois Transmission's margins increased $43 million, or 23%, in 2016 compared with 2015, as discussed in the Ameren Transmission section below.

Ameren Transmission

The provisions of FERC's electric transmission formula rate framework provide for an annual reconciliation of the electric transmission service revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If the current year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) in the Electric and Natural Gas Margins table above. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Transmission's revenue requirement reconciliation.

Ameren Transmission's margins increased $96 million, or 37%, in 2016 compared with 2015, driven by Ameren Illinois Transmission and ATXI results. The increase in margins for both Ameren Transmission and Ameren Illinois Transmission was primarily due to significant capital investment, which increased rate base by 42% and 27%, respectively, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. See Cash Flows from Investing Activities in this section for information regarding capital expenditures, including those for the Illinois Rivers project. Ameren Transmission and Ameren Illinois

Transmission margins also benefited from a temporarily higher allowed return on common equity, recognizing an allowed return on common equity of 12.38% for nearly four months in 2016, as a result of the expiration of the refund period in the February 2015 complaint case. 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.

2015 versus 2014

Ameren

Ameren's electric margins increased $162 million, or 4%, in 2015 compared with 2014, primarily because of increased margins at Ameren Transmission, Ameren Illinois Electric Distribution, and Ameren Missouri. Ameren's natural gas margins decreased $22 million, or 4%, in 2015 compared with 2014, primarily because of decreased margins at Ameren Illinois Natural Gas.

Ameren Missouri

Ameren Missouri's electric margins increased $45 million, or 2%, in 2015 compared with 2014. The following items had a favorable effect on Ameren Missouri's electric margins:

•Higher MEEIA 2013 net shared benefits caused by increased customer implementation of longer-lived energy efficiency products and increased nonresidential customer participation, which increased revenues by $33 million. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency-related volume reductions in current and future periods.
•Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $17 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$82 million) and the change in effect of higher net energy costs included in base rates (-$65 million) in the Electric and Natural Gas Margins table above.

The following items had an unfavorable effect on Ameren Missouri's electric margins in 2015 compared with 2014:

•Lower sales volumes, primarily caused by the MEEIA 2013 programs and other customer energy efficiency measures, and reduced sales to the New Madrid Smelter. Excluding the estimated effect of weather and reduced sales to the New Madrid Smelter, total retail sales volumes decreased by 1%, which decreased revenues by $25 million. Reduced sales to the New Madrid Smelter decreased revenues by $11 million. The sales volumes to the New Madrid Smelter were lower than those reflected in rates established in the April 2015 MoPSC electric rate order. Lower sales volumes led to a decrease in net energy costs of $24 million. The change in net energy costs is the sum of the change in off-system sales, transmission services revenues, and capacity revenues (+$3 million) and the change in energy costs (excluding the estimated effect of weather) (+$21 million) in the Electric and Natural Gas Margins table above.
•Winter temperatures in 2015 were warmer compared with 2014, as heating degree-days decreased 19%. The effect of weather decreased margins by an estimated $10 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$20 million) and the effect of weather (estimate) on fuel and purchased power (+$10 million) in the Electric and Natural Gas Margins table above.
•The exclusion of transmission revenues and substantially all transmission charges from the FAC beginning May 30, 2015, which decreased margins by $6 million. The change in margins as a result of the changes to the FAC is the sum of FAC exclusion of transmission services charges (-$7 million) and transmission services revenues (+$1 million) in the Electric and Natural Gas Margins table above.

Ameren Missouri's natural gas margins were comparable between years.

Ameren Illinois

Ameren Illinois' electric margins increased by $84 million, or 7%, in 2015 compared with 2014 driven by increases in Ameren Illinois Electric Distribution ($49 million) and Ameren Illinois Transmission ($35 million) margins.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution's revenues increased $129 million in 2015 compared with 2014, primarily because of higher power supply costs as a result of increased MISO capacity prices. Ameren Illinois Electric Distribution has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its electric distribution customers. These pass-through costs do not affect Ameren Illinois Electric Distribution's margins, as any change in costs is offset by a corresponding change in revenues.

Ameren Illinois Electric Distribution's margins increased $49 million, or 5%, in 2015 compared with 2014. The following items had a favorable effect on Ameren Illinois Electric Distribution's electric margins:

•Revenues increased by $34 million, primarily due to an increase in rate base of 8% and higher recoverable costs in 2015 compared with 2014 under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity due to a reduction in 30-year United States Treasury bond yields, which decreased 50 basis points in 2015 compared with 2014.
•A January 2015 ICC order regarding Ameren Illinois' cumulative power usage cost and its purchased power rider mechanism, which caused electric revenues to increase by $15 million compared with 2014.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas' revenues decreased $193 million in 2015 compared with 2014 because of lower natural gas commodity prices and lower sales volumes due to weather. Ameren Illinois Natural Gas has a cost recovery mechanism for natural gas

purchased on behalf of its customers. These pass-through purchased natural gas costs do not affect Ameren Illinois Natural Gas' margins, as any change in costs is offset by a corresponding change in revenues.

Ameren Illinois Natural Gas' margins decreased $18 million, or 4%, in 2015 compared with 2014. Winter temperatures in 2015 were warmer compared with 2014, as heating degree-days decreased 18%, which decreased margins by an estimated $10 million. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (-$72 million) and the effect of weather (estimate) on natural gas purchased for resale (+$62 million) in the Electric and Natural Gas Margins table above.

Ameren Illinois Transmission

Ameren Illinois Transmission's margins increased $35 million, or 23%, in 2015 compared with 2014, as discussed in the Ameren Transmission section below.

Ameren Transmission

Ameren Transmission's margins increased $72 million, or 39%, in 2015 compared with 2014, driven by Ameren Illinois Transmission and ATXI results. The increase in margins for both Ameren Transmission and Ameren Illinois Transmission was primarily due to significant capital investment, which increased rate base by 54% and 27%, respectively, as well as higher recoverable costs in 2015 compared with 2014 under forward-looking formula ratemaking. See Cash Flows from Investing Activities in this section for information regarding capital expenditures, including those for the Illinois Rivers project. Ameren Transmission and Ameren Illinois Transmission margins were reduced by an estimate of the probable customer refunds as a result of the FERC complaint cases regarding the allowed base return on common equity. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the FERC complaint cases.

Other Operations and Maintenance Expenses

2016 versus 2015

Ameren

Other operations and maintenance expenses decreased $18 million in 2016 compared with 2015, primarily because of decreased expenses at Ameren Missouri and Ameren Illinois Natural Gas, partially offset by an increase in expenses at Ameren Illinois Electric Distribution, Ameren Transmission, and other businesses.

Ameren Missouri

Other operations and maintenance expenses were $32 million lower in 2016 compared with 2015. The following items decreased other operations and maintenance expenses between years:

•MEEIA customer energy efficiency program costs decreased by $34 million in 2016, primarily due to the expiration of MEEIA 2013, partially offset by costs incurred

for MEEIA 2016. Electric revenues decreased by a corresponding amount, with no overall effect on net income.

•Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center discussed below, decreased by $18 million, primarily because of reduced staffing costs and decreased routine maintenance costs, partially offset by higher coal handling charges.
•Electric distribution maintenance expenditures decreased by $16 million, primarily related to reduced system repair and vegetation management work.
•Employee benefit costs decreased by $11 million, primarily due to a $6 million reduction in the base level of pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order, and lower medical benefit costs. Electric base rates billed to customers related to pension and postretirement expenses decreased electric revenues by a corresponding amount, with no overall effect on net income.
•An unrealized MTM gain in 2016 compared with an unrealized MTM loss in 2015 decreased costs by $4 million, resulting from changes in the market value of company-owned life insurance.

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

•Refueling and maintenance outage costs at the Callaway energy center increased by $26 million, primarily due to costs for the 2016 scheduled refueling and maintenance outage. There was no Callaway refueling and maintenance outage in 2015.
•Litigation costs increased by $11 million, primarily related to increases in estimated obligations for pending legal claims.
•Amortization of previously deferred solar rebate costs increased by $9 million, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers increased electric revenues by a corresponding amount, with no overall effect on net income.
•Storm-related repair costs increased by $7 million.

Ameren Illinois

Other operations and maintenance expenses increased $7 million in 2016 compared with 2015, primarily because of increased expenses at Ameren Illinois Electric Distribution and Ameren Illinois Transmission, partially offset by a reduction in expenses at Ameren Illinois Natural Gas.

Ameren Illinois Electric Distribution

Pursuant to the provisions of the IEIMA's formula rate framework, recoverable electric distribution costs that are not recovered through separate cost recovery mechanisms are included in a revenue requirement reconciliation, which results in a corresponding adjustment to electric revenues, with no overall effect on net income. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.

Other operations and maintenance expenses were $6 million higher in 2016 compared with 2015. The following items increased other operations and maintenance expenses between years:

•Labor costs increased by $6 million, primarily because of staff additions to meet enhanced standards and goals related to the IEIMA.
•Storm-related repair costs increased by $3 million.
•Bad debt, customer energy efficiency, and environmental remediation costs increased by $2 million. These expenses are included in cost riders that result in increased electric revenues, with no overall effect on net income.
•Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.

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

•Employee benefit costs decreased by $6 million, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.
•Electric distribution operations and maintenance expenditures decreased by $3 million, primarily related to reduced circuit maintenance work, partially offset by increased vegetation management work.

Ameren Illinois Natural Gas

Other operations and maintenance expenses were $4 million lower in 2016 compared with 2015. The following items decreased other operations and maintenance expenses between years:

•Bad debt, customer energy efficiency, and environmental remediation costs decreased by $10 million. These expenses are included in cost riders that result in lower natural gas revenues, with no overall effect on net income.
•Employee benefit costs decreased by $5 million, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

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

•Repairs and compliance expenditures increased by $8 million, primarily related to increased pipeline integrity and storage field maintenance.
•Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.

Ameren Illinois Transmission

Other operations and maintenance expenses were $5 million higher in 2016 compared with 2015, primarily because of an increase in system operations and labor costs.

Ameren Transmission

Pursuant to the provisions of the FERC's formula rate framework, recoverable transmission costs that are not recovered through separate cost recovery mechanisms are included in Ameren Transmission's and Ameren Illinois Transmission's revenue requirement reconciliations, which result in corresponding adjustments to electric revenues, with no overall effect on net income. These recoverable transmission costs are included in other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.

Other operations and maintenance expenses increased $4 million in 2016 compared with 2015, primarily because of an increase in system operations and labor costs.

2015 versus 2014

Ameren

Other operations and maintenance expenses increased $10 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Illinois Electric Distribution and Ameren Transmission, partially offset by a reduction in expenses at Ameren Missouri. Other operations and maintenance expenses were comparable between years at Ameren Illinois Natural Gas.

Ameren Missouri

Other operations and maintenance expenses were $14 million lower in 2015 compared with 2014. The following items decreased other operations and maintenance expenses between years:

•Refueling and maintenance outage costs at the Callaway energy center decreased by $27 million. There was no refueling outage scheduled in 2015; however, $9 million in preparation costs were incurred in 2015 for the 2016 scheduled outage.
•Employee benefit costs decreased by $9 million, primarily due to a change in pension and postretirement expenses allowed in rates as a result of the April 2015 MoPSC electric rate order.
•Disposal costs for low-level radioactive nuclear waste decreased by $8 million.
•Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, decreased by $6 million, primarily because of fewer major outages.
•Bad debt expense decreased by $3 million, due to improved customer collections.

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

•Amortization of previously-deferred solar rebate costs increased by $17 million as a result of the April 2015 MoPSC electric rate order.
•MEEIA customer energy efficiency program costs increased by $16 million in 2015, primarily due to program enhancements and increased customer participation.
•An unrealized MTM loss in 2015 compared with an unrealized MTM gain in 2014 increased costs by $3 million, resulting from changes in the market value of company-owned life insurance.
•Electric distribution maintenance expenditures increased by $2 million, primarily related to increased system repair work.

Ameren Illinois

Other operations and maintenance expenses increased $26 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Illinois Electric Distribution. Other operations and maintenance expenses were comparable between years at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses were $25 million higher in 2015 compared with 2014. The following items increased other operations and maintenance expenses between years:

•Bad debt, customer energy efficiency, and environmental remediation costs increased by $10 million.
•Circuit maintenance and system repair work increased by $7 million, primarily related to regulatory compliance requirements.
•Labor costs increased by $5 million, primarily because of staff additions to meet enhanced standards and goals related to the IEIMA and higher wages.
•Storm-related repair costs increased by $3 million.
•Employee benefit costs increased by $3 million, primarily due to higher pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

Ameren Transmission

Other operations and maintenance expenses increased $7 million in 2015 compared with 2014, primarily because of increased expenses at ATXI, resulting from an increase in support services, labor costs and consulting expenditures.

Provision for Callaway Construction and Operating License

Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site in 2015. As a result of this decision, in 2015, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision for the previously capitalized COL costs.

Depreciation and Amortization

2016 versus 2015

Ameren

Depreciation and amortization expenses increased $49 million in 2016 compared with 2015, primarily because of increased expenses at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, as discussed below.

Ameren Missouri

Depreciation and amortization expenses increased $22 million, primarily because of electric system capital additions and increased depreciation rates resulting from the April 2015 MoPSC electric rate order.

Ameren Illinois

Depreciation and amortization expenses increased $24 million, primarily because of increased expenses at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, as discussed below.

Ameren Illinois Electric Distribution

Depreciation and amortization expenses increased $14 million, primarily because of capital additions.

Ameren Illinois Natural Gas

Depreciation and amortization expenses increased $3 million, primarily because of capital additions.

Ameren Illinois Transmission

Depreciation and amortization expenses increased $7 million, primarily because of capital additions.

Ameren Transmission

Depreciation and amortization expenses increased $10 million, primarily because of capital additions at Ameren Illinois Transmission.

2015 versus 2014

Ameren

Depreciation and amortization expenses increased $51 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, as discussed below.

Ameren Missouri

Depreciation and amortization expenses increased $19 million, primarily because of multiple significant electric projects completed in 2014 and increased depreciation rates resulting from the April 2015 MoPSC electric rate order.

Ameren Illinois

Depreciation and amortization expenses increased $32 million, primarily because of increased expenses at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, as discussed below.

Ameren Illinois Electric Distribution

Depreciation and amortization expenses increased $15 million, primarily because of capital additions.

Ameren Illinois Natural Gas

Depreciation and amortization expenses increased $11 million, primarily because of capital additions.

Ameren Illinois Transmission

Depreciation and amortization expenses increased $6 million, primarily because of capital additions.

Ameren Transmission

Depreciation and amortization expenses increased $7 million, primarily because of capital additions at Ameren Illinois Transmission.

Taxes Other Than Income Taxes

2016 versus 2015

Ameren

Taxes other than income taxes decreased $6 million in 2016 compared with 2015, primarily because of decreased expenses at Ameren Missouri, partially offset by increased expenses at Ameren Illinois Natural Gas and Ameren Transmission, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.

Ameren Missouri

Taxes other than income taxes decreased $10 million, primarily because of decreased gross receipts taxes resulting from lower residential and commercial electric revenues and because of a decrease in property taxes. Electric revenues for gross receipts taxes decreased by an amount corresponding to the reduction in gross receipts taxes, with no overall effect on net income.

Ameren Illinois

Taxes other than income taxes increased $2 million, primarily because of increased expenses at Ameren Illinois Natural Gas, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Transmission.

Ameren Illinois Natural Gas

Taxes other than income taxes increased $2 million, primarily because of an increase in Illinois state natural gas invested capital taxes.

Ameren Transmission

Taxes other than income taxes increased $2 million, primarily because of an increase in property taxes at ATXI.

2015 versus 2014

Ameren

Taxes other than income taxes increased $5 million in 2015 compared with 2014, primarily because of increased expenses at Ameren Missouri, partially offset by decreased expenses at Ameren Illinois Natural Gas, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution and Ameren Transmission.

Ameren Missouri

Taxes other than income taxes increased $13 million, primarily because of increased property taxes resulting from both higher tax rates and assessed property tax values, and increased gross receipts taxes resulting from higher electric service rates.

Ameren Illinois

Taxes other than income taxes decreased $8 million, primarily because of decreased expenses at Ameren Illinois Natural Gas, as discussed below. Taxes other than income taxes were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Transmission.

Ameren Illinois Natural Gas

Taxes other than income taxes decreased $7 million, primarily because of decreased gross receipts taxes resulting from lower natural gas sales prices and volumes.

Other Income and Expenses

2016 versus 2015

Ameren

Other income, net of expenses, was comparable between years at Ameren, Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. See Note 6 – Other Income and Expenses under Part II, Item 8, of this report for additional information.

Ameren Illinois

Other income, net of expenses, was comparable between years at Ameren Illinois, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission.

2015 versus 2014

Ameren

Other income, net of expenses, decreased $13 million in 2015 compared with 2014, primarily because of a $5 million increase in donations at Ameren (parent) due to the timing of charitable contributions and a decrease in other income, net of expenses, at Ameren Missouri and Ameren Transmission, partially offset by an increase in other income, net of expenses, at Ameren Illinois Electric Distribution, as discussed below. Other income, net of expenses, was comparable between years at Ameren Illinois Natural Gas.

Ameren Missouri

Other income, net of expenses, decreased $7 million, primarily because of a decrease in the allowance for equity funds used during construction, as multiple significant electric capital projects were completed in 2014.

Ameren Illinois

Other income, net of expenses, was comparable between years. Other income, net of expenses, was lower at Ameren Illinois Transmission, partially offset by an increase in other income, net of expenses, at Ameren Illinois Electric Distribution, as discussed below. Other income, net of expenses, was comparable between years at Ameren Illinois Natural Gas.

Ameren Illinois Electric Distribution

Other income, net of expenses, increased $4 million, primarily because of increased interest income on the IEIMA 2013, 2014, and 2015 revenue requirement reconciliation regulatory assets.

Ameren Illinois Transmission

Other income, net of expenses, decreased $4 million, primarily because of decreased income from customer-requested construction.

Ameren Transmission

Other income, net of expenses, decreased $4 million, primarily because of decreased income from customer-requested construction at Ameren Illinois Transmission.

Interest Charges

2016 versus 2015

Ameren

Interest charges increased $27 million in 2016 compared with 2015, because of an approximately $475 million increase in average outstanding debt and an increase in the cost of debt at Ameren (parent). Ameren (parent) issued senior unsecured notes in November 2015 to repay lower-cost short-term debt incurred primarily in connection with the funding of increasing ATXI investments. An increase in interest charges at Ameren Transmission was partially offset by a decrease in interest charges at Ameren Missouri, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.

Ameren Missouri

Interest charges decreased $8 million, primarily because of a decrease in average outstanding debt.

Ameren Illinois

Interest charges increased $9 million, primarily because of an increase in interest charges at Ameren Illinois Transmission. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.

Ameren Illinois Transmission

Interest charges increased $9 million, primarily because of an increase in Ameren Illinois' average outstanding debt, interest charges on regulatory liabilities, and a decrease in the allowance for funds used during construction because of a reduction in construction work in progress as more projects were placed in service in 2016.

Ameren Transmission

Interest charges increased $23 million, primarily because of an increase in ATXI's and Ameren Illinois' average outstanding debt and an increase in the cost of debt.

2015 versus 2014

Ameren

Interest charges increased $14 million in 2015 compared with 2014, primarily because of increases in interest charges at Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, as discussed below. The increases were offset, in part, by a reduction in interest charges at Ameren (parent) of $15 million, primarily because of a decrease in average outstanding debt. Ameren (parent) repaid senior unsecured notes in May 2014, with proceeds from commercial paper issuances. Ameren (parent) issued senior unsecured notes in November 2015, the proceeds of which were used to repay commercial paper borrowings.

Ameren Missouri

Interest charges increased $8 million, primarily because of a decrease in the allowance for funds used during construction, as multiple significant electric projects were completed in 2014, and because of an increase in average outstanding debt.

Ameren Illinois

Interest charges increased $19 million, primarily because of an increase in average outstanding debt.

Ameren Illinois Electric Distribution

Interest charges increased $8 million, because of an increase in Ameren Illinois' average outstanding debt, and the absence in 2015 of a reduction from an ICC rate order received in December 2014, which partially reversed a charge recorded in 2013 that had disallowed the recovery from customers of certain debt premium costs.

Ameren Illinois Natural Gas

Interest charges increased $7 million, because of an increase in Ameren Illinois' average outstanding debt, and the absence in 2015 of a reduction from an ICC rate order received in December 2014, which partially reversed a charge recorded in 2013 that had disallowed the recovery from customers of certain debt premium costs.

Ameren Illinois Transmission

Interest charges increased $4 million, primarily because of an increase in Ameren Illinois' average outstanding debt.

Ameren Transmission

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

Income Taxes

The following table presents effective income tax rates for the years ended December 31, 2016, 2015, and 2014:

201620152014
Ameren37%38%39%
Ameren Missouri38%37%37%
Ameren Illinois38%37%41%
Ameren Illinois Electric Distribution38%36%40%
Ameren Illinois Natural Gas39%40%43%
Ameren Illinois Transmission38%37%42%
Ameren Transmission39%38%42%

See Note 13 – 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.

2016 versus 2015

Ameren

The effective tax rate was comparable between years. The one percentage point reduction in the 2016 effective tax rate, as compared to the 2015 effective tax rate, was primarily a result of the recognition of tax benefits associated with share-based compensation resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. This reduction was partially offset by a higher effective tax rate in 2016 as compared to 2015 at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between years at Ameren Missouri, Ameren Illinois Natural Gas, and Ameren Transmission.

Ameren Illinois

The effective tax rate was comparable between years. The effective tax rate was higher at Ameren Illinois Electric Distribution, primarily because of items detailed below. The effective tax rate was comparable between years at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

The effective tax rate was higher, primarily because of lower tax benefits from certain depreciation differences on property-related items.

2015 versus 2014

Ameren

The effective tax rate was comparable between years. The effective tax rate was lower in 2015 as compared to 2014 at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, primarily because of items detailed below. The effective tax rate was comparable between years at Ameren Missouri.

Ameren Illinois

The effective tax rate was lower, primarily because of items discussed at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission below. The Illinois statutory income tax rate was 9.5% in 2014 and decreased to 7.75% in 2015.

Ameren Illinois Electric Distribution

The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015, as well as higher tax benefits from certain depreciation differences on property-related items and fewer non-tax deductible costs.

Ameren Illinois Natural Gas

The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015 and the 2014 impacts on accumulated deferred income taxes of reducing the state statutory rate.

Ameren Illinois Transmission

The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015, as well as higher tax benefits from certain depreciation differences on property-related items and higher non-taxable income.

Ameren Transmission

The effective tax rate was lower, primarily because of a reduced Illinois state statutory rate in 2015, as well as higher tax benefits from certain depreciation differences on property-related items and higher non-taxable income at Ameren Illinois Transmission.

Income (Loss) from Discontinued Operations, Net of Taxes

No material activity was recorded associated with discontinued operations in 2016. In 2015, based on completion of the IRS audit of Ameren’s 2013 tax year, Ameren recognized a tax benefit of $53 million due to the resolution of an uncertain tax position from discontinued operations. No material activity was recorded associated with discontinued operations in 2014. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Our tariff-based gross margins 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, money pool borrowings, or, in the case of Ameren Missouri and Ameren Illinois, other short-term borrowings from affiliates 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). 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, environmental compliance, and other improvements. We intend to fund those capital expenditures primarily with cash provided by operating activities and short-term and long-term debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.

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, 2016, for the Ameren Companies. The working capital deficit as of December 31, 2016, 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, the Ameren Companies had access to $1.5 billion of liquidity at December 31, 2016.

The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2016, 2015, and 2014:

Net Cash Provided by (Used in) Operating ActivitiesNet Cash Provided by (Used in) Investing ActivitiesNet Cash Provided by (Used in) Financing Activities
201620152014201620152014201620152014
Ameren(a) – continuing operations$2,124$2,035$1,571$(2,141)$(1,951)$(1,856)$(265)$232$127
Ameren(a) – discontinued operations(1)(4)(6)—(25)139———
Ameren Missouri1,1691,247950(934)(724)(837)(434)(325)(113)
Ameren Illinois803763445(918)(913)(828)44220383
(a)Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Cash Flows from Operating Activities

Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional rate proceeding. Similar regulatory mechanisms exist for certain operating expenses that can also affect the timing of cash provided by operating activities. Each of these types of regulatory mechanisms have different recovery periods from when we pay a cost that is included in a regulatory mechanism until we receive cash from customers. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by changes in customer demand due to weather, significantly impact the amount and timing of our cash provided by operating activities. See 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.

2016 versus 2015

Ameren

Ameren’s cash from operating activities associated with continuing operations increased $89 million in 2016, compared with 2015. The following items contributed to the increase:

•A $126 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.
•A $70 million decrease in pension and postretirement benefit plan contributions.
•A $42 million insurance receipt at Ameren Missouri related to the Taum Sauk breach that occurred in 2005.
•A $40 million increase in cash associated with the recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
•A $38 million decrease in payments for purchased power compared with amounts collected from Ameren Illinois customers through a rider mechanism.
•A $37 million decrease in coal inventory purchases at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions experienced in 2014.
•A $33 million decrease in expenditures for customer energy efficiency program costs compared with amounts collected from customers.
•A $19 million increase in cash associated with the recovery of Ameren Illinois' transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.

The following items partially offset the increase in Ameren's cash from operating activities associated with continuing operations between years:

•A $166 million decrease resulting from the change in customer receivable balances.
•A $94 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.
•A $23 million increase in interest payments, primarily due to an increase in the cost and amount of outstanding debt of Ameren (parent) and an increase in the average outstanding debt at Ameren Illinois.
•A $20 million increase in payments for the refueling and maintenance outage at Ameren Missouri's Callaway energy center. There was no refueling and maintenance outage in 2015.
•A $9 million increase in labor costs at Ameren Illinois, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.
•A $7 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects.

Ameren’s cash from operating activities associated with discontinued operations was immaterial in both 2016 and 2015.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased $78 million in 2016, compared with 2015. The following items contributed to the decrease:

•A $142 million decrease resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.
•A $94 million decrease in net energy costs collected from customers under the FAC.
•A $20 million increase in payments for the refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.

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

•A $45 million decrease in income tax payments, pursuant to the tax allocation agreement with Ameren (parent), primarily related to higher deductions related to increased capital expenditures in 2016.
•A $42 million insurance receipt related to the Taum Sauk breach that occurred in December 2005.
•A $37 million decrease in coal inventory purchases, as additional coal was purchased in 2015 to compensate for delivery disruptions experienced in 2014.
•A $33 million decrease in pension and postretirement benefit plan contributions.
•A $11 million decrease in expenditures for customer energy efficiency program costs compared with amounts collected from customers.

Ameren Illinois

Ameren Illinois’ cash from operating activities increased $40 million in 2016, compared with 2015. The following items contributed to the increase:

•A $58 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, which was partially offset by the change in customer receivable balances.
•A $40 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.
•A $38 million decrease in payments for purchased power, compared with amounts collected from customers through a rider mechanism.
•A $22 million decrease in pension and postretirement benefit plan contributions.
•A $22 million decrease in expenditures for customer energy efficiency program costs compared with amounts collected from customers.
•A $19 million increase in cash associated with the recovery of transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.

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

•Income tax payments of $8 million in 2016, compared with income tax refunds of $113 million in 2015. During 2015, Ameren Illinois used net operating loss carryforwards from prior years, resulting in a reduction in payments. Ameren Illinois also had higher deductions for increased capital expenditures in 2015.
•A $9 million increase in labor costs primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.
•A $7 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects.
•A $7 million increase in interest payments, primarily due to an increase in the average outstanding debt, including senior secured notes issued in December 2015.

2015 versus 2014

Ameren

Ameren’s cash from operating activities associated with continuing operations increased $464 million in 2015, compared with 2014. The following items contributed to the increase:

•A $192 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 $149 million increase in net energy costs collected from Ameren Missouri customers under the FAC.
•A $137 million increase in cash associated with the recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments, as Ameren Illinois collected $69 million from customers in 2015 and refunded $68 million to customers in 2014.
•A $57 million decrease in Ameren Missouri rebate payments provided for customer-installed solar generation, as the rebate program was substantially completed by the end of 2014.
•A $33 million increase in natural gas commodity costs collected from customers under the PGAs, primarily related to Ameren Illinois.
•A $31 million decrease in the cost of natural gas held in storage caused primarily by lower natural gas prices.
•A $19 million decrease in payments for nuclear refueling and maintenance outages at the Ameren Missouri Callaway energy center. There was no refueling and maintenance outage in 2015; however, there were cash expenditures related to the planned 2016 spring outage made in 2015.

The following items partially offset the increase in Ameren's cash from operating activities associated with continuing operations during 2015, compared with 2014:

•A $49 million increase in coal inventory costs at Ameren Missouri caused by increased volumes resulting from the absence of weather-related railroad delivery delays that occurred in 2014.
•A net $29 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.
•A $24 million decrease in income tax refunds primarily due to the absence in 2015 of tax settlements pertaining to 2007 through 2011 that were received in 2014. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for income tax refund information.
•A $24 million increase in pension and postretirement benefit plan contributions.
•A $7 million increase in property tax payments at Ameren Missouri caused by both higher assessed property tax values and tax rates.
•A $7 million increase in expenditures for customer energy efficiency programs compared with amounts collected from Ameren Illinois customers.

Ameren’s cash from operating activities associated with discontinued operations was comparable between 2015 and 2014.

Ameren Missouri

Ameren Missouri’s cash from operating activities increased $297 million in 2015, compared with 2014. The following items contributed to the increase:

•A $149 million increase in net energy costs collected from customers under the FAC.
•A $143 million decrease in income taxes paid to Ameren (parent) pursuant to the tax allocation agreement, primarily related to a change in the tax treatment for generation repairs adopted in 2013, which increased payments in 2014.
•A $57 million decrease in rebate payments provided for customer-installed solar generation, as the rebate program was substantially completed by the end of 2014.
•A $37 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 $19 million decrease in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center. There was no refueling and maintenance outage in 2015; however, there were cash expenditures related to the 2016 spring outage made in 2015.

The following items partially offset the increase in Ameren Missouri's cash from operating activities during 2015, compared with 2014:

•A $49 million increase in coal inventory costs caused by increased volumes resulting from the absence of weather-related railroad delivery delays that occurred in 2014.
•A net $12 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.
•An $11 million increase in pension and postretirement benefit plan contributions.
•A $7 million increase in property tax payments caused by both higher assessed property tax values and tax rates.

Ameren Illinois

Ameren Illinois’ cash from operating activities increased $318 million in 2015, compared with 2014. The following items contributed to the increase:

•A $137 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments, as $69 million was collected from customers in 2015 and $68 million was refunded to customers in 2014.
•A $101 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 $69 million increase in income taxes refunds, pursuant to the tax allocation agreement with Ameren (parent), primarily related to deductions for accelerated depreciation and increased capital expenditures.
•A $31 million increase in natural gas commodity costs collected from customers under the PGA.
•A $26 million decrease in the cost of natural gas held in storage caused primarily by lower natural gas prices.

The following items partially offset the increase in Ameren Illinois’ cash from operating activities during 2015, compared with 2014:

•A net $17 million decrease in returns of collateral posted with counterparties, primarily resulting from changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades.
•A $12 million increase in pension and postretirement benefit plan contributions.
•A $7 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.

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. Considering Ameren’s assumptions at December 31, 2016, its investment performance in 2016, and its pension funding policy, Ameren expects to make annual contributions of $50 million to $70 million in each of the next five years, with aggregate estimated contributions of $290 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 35% and 55%, respectively. These amounts are estimates. They may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In 2016, Ameren contributed $57 million to its pension plans. See Note 11 – Retirement Benefits under Part II, Item 8, of this report for additional information.

Cash Flows from Investing Activities

2016 versus 2015

Ameren's cash used in investing activities associated with continuing operations increased by $190 million during 2016, compared with 2015. Capital expenditures increased $159 million, primarily because of increased transmission expenditures, which included a $41 million increase at ATXI primarily related to the Illinois Rivers project, and increased Ameren Missouri and Ameren Illinois capital expenditures.

During 2016, there was no cash used in investing activities associated with discontinued operations. During 2015, Ameren’s cash used in investing activities associated with discontinued operations consisted of a $25 million payment for a liability associated with the New AER divestiture.

Ameren Missouri’s cash used in investing activities

increased by $210 million during 2016, compared with 2015. Capital expenditures increased $116 million, primarily related to electric distribution system reliability and energy center projects. Additionally, there was an increase in net advances to the money pool of $89 million.

Ameren Illinois’ cash used in investing activities increased by $5 million during 2016, compared with 2015, because of increased capital expenditures, primarily related to qualified investments in natural gas infrastructure under the QIP rider, storm restoration costs, and reliability.

2015 versus 2014

Ameren's cash used in investing activities associated with continuing operations increased by $95 million during 2015, compared with 2014. Capital expenditures increased $132 million, because of increased transmission expenditures, which included a $174 million increase at ATXI, primarily related to the Illinois Rivers project, and increased Ameren Illinois capital expenditures, partially offset by decreased expenditures at Ameren Missouri.

During 2015, Ameren’s cash used in investing activities associated with discontinued operations consisted of a $25 million payment for a liability associated with the New AER divestiture. During 2014, cash provided by investing activities associated with Ameren’s discontinued operations consisted of $152 million received from Rockland Capital for the sale of the Elgin, Gibson City, and Grand Tower natural-gas-fired energy centers in January 2014, offset by payment of $13 million to IPH for the final working capital adjustment and certain liabilities associated with the New AER divestiture.

Ameren Missouri’s cash used in investing activities decreased by $113 million during 2015, compared with 2014. Capital expenditures decreased $125 million, primarily because several large projects were completed in 2014. Nuclear fuel expenditures decreased by $22 million because of the timing of purchases in 2015 compared with 2014. In addition, cash used in investing activities increased in 2015 because of net advances to the money pool of $36 million; there were no advances in 2014.

Ameren Illinois’ cash used in investing activities increased by $85 million during 2015, compared with 2014, because of increased capital expenditures, primarily for reliability and IEIMA projects.

Capital Expenditures

The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2016, 2015, and 2014:

201620152014
Ameren(a)$2,076$1,917$1,785
Ameren Missouri738622747
Ameren Illinois(b)924918835
(a)Includes amounts for Ameren registrant and nonregistrant subsidiaries and the elimination of intercompany transfers.
(b)See Note 16 – Segment Information under Part II, Item 8, of this report for additional information on Ameren Illinois' capital expenditures by segment.

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

Ameren’s 2015 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $375 million primarily on the Illinois Rivers project. Ameren Illinois spent $294 million on transmission projects and $134 million on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.

Ameren’s 2014 capital expenditures consisted of expenditures made by its subsidiaries including ATXI, which spent $201 million on the Illinois Rivers project. Ameren Missouri spent $101 million for electrostatic precipitator upgrades at its Labadie energy center, $33 million for the replacement of the nuclear reactor vessel head at its Callaway energy center, and $16 million for the construction of the O’Fallon energy center. Ameren Illinois spent $295 million on transmission projects 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, as well as to fund various Ameren Missouri energy center upgrades.

In December 2015, a federal tax law was enacted that authorized the continued use of bonus depreciation that allows for an acceleration of deductions for tax purposes. Bonus depreciation is expected to increase cash flow through at least 2020. Ameren expects to use this incremental cash flow to make capital investments in utility infrastructure for the benefit of its customers. Without these investments, the bonus depreciation would reduce rate base, which would reduce our revenue requirements and future earnings growth. The impact of bonus depreciation on Ameren Missouri, Ameren Illinois, and ATXI will vary based on investment levels at each company.

The following table presents Ameren's estimate of capital expenditures that will be incurred from 2017 through 2021, including construction expenditures, allowance for funds used during construction, and expenditures for compliance with existing environmental regulations. Ameren expects to continue to allocate more of its capital expenditures to Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission based, in part, on the constructive regulatory frameworks within which they operate.

20172018-2021Total
Ameren Missouri$785$3,070-$3,395$3,855-$4,180
Ameren Illinois Electric Distribution4801,965-2,1652,445-2,645
Ameren Illinois Natural Gas2551,110-1,2251,365-1,480
Ameren Illinois Transmission3751,7601,9502,1352,325
ATXI325240-265565-590
Other510-1515-20
Ameren$2,225$8,155-$9,015$10,380-$11,240

Ameren Missouri’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with environmental regulations. 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 three MISO-approved multi-value transmission projects. For additional information regarding the IEIMA capital expenditure requirements, the QIP rider, and ATXI's transmission projects, see Part I, Item 1, 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. 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 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, mercury, and CO2 emissions from its coal-fired energy centers. See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing environmental laws and regulations that affect, or may affect, our facilities and capital expenditures to comply with such laws and regulations.

Cash Flows from Financing Activities

Cash provided by, or used in, financing activities is driven by our financing needs, which depend on the level of cash provided

by operating activities, the level of cash used in investing activities, the dividends declared by Ameren's board of directors, and our long-term debt maturities, among other things.

2016 versus 2015

Ameren's financing activities associated with continuing operations used net cash of $265 million in 2016, compared with providing net cash of $232 million in 2015. The timing of short-term and long-term debt issuances, net of their repayments, resulted in $413 million less cash provided by financing activities in 2016, compared to 2015. No cash from financing activities was used for discontinued operations during 2016.

Ameren Missouri’s cash used in financing activities increased by $109 million in 2016, compared with 2015, primarily because of a $149 million decrease in cash provided by short-term and long-term debt activity. This was partially offset by a $40 million decrease in cash paid to Ameren (parent), net of capital contributions received.

Ameren Illinois' cash provided by financing activities decreased by $176 million in 2016, compared with 2015. Short-term and long-term debt issuances, net of their repayments, resulted in $39 million less cash provided by financing activities in 2016, compared with 2015. Additionally, there was a $110 million increase in dividends paid to Ameren (parent).

2015 versus 2014

Ameren's cash provided by financing activities associated with continuing operations increased $105 million in 2015, compared with 2014. Short-term and long-term debt issuances, net of their repayments, resulted in $117 million more cash provided by financing activities in 2015, compared with 2014.

Ameren Missouri’s cash used in financing activities increased $212 million in 2015, compared with 2014, primarily because of a $201 million decrease in cash provided by net short-term and long-term debt activity. Additionally, cash paid to Ameren (parent), net of capital contributions received, increased $11 million.

Ameren Illinois' cash provided by financing activities decreased $163 million in 2015, compared with 2014, primarily because of a $175 million decrease in cash provided by net short-term and long-term debt activity, partially offset by a $10 million increase in capital contributions received from Ameren (parent).

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 short-term intercompany borrowings, drawings under the Credit Agreements, or commercial paper issuances. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, short-term borrowing activity, commercial paper issuances, relevant interest rates, and

borrowings under Ameren’s money pool arrangements.

The following table presents Ameren's consolidated liquidity as of December 31, 2016:

Available at December 31, 2016
Ameren and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity$1,000
Less: Ameren (parent) commercial paper outstanding296
Missouri Credit Agreement – credit available704
Ameren and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity1,100
Less: Ameren (parent) commercial paper outstanding211
Less: Ameren Illinois commercial paper outstanding51
Less: Letters of credit4
Illinois Credit Agreement – credit available834
Total Credit Available$1,538
Cash and cash equivalents9
Total Liquidity$1,547

In December 2016, Ameren, Ameren Missouri and Ameren Illinois amended, restated, and extended the maturity dates of their Credit Agreements from December 2019, to December 2021. Borrowings by Ameren 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 scheduled to mature in December 2021, but the maturity date may be extended for two additional one-year periods upon mutual consent of the borrowers and lenders. The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren’s (parent), Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the Credit Agreements are available to Ameren to support issuances under Ameren’s commercial paper program, subject to borrowing sublimits. 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.

The following table presents the maximum aggregate amount available to each borrower under each facility:

Missouri Credit AgreementIllinois Credit Agreement
Ameren$700$500
Ameren Missouri800(a)
Ameren Illinois(a)800
(a)Not applicable.

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 approval by the FERC under the Federal Power Act. In February 2016, the FERC issued an order authorizing Ameren Missouri to issue up to $1 billion of short-term debt securities through March 2018. In August 2016, the FERC issued an order authorizing Ameren Illinois to issue up to $1 billion of short-term debt securities through September 2018. In July 2015, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2017.

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 our issuances (net of issuance discounts), redemptions, repurchases, and maturities of long-term debt for the years ended December 31, 2016, 2015, and 2014. The Ameren Companies did not issue any common stock or redeem or repurchase any preferred stock during the years ended 2016, 2015, and 2014. In 2016, 2015 and 2014, Ameren Missouri received cash capital contributions as a result of the tax allocation agreement from Ameren (parent). 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.

Month Issued, Redeemed, Repurchased, or Matured201620152014
Issuances of Long-term Debt
Ameren (parent)
2.70% Senior unsecured notes due 2020November$—$350$—
3.65% Senior unsecured notes due 2026November—350—
Ameren Missouri:
3.50% Senior secured notes due 2024April——350
3.65% Senior secured notes due 2045April—249—
3.65% Senior secured notes due 2045June149
Ameren Illinois:
4.30% Senior secured notes due 2044June——248
3.25% Senior secured notes due 2025December——300
4.15% Senior secured notes due 2046December240248—
Total long-term debt issuances$389$1,197$898
Redemptions, Repurchases, and Maturities of Long-term Debt
Ameren (parent):
8.875% Senior unsecured notes due 2014May$—$—$425
Ameren Missouri:
5.40% Senior secured notes due 2016February260
4.75% Senior secured notes due 2015April—114—
5.50% Senior secured notes due 2014May——104
City of Bowling Green capital lease (Peno Creek CT)December665
Ameren Illinois:
5.90% Series 1993 due 2023(a)January——32
5.70% 1994A Series due 2024(a)January——36
5.95% 1993 Series C-1 due 2026January——35
5.70% 1993 Series C-2 due 2026January——8
5.40% 1998A Series due 2028January——19
5.40% 1998B Series due 2028January——33
6.20% Senior secured notes due 2016June54——
6.25% Senior secured notes due 2016June75——
Total long-term debt redemptions, repurchases, and maturities$395$120$697

(a) Less than $1 million principal amount of the bonds remain outstanding after redemption.

In June 2015, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing. It will expire in June 2018.

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, 2016, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation. 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 and in certain of the Ameren Companies’ indentures and articles of incorporation.

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 and Return of Capital

Ameren paid to its shareholders common stock dividends totaling $416 million, or $1.715 per share, in 2016, $402 million, or $1.655 per share, in 2015, and $390 million, or $1.610 per share, in 2014.

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 10, 2017, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 44 cents per share, payable on March 31, 2017, to shareholders of record on March 14, 2017.

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 related to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in its 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 may not pay any dividend on its stock unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

At December 31, 2016, 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 $2.1 billion.

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

201620152014
Ameren Missouri$355$575(a)$340
Ameren Illinois110——
Ameren416402390
(a)Additionally, during 2014, Ameren Missouri returned capital of $215 million to Ameren (parent).

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 the preferred stock dividends to shareholders of record on a certain date, stating the date on which the dividend is payable and the amount to be paid. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.

Contractual Obligations

The following table presents our contractual obligations as of December 31, 2016. See Note 11 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.

Less than 1 Year1 – 3 Years3 – 5 YearsAfter 5 YearsTotal
Ameren:(a)
Long-term debt and capital lease obligations(b)$681$1,421$450$4,774$7,326
Interest payments(c)5028417374,6786,758
Operating leases(d)1324212381
Other obligations(e)1,2581,4083778293,872
Total cash contractual obligations$2,454$3,694$1,585$10,304$18,037
Ameren Missouri:
Long-term debt and capital lease obligations(b)$431$964$100$2,524$4,019
Interest payments(c)3526165523,4314,951
Operating leases(d)1122192173
Other obligations(e)7519332353702,289
Total cash contractual obligations$1,545$2,535$906$6,346$11,332
Ameren Illinois:
Long-term debt(b)$250$457$—$1,900$2,607
Interest payments(c)1291811521,1951,657
Operating leases(d)12216
Other obligations(e)4644631424441,513
Total cash contractual obligations$844$1,103$296$3,540$5,783
(a)Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(b)Excludes unamortized discount and premium and debt issuance costs of $50 million, $25 million, and $19 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, 2016.
(d)Amounts for certain land-related leases have indefinite payment periods. The annual obligation of $3 million, $2 million, and $1 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, for these items is included in the Less than 1 Year, 1 – 3 Years, and 3 – 5 Years columns. See Leases in Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for additional information.
(e)See Other Obligations in Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein.

As of December 31, 2016, Ameren, Ameren Missouri, and Ameren Illinois had no unrecognized tax benefits (detriments) for uncertain tax positions.

Off-Balance-Sheet Arrangements

At December 31, 2016, none of the Ameren Companies had off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

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 debtBaa1BBB+
Commercial paperP-2A-2
Ameren Illinois:
Issuer/corporate credit ratingA3BBB+
Secured debtA1A
Senior unsecured debtA3BBB+
Commercial paperP-2A-2

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 was $12 million at Ameren and Ameren Missouri at December 31, 2016. Cash collateral posted by external parties with Ameren, Ameren Missouri, and Ameren Illinois were immaterial at December 31, 2016. A sub-investment-grade issuer or senior unsecured debt rating (whether below “BBB-” from S&P or below “Baa3” from Moody's) at December 31, 2016, 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 $80 million, $54 million, and $26 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2016, if market prices were 15% higher or lower than December 31, 2016 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 are seeking to improve our regulatory frameworks and cost recovery mechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We are seeking to align our overall spending, both operating and capital, with economic conditions and with regulatory frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We are focused on minimizing the gap between allowed and earned returns on equity and intend to allocate capital resources to our business opportunities that we expect to offer the most attractive risk-adjusted return potential.

As a part of Ameren's strategic plan, we are pursuing projects to meet our customer energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories, as well as evaluating competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO as they arise. Additionally, Ameren Missouri will make investments over time that will enable it to transition to a more diverse energy portfolio.

Below are some key trends, events, and uncertainties that are reasonably likely to affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2017 and beyond.

Operations

•Ameren continues to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The Illinois Rivers project involves the construction of a transmission line from western Indiana across the state of Illinois to eastern Missouri. The last section of this project is expected to be completed by 2019. The Spoon River project, located in northwest Illinois, and the Mark Twain project, located in northeast Missouri, are the other two MISO-approved projects to be constructed by ATXI. Construction activities for the Spoon River project are continuing on schedule and the project is expected to be completed in 2018. The Illinois Rivers and the Spoon River projects have received all of the necessary approvals to authorize their construction. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. Before starting construction, ATXI must obtain assents for road crossings from the five counties where the line will be constructed. None of the five county commissions have approved ATXI’s requests for the assents. ATXI is planning to complete the project in 2019; however, further delays in obtaining the assents could delay the completion date. The total investment in all three projects is expected to be more than $575 million from 2017 through 2019. Ameren Illinois expects to invest $2.2 billion in electric transmission assets from 2017 through 2021 to replace aging infrastructure and improve reliability.
•Both 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 the rates that became effective on January 1, 2017, and the currently allowed 10.82% return on common equity, the 2017 revenue requirement for Ameren Illinois’ electric transmission business would be $258 million. The 2017 revenue requirement represents a $33 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.4 billion. Based on the rates that became effective on January 1, 2017, and the currently allowed 10.82% return on equity, the 2017 revenue requirement for ATXI’s electric transmission business would be $171 million. The 2017 revenue requirement represents a $44 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a 10.82% return on common equity. These January 2017 rates reflect a capital structure comprised of 56.3% common equity and a projected average rate base of $1.1 billion, reflecting additional investment in the Illinois Rivers project.
•The return on common equity was the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each challenged the allowed base return on common equity for MISO transmission owners, including Ameren Illinois and ATXI. In September 2016, the FERC issued a final order in

the November 2013 complaint case which lowered the allowed base return on common equity to 10.32%, or a 10.82% total return on common equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. The order was consistent with the initial decision an administrative law judge issued in December 2015, and requires customer refunds, with interest, to be issued for the 15-month period ended February 2015. In addition, the new allowed return on common equity is reflected in rates prospectively from the September 2016 effective date of the order. Refunds for the November 2013 complaint case are expected to be issued in the first half of 2017. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by FERC, would lower the allowed base return on common equity to 9.70%, or a 10.20% total return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. It would also require the issuance of customer refunds, with interest, for the 15-month period ended May 2016. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. That final order will determine the allowed return on common equity for the 15-month period ended May 2016. That final order will also establish the allowed return on common equity that will apply prospectively from its expected second quarter 2017 effective date, replacing the current 10.82% total return on common equity, which became effective in September 2016. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren's and Ameren Illinois' annual earnings by an estimated $7 million and $4 million, respectively, based on each company’s 2017 projected rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective December 31, 2016 balance sheets, representing their estimate of the expected refunds.

•In July 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service. Relating to that request, in February 2017, Ameren Missouri, the MoPSC staff, the MoOPC, and all intervenors filed a unanimous stipulation and agreement with the MoPSC. The stipulation and agreement, which is subject to MoPSC approval, would result in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate order. The stipulation and agreement did not specify the common equity percentage, the rate base, or the allowed return on common equity. The new revenue requirement reflects the current actual sales volumes of the New Madrid Smelter, whose operations remain suspended, as well as other agreed upon sales volumes. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs under the stipulation and agreement would decrease by $54 million from the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the

amortization period of certain regulatory assets, would reduce expenses by $26 million from the base levels established in the MoPSC's April 2015 electric rate order. The stipulation and agreement contemplates that new rates will become effective on or before March 20, 2017.

•In the first quarter of 2016, Noranda, which was historically Ameren Missouri's largest customer, suspended operations at the New Madrid Smelter and filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. Operations at the New Madrid Smelter remain suspended, and Ameren Missouri is uncertain of future sales to the smelter. As a result, Ameren Missouri will not fully recover its revenue requirement until rates are adjusted prospectively by the MoPSC to accurately reflect the actual sales volumes to the New Madrid Smelter. Based on the unanimous stipulation and agreement filed with the MoPSC in February 2017, electric rates are expected to be adjusted in March 2017 to accurately reflect the smelter’s actual sales volumes.
•The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois' 2017 electric distribution service revenues will be based on its 2017 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2017 revenue requirement is expected to be higher than the 2016 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of 5.25%, and an expected increase in the monthly average of United States treasury bonds. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $7 million change in Ameren's and Ameren Illinois' net income, based on its 2017 projected rate base.
•In December 2016, the ICC issued an order with respect to Ameren Illinois’ annual update filing. The ICC approved a $14 million decrease in Ameren Illinois’ electric distribution service revenue requirement that began in January 2017. These rates have affected, and will continue to affect, Ameren Illinois' cash receipts during 2017, but will not affect its electric distribution service operating revenues, which will instead be determined by Ameren Illinois' recoverable costs, rate base, common equity percentage, and the monthly average of the United States treasury bonds in 2017. The 2017 revenue requirement reconciliation, as discussed above, is expected to result in a regulatory asset that will be collected from customers in 2019.
•Beginning as early as June 2017, the FEJA will allow Ameren Illinois to earn a return on its electric energy efficiency program investments. Ameren Illinois electric energy efficiency investments will be deferred as a regulatory asset and will earn a return at the company’s weighted average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity

portion of Ameren Illinois’ return on electric energy efficiency investments can also be increased or decreased by 200 basis points based on the achievement of annual energy savings goals. The FEJA increased the level of electric energy efficiency saving targets through 2030. Based on a formula provided in the act, Ameren Illinois estimates it can annually invest up to $100 million from 2018 through 2021, up to $107 million annually from 2022 through 2025, and up to $114 million annually from 2026 through 2030. The ICC has the ability to lower the electric energy efficiency saving goals if there are insufficient cost effective measures available. The electric energy efficiency program investments and the return on those investments will be recovered through a rider, and will not be included in the IEIMA formula rate process.

•Beginning in 2017, the FEJA decouples electric distribution revenues established in a rate proceeding from actual sales volumes by providing that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes reflected in that year's rates will be collected from or refunded to customers within two years.
•Ameren Missouri's next scheduled refueling and maintenance outage at its Callaway energy center will be in fall 2017 and Ameren Missouri expects to incur $32 million of maintenance expenses, which approximates the cost of the spring 2016 outage. During a scheduled outage, 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.
•As we continue to experience cost increases and to make infrastructure investments, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy efficiency programs, increased customer use of innovative and increasingly cost-effective technological advances including private generation and storage, increased investments and expected future investments for environmental compliance, system reliability improvements, and new generation capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs and higher property taxes, among other costs.

For additional information regarding recent rate orders,

lawsuits, and related appeals and pending requests filed with state and federal regulatory commissions, including the February 2017 unanimous stipulation and agreement filed with the MoPSC that settles Ameren Missouri's July 2016 electric rate case, see Note 2 – Rate and Regulatory Matters and Note 10 – Callaway Energy Center under Part II, Item 8, of this report.

Liquidity and Capital Resources

•Through 2021, 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 in total up to $11.2 billion (Ameren Missouri – up to $4.2 billion; Ameren Illinois – up to $6.4 billion; ATXI – up to $0.6 billion) of capital expenditures during the period from 2017 through 2021.
•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. These costs could be prohibitive, which could result in the closure 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 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 rates charged to customers.
•In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until the legal appeals are concluded. If the rule is ultimately upheld and not rescinded or altered significantly by the new federal administration, Ameren Missouri expects to incur increased net fuel and operating costs, and make new or accelerated capital expenditures, in addition to the costs of making modifications to existing operations in order to achieve compliance. Compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could result in increased operating costs.
•Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three years and will file its next plan in 2017. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, was a 20-year plan that supported a more diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, hydro and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as those energy centers reach the end of their useful lives, expanding customer energy efficiency programs, and adding natural gas-fired combined cycle generation.
•The Ameren Companies have multiyear credit agreements

that cumulatively provide $2.1 billion of credit through December 2021, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements. By the end of 2018, $803 million and $707 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their outstanding short-term debt with long-term debt in 2017. 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.

•In December 2015, a federal tax law was enacted that authorized the continued use of bonus depreciation which allows for an acceleration of deductions for tax purposes at a rate of 50% through 2017. The rate will be reduced to 40% in 2018 and then to 30% in 2019. Bonus depreciation will be phased out in 2020 unless a new law is enacted. Based on existing tax laws, bonus depreciation is expected to reduce or eliminate federal income tax payments through at least 2020. Ameren expects to use this incremental cash flow to make capital investments in utility infrastructure for the benefit of its customers. Without these investments, bonus depreciation would reduce rate base, which reduces our revenue requirements and future earnings growth. The impact of bonus depreciation on the Ameren Companies will vary based on investment levels at each company.
•As of December 31, 2016, Ameren had $539 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $37 million and Ameren Illinois – $137 million) and $130 million in federal and state income tax credit carryforwards (Ameren Missouri – $29 million and Ameren Illinois – $1 million). In addition, Ameren has $35 million of expected state income tax refunds and state overpayments. Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities for Ameren Missouri through 2017 and Ameren Illinois until 2021. Based on existing tax laws, Ameren does not expect to make material federal income tax payments until 2021. These tax benefits, primarily at the Ameren (parent) level, when realized, would be available to support funding Ameren Transmission investments.
•Ameren expects its cash used for capital expenditures and dividends to exceed cash provided by operating activities over the next several years. Ameren expects to use debt to fund such cash shortfalls; it does not currently expect to issue equity over the next several years.

The above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance

our results of operations, financial position, or liquidity. These strategies may include acquisitions, divestitures, and 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, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments
•Ameren Illinois’ assessment of and ability to estimate the current year’s electric delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking process
•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 process
•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. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. 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 revenue requirement pursuant to the IEIMA for interim periods by using internal forecasted information, such as projected operations and maintenance expenses, depreciation expense, taxes other than income taxes, and rate base, as well as published forecasted data regarding that year's monthly average yields of the 30-year United States Treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31 of each year using that year's actual operating results and assesses the probability of recovery from or refund to customers that the ICC will order at the end of the following year. Variations in costs incurred, investments made, or orders by the ICC or courts can result in a subsequent change in Ameren Illinois' estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates lost revenues 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 11 – 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 11 – 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 10 – Callaway Energy Center and Note 15 – 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 13 – Income Taxes under Part II, Item 8, of this report.

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

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, change 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 results of 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 13 – Income Taxes under Part II, Item 8, of this report for the amount of deferred tax assets and uncertain tax positions recorded at December 31, 2016.

Unbilled Revenue

At the end of each period, Ameren, Ameren Missouri, and Ameren Illinois estimate the usage that has been provided to customers but not yet billed. This usage amount, along with a per unit price, is used to estimate an unbilled balance.

•Estimating customer energy usage
•Estimating impacts of weather and other usage-affecting factors for the unbilled period
•Estimating loss of energy during transmission and delivery

Basis for Judgment

We base our estimate of unbilled revenue each period on the volume of energy delivered, as valued by a model of billing cycles and historical usage rates and growth or contraction by customer class for our service area. This figure is then adjusted for the modeled impact of seasonal and weather variations based on historical results. See the balance sheet for each of the Ameren Companies under Part II, Item 8, of this report for unbilled revenue amounts.

Impact of New Accounting Pronouncements

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

EFFECTS OF INFLATION AND CHANGING PRICES

Ameren’s rates for retail electric and natural gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by the FERC. Rate regulation is generally based on the recovery of historical or projected costs. As a result, revenue increases could lag behind changing prices. Ameren Illinois participates in the performance-based formula ratemaking process pursuant to the IEIMA for its electric distribution business. Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Within the IEIMA formula, the monthly average yields of 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the earnings of Ameren Illinois’ electric distribution business. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula 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 actual sales volumes, is used to adjust billing rates in a subsequent year.

The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable

from customers. As a result, customer rates designed to provide recovery of historical costs through depreciation might not be adequate to replace plant in future years.

Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. The April 2015 MoPSC electric rate order approved Ameren Missouri’s request for continued use of the FAC; however, it changed the FAC to exclude all transmission revenues and substantially all transmission charges. Ameren Missouri is therefore exposed to transmission charges to the extent they exceed transmission revenues. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.

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

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

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