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

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

Below is a summary description of Ameren’s principal subsidiaries, including Ameren Missouri, Ameren Illinois, and ATXI. Ameren also has other subsidiaries that conduct other activities, such as the provision of shared services. Ameren evaluates competitive electric transmission investment opportunities as they arise. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

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

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

•	ATXI operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers and Mark Twain projects, and placed the Spoon River project in service in February 2018.

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

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. Ameren remains focused on disciplined cost management and strategic capital allocation. In 2017, Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks. It invested $1.4 billion of capital expenditures in its FERC rate-regulated electric transmission and Illinois electric and natural gas distribution businesses.

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The electric rate order resulted in a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in the base level of net energy costs, and a $26 million reduction in the base level of certain tracked expenses, compared with the amounts in the MoPSC’s April 2015 rate order. The new rates and base level of expenses became effective on April 1, 2017. In September 2017, Ameren Missouri filed its nonbinding 20-year integrated resource plan with the MoPSC. This plan includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable sources by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, and adding 100 megawatts of solar generation over the next 10 years. These new renewable energy sources would support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to customer rate increase limitations. The plan also provides for expanding renewable generation, retiring coal-fired energy centers as they reach the end of their useful lives, expanding customer energy-efficiency programs, and adding cost-effective demand response programs. The new renewable energy sources identified in Ameren Missouri’s plan could represent incremental investments of approximately $1 billion through 2020. In connection with the integrated resource plan filing, Ameren Missouri established a goal of reducing CO2 emissions 80% by

2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of its useful life.

In January 2017, Ameren Illinois implemented provisions of the FEJA that improved the constructive regulatory framework of its electric distribution business. The FEJA decoupled electric distribution revenues established in a rate proceeding from actual sales volumes. It provided that any revenue changes driven by actual electric distribution sales volumes differing from sales volumes that are reflected in that year’s rates be collected from, or refunded to, customers within two years. Also, since June 2017, the FEJA has allowed Ameren Illinois to defer the costs of its electric energy-efficiency program as a regulatory asset and earn a return on those investments. The regulatory asset earns 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 program investments can also be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49 million, which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider. The request was based on a 10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion.

In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with Ameren Missouri and an electric cooperative in northeast Missouri to locate almost all of the Mark Twain project on existing line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. In January 2018, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain project. ATXI plans to begin construction in the second quarter of 2018 and to complete the project by the end of 2019.

In October 2017, Ameren’s board of directors increased the quarterly common stock dividend to 45.75 cents per share, resulting in an annualized equivalent dividend rate of $1.83 per share.

Earnings

Net income attributable to Ameren common shareholders from continuing operations was $523 million, or $2.14 per diluted share, for 2017, and $653 million, or $2.68 per diluted share, for 2016. Net income was unfavorably affected in 2017, compared with 2016, by increased income tax expense due to a noncash charge to earnings for the revaluation of deferred taxes primarily at Ameren (parent) as a result of the TCJA and the increase in the Illinois income tax rate. Earnings were also unfavorably affected in 2017, compared with 2016, by decreased demand, primarily at Ameren Missouri, due to milder temperatures in 2017, by the absence in 2017 of the MEEIA 2013 performance incentive, and by increased depreciation and amortization expenses at Ameren Missouri. Net income was favorably affected in 2017, compared with 2016, by an increase in base rates, and lower base level of expenses at Ameren Missouri, pursuant to the MoPSC’s March 2017 electric rate order, and by increased investments in infrastructure at the Ameren Illinois Electric Distribution and Ameren Transmission segments, which reflect Ameren’s strategy to allocate incremental capital to those businesses.

After the application of jurisdictional regulatory recovery mechanisms, the effect of the revaluation of deferred taxes as a result of the TCJA was a decrease to Ameren’s and Ameren Missouri’s net income of $154 million and $36 million, respectively, while the effect on Ameren Illinois’ net income was immaterial.

Liquidity

At December 31, 2017, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.6 billion.

Capital Expenditures

In 2017, Ameren continued to make significant investment in its utility businesses by making capital expenditures of $0.8 billion, $0.5 billion, $0.2 billion, and $0.6 billion in Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission, respectively. For 2018 through 2022, Ameren’s cumulative capital expenditures are projected to range from $10.5 billion to $11.4 billion. The projected spending by segment includes up to $4.5 billion, $2.5 billion, $1.7 billion, and $2.7 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. Economic conditions, energy-efficiency investments by our customers and by us, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by nuclear refueling and other energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. Almost all of Ameren’s revenues are subject to state or federal regulation.

This regulation has a material impact on the prices we charge for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, within the frameworks established by our regulators.

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. As described below, 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 Missouri’s FAC cost recovery mechanism allows it to recover or refund, through customer rates, 95% of the variance in net energy costs from the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. Ameren Missouri accrues net energy costs that exceed the amount set in base rates (FAC under-recovery) as a regulatory asset. Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense to reduce the previously recognized FAC regulatory asset. In addition, Ameren Missouri’s MEEIA customer energy-efficiency program costs, the throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional rate proceeding. Ameren Missouri also has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a renewable energy standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to defer the difference between actual costs incurred and costs included in customer rates as a regulatory asset or regulatory liability. The difference will be reflected in base rates in a subsequent MoPSC rate order.

Ameren Illinois’ electric distribution service business has cost recovery mechanisms for power purchased and transmission services incurred on behalf of its customers. The FEJA also provides Ameren Illinois with cost recovery of renewable energy credit compliance, zero-emission credits, and energy-efficiency investments as well as a return on those electric energy-efficiency investments. Ameren Illinois’ natural gas business has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through costs do not affect Ameren Illinois’ electric or natural gas margins, as any change in costs is offset by a corresponding change in revenues. Ameren Illinois employs other cost recovery mechanisms for natural gas customer energy-efficiency program costs and certain environmental costs, as well as bad debt expense and costs of certain asbestos-related claims not recovered in base rates. Ameren Illinois’ natural gas business also has the QIP rider, which provides for recovery of, and a return on, qualifying infrastructure plant investments that are placed in service between regulatory rate reviews.

Ameren Illinois’ electric distribution service rates are reconciled annually to its actual revenue requirement and allowed return on equity, under a formula ratemaking process effective through 2022. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement. The regulatory balance is then collected from, or refunded to, customers within two years.

Ameren Illinois’ electric distribution service revenue requirement is based on recoverable costs, year-end rate base, a capital structure of 50% common equity, and a return on equity. The return on equity component under the IEIMA and the FEJA is equal to the calendar year average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois’ annual return on equity under the formula ratemaking frameworks for both its electric distribution service and its electric energy-efficiency investments is directly correlated to the yields on such bonds. Beginning in 2017, the FEJA also provides that Ameren Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes.

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

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

Earnings Summary

The following table presents a summary of Ameren’s earnings for the years ended December 31, 2017, 2016, and 2015:

	2017				2016				2015
Net income attributable to Ameren common shareholders	$	523			$	653			$	630
Earnings per common share – diluted	2.14				2.68				2.59
Net income attributable to Ameren common shareholders – continuing operations	523				653				579
Earnings per common share – diluted – continuing operations	2.14				2.68				2.38

2017 versus 2016

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

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

•	an increase in income tax expense, primarily at Ameren (parent), due to the revaluation of deferred taxes, as a result of a decrease in the federal statutory corporate income tax rate resulting from enactment of the TCJA (63 cents per share), and an increase in the Illinois corporate income tax rate (6 cents per share), as discussed in Note 12 – Income Taxes under Part II, Item 8, of this report;

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

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

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

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

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

•	an increase in base rates, net of increased revenues in 2016 from the suspension of operations at the New Madrid Smelter, and lower base level of expenses at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order as discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report (32 cents per share);

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

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

•

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

The cents per share information presented above is based on the diluted average shares outstanding in 2016. Pretax amounts have been presented net of income taxes, using Ameren’s 2016 statutory tax rate of 39%.

2016 versus 2015

Net income attributable to Ameren common shareholders from continuing operations in 2016 increased $74 million, or $0.30 per diluted share, from 2015. The increase was due to net income increases of $34 million, $22 million, $5 million, and $3 million at Ameren Transmission, Ameren Illinois Natural Gas, Ameren Missouri, and Ameren Illinois Electric Distribution, respectively. Additionally, the net loss from other businesses, primarily Ameren (parent), and intersegment eliminations decreased $10 million.

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

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

•

increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base investment. Ameren Transmission earnings also benefited from a temporarily higher allowed return on common equity, recognizing an allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 complaint case (19 cents per share);

•	the absence of a provision recognized in 2015, as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its Callaway energy center site (18 cents per share);

•	increased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures (estimated at 15 cents per share);

•	higher natural gas distribution rates at Ameren Illinois pursuant to a December 2015 order (11 cents per share);

•	an income tax benefit recorded at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation (9 cents per share);

•	decreased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri (7 cents per share). This was due, in part, to a reduction in energy center maintenance costs, excluding the cost of the Callaway energy center’s scheduled refueling and maintenance outage (discussed below), and reduced electric distribution maintenance expenditures; and

•	increased Ameren Illinois Electric Distribution earnings under formula ratemaking, primarily due to additional rate base investment, partially offset by a lower return on equity resulting from a reduction in the 30-year United States Treasury bond yields (2 cents per share).

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

•	the absence in 2016 of MEEIA net shared benefits due to the expiration of MEEIA 2013, partially offset by the recognition of a MEEIA 2013 performance incentive (15 cents per share);

•	decreased Ameren Missouri sales to the New Madrid Smelter resulting from a reduction in operations at the smelter (15 cents per share);

•	the cost of the Callaway energy center’s scheduled refueling and maintenance outage in 2016. There was no Callaway refueling and maintenance outage in 2015 (7 cents per share);

•	increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri, primarily resulting from additional electric property, plant, and equipment (4 cents per share);

•	decreased Ameren Illinois Electric Distribution earnings resulting from the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism (4 cents per share);

•	decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues (3 cents per share); and

•	increased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Illinois Natural Gas, primarily due to increased repairs and compliance expenditures (2 cents per share).

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

For additional details regarding the Ameren Companies’ segment results of operations, including explanations of 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, 2017, 2016, and 2015:

2017	Ameren Missouri				Ameren Illinois Electric Distribution				Ameren Illinois Natural Gas				Ameren Transmission				Other / Intersegment Eliminations				Total
Electric margins	$	2,431			$	1,109			$	—			$	426			$	(31	)		$	3,935
Natural gas margins	79				—				479				—				(2		)		556
Other revenues	—				1				—				—				(1		)		—
Other operations and maintenance	(902		)		(512		)		(224		)		(63		)		41				(1,660		)
Depreciation and amortization	(533		)		(239		)		(59		)		(60		)		(5		)		(896		)
Taxes other than income taxes	(328		)		(74		)		(60		)		(6		)		(9		)		(477		)
Other income and (expenses)	40				3				(3		)		1				(3		)		38
Interest charges	(207		)		(73		)		(36		)		(67		)		(8		)		(391		)
Income taxes	(254		)		(83		)		(36		)		(90		)		(113		)		(576		)
Net income (loss)	326				132				61				141				(131		)		529
Noncontrolling interests – preferred stock dividends	(3		)		(1		)		(1		)		(1		)		—				(6		)
Net income (loss) attributable to Ameren common shareholders	$	323			$	131			$	60			$	140			$	(131	)		$	523
2016
Electric margins	$	2,397			$	1,105			$	—			$	355			$	(27	)		$	3,830
Natural gas margins	79				—				462				—				(2		)		539
Other revenues	1				—				—				—				(1		)		—
Other operations and maintenance	(893		)		(538		)		(215		)		(60		)		30				(1,676		)
Depreciation and amortization	(514		)		(226		)		(55		)		(43		)		(7		)		(845		)
Taxes other than income taxes	(325		)		(72		)		(58		)		(4		)		(8		)		(467		)
Other income and (expenses)	42				8				(1		)		2				(9		)		42
Interest charges	(211		)		(72		)		(34		)		(58		)		(7		)		(382		)
Income taxes	(216		)		(78		)		(39		)		(74		)		25				(382		)
Net income (loss)	360				127				60				118				(6		)		659
Noncontrolling interests – preferred stock dividends	(3		)		(1		)		(1		)		(1		)		—				(6		)
Net income (loss) attributable to Ameren common shareholders	$	357			$	126			$	59			$	117			$	(6	)		$	653
2015
Electric margins	$	2,481			$	1,074			$	—			$	259			$	(26	)		$	3,788
Natural gas margins	80				—				425				—				(2		)		503
Other revenues	2				—				—				—				(2		)		—
Other operations and maintenance	(925		)		(532		)		(219		)		(56		)		38				(1,694		)
Provision for Callaway construction and operating license	(69		)		—				—				—				—				(69		)
Depreciation and amortization	(492		)		(212		)		(52		)		(33		)		(7		)		(796		)
Taxes other than income taxes	(335		)		(72		)		(56		)		(2		)		(8		)		(473		)
Other income and (expenses)	41				8				(1		)		2				(6		)		44
Interest charges	(219		)		(71		)		(35		)		(35		)		5				(355		)
Income taxes	(209		)		(71		)		(24		)		(51		)		(8		)		(363		)
Income (loss) from continuing operations	355				124				38				84				(16		)		585
Income from discontinued operations, net of taxes	—				—				—				—				51				51
Net income	355				124				38				84				35				636
Noncontrolling interests – preferred stock dividends	(3		)		(1		)		(1		)		(1		)		—				(6		)
Net income attributable to Ameren common shareholders	$	352			$	123			$	37			$	83			$	35			$	630

Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2017, 2016, and 2015:

2017	Electric Distribution				Natural Gas				Transmission				Total
Electric margins	$	1,109			$	—			$	258			$	1,367
Natural gas margins	—				479				—				479
Other revenues	1				—				—				1
Other operations and maintenance	(512		)		(224		)		(53		)		(789		)
Depreciation and amortization	(239		)		(59		)		(43		)		(341		)
Taxes other than income taxes	(74		)		(60		)		(3		)		(137		)
Other income and (expenses)	3				(3		)		1				1
Interest charges	(73		)		(36		)		(35		)		(144		)
Income taxes	(83		)		(36		)		(47		)		(166		)
Net income	132				61				78				271
Preferred stock dividends	(1		)		(1		)		(1		)		(3		)
Net income attributable to common shareholder	$	131			$	60			$	77			$	268
2016
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		)		2				9
Interest charges	(72		)		(34		)		(34		)		(140		)
Income taxes	(78		)		(39		)		(41		)		(158		)
Net income	127				60				68				255
Preferred stock dividends	(1		)		(1		)		(1		)		(3		)
Net income attributable to common shareholder	$	126			$	59			$	67			$	252
2015
Electric margins	$	1,074			$	—			$	189			$	1,263
Natural gas margins	—				425				—				425
Other operations and maintenance	(532		)		(219		)		(46		)		(797		)
Depreciation and amortization	(212		)		(52		)		(31		)		(295		)
Taxes other than income taxes	(72		)		(56		)		(2		)		(130		)
Other income and (expenses)	8				(1		)		2				9
Interest charges	(71		)		(35		)		(25		)		(131		)
Income taxes	(71		)		(24		)		(32		)		(127		)
Net income	124				38				55				217
Preferred stock dividends	(1		)		(1		)		(1		)		(3		)
Net income attributable to common shareholder	$	123			$	37			$	54			$	214

Margins

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2017 compared with 2016, as well as 2016 compared with 2015. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Electric and Natural Gas Margins
2017 versus 2016	Ameren Missouri				Ameren Illinois Electric Distribution				Ameren Illinois Natural Gas				Ameren Transmission(a)				Other / Intersegment Eliminations				Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	(65	)		$	(5	)		$	—			$	—			$	—			$	(70	)
Base rates (estimate)	61				42				—				71				—				174
Recovery of power restoration efforts provided to other utilities	7				1				—				—				—				8
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)	(6		)		—				—				—				—				(6		)
Off-system sales and capacity revenues	22				—				—				—				—				22
MEEIA 2013 performance incentive	(28		)		—				—				—				—				(28		)
Transmission services revenues	11				—				—				—				—				11
Other	4				(1		)		—				—				5				8
Cost recovery mechanisms – offset in fuel and purchased power(c)	(11		)		18				—				—				—				7
Other cost recovery mechanisms(d)	24				(36		)		—				—				—				(12		)
Total electric revenue change	$	19			$	19			$	—			$	71			$	5			$	114
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)	$	(22	)		$	—			$	—			$	—			$	—			$	(22	)
Effect of weather (estimate)(b)	13				(1		)		—				—				—				12
Effect of lower net energy costs included in base rates	39				—				—				—				—				39
Transmission services charges	(16		)		—				—				—				—				(16		)
Other	(10		)		4				—				—				(9		)		(15		)
Cost recovery mechanisms – offset in electric revenue(c)	11				(18		)		—				—				—				(7		)
Total fuel and purchased power change	$	15			$	(15	)		$	—			$	—			$	(9	)		$	(9	)
Net change in electric margins	$	34			$	4			$	—			$	71			$	(4	)		$	105
Natural gas revenue change:
Effect of weather (estimate)(b)	$	(4	)		$	—			$	—			$	—			$	—			$	(4	)
QIP rider	—				—				12				—				—				12
Other	—				—				(3		)		—				—				(3		)
Cost recovery mechanisms – offset in natural gas purchased for resale(c)	2				—				(28		)		—				—				(26		)
Other cost recovery mechanisms(d)	—				—				8				—				—				8
Total natural gas revenue change	$	(2	)		$	—			$	(11	)		$	—			$	—			$	(13	)
Natural gas purchased for resale change:
Effect of weather (estimate)(b)	$	4			$	—			$	—			$	—			$	—			$	4
Cost recovery mechanisms – offset in natural gas revenue(c)	(2		)		—				28				—				—				26
Total natural gas purchased for resale change	$	2			$	—			$	28			$	—			$	—			$	30
Net change in natural gas margins	$	—			$	—			$	17			$	—			$	—			$	17

2016 versus 2015	Ameren Missouri				Ameren Illinois Electric Distribution				Ameren Illinois Natural Gas				Ameren Transmission(a)				Other / Intersegment Eliminations				Ameren
Electric revenue change:
Effect of weather (estimate)(b)	$	57			$	15			$	—			$	—			$	—			$	72
Base rates (estimate)	48				38				—				102				—				188
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)	7				—				—				—				—				7
New Madrid Smelter revenues	(129		)		—				—				—				—				(129		)
Off-system sales and capacity revenues	153				—				—				—				—				153
MEEIA 2013 net shared benefits	(85		)		—				—				—				—				(85		)
MEEIA 2013 performance incentive	28				—				—				—				—				28
Transmission services revenues	3				—				—				—				—				3
Purchased power rider order in 2015	—				(15		)		—				—				—				(15		)
Other	(1		)		(1		)		—				(6		)		(21		)		(29		)
Cost recovery mechanisms – offset in fuel and purchased power(c)	(118		)		(22		)		—				—				—				(140		)
Other cost recovery mechanisms(d)	(39		)		2				—				—				—				(37		)
Total electric revenue change	$	(76	)		$	17			$	—			$	96			$	(21	)		$	16
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)	$	(145	)		$	—			$	—			$	—			$	—			$	(145	)
New Madrid Smelter energy costs	72				—				—				—				—				72
Effect of weather (estimate)(b)	(9		)		(8		)		—				—				—				(17		)
Effect of higher net energy costs included in base rates	(34		)		—				—				—				—				(34		)
Transmission services charges	(16		)		—				—				—				—				(16		)
Other	6				—				—				—				20				26
Cost recovery mechanisms – offset in electric revenue(c)	118				22				—				—				—				140
Total fuel and purchased power change	$	(8	)		$	14			$	—			$	—			$	20			$	26
Net change in electric margins	$	(84	)		$	31			$	—			$	96			$	(1	)		$	42
Natural gas revenue change:
Effect of weather (estimate)(b)	$	(7	)		$	—			$	13			$	—			$	—			$	6
Base rates (estimate)	—				—				42				—				—				42
Other	—				—				2				—				—				2
Cost recovery mechanisms – offset in natural gas purchased for resale(c)	(2		)		—				(76		)		—				—				(78		)
Other cost recovery mechanisms(d)	—				—				(10		)		—				—				(10		)
Total natural gas revenue change	$	(9	)		$	—			$	(29	)		$	—			$	—			$	(38	)
Natural gas purchased for resale change:
Effect of weather (estimate)(b)	$	6			$	—			$	(10	)		$	—			$	—			$	(4	)
Cost recovery mechanisms – offset in natural gas revenue(c)	2				—				76				—				—				78
Total natural gas purchased for resale change	$	8			$	—			$	66			$	—			$	—			$	74
Net change in natural gas margins	$	(1	)		$	—			$	37			$	—			$	—			$	36

(a)

Includes an increase in transmission margins of $26 million and $43 million in 2017 and 2016, respectively, at Ameren Illinois. The 2017 increase in transmission margins at Ameren Illinois is the change in base rates (estimate) of $26 million. The 2016 increase in transmission margins at Ameren Illinois is the sum of the change in base rates (estimate) of $49 million and the change in Other of -$6 million.

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

(c)	Includes amounts for power supply, renewable energy adjustment, zero-emission credits, transmission services, and purchased natural gas cost recovery mechanisms, as well as FAC recoveries. Electric and natural gas revenue changes are offset by corresponding changes in fuel, purchased power, and natural gas purchased for resale, resulting in no change to electric and natural gas margins.

(d)	Includes amounts for bad debt, energy-efficiency programs, and environmental remediation cost recovery mechanisms, as well as gross receipts tax revenues. See Other Operations and Maintenance Expenses or Taxes Other Than Income Taxes in this section for the related offsetting increase or decrease to expense. These items have no overall impact on earnings.

2017 versus 2016

Ameren

Ameren’s electric margins increased $105 million, or 3%, in 2017 compared with 2016, primarily because of increased margins at Ameren Transmission and Ameren Missouri. Ameren’s natural gas margins increased $17 million, or 3%, in 2017 compared with 2016, because of increased margins at Ameren Illinois Natural Gas.

Ameren Transmission

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

Ameren Missouri

Ameren Missouri’s electric margins increased $34 million, or 1%, in 2017 compared with 2016. Ameren Missouri’s natural gas margins were comparable between years.

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

•

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

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

•	The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts primarily caused by hurricane damage, which increased revenues by $7 million.

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

•

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

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

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

•

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

Ameren Illinois

Ameren Illinois’ electric margins increased $30 million, or 2%, in 2017 compared with 2016, driven by increases in Ameren Illinois Electric Distribution ($4 million) and Ameren Illinois Transmission ($26 million) margins. Ameren Illinois Natural Gas’ margins increased $17 million, or 4%, in 2017 compared with 2016, primarily due to increased QIP rider recoveries, which increased margins by $12 million.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $4 million, or less than 1%, in 2017 compared with 2016. Ameren Illinois Electric Distribution’s margins were favorably affected by an increase in rate base of 6% in 2017 compared with 2016 and a higher return on common equity due to an increase in 30-year United States Treasury bond yields of 29 basis points in 2017 compared with 2016, as well as higher recoverable expenses under formula ratemaking pursuant to the IEIMA, which collectively increased margins by $42 million. Ameren Illinois Electric Distribution’s margins were unfavorably affected by the absence of the impact of warmer-than-normal summer temperatures experienced in 2016, which decreased margins by an estimated $6 million. Ameren Illinois Electric Distribution revenues were decoupled from sales volumes beginning in 2017. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-$5 million) and the effect of weather (estimate) on fuel and purchased power (-$1 million) in the Electric and Natural Gas Margins table above.

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins increased $26 million, or 11%, in 2017 compared with 2016. Margins were favorably affected by increased capital investment, as evidenced by an increase in rate base of 16% in 2017 compared with 2016, as well as higher recoverable costs

in 2017 compared with 2016 under forward-looking formula ratemaking. Margins were unfavorably affected by the absence in 2017 of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.

2016 versus 2015

Ameren

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

Ameren Transmission

Ameren Transmission’s margins increased $96 million, or 37%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a 42% increase in rate base used to calculate the revenue requirement, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.

Ameren Missouri

Ameren Missouri’s electric margins decreased $84 million, or 3%, in 2016 compared with 2015. Ameren Missouri’s natural gas margins were comparable between years.

The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2016 compared with 2015:

•

The suspension of the New Madrid Smelter operations in the first quarter of 2016, which decreased margins by $57 million. The change in margins due to lower sales to the New Madrid Smelter is the sum of New Madrid Smelter revenues (-$129 million) and New Madrid Smelter energy costs (+$72 million) in the Electric and Natural Gas Margins table above. New Madrid Smelter energy costs included the impact of a provision in the FAC tariff that, under certain circumstances, allowed Ameren Missouri to retain a portion of the revenues from any off-system sales it made as a result of reduced sales to the New Madrid Smelter.

•

The expiration of MEEIA 2013, which decreased margins by $57 million. The change in margins due to the expiration of MEEIA 2013 is the sum of MEEIA 2013 net shared benefits (-$85 million) and MEEIA 2013 performance incentive (+$28 million) in the Electric and Natural Gas 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 cost-sharing by all MISO participants of additional MISO-approved electric transmission investments made by other entities, which decreased margins by $16 million.

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

•

Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 16%, while heating degree-days decreased 6%. The net effect of weather increased margins by an estimated $48 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$57 million) and the effect of weather (estimate) on fuel and purchased power (-$9 million) in the Electric and Natural Gas Margins table above.

•

Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, which increased margins by an estimated $14 million. The change in electric base rates is the sum of the change in base rates (estimate) (+$48 million) and the change in effect of higher net energy costs included in base rates (-$34 million) in the Electric and Natural Gas Margins table above.

•

Lower net energy costs as a result of the 5% of changes retained by Ameren Missouri through the FAC, primarily due to higher MISO capacity revenues, which increased margins by $8 million. The change in net energy costs is the sum of the change in off-system sales and capacity revenues (+$153 million) and the change in energy costs (excluding the New Madrid Smelter and estimated effect of weather) (-$145 million) in the Electric and Natural Gas Margins table above.

•

Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effect of weather, total retail sales volumes increased by less than 1%, which increased revenues by $7 million, due to an additional day as a result of the leap year and growth, partially offset by the carryover effect of MEEIA 2013 on sales volumes and the effect of MEEIA 2016 customer energy-efficiency programs. MEEIA 2016 customer energy-efficiency programs reduced retail sales volumes but the throughput disincentive recovery ensured that electric margins were not affected.

Ameren Illinois

Ameren Illinois’ electric margins increased $74 million, or 6%, in 2016 compared with 2015, driven by increases in Ameren Illinois Electric Distribution ($31 million) and Ameren Illinois Transmission ($43 million) margins. Ameren Illinois Natural Gas’ margins increased $37 million, or 9%, in 2016 compared with 2015.

Ameren Illinois Electric Distribution

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

•	Revenues increased by $38 million, primarily because of an increase in rate base of 8% and higher recoverable costs in 2016 compared with 2015, under formula ratemaking pursuant to the IEIMA. These revenues were reduced by a lower return on equity due to a reduction in 30-year United States Treasury bond yields, which decreased 24 basis points in 2016 compared with 2015.

•

Temperatures in 2016 were warmer compared with 2015, as cooling degree-days increased 13%, while heating degree-days decreased 5%. The net effect of weather increased margins by an estimated $7 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$15 million) and the effect of weather (estimate) on fuel and purchased power (-$8 million) in the Electric and Natural Gas Margins table above.

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

Ameren Illinois Natural Gas

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

•	Higher natural gas base rates in 2016, which increased margins by an estimated $42 million.

•

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

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins increased $43 million, or 23%, in 2016 compared with 2015. Margins were favorably affected by increased capital investment, as evidenced by a 27% increase in rate base used to calculate the revenue requirement, as well as higher recoverable costs in 2016 compared with 2015 under forward-looking formula ratemaking. Margins also benefited from a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 FERC complaint case.

Other Operations and Maintenance Expenses

2017 versus 2016

Ameren

Other operations and maintenance expenses decreased $16 million in 2017 compared with 2016, because of items discussed below and an increase in intersegment eliminations of $14 million.

Ameren Transmission

Other operations and maintenance expenses increased $3 million in 2017 compared with 2016, primarily because of an increase in labor costs due to increased wages and staffing additions.

Ameren Missouri

Other operations and maintenance expenses were $9 million higher in 2017 compared with 2016. The following items increased other operations and maintenance expenses between years:

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

•	Labor and benefit costs increased by $11 million due to increased wages, as well as assistance provided to other utilities to aid in storm recovery efforts, primarily caused by hurricane damage.

•	Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, increased by $3 million, primarily due to higher coal handling charges.

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

•	Employee benefit costs decreased by $21 million, primarily due to a reduction in the base level of pension and postretirement expenses allowed in rates as a result of the March 2017 MoPSC electric rate order, as well as changes in the market value of company-owned life insurance.

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

Ameren Illinois

Other operations and maintenance expenses decreased $15 million in 2017 compared with 2016, as discussed below. Other operations and maintenance expenses were comparable at Ameren Illinois Transmission in 2017 compared with 2016.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses were $26 million lower in 2017 compared with 2016, primarily because of a $47 million decrease in customer energy-efficiency costs, which was partially offset by an $11 million increase in environmental remediation costs and a $3 million increase in labor costs resulting from increased wages.

Ameren Illinois Natural Gas

Other operations and maintenance expenses were $9 million higher in 2017 compared with 2016, primarily because of increased bad debt, customer energy-efficiency, and environmental remediation costs.

2016 versus 2015

Ameren

Other operations and maintenance expenses decreased $18 million in 2016 compared with 2015, as discussed below.

Ameren Transmission

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

Ameren Missouri

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

•	MEEIA customer energy-efficiency program costs decreased by $34 million in 2016, primarily because of the expiration of MEEIA 2013, partially offset by costs incurred for MEEIA 2016.

•	Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center discussed below, decreased by $18 million, primarily because of reduced staffing costs and decreased routine maintenance costs, partially offset by higher coal handling charges.

•	Electric distribution maintenance expenditures decreased by $16 million, primarily related to reduced system repair and vegetation management work.

•	Employee benefit costs decreased by $15 million, primarily because of a $6 million reduction in the base level of pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order, and lower medical benefit costs, as well as a $4 million decrease due to changes in the market value of company-owned life insurance.

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

•	Refueling and maintenance outage costs at the Callaway energy center increased by $26 million, primarily because of costs for the 2016 scheduled refueling and maintenance outage. There was no Callaway refueling and maintenance outage in 2015.

•	Litigation costs increased by $11 million, primarily related to increases in estimated obligations for pending legal claims.

•	Solar rebate costs increased by $9 million, as a result of the April 2015 MoPSC electric rate order.

•	Storm-related repair costs increased by $7 million.

Ameren Illinois

Other operations and maintenance expenses increased $7 million in 2016 compared with 2015, as discussed below.

Ameren Illinois Electric Distribution

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

•	Labor costs increased by $6 million, primarily because of staffing additions to meet enhanced standards and goals related to the IEIMA.

•	Storm-related repair costs increased by $3 million.

•	Bad debt, customer energy efficiency, and environmental remediation costs increased by $2 million.

•	Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.

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

•	Employee benefit costs decreased by $6 million, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

•	Electric distribution operations and maintenance expenditures decreased by $3 million, primarily related to reduced circuit maintenance work, partially offset by increased vegetation management work.

Ameren Illinois Natural Gas

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

•	Bad debt, customer energy-efficiency, and environmental remediation costs decreased by $10 million.

•	Employee benefit costs decreased by $5 million, primarily because of lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

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

•	Repairs and compliance expenditures increased by $8 million, primarily related to increased pipeline integrity and storage field maintenance.

•	Litigation costs increased by $2 million, primarily related to increases in estimated obligations for pending legal claims.

Ameren Illinois Transmission

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

Provision for Callaway Construction and Operating License

Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway energy center site in 2015, primarily 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. As a result of this decision, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision in 2015 for the previously capitalized COL costs.

Depreciation and Amortization

2017 versus 2016

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

2016 versus 2015

Depreciation and amortization expenses increased $49 million, $22 million, and $24 million in 2016 compared with 2015 at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment across their respective segments. Additionally, Ameren Missouri’s depreciation rates increased as a result of the April 2015 MoPSC electric rate order.

Taxes Other Than Income Taxes

2017 versus 2016

Ameren

Taxes other than income taxes increased $10 million in 2017 compared with 2016, as discussed below. Taxes other than income taxes were comparable at Ameren Transmission. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.

Ameren Missouri

Taxes other than income taxes increased $3 million, primarily because of higher gross receipts taxes resulting from an increase in electric revenues.

Ameren Illinois

Taxes other than income taxes increased $5 million, primarily because of increased property taxes at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas. Taxes other than income taxes were comparable at Ameren Illinois Transmission.

2016 versus 2015

Ameren

Taxes other than income taxes decreased $6 million in 2016 compared with 2015, primarily at Ameren Missouri, as discussed below. Taxes other than income taxes were comparable at Ameren Transmission, as well as at Ameren Illinois and its respective segments.

Ameren Missouri

Taxes other than income taxes decreased $10 million, primarily because of decreased gross receipts taxes resulting from lower residential and commercial electric revenues and because of decreased property taxes.

Other Income and Expenses

2017 versus 2016

Ameren

Other income, net of expenses, decreased $4 million in 2017 compared with 2016, primarily due to decreased income at Ameren Illinois Electric Distribution, as discussed below, along with a decrease in the allowance for equity funds used during construction, partially offset by decreased donations in 2017. Other income, net of expenses, was comparable at the remaining Ameren segments. 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, decreased $8 million, primarily because of lower interest income associated with a lower IEIMA revenue requirement reconciliation regulatory asset balance at Ameren Illinois Electric Distribution. Other income, net of expenses, was comparable at the remaining Ameren Illinois segments.

2016 versus 2015

Other income, net of expenses, was comparable between years at Ameren, Ameren Missouri, Ameren Illinois, and their respective segments.

Interest Charges

2017 versus 2016

Ameren

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

Ameren Transmission

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

Ameren Missouri

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

Ameren Illinois

Interest charges increased $4 million, primarily because of an increase in average outstanding debt, partially offset by a decrease in the average interest rate of debt. Interest charges were comparable between years at each of the Ameren Illinois segments.

2016 versus 2015

Ameren

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

Ameren Transmission

Interest charges increased $23 million, because of an increase in ATXI’s and Ameren Illinois’ average outstanding debt and an increase in the average interest rate of debt.

Ameren Missouri

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

Ameren Illinois

Interest charges increased $9 million, primarily at Ameren Illinois Transmission, as discussed below. Interest charges were comparable between years at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas.

Ameren Illinois Transmission

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

Income Taxes

The following table presents effective income tax rates for the years ended December 31, 2017, 2016, and 2015:

							2017		2016		2015
Ameren							52%	(a)	37%		38%
Ameren Missouri							44%	(b)	38%		37%
Ameren Illinois							38%	(c)	38%		37%
Ameren Illinois Electric Distribution							38%	(c)	38%		36%
Ameren Illinois Natural Gas							38%	(c)	39%		40%
Ameren Illinois Transmission							37%	(c)	38%		37%
Ameren Transmission							39%	(c)	39%		38%

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

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

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

See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois, as well as a discussion of the effect of the TCJA and the revaluation of deferred taxes in 2017.

2017 versus 2016

Ameren

The effective income tax rate was higher in 2017 compared with 2016, primarily because of revaluation of deferred taxes due to enactment of the TCJA, which decreased the federal statutory corporate income tax rate from 35% to 21% for years after 2017. In addition, income tax expense increased due to the revaluation of deferred taxes as a result of an increase in the Illinois income tax rate in 2017 and due to a decrease in the recognition of tax benefits associated with share-based compensation, resulting from the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes. These items were partially offset by a reduction in the valuation allowance related to charitable contributions, due to higher-than-expected current-year taxable income.

Ameren Transmission

The effective income tax rate was comparable between years.

Ameren Missouri

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

Ameren Illinois

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

2016 versus 2015

Ameren

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

Ameren Illinois

The effective tax rate was comparable between years. The effective tax rate was higher at Ameren Illinois Electric Distribution, primarily because of items detailed below. The effective tax rate was comparable between years at the remaining Ameren Illinois segments.

Ameren Illinois Electric Distribution

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

Income (Loss) from Discontinued Operations, Net of Taxes

No material activity was recorded associated with discontinued operations in 2017 or 2016. In 2015, based on completion of the IRS audit of Ameren’s 2013 tax year, Ameren recognized a tax benefit of $53 million due to the resolution of an uncertain tax position from discontinued operations. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based gross 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 affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital

contributions from Ameren (parent). The TCJA will benefit customers through lower rates for our services but is not expected to materially affect our earnings. However, our cash flows and rate base are expected to be materially affected in the near term. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. We also 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. As part of its plan to fund these capital expenditures, beginning in the first quarter of 2018, Ameren will use newly issued shares, rather than market-purchased shares, to satisfy requirements under its DRPlus and employee benefit plans and expects to do so over the next five years. Additionally, we may be required to issue incremental debt and/or equity, with the long-term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.

The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments will periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2017, for the Ameren Companies. The working capital deficit as of December 31, 2017, 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 $1.6 billion of liquidity at December 31, 2017.

The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2017, 2016, and 2015:

	Net Cash Provided by (Used in) Operating Activities												Net Cash Used in Investing Activities												Net Cash Provided by (Used in) Financing Activities
	2017				2016				2015				2017				2016				2015				2017				2016				2015
Ameren(a) – continuing operations	$	2,104			$	2,124			$	2,035			$	(2,205	)		$	(2,141	)		$	(1,951	)		$	102			$	(265	)		$	232
Ameren(a) – discontinued operations	—				(1		)		(4		)		—				—				(25		)		—				—				—
Ameren Missouri	1,016				1,169				1,247				(685		)		(934		)		(724		)		(331		)		(434		)		(325		)
Ameren Illinois	815				803				763				(1,070		)		(918		)		(913		)		255				44				220

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

Cash Flows from Operating Activities

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

2017 versus 2016

Ameren

Ameren’s cash from operating activities associated with continuing operations decreased $20 million in 2017, compared with 2016. The following items contributed to the decrease:

•	A $48 million decrease in cash related to customer energy-efficiency program recovery mechanisms.

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

•	A $36 million decrease in cash recoveries associated with Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. The

2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

•	A $27 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.

•	A $27 million decrease in cash related to Ameren Illinois’ power procurement cost recovery mechanism.

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

•	A $17 million decrease in cash associated with Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

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

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

•	A $10 million increase in labor costs at Ameren Missouri and Ameren Illinois, primarily because of wage increases.

•	A $7 million increase in pension and postretirement benefit plan contributions.

•	A $4 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and increased natural gas compliance costs.

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

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

•	A $37 million increase in cash collected from Ameren Illinois customers related to zero-emission credits pursuant to the FEJA. In the first quarter of 2018, these funds will be used for the purchase of zero-emission credits pursuant to an IPA procurement event.

•	A $23 million increase in cash collected from Ameren Illinois’ alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.

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

Ameren’s cash from operating activities associated with discontinued operations was immaterial in both 2017 and 2016.

Ameren Missouri

Ameren Missouri’s cash from operating activities decreased $153 million in 2017, compared with 2016. The following items contributed to the decrease:

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

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

•	A $27 million decrease in net energy costs collected from customers under the FAC.

•	A $20 million decrease in cash related to customer energy-efficiency program recovery mechanisms.

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

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

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

Ameren Illinois

Ameren Illinois’ cash from operating activities increased $12 million in 2017, compared with 2016. The following items contributed to the increase:

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

•	A $37 million increase in cash collected from customers related to zero-emission credits pursuant to the FEJA. In the first quarter of 2018, these funds will be used for the purchase of zero-emission credits pursuant to an IPA procurement event.

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

•	A $23 million increase in cash collected from alternative retail electric supplier customers for renewable energy credit compliance pursuant to the FEJA.

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

•	A $36 million decrease in cash recoveries associated with IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

•	A $28 million decrease in cash related to customer energy-efficiency program recovery mechanisms.

•	A $27 million decrease in cash related to the power procurement cost recovery mechanism.

•	A $17 million decrease in cash recoveries associated with the transmission revenue requirement reconciliation adjustments. The 2015 transmission revenue requirement reconciliation adjustment, which was recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

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

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

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

2016 versus 2015

Ameren

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

•	A $126 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.

•	A $70 million decrease in pension and postretirement benefit plan contributions.

•	A $42 million insurance receipt at Ameren Missouri related to the Taum Sauk breach that occurred in 2005.

•	A $40 million increase in cash associated with the recovery of Ameren Illinois’ IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.

•	A $38 million increase in cash related to Ameren Illinois’ power procurement cost recovery mechanism.

•	A $37 million decrease in coal inventory purchases at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.

•	A $33 million increase in cash related to customer energy-efficiency program recovery mechanisms.

•	A $19 million increase in cash associated with the recovery of Ameren Illinois’ transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.

The following items partially offset the increase in Ameren’s cash from operating activities associated with continuing operations during 2016, compared with 2015:

•	A $166 million decrease resulting from the change in customer receivable balances.

•	A $94 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.

•	A $23 million increase in interest payments, primarily due to an increase in the cost and amount of outstanding debt of Ameren (parent) and an increase in the average outstanding debt at Ameren Illinois.

•	A $20 million increase in payments for the refueling and maintenance outage at Ameren Missouri’s Callaway energy center. There was no refueling and maintenance outage in 2015.

•	A $9 million increase in labor costs at Ameren Illinois, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals related to the IEIMA.

•	A $7 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects.

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

Ameren Missouri

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

•	A $142 million decrease resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

•	A $94 million decrease in net energy costs collected from customers under the FAC.

•	A $20 million increase in payments for the refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.

The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during 2016, compared with 2015:

•	A $45 million decrease in income tax payments, pursuant to the tax allocation agreement with Ameren (parent), primarily related to higher deductions related to increased capital expenditures in 2016.

•	A $42 million insurance receipt related to the Taum Sauk breach that occurred in December 2005.

•	A $37 million decrease in coal inventory purchases, as additional coal was purchased in 2015 to compensate for delivery disruptions in 2014.

•	A $33 million decrease in pension and postretirement benefit plan contributions.

•	An $11 million increase in cash related to customer energy-efficiency program recovery mechanisms.

Ameren Illinois

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

•	A $58 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, which was partially offset by the change in customer receivable balances.

•	A $40 million increase in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.

•	A $38 million increase in cash related to the power procurement cost recovery mechanism.

•	A $22 million decrease in pension and postretirement benefit plan contributions.

•	A $22 million increase in cash related to customer energy-efficiency program recovery mechanisms.

•	A $19 million increase in cash associated with the recovery of transmission revenue requirement reconciliation adjustments. The 2014 transmission revenue requirement reconciliation adjustment was recovered from customers in 2016, while the 2013 revenue requirement reconciliation adjustment was refunded to customers in 2015.

The following items partially offset the increase in Ameren Illinois’ cash from operating activities during 2016, compared with 2015:

•

A $121 million decrease resulting from income tax payments of $8 million in 2016, compared with income tax refunds of $113 million in 2015, pursuant to the tax allocation agreement with Ameren (parent). 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.

Pension Plans

Ameren’s pension plans are funded in compliance with income tax regulations, federal funding, and other regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension cost or the legally required minimum contribution. Based on Ameren’s assumptions at December 31, 2017, its investment performance in 2017, and its pension funding policy, Ameren expects to make annual contributions of less than $1 million to $60 million in each of the next five years, with aggregate estimated contributions of $120 million. We expect Ameren Missouri’s and Ameren Illinois’ portions of the future funding requirements to be 35% and 55%, respectively. These amounts are estimates. They may change based on actual investment performance, changes in interest rates, changes in our assumptions, changes in government regulations, and any voluntary contributions. In 2017, Ameren contributed $64 million to its pension plans. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for additional information.

Cash Flows from Investing Activities

2017 versus 2016

Ameren’s cash used in investing activities associated with continuing operations increased by $64 million during 2017, compared with 2016. Capital expenditures increased $56 million as a result of activity at Ameren Missouri and Ameren Illinois, discussed below. The $187 million increase in capital expenditures at Ameren Missouri and Ameren Illinois was partially offset by a $127 million decrease in capital expenditures at ATXI due to reduced spending on the Illinois Rivers project, partially offset by an increase in spending on the Spoon River project. During 2017 and 2016, there was no cash used in investing activities associated with discontinued operations.

Ameren Missouri’s cash used in investing activities decreased by $249 million during 2017, compared with 2016, primarily because of net money pool advances. During 2017, Ameren Missouri received $161 million in returns of net money pool advances compared with investing $125 million in net money pool advances in 2016. This decrease was partially offset by a $35 million increase in capital expenditures, primarily related to electric distribution and transmission system reliability and energy center projects.

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

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.

Capital Expenditures

The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2017, 2016, and 2015:

	2017				2016				2015
Ameren Missouri	$	773			$	738			$	622
Ameren Illinois Electric Distribution	476				470				491
Ameren Illinois Natural Gas	245				181				133
Ameren Illinois Transmission	355				273				294
ATXI	289				416				375
Other (a)	(6		)		(2		)		2
Ameren	$	2,132			$	2,076			$	1,917

(a)	Includes amounts for the elimination of intercompany transfers.

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

Ameren’s 2016 capital expenditures consisted of expenditures made by its subsidiaries, including ATXI, which spent $416 million primarily on the Illinois Rivers project. Ameren Illinois spent $273 million on transmission projects and $109 million on IEIMA projects. Other

capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois as well as to fund various Ameren Missouri energy center upgrades.

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

The following table presents Ameren’s estimate of capital expenditures that will be incurred from 2018 through 2022, 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.

	2018				2019-2022								Total
Ameren Missouri	$	845			$	3,310		-	$	3,660			$	4,155		-	$	4,505
Ameren Illinois Electric Distribution	465				1,815			-	2,005				2,280			-	2,470
Ameren Illinois Natural Gas	330				1,220			-	1,350				1,550			-	1,680
Ameren Illinois Transmission	470				1,765			-	1,950				2,235			-	2,420
ATXI	70				215			-	240				285			-	310
Other	5				15			-	15				20			-	20
Ameren	$	2,185			$	8,340		-	$	9,220			$	10,525		-	$	11,405

Ameren Missouri’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with environmental regulations. The estimates above do not reflect the potential additional investments identified in Ameren Missouri’s integrated resource plan, which could represent incremental investments of approximately $1 billion through 2020 and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made. 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, and mercury emissions from its coal-fired energy centers. See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws 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 a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the dividends declared by Ameren’s board of directors, and our long-term debt maturities, among other things.

2017 versus 2016

Ameren’s financing activities associated with continuing operations provided net cash of $102 million in 2017, compared with using net cash of $265 million in 2016. During 2017, Ameren utilized net proceeds from the issuance of $1,345 million of long-term indebtedness to repay $681 million of higher-cost long-term indebtedness, to repay $74 million of net commercial paper issuances, and to fund, in part, investing activities. In comparison, during 2016, Ameren utilized net proceeds from the issuance of $646 million of long-term indebtedness

and net commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and to fund, in part, investing activities. Additionally, during 2017, Ameren made $431 million in dividend payments to shareholders, compared with $416 million in dividend payments in 2016. No cash from financing activities was used for discontinued operations during 2017.

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

Ameren Illinois’ cash provided by financing activities increased by $211 million in 2017, compared with 2016. During 2017, Ameren Illinois utilized net proceeds from the issuance of $507 million of long-term indebtedness and net commercial paper issuances to repay at maturity $250 million of higher-cost long-term indebtedness. In comparison, during 2016, Ameren Illinois issued $291 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay at maturity $129 million of higher-cost long-term indebtedness. Additionally, in 2017, no dividends were paid to Ameren (parent) compared to $110 million paid in 2016.

2016 versus 2015

Ameren’s financing activities associated with continuing operations used net cash of $265 million in 2016, compared with providing net cash of $232 million in 2015. During 2016, Ameren utilized net proceeds from the issuance of $646 million of long-term indebtedness and net commercial paper issuances to repay $395 million of higher-cost long-term indebtedness and to fund, in part, investing activities. In comparison, during 2015, Ameren utilized net proceeds from the issuance of $1,197 million of long-term indebtedness to repay $413 million of net commercial paper issuances, $120 million of higher-cost long-term indebtedness, and to fund, in part, investing activities. No cash from financing activities was used for discontinued operations during 2016.

Ameren Missouri’s cash used in financing activities increased by $109 million in 2016, compared with 2015. During 2016, Ameren Missouri utilized net proceeds from the issuance of $149 million of long-term indebtedness, along with cash on hand, to repay $266 million of higher-cost long-term indebtedness. In comparison, during 2015, Ameren Missouri utilized net proceeds from the issuance of $249 million of long-term indebtedness to repay $120 million of higher-cost long-term indebtedness and $97 million of net commercial paper issuances. Additionally, during 2016, Ameren Missouri paid $355 million in dividends to Ameren (parent), compared with $575 million dividends paid in the year-ago period. Also, in 2016, Ameren Missouri received $44 million as a capital contribution from Ameren (parent) compared to $224 million received in 2015.

Ameren Illinois’ cash provided by financing activities decreased by $176 million in 2016, compared with 2015. During 2016, Ameren Illinois issued $291 million of long-term indebtedness and net commercial paper issuances and utilized the proceeds to repay at maturity $129 million of higher-cost long-term indebtedness. In comparison, during 2015, Ameren Illinois utilized proceeds from the issuance of $248 million of long-term indebtedness to repay $32 million of net commercial paper issuances and to fund, in part, investing activities. Additionally, in 2016 Ameren Illinois paid $110 million in dividends to Ameren (parent) compared to no dividends paid in the year-ago period.

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 affiliate 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 affiliate 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, 2017:

		Available at December 31, 2017
Ameren (parent) and Ameren Missouri (a):
Missouri Credit Agreement – borrowing capacity		$	1,000
Less: Ameren (parent) commercial paper outstanding		224
Less: Ameren Missouri commercial paper outstanding		39
Missouri Credit Agreement – credit available		737
Ameren (parent) and Ameren Illinois(b):
Illinois Credit Agreement – borrowing capacity		1,100
Less: Ameren (parent) commercial paper outstanding		159
Less: Ameren Illinois commercial paper outstanding		62
Less: Letters of credit		1
Illinois Credit Agreement – credit available		878
Total Credit Available		$	1,615
Cash and cash equivalents		10
Total Liquidity		$	1,625

(a)	The maximum aggregate amount available to Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $700 million and $800 million, respectively. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for further discussion of the Credit Agreements.

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

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

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

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by the FERC under the Federal Power Act. In June 2017, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities through July 2019. In 2016, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 2018 and through September 2018, respectively.

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 premiums or discounts), redemptions, repurchases, and maturities of long-term debt for the years ended December 31, 2017, 2016, and 2015. The Ameren Companies did not issue any common stock or redeem or repurchase any preferred stock during the years ended 2017, 2016, and 2015. In 2017, 2016, and 2015, Ameren Missouri received cash capital contributions as a result of the tax allocation agreement from Ameren (parent). In 2017 and 2015, Ameren Illinois received cash capital contributions from Ameren (parent). 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 Matured		2017				2016				2015
Issuances of Long-term Debt
Ameren (parent)
2.70% Senior unsecured notes due 2020	November		$	—			$	—			$	350
3.65% Senior unsecured notes due 2026	November		—				—				350
Ameren Missouri:
3.65% Senior secured notes due 2045	April		—				—				249
3.65% Senior secured notes due 2045	June		—				149				—
2.95% Senior secured notes due 2027	June		399				—				—
Ameren Illinois:
3.70% First mortgage bonds due 2047	November		496				—				—
4.15% Senior secured notes due 2046	December		—				240				248
ATXI:
3.43% Senior notes due 2050	June		150				—				—
3.43% Senior notes due 2050	August		300				—				—
Total long-term debt issuances			$	1,345			$	389			$	1,197
Redemptions, Repurchases, and Maturities of Long-term Debt
Ameren Missouri:
5.40% Senior secured notes due 2016	February		—				260				—
4.75% Senior secured notes due 2015	April		—				—				114
6.40% Senior secured notes due 2017	June		425				—			—	—
City of Bowling Green capital lease (Peno Creek CT)	December		6				6				6
Ameren Illinois:
6.20% Senior secured notes due 2016	June		—				54				—
6.25% Senior secured notes due 2016	June		—				75				—
6.125% Senior secured notes due 2017	November		250				—				—
Total long-term debt redemptions, repurchases, and maturities			$	681			$	395			$	120

In June 2017, Ameren Missouri issued $400 million of 2.95% senior secured notes due June 2027, with interest payable semiannually on June 15 and December 15 of each year, beginning December 15, 2017. Ameren Missouri received proceeds of $396 million, which were used, in conjunction with other available funds, to repay at maturity $425 million of Ameren Missouri’s 6.40% senior secured notes in June 2017.

In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes, due 2050, with interest payable semiannually on the last day of February and August of each year, beginning February 28, 2018, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes, which were used by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).

In November 2017, Ameren Illinois issued $500 million of 3.70% first mortgage bonds due December 2047, with interest payable semiannually on June 1 and December 1 of each year, beginning June 1, 2018. Ameren Illinois received proceeds of $492 million, which were used to repay outstanding short-term debt, including short-term debt that Ameren Illinois incurred in connection with the repayment of $250 million of its 6.125% senior secured notes that matured in November 2017.

In December 2017, Ameren, Ameren Missouri, and Ameren Illinois filed a Form S-3 shelf registration statement with the SEC, registering the issuance of an indeterminate amount of certain types of securities. The registration statement became effective immediately upon filing and expires in December 2020.

Ameren filed a Form S-3 registration statement with the SEC in May 2017, which expires in May 2020, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions.

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

Indebtedness Provisions and Other Covenants

At December 31, 2017, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement. See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreement.

We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital markets or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

Ameren paid to its shareholders common stock dividends totaling $431 million, or $1.778 per share, in 2017, $416 million, or $1.715 per share, in 2016, and $402 million, or $1.655 per share, in 2015.

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 9, 2018, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 45.75 cents per share, payable on March 29, 2018, to shareholders of record on March 14, 2018.

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

Ameren Illinois’ articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions with respect to certain operating expenses and accumulations of earned surplus. Additionally, Ameren has committed to the FERC to maintain a minimum of 30% equity in 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, 2017, the amount of restricted net assets of Ameren’s subsidiaries that may not be distributed to Ameren in the form of a loan or dividend was $2.3 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:

	2017				2016				2015
Ameren	$	431			$	416			$	402
Ameren Missouri	362				355				575
Ameren Illinois	—				110				—

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, 2017. See Note 10 – Retirement Benefits under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans. These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.

	Less Than 1 Year				1 – 3 Years				3 – 5 Years				After 5 Years				Total
Ameren:(a)
Long-term debt and capital lease obligations(b)	$	841			$	1,023			$	514			$	5,617			$	7,995
Interest payments(c)	464				855				814				5,018				7,151
Operating leases	10				17				12				14				53
Other obligations(d)	981				964				206				254				2,405
Total cash contractual obligations	$	2,296			$	2,859			$	1,546			$	10,903			$	17,604
Ameren Missouri:
Long-term debt and capital lease obligations(b)	$	384			$	673			$	64			$	2,867			$	3,988
Interest payments(c)	331				592				575				3,208				4,706
Operating leases	8				15				12				14				49
Other obligations(d)	628				654				163				194				1,639
Total cash contractual obligations	$	1,351			$	1,934			$	814			$	6,283			$	10,382
Ameren Illinois:
Long-term debt(b)	$	457			$	—			$	400			$	2,000			$	2,857
Interest payments(c)	106				188				185				1,584				2,063
Operating leases	1				—				—				1				2
Other obligations(d)	352				310				43				40				745
Total cash contractual obligations	$	916			$	498			$	628			$	3,625			$	5,667

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

(b)	Excludes unamortized discount and premium and debt issuance costs of $60 million, $27 million, and $27 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of this report, for discussion of items included herein.

(c)	The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2017.

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

As of December 31, 2017, Ameren, Ameren Missouri, and Ameren Illinois had no unrecognized tax benefits (detriments) for uncertain tax positions.

Off-Balance-Sheet Arrangements

At December 31, 2017, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, letters of credit, and Ameren (parent) guarantee arrangements on behalf of its subsidiaries.

Credit Ratings

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

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

	Moody’s	S&P
Ameren:
Issuer/corporate credit rating	Baa1	BBB+
Senior unsecured debt	Baa1	BBB
Commercial paper	P-2	A-2
Ameren Missouri:
Issuer/corporate credit rating	Baa1	BBB+
Secured debt	A2	A
Senior unsecured debt	Baa1	BBB+
Commercial paper	P-2	A-2
Ameren Illinois:
Issuer/corporate credit rating	A3	BBB+
Secured debt	A1	A
Senior unsecured debt	A3	BBB+
Commercial paper	P-2	A-2
ATXI:
Issuer credit rating	A2	Not Rated
Senior unsecured debt	A2	Not Rated

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

Collateral Postings

Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial at December 31, 2017. 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, 2017, 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 $82 million, $44 million, and $38 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at December 31, 2017, if market prices were 15% higher or lower than December 31, 2017, levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade obligations.

OUTLOOK

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

As part of Ameren’s strategic plan, we pursue projects to meet our customer energy needs and to improve electric and natural gas system reliability, safety, and security within our service territories. Ameren also evaluates competitive electric transmission investment opportunities as they arise. Additionally, Ameren Missouri expects to make investments over time that will enable it to transition to a more diverse energy generation portfolio.

Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2018 and beyond.

Operations

•	Ameren continues to invest in FERC-regulated electric transmission. ATXI has three MISO-approved multi-value projects, the Illinois Rivers, Spoon River, and Mark Twain projects. The Illinois Rivers project involves the construction of a transmission line from eastern

Missouri across Illinois to western Indiana. Construction activities for the Illinois Rivers project are continuing on schedule, and the last section of this project is expected to be completed by the end of 2019. The Spoon River project, located in northwest Illinois, was placed in service in February 2018. The Mark Twain project, located in northeast Missouri and connecting the Illinois Rivers project to Iowa, is expected to be completed by the end of 2019. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding the Mark Twain project and its approval process and the Illinois Rivers project. As of December 31, 2017, ATXI’s expected remaining investment in all three projects is approximately $300 million, with the total investment to be more than $1.6 billion. In addition, Ameren Illinois expects to invest $2.3 billion in electric transmission assets from 2018 through 2022 to replace aging infrastructure and improve reliability.

•

Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base growth and the currently allowed 10.82% return on common equity, the 2018 revenue requirements for Ameren Illinois’ and ATXI’s electric transmission businesses are $270 million and $174 million, respectively. These revenue requirements represent an increase in Ameren Illinois' and ATXI's revenue requirements of $11 million and $4 million, respectively, primarily because of the rate base growth described above, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA.

•

The return on common equity for MISO transmission owners, including Ameren Illinois and ATXI, was the subject of a FERC complaint case filed in February 2015 which challenged the allowed base return on common equity. Ameren Illinois and ATXI currently use the FERC authorized total allowed return on common equity of 10.82% in customer rates. A final FERC order would establish the allowed return on common equity to be applied to the 15-month period from February 2015 to May 2016 and also establish the return on common equity to be included in customer rates prospectively from the effective date of such order, replacing the current 10.82% total return on common equity. The timing and amount of any adjustment to the total allowed return on common equity that may be ordered as a result of the complaint case is uncertain. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren’s and Ameren Illinois’ annual earnings by an estimated $8 million and $4 million, respectively, based on each company’s 2018 projected rate base. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding FERC complaint cases.

•

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 million increase in Ameren Missouri’s annual revenue requirement for electric service, compared with the prior revenue requirement established in the MoPSC’s April 2015 electric rate order. The new rates, base level of expenses, and amortizations became effective on April 1, 2017. Excluding cost reductions associated with reduced sales volumes, the base level of net energy costs decreased by $54 million from the base level established in the MoPSC’s April 2015 electric rate order. Changes in amortizations and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC’s April 2015 electric rate order.

•

In December 2017, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $17 million decrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2018. However, Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and investment return in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois’ 2018 electric distribution service revenues will be based on its 2018 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. The 2018 revenue requirement is expected to be comparable to the 2017 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of approximately 5%, and an expected increase in the monthly average yield of 30-year United States Treasury bonds, partially offset by a decrease due to the lower federal statutory corporate income tax rates enacted under the TCJA. The 2018 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2020. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $8 million change in Ameren’s and Ameren Illinois’ net income, based on Ameren Illinois’ 2018 projected year-end rate base.

•

The FEJA allows Ameren Illinois to earn a return on its electric energy-efficiency program investments. Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and 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 be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. Pursuant to the FEJA, Ameren Illinois plans to invest up to $99 million per year in electric energy-efficiency programs from 2018 through 2021 that will earn a return. Ameren Illinois plans to make similar yearly investments in electric energy-efficiency programs from 2022 through 2030. The ICC has the ability to reduce electric energy-efficiency savings goals if there are insufficient cost-effective programs available or if the savings goals would require investment levels that exceed amounts allowed by legislation. The electric energy-efficiency program investments and the return on those investments will be collected from customers through a rider; they will not be included in the IEIMA formula ratemaking framework. See Note 2 – Rate and

Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ approved energy-efficiency program for 2018 through 2021.

•

In January 2018, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $49 million, which included an estimated $42 million of annual revenues that would otherwise be recovered under a QIP rider. The request was based on a 10.3% return on common equity, a capital structure composed of 50% common equity, and a rate base of $1.6 billion. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois’ Natural Gas Delivery Service Regulatory Rate Review.

•

Ameren Missouri’s next scheduled refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2019. During the 2017 refueling, Ameren Missouri incurred maintenance expenses of $35 million. During a scheduled 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. In addition, Ameren Missouri may incur increased nonnuclear energy center maintenance costs in non-outage years.

•

Ameren and Ameren Missouri expect an approximately $15 million decrease in annual interest charges as a result of the repayment of $425 million of Ameren Missouri’s 6.40% senior secured notes at maturity and issuance of $400 million 2.95% senior secured notes in 2017. In 2018, Ameren Missouri expects to refinance maturing long-term debt with lower-cost long-term debt, which would further reduce Ameren’s and Ameren Missouri’s annual interest charges.

•

As we continue to make infrastructure investments and to experience cost increases, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective technological advances, including private generation and storage. However, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy as a means to address CO2 emission concerns. Increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, result in rate base earnings growth but also higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property taxes, and higher state income taxes, among other costs.

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

Liquidity and Capital Resources

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In September 2017, Ameren Missouri filed its nonbinding 20-year integrated resource plan with the MoPSC. This plan includes Ameren Missouri’s preferred approach for meeting customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliability. The plan targets cleaner and more diverse sources of energy generation, including solar, wind, natural gas, hydro, and nuclear power. It also includes expanding renewable sources by adding at least 700 megawatts of wind generation by 2020 in Missouri and neighboring states, and adding 100 megawatts of solar generation over the next 10 years. The new wind generation facilities are expected to be located in Missouri and neighboring states. The source, location, and cost of the new wind generation, among other items, remain subject to reaching agreements with developers. Based on current and projected market prices for energy, and for wind and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost option for customers. The plan also provides for the expected implementation of continued customer energy-efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be affected by, among other factors: the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind and solar generation technologies, as well as energy prices; Ameren Missouri’s ability to obtain timely interconnection agreements with MISO or other RTOs, including the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC for projects located in Missouri, and any other required project approvals.

•	In connection with the integrated resource plan filing, discussed above, Ameren Missouri established a goal of reducing CO2 emissions 80% by 2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO2 emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of its useful life.

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Through 2022, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest up to $11.4 billion (Ameren Missouri – up to $4.5 billion; Ameren Illinois – up to $6.6 billion; ATXI – up to $0.3 billion) of capital expenditures during the period from 2018 through 2022. These estimates do not reflect the potential additional investments identified in Ameren Missouri’s integrated resource plan discussed above, which could represent incremental investments of approximately $1 billion through 2020 and are subject to regulatory approval. They also do not reflect potential additional investments that Ameren Missouri could make if improvements in its regulatory frameworks were made.

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

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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 2019, $951 million and $457 million of senior secured notes are scheduled to mature at Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their short-term debt with long-term debt in 2018 and 2019. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

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Federal income tax legislation enacted under the TCJA will have significant impacts on our results of operations, financial position, liquidity, and financial metrics. The TCJA will benefit customers through lower rates for our services but is not expected to materially affect our earnings. However, our cash flows and rate base are expected to be materially affected in the near term. Our rate-regulated businesses recover income taxes in customer rates based on the federal and state statutory corporate income tax rates in effect when the revenue requirements used to determine those rates were established. However, there is a timing difference between when we collect funds from our customers for income taxes and when we pay such taxes. The TCJA eliminated 50% accelerated tax depreciation on nearly all capital investments, which has the effect of increasing Ameren’s near-term projected income tax liabilities. Ameren expects to largely offset its income tax obligations through about 2020 with existing net operating loss and tax credit carryforwards. Since we have been using existing net operating loss and tax credit carryforwards to largely offset income tax obligations, the effect of the reduced federal statutory corporate income tax rate is expected to be a decrease in operating cash flows. The decrease in operating cash flows results from reduced customer rates, reflecting the tax rate decrease, without a corresponding reduction in income tax payments until about 2021. Additionally, operating cash flows will be further reduced by lower customer rates, reflecting the return of excess deferred taxes previously collected from customers over periods of time determined by our regulators. The decrease in operating cash flows as a result of the TCJA is expected to be partially offset over time by increased customer rates due to higher rate base amounts, once approved by our regulators. We expect rate base amounts to be higher as a result of lower accumulated deferred income tax liabilities, due to the elimination of 50% accelerated tax depreciation, the reduced statutory income tax rate, and the return of excess deferred taxes to customers. Ameren expects a decrease in operating cash flows of approximately $1 billion from 2018 through 2022 (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.4 billion) as a result of the TCJA, and expects an increase in rate base of approximately $1 billion over the same time period (Ameren Missouri – $0.3 billion; Ameren Illinois – $0.5 billion).

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As of December 31, 2017, Ameren had $235 million in tax benefits from federal and state net operating loss carryforwards and $120 million in federal and state income tax credit carryforwards. These carryforwards are expected to partially offset income tax obligations until 2021, at which time Ameren expects to begin making material income tax payments. Consistent with the tax allocation agreement between Ameren (parent) and its subsidiaries, Ameren Missouri and Ameren Illinois expect to begin making material income tax payments to Ameren (parent) beginning in 2018.

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Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its plan to fund these cash requirements, beginning in the first quarter of 2018, Ameren will use newly issued shares, rather than market-purchased shares, to satisfy requirements under its DRPlus and employee benefit plans and expects to do so over the next five years. Additionally, Ameren may be required to issue incremental debt and/or equity, with the long-

term intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks. Ameren Missouri and Ameren Illinois expect to fund cash flows needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent), with the intent to maintain strong financial metrics and an equity ratio around 50%, as calculated in accordance with ratemaking frameworks.

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

REGULATORY MATTERS

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

ACCOUNTING MATTERS

Critical Accounting Estimates

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

Accounting Estimate		Uncertainties Affecting Application

Regulatory Mechanisms and Cost Recovery

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

•	Regulatory environment and external regulatory decisions and requirements

•	Anticipated future regulatory decisions and our assessment of their impact

•	The impact of prudence reviews, complaint cases, and opposition during the ratemaking process that may limit our ability to timely recover costs and earn a fair return on our investments

•	Ameren Illinois’ assessment of and ability to estimate the current year’s electric delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking framework

•	Ameren Illinois’ and ATXI’s assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking frameworks

•	Ameren Missouri’s estimate of revenue recovery under the MEEIA plans

•	Any adjustments related to the TCJA

Basis for Judgment

The application of accounting guidance for rate-regulated businesses results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, 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 rate base, and published forecasted data regarding that year’s monthly average yields of the 30-year United States Treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31 of each year using that year’s actual operating results and assesses the probability of recovery from or refund to customers that the ICC will order at the end of the following year. Variations in investments made or orders by the ICC or courts can result in a subsequent change in Ameren Illinois’ estimate. Ameren Illinois and ATXI follow a similar process for their FERC rate-regulated electric transmission businesses. Ameren Missouri estimates 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. The Ameren Companies made provisional estimates to deferred tax balances as a result of the TCJA. The revaluation of certain deferred taxes was deferred as a regulatory asset or liability on the balance sheet and will be collected from or refunded to customers as determined by our regulators. These estimates are subject to change, as discussed in the Accounting for Income Taxes section below. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for quantification of these assets or liabilities

for each of the Ameren Companies. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for a listing of regulatory mechanisms used by Ameren Missouri and Ameren Illinois.

Benefit Plan Accounting

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

•	Future rate of return on pension and other plan assets

•	Valuation inputs and assumptions used in the fair value measurements of plan assets, excluding those inputs that are readily observable

•	Discount rate

•	Future compensation increase assumption

•	Health care cost trend rates

•	Timing of employee retirements and mortality assumptions

•	Ability to recover certain benefit plan costs from our customers

•	Changing market conditions that may affect investment and interest rate environments

Basis for Judgment

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

Accounting for Contingencies

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

•	Estimating financial impact of events

•	Estimating likelihood of various potential outcomes

•	Regulatory and political environments and requirements

•	Outcome of legal proceedings, settlements, or other factors

•	Changes in regulation, expected scope of work, technology or timing of environmental remediation

Basis for Judgment

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

Accounting for Income Taxes

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

•	Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations

•	Estimates of the amount and character of future taxable income

•	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, change 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. Additional interpretations, regulations, amendments, or technical corrections related to the federal income tax code as a result of the TCJA, as well as the associated treatment by our regulators, may impact the estimates for income taxes discussed above. See Note 12 – Income Taxes under Part II, Item 8, of this report for the amount of deferred income taxes recorded at December 31, 2017.

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. For its electric distribution business, Ameren Illinois then considers and reflects the effect of the decoupling provisions of the FEJA.

•	Estimating customer energy usage

•	Estimating impacts of weather and other usage-affecting factors for the unbilled period

•	Estimating loss of energy during transmission and delivery

Basis for Judgment

We base our estimate of unbilled revenue each period on the volume of energy delivered, as valued by a model of billing cycles and historical usage rates and by growth or contraction by customer class for our service area. This figure is then adjusted for the modeled impact of seasonal and weather variations based on historical results. As a result of its regulatory framework, Ameren Illinois adjusts unbilled electric distribution revenues to reflect the decoupling provisions of the FEJA, with an offset to a regulatory asset or liability. 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’ and ATXI’s electric transmission rates are determined pursuant to formula ratemaking. Additionally, Ameren Illinois participates in performance-based formula ratemaking frameworks established pursuant to the IEIMA and the FEJA for its electric distribution business and its electric energy-efficiency investments. Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Within the IEIMA and the FEJA formula ratemaking frameworks, the monthly average yields of 30-year United States Treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States Treasury bonds, which are affected by inflation, and the annual return on equity applicable to Ameren Illinois’ electric distribution business and electric energy-efficiency investments. Ameren Illinois and ATXI use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates. These forward-looking rates are updated each January with forecasted information. A reconciliation during the year, which adjusts for the actual revenue requirement and for actual sales volumes, is used to adjust billing rates in a subsequent year.

The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, customer rates designed to provide recovery of historical costs through depreciation might not be adequate to replace plant in future years.

Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. The March 2017 MoPSC electric rate order approved Ameren Missouri’s request for continued use of the FAC; however, the FAC

excludes substantially all transmission revenues and charges. Ameren Missouri is therefore exposed to transmission charges to the extent that they exceed transmission revenues. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.

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

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