SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



ý	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended ~~September 30, 2016~~March 31, 2017



¨	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to



Commission File Number	Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number	IRS Employer Identification No.
1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-3672	Ameren Illinois Company	37-0211380
	(Illinois Corporation)
	6 Executive Drive
	Collinsville, Illinois 62234
	(618) 343-8150



Ameren Corporation	Yes	ý	No	¨
Union Electric Company	Yes	ý	No	¨
Ameren Illinois Company	Yes	ý	No	¨

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



Ameren Corporation	Yes	ý	No	¨
Union Electric Company	Yes	ý	No	¨
Ameren Illinois Company	Yes	ý	No	¨

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated ~~filer”~~filer,” “smaller reporting company,” and ~~“smaller reporting~~“emerging growth company” in Rule 12b-2 of the Exchange Act.



	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer	Smaller Reporting Company	Emerging Growth Company
Ameren Corporation	ý	¨	¨	¨	¨
Union Electric Company	¨	¨	ý	¨	¨
Ameren Illinois Company	¨	¨	ý	¨	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.



Ameren Corporation	¨
Union Electric Company	¨
Ameren Illinois Company	¨

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



Ameren Corporation	Yes	¨	No	ý
Union Electric Company	Yes	¨	No	ý
Ameren Illinois Company	Yes	¨	No	ý

The number of shares outstanding of each registrant’s classes of common stock as of ~~October 31, 2016,~~April 28, 2017, was as follows:



Ameren Corporation		Common stock, $0.01 par value per share – 242,634,798
Union Electric Company		Common stock, $5 par value per share, held by Ameren Corporation – 102,123,834
Ameren Illinois Company		Common stock, no par value, held by Ameren Corporation – 25,452,373

______________________________________________________________________________________________________

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

This report contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed. Refer to the Form 10-K for a complete listing of glossary terms and abbreviations. Only new or significantly changed terms and abbreviations are included below.

EMANI – European Mutual Association for Nuclear Insurance.

Form 10-K – The combined Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, filed by the Ameren Companies with the SEC.

~~MEEIA 2013~~Westinghouse – ~~Ameren Missouri’s portfolio of customer energy efficiency programs, net shared benefits, and performance incentive for 2013 through 2015, as approved by the MoPSC in August 2012.~~

~~MEEIA 2016~~ – Ameren Missouri’s portfolio of customer energy efficiency programs, throughput disincentive, and performance incentive for March 2016 through February 2019, as approved by the MoPSC in February 2016.

~~MoOPC~~ ~~– Missouri Office of Public Counsel.~~

~~New Madrid Smelter~~ ~~– Aluminum smelter located in southeast Missouri that was formerly owned by Noranda. Noranda sold the New Madrid Smelter to ARG International AG in October 2016.~~Westinghouse Electric Company, LLC.

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors in the Form 10-K, and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

regulatory, judicial, or legislative actions, including any changes in regulatory policies and ratemaking determinations, such as those that may result from the complaint case filed in February 2015 with the FERC seeking a reduction in the allowed base return on common equity under the MISO tariff, Ameren Missouri’s July 2016 electric rate case filing, Ameren Missouri's appeal of a MoPSC order that clarified the method applied to determine an input used to calculate its performance incentive under MEEIA 2013, Ameren Illinois’ April ~~2016~~2017 annual electric distribution ~~service~~ formula

rate update filing, and future regulatory, judicial, or legislative actions that change regulatory recovery mechanisms;

the effect of Ameren Illinois participating in a performance-based formula ratemaking process under the IEIMA, including the direct relationship between Ameren Illinois' return on common equity and 30-year United States Treasury bond yields and the related financial ~~commitments required by the IEIMA;~~

~~our ability to align our overall spending, both operating and capital, with regulatory frameworks established by our regulators in an attempt to earn our allowed return on equity;~~commitments;

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

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

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

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

Ameren Illinois’ achievement of FEJA electric energy efficiency goals and the resulting impact on its allowed return on program investments;

our ability to align overall spending, both operating and capital, with frameworks established by our regulators in our attempt to earn our allowed return on equity;

the timing of increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely manner;

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

disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including ~~ultra-low-sulfur coal used for Ameren Missouri’s compliance with environmental regulations;~~nuclear fuel assemblies from Westinghouse, Callaway’s only NRC-licensed supplier of such assemblies, which is currently in bankruptcy proceedings;

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

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

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

suspended operations at the New Madrid Smelter, and the resulting impacts to Ameren Missouri's ability to recover its revenue requirement in its July 2016 electric rate case and future rate cases to accurately reflect the New Madrid Smelter’s actual sales volumes;

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

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

the impact of adopting new accounting guidance and the application of appropriate accounting rules and guidance;

the impact of weather conditions on Ameren Missouri and other natural phenomena on us and our customers, including the impact of system outages;

the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;

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

the effects of our increasing investment in electric transmission projects, our ability to obtain all of the necessary approvals to complete the projects, and the uncertainty as to whether we will achieve our expected returns in a timely manner;

operation of Ameren Missouri's Callaway energy center, including planned and unplanned outages, and decommissioning costs;

the effects of strategic initiatives, including mergers, acquisitions, and ~~divestitures, and any related tax implications;~~divestitures;

•

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

the impact of complying with renewable energy portfolio requirements in Missouri;

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

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

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

legal and administrative proceedings;

the impact of cyber attacks, which could result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer data and account information; and

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

New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to

which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions, except per share amounts)

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Unaudited) (In millions)

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
Income from Continuing Operations $ 371
$ 345
$ 626
$ 554
Other Comprehensive Income from Continuing Operations, Net of Taxes

Pension and other postretirement benefit plan activity, net of income taxes of $-, $-, $4, and $4, respectively (1 ) —
1
4
Comprehensive Income from Continuing Operations 370
345
627
558
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests 2
2
5
5
Comprehensive Income from Continuing Operations Attributable to Ameren Common Shareholders 368
343
622
553

Comprehensive Income from Discontinued Operations Attributable to Ameren Common Shareholders —
—
—
52
Comprehensive Income Attributable to Ameren Common Shareholders $ 368
$ 343
$ 622
$ 605



	Three Months Ended March 31,
	2017		2016
Net Income	$	104	$	107
Other Comprehensive Loss, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $- and $1, respectively	—		(2		)
Comprehensive Income	104		105
Less: Comprehensive Income Attributable to Noncontrolling Interests	2		2
Comprehensive Income Attributable to Ameren Common Shareholders	$	102	$	103

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except per share amounts)

The accompanying notes are an integral part of these consolidated financial statements.

UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)

(Unaudited) (In millions, except per share amounts)

The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.

AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)

STATEMENT OF INCOME AND COMPREHENSIVE INCOME

(Unaudited) (In millions)

The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.

AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)

(Unaudited) (In millions)

The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.

AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (d/b/a Ameren Missouri)

AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

~~September 30, 2016~~March 31, 2017

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005. Ameren’s primary assets are its equity interests in its subsidiaries, including Ameren Missouri, Ameren Illinois, and ~~Ameren Illinois.~~ATXI. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. ~~Also see~~Ameren also has various other subsidiaries that conduct other activities, such as the ~~Glossary~~provision of ~~Terms and Abbreviations at the front~~shared services. Ameren is also evaluating competitive electric transmission investment opportunities outside of ~~this report and in the Form 10-K.~~MISO as they arise.

Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas ~~transmission and~~ distribution business in Missouri.

Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution and natural gas ~~transmission and~~ distribution businesses in Illinois.

~~Additionally, Ameren has a subsidiary,~~ ATXI ~~that~~ operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers, Spoon River, and Mark Twain projects. Ameren is also pursuing projects to improve electric transmission system reliability within Ameren Missouri's and Ameren Illinois' service territories as well as evaluating competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO.

~~Ameren also has various other subsidiaries that conduct activities such as the provision of shared services.~~

Unless otherwise stated, these notes to Ameren’s financial statements exclude discontinued operations for all periods presented. See Note 12 – Discontinued Operations in this report and Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information.

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, and therefore their financial statements are not prepared on a consolidated basis.~~subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair statement of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. See Note 2 – Rate and Regulatory Matters for information regarding the 2017 change in Ameren Illinois' method used to recognize interim period revenue in connection with the revenue decoupling provisions of the FEJA. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Discontinued operations were immaterial to all periods presented in Ameren’s financial statements. As such, the December 31, 2016 balance sheet presentation of discontinued operations has been reclassified in this report to “Other current assets” for assets of discontinued operations and to “Other current liabilities” for liabilities of discontinued operations. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, and Ameren Illinois increased during the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2017, to reflect the accretion of the estimated obligation due to the passage of time, partially offset by immaterial settlements.

Share-based Compensation

A summary of nonvested performance share units at ~~September 30, 2016~~March 31, 2017, and changes during the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017, under ~~the 2006 Incentive Plan and~~ the 2014 Incentive Plan are presented below:

Performance share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees ~~will~~ vary depending on actual performance over the three-year measurement period.

The fair value of each performance share unit awarded in ~~2016~~2017 under the 2014 Incentive Plan was determined to be

$~~44.13~~59.16, which was based on Ameren’s closing common share price of $~~43.23~~52.46 at December 31, ~~2015~~2016, and lattice simulations.

Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period beginning January 1, 2017 relative to the designated peer ~~group beginning January 1, 2016.~~group. The simulations can produce a greater fair value for the performance share unit than the December 31 applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of ~~1.31%~~1.47%, volatility of 15% to ~~20%~~21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.

Operating Revenue

The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period. For certain regulatory recovery mechanisms qualifying as alternative revenue programs, such as revenue requirement reconciliations, the Ameren Companies recognize revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected from customers within two years.

Excise Taxes

Ameren Missouri and Ameren Illinois collect certain excise taxes from customers that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business and are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Gas” and “Operating Expenses – Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes for electric service in Illinois are levied on the customer and therefore are ~~therefore~~ not included in Ameren Illinois’ revenues and expenses. The following table presents excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Gas” and “Operating Expenses – Taxes other than income taxes” for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:


	Three Months				Nine Months				Three Months
	2016		2015		2016		2015		2017		2016
Ameren Missouri	$	52	$	52	$	122	$	127	$	31	$	30
Ameren Illinois	9		9		40		42		19		20
Ameren	$	61	$	61	$	162	$	169	$	50	$	50

Earnings Per Share

~~Basic~~There were no material differences between Ameren’s basic and diluted earnings per share ~~is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by~~amounts for the ~~weighted-average number~~three months ended March 31, 2017 and 2016. The assumed settlement of common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number of diluted common shares outstanding during the period. Earnings per diluted share reflects the potential dilution that would occur if certain stock-baseddilutive performance share units were settled. The number of performance share units assumed to be settled was 0.3 million and 0.4 million in the three and nine months ended September 30, 2016, respectively, and 1.3 million and 1.2 million, respectively, in the year-ago periods.had an immaterial impact on earnings per share. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015. The calculation of diluted earnings per share~~2016.

~~prospectively reflected the adoption of FASB guidance related to employee share-based payment accounting discussed below.~~

Accounting and Reporting Developments

Below is a summary of updates related to our adoption of recently issued authoritative accounting standards. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information about recently issued authoritative accounting standards ~~relevant~~relating to leases, financial instruments, restricted cash, and the ~~Ameren Companies.~~consolidation analysis for variable interest entities and voting interest entities.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative ~~accounting~~ guidance that changes the criteria for recognizing revenue from a contract with a customer. The underlying principle of the guidance is that an entity will recognize revenue for the transfer of promised goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance ~~also~~ requires additional disclosures to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with ~~customers.~~customers, as well as separate presentation of alternative revenue programs. Entities can apply the guidance ~~retrospectively~~ to each reporting period presented, the full retrospective method, or ~~retrospectively~~ by recording a cumulative effect adjustment to retained earnings in the period of initial ~~adoption. The Ameren Companies are currently assessing~~adoption, the ~~impact~~modified retrospective method.

During the first quarter of ~~this guidance on their results of operations, financial position, and disclosures, including their accounting for~~2017, we determined that contributions in aid of construction and similar arrangements are not within the scope of this guidance. Therefore, our accounting for such arrangements will not change upon adoption of this guidance. In addition, we determined that the calculation of revenue and bad debt expense for tariff sales contracts will not materially change as ~~well as~~a result of the collectibility criterion included within the guidance. We plan to complete our assessment of the impacts of this guidance on our results of operations, financial position, disclosures, and determine our transition method, ~~that they will use~~in the next few months prior to ~~adopt the guidance. The guidance will be effective for the Ameren Companies~~our adoption in the first quarter of 2018.

~~Amendments to~~Improving the ~~Consolidation Analysis~~Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In February ~~2015,~~2017, the FASB issued authoritative ~~accounting~~ guidance that ~~amends~~requires an entity to retrospectively report the ~~consolidation analysis~~service cost component of net benefit cost in the same line item(s) as other compensation costs arising from services rendered by employees during the periodand to present the other components of net benefit cost in the income statement separately from the service cost component, and outside of operating income. The guidance also requires that an entity only capitalize the service cost component as part of an asset such as inventory or property, plant, and equipment on a prospective basis. Previously, all of the net benefit cost components were eligible for variable interest entities and voting interest entities. The new guidance affects (1) limited partnerships, similar legal entities, and certain investment funds, (2) the evaluation of fees paid to a decision maker or service provider as a variable interest, (3) how fee arrangements impact the primary beneficiary determination, and (4) the evaluation of related party relationships on the primary beneficiary determination.capitalization. The adoption of this guidance in the first quarter of ~~2016 did not impact~~2018 may result in the ~~Ameren Companies’~~recognition of new regulatory assets related to the recovery of, and return on, the non-service cost components of net benefit cost and related allowance for funds used during construction balances. We are currently assessing the impacts of this guidance on our results of operations, financial position, ~~liquidity, or~~and disclosures.

~~Leases~~

In February 2016, the FASB issued authoritative accounting guidance that will require an entity to recognize assets and liabilities arising from a lease. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease will depend primarily on its classification as a finance or operating lease. The guidance also requires additional disclosures to enable users of financial statements to understand the amount, timing, and uncertainty of cash flows arising from leases. The guidance will be effective for the Ameren Companies in the first quarter of 2019, with an option for entities to adopt early. Upon adoption, the Ameren Companies will recognize and measure operating leases on their respective balance sheets at the beginning of the earliest period presented. The Ameren Companies are currently assessing the impact of

~~this guidance on their results of operations, financial position, statement of cash flows, and disclosures.~~

~~Improvements to Employee Share-Based Payment Accounting~~

In March 2016, the FASB issued authoritative accounting guidance that simplifies the accounting for share-based payment transactions, including the income tax consequences, the calculation of diluted earnings per share, the treatment of forfeitures, the classification of awards as either equity or liabilities, and the classification on the statement of cash flows. Ameren determines for each performance share unit award whether the difference between the deduction for tax purposes and the compensation cost recognized for financial reporting purposes results in either an excess tax benefit or an excess tax deficit. Previously, excess tax benefits were recognized in "Other paid-in capital" on Ameren’s consolidated balance sheet, and in certain cases, excess tax deficits were recognized in “Income taxes” on Ameren’s consolidated income statement. The new guidance increases income statement volatility by requiring all excess tax benefits and deficits to be recognized in “Income taxes,” and treated as discrete items in the period in which they occur. Ameren adopted this guidance in the first quarter of 2016 and prospectively applied the amendment in this guidance requiring recognition of excess tax benefits and deficits in the income statement, which resulted in recognition of a $21 million income tax benefit and a corresponding $21 million increase in income from continuing operations and net income (9 cents per diluted share) during that period. Also as a result of the adoption of this guidance, Ameren made an accounting policy election to continue to estimate the number of forfeitures expected to occur. The amendments in the guidance that require application using a modified retrospective transition method did not impact Ameren. Therefore, there was no cumulative-effect adjustment to retained earnings recognized as of January 1, 2016. Ameren applied the amendments in this guidance relating to classification on the statement of cash flows retrospectively. As a result, for the nine months ended September 30, 2015, Ameren reclassified, for comparison purposes, $2 million of excess tax benefits on the statement of cash flows from financing to operating activity, and $12 million of employee payroll taxes related to share-based payments from operating to financing activity.

NOTE 2 – RATE AND REGULATORY MATTERS

Below is a summary of updates to significant regulatory proceedings and related lawsuits. See also Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

~~2016~~March 2017 Electric Rate ~~Case~~Order

~~On July 1, 2016, Ameren Missouri filed a request with~~In March 2017, the MoPSC ~~seeking approval to~~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 ~~its~~in Ameren Missouri’s annual ~~revenues~~revenue requirement for electric service, ~~by $206 million. The~~compared to its prior revenue requirement established in the MoPSC's April 2015 electric rate ~~increase request~~

~~is based~~order. The new rates, base level of expenses, and amortizations became effective on a 9.9% return on equity, a capital structure comprised of 51.8% equity, a rate base of $7.2 billion, and a test year ended March 31, 2016, with certain pro-forma adjustments through the true-up date of December 31, 2016. The rate request includes $74 million that primarily relates to nearly $1.4 billion of new gross electric infrastructure investments since the true-up date in Ameren Missouri’s last electric rate case. This $74 million includes depreciation expenses of $39 million, return on rate base of $25 million, and increased property taxes of $10 million. The rate request also includes $51 million related to reduced customer sales volumes, including reductions from the suspended operations at the New Madrid Smelter, and $34 million related to increases in transmission charges. Other changes in expenses reflected in the rate request include decreases in pension and other post-employment benefit plan expenses of $24 million and solar rebate expenses of $15 million, both of which are subject to regulatory tracking mechanisms; increased net energy costs, excluding the impact of the suspended operations at the New Madrid Smelter and other customer sales volumes, of $23 million; and increased income taxes of $15 million.

As a part of its filing, Ameren Missouri requested the amortization over ten years of an estimated $81 million of lost fixed cost recovery due to lower sales volumes, as discussed below, from the New Madrid Smelter during the period April ~~2015 through May~~1, 2017.

~~Ameren Missouri also requested~~The order included the continued use of ~~its~~the FAC and the regulatory tracking mechanisms for pension and postretirement benefits, ~~and~~ uncertain income tax positions, and renewable energy standards that the MoPSC ~~previously~~ authorized in earlier electric rate orders. ~~Additionally, Ameren Missouri requested the implementation of a new regulatory tracking mechanism for transmission charges and revenues.~~

The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by late April 2017 and new rates effective in late May 2017. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the requestedThese regulatory tracking mechanisms will be approved, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

~~Noranda and New Madrid Smelter~~

~~In the first quarter of 2016, Noranda suspended operations at the New Madrid Smelter and filed voluntary petitions~~provide for a ~~court-supervised restructuring process under Chapter 11~~base level of the United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. As of September 30, 2016, Ameren Missouri has been paid in full for all previous electric service amounts, and expects to continueexpense to be ~~paid~~reflected in ~~full for~~Ameren Missouri’s base electric rates with differences in the ~~minimal amount~~actual expenses incurred recorded as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes, the base level of ~~electric service it is currently providing to~~net energy costs decrease by $54 million from the ~~New Madrid Smelter.~~

~~In its~~base level established in the MoPSC's April 2015 electric rate ~~order,~~order. Changes in amortizations and the ~~MoPSC approved a rate design that~~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 $78 million in annual revenues, net of fuel and purchased power costs, as the New Madrid Smelter’s portion of Ameren Missouri’s revenue requirement. In 2016, as a result of the suspended operations, actual sales volumes to the New Madrid Smelter are significantly below the sales volumes reflected in rates. As a result, full recovery by Ameren Missouri of its revenue requirement has not occurred and will not occur until rates are adjusted prospectively by the MoPSC in the ~~July 2016~~MoPSC's April 2015 electric rate case to accurately reflect the actual sales volumes to the New Madrid Smelter. In its July 2016 electric rate case, Ameren Missouri is seeking to recover the April 2015 through May 2017 lost fixed costs caused by the lower sales volumes to New Madrid Smelter. Also, as a result of the New Madrid Smelter’s suspended operations, Ameren Missouri is applying a provision in its FAC tariff that, under certain circumstances, allows Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced sales to the smelter. The current market price of electricity is less than the New Madrid Smelter’s electric rate, and Ameren Missouri expects market prices to remain below the New Madrid Smelter’s electric rate through the date that new rates in the July 2016 rate case become effective. Accordingly, this FAC-tariff provision will not enable Ameren Missouri to fully recover its revenue requirement under current market conditions. Operations at the New Madrid Smelter remain suspended and Ameren Missouri is uncertain of future sales to the smelter.

~~MEEIA 2013~~

The MEEIA 2013 performance incentive allowed Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy efficiency goals, including $19 million if 100% of the goals were achieved during the three-year period, with the potential to earn a larger performance incentive if Ameren Missouri’s energy savings exceeded those goals. In September 2016, Ameren Missouri and the MoPSC staff filed a stipulation agreement with the MoPSC that supported a $29 million MEEIA 2013 performance incentive. The MoOPC opposed this stipulation agreement; however, it did not oppose the conclusion that Ameren Missouri achieved at least 100% of the customer energy efficiency goals. As there was no challenge to the achievement of at least 100% of the customer energy efficiency goals, Ameren Missouri recognized $19 million of revenue during the third quarter of 2016 related to the MEEIA 2013 performance incentive. In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a revised stipulation agreement between Ameren Missouri, the MoPSC staff, and the MoOPC. As a result, Ameren Missouri will recognize $9 million of additional revenues in the fourth quarter of 2016 relating to the MEEIA 2013 performance incentive. Further, the revised stipulation agreement included a provision to incorporate the results of the appeal, discussed below, regarding the determination of an input used to calculate the performance incentive.

~~In November 2015, the MoPSC issued an order regarding the determination of an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the~~

Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals, Western District, overturns the November 2015 MoPSC order, Ameren Missouri may recognize additional revenues in excess of the $28 million approved by the MoPSC in November 2016.order.

ATXI’s Mark Twain Project

The Mark Twain project is a MISO-approved ~~95-mile~~ transmission line to be located in northeast Missouri. In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity for the Mark Twain ~~project. Before starting construction,~~project conditioned upon ATXI ~~must obtain~~obtaining county assents for road ~~crossings from the five counties where the line will be constructed.~~crossings. None of the five county commissions have approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in the circuit courts for each of the five ~~county circuit courts~~counties to obtain the ~~assents.~~assents for the original project route. A decision ~~from~~in each of the ~~county circuit courts~~five lawsuits is expected in late 2017. In March 2017, the MoPSC’s April 2016 order was vacated by the Missouri Court of Appeals, Western District, which ruled that the MoPSC could not lawfully grant a certificate of convenience and necessity conditioned upon ATXI obtaining the assents. ATXI is evaluating whether to appeal the March 2017 Court of Appeals decision to the Missouri Supreme Court.

In April 2017, ATXI reached agreements in principle with a

cooperative electric company in northeast Missouri and with Ameren Missouri to locate portions of the Mark Twain project on existing transmission line corridors, resulting in a proposed alternative project route. ATXI will finalize the proposed alternative project route and then request assents for road crossings from the five affected counties. If all five county commissions provide assents for the proposed alternative project route, ATXI will then seek MoPSC approval.

ATXI plans to complete the project in ~~2018;~~2019; however, delays in obtaining the assents and approval from the MoPSC could delay ~~the completion date.~~completion.

Illinois

IEIMA & FEJA

Under the provisions of ~~the IEIMA's performance-based formula rate-making framework, which currently extends through 2019,~~Illinois law, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable ~~costs. Throughout each~~costs and allowed return on equity. This revenue requirement reconciliation qualifies as an alternative revenue program under GAAP. Each year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement reflected in customer rates for that year and its estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual recoverable costs ~~incurred.~~incurred and investment return. As of ~~September 30, 2016,~~March 31, 2017, Ameren Illinois had recorded regulatory assets of ~~$23 million, $66~~$24 million and ~~$22~~$54 million to reflect its ~~expected~~ 2016 ~~and 2015~~ revenue requirement reconciliation ~~adjustments,~~adjustment, which was included in the April 2017 formula rate update discussed below, and the approved ~~2014~~2015 revenue requirement reconciliation adjustment, with interest, respectively. For the three months ended March 31, 2017, Ameren Illinois recorded a regulatory asset of $46 million to reflect the difference between Ameren Illinois’ estimate of its revenue requirement and the revenue requirement reflected in customer rates.

In April ~~2016,~~2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for ~~2017~~2018 rates. Pending ICC approval, ~~Ameren Illinois’~~this update filing will result in a ~~$14~~$16 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January ~~2017.~~2018. This update reflects an increase to the annual formula rate based on ~~2015~~2016 actual costs and expected net plant additions for ~~2016,~~2017, an increase to include the ~~2015~~2016 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the ~~2014~~2015 revenue requirement reconciliation adjustment, which will be fully collected from customers in ~~2016,~~2017, consistent with the ICC’s December ~~2015~~2016 annual update filing order. AsThe revenue requirement decrease in the April 2017 update filing is a result of ~~December 31,~~the 2015 ~~Ameren Illinois had recorded a regulatory asset of $103 million related to the approved 2014~~ revenue requirement reconciliation ~~adjustment. In October~~adjustment being larger than the 2016 ~~an administrative law judge issued a proposed order that reflected a decrease~~revenue requirement reconciliation adjustment.An ICC decision regarding the revenue requirement to ~~Ameren Illinois’~~be used for customer rates in 2018 is expected by December 2017.

The FEJA revised certain portions of the IEIMA, including extending the IEIMA formula ratemaking process through 2022, and clarifying that a common equity ratio of up to, and including, 50% is prudent. Beginning in 2017, the FEJA provides that Ameren Illinois will recover, within the following two years, its electric distribution ~~service~~ revenue requirement for a given year, independent of ~~$14 million. An ICC decision~~actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumes resulting from, among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenues during the third quarter, and less revenues during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois will now recognize revenue consistent with the timing of actual incurred electric distribution recoverable costs and recognize revenue associated with the expected return on its rate base ratably over the year. Ameren Illinois recognized $46 million and $11 million of electric distribution revenue to reflect the difference between the estimate of its revenue requirement and the revenue requirement ~~used~~reflected in customer rates for the three months ended March 31, 2017 ~~rates is expected by December 2016.~~and March 31, 2016, respectively.

Federal

FERC Complaint Cases

In November 2013, a customer group filed a complaint case with the FERC seeking a reduction in the allowed base return on common equity for ~~the~~ FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32%., or a 10.82% total allowed return on common equity with the inclusion of the 50 basis point incentive adder for participation in an RTO. The order ~~was consistent with the initial decision an administrative law judge issued in December 2015 and requires~~required customer refunds, with interest, to be issued for that 15-month period. During the ~~15-month period ended February 2015.~~first quarter of 2017,

Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the November 2013 complaint case. In addition, the ~~new~~10.82% allowed ~~base~~ return on common equity ishas been reflected in rates ~~prospectively from the~~since September ~~2016 effective date of the order. Refunds for the November 2013 complaint case are expected to be issued in the first half of 2017.~~2016.

~~After~~As the maximum FERC-allowed refund period for the November 2013 complaint case ended in February 2015, another customer complaint case was filed in February 2015. The February 2015 complaint case seeks a further reduction in the allowed base return on common equity for the FERC-regulated transmission rate base under the MISO ~~tariff to 8.67%.~~tariff. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by the FERC, would lower the allowed base return on common equity to 9.70% and would require customer refunds, with interest, to be issued for the 15-month period ended May 2016. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. The final order in the February 2015 complaint case will determine the allowed base return on common equity for the 15-month period ~~ended~~of February 2015 to May ~~2016.~~2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO and require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case, which will ~~also establish~~prospectively replace the current 10.82% allowed return on equity, is uncertain for two reasons. First, at this time the FERC lacks a quorum of three commissioners. Second, the United States Court of Appeals for the District of Columbia recently vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity ~~that will apply prospectively from its expected second quarter 2017 effective date, replacing~~methodology used in the ~~10.32% allowed base return on common equity, which became effective in September 2016. The 12.38% allowed base return on common equity was effective~~two MISO complaint cases described above. Ameren is unable to predict the impact of the outcome of the United States Court of Appeals for the ~~period that began at the conclusion~~District of ~~the 15-month period for the February 2015 complaint case in May~~

~~2016 through the September 2016 effective date of the final order in the November 2013 complaint case.~~

~~On January 6, 2015, a FERC-approved incentive adder of up to 50 basis points~~Columbia Circuit’s remand on the allowed base return on common equity for our participation in an RTO became effective. Beginning with its January 6, 2015 effective date, the incentive adder reduces any refund to customers relating to a reduction of the allowed base return on common equity from theMISO FERC complaint cases ~~discussed above and will also be applied prospectively from the effective date of the September 2016 FERC order, resulting in a current allowed return on common equity of 10.82%.~~at this time.

As of ~~September 30, 2016,~~March 31, 2017, Ameren and Ameren Illinois recorded current regulatory liabilities of ~~$61~~$41 million and ~~$42~~$24 million, respectively, to reflect the expected refunds, including interest, associated with the reduced allowed ~~base~~ returns on common equity in ~~the September 2016 FERC order and~~ the initial decision in the February 2015 complaint case. Ameren Missouri ~~did not record a liability as of September 30, 2016, as it~~ does not expect that a reduction in the FERC-allowed base return on common equity ~~for MISO transmission owners~~ would be material to its results of operations, financial position, or liquidity.

~~Combined Construction and Operating License~~

In 2008, Ameren Missouri filed an application with the NRC for a COL for a second nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a second nuclear unit at its existing Callaway site, and the NRC suspended review of the COL application. Prior to suspending its efforts, Ameren Missouri had capitalized $69 million related to the project. Primarily because of changes in vendor support for licensing efforts at the NRC, Ameren Missouri’s assessment of long-term capacity needs, declining costs of alternative generation technologies, and the regulatory framework in Missouri, Ameren Missouri discontinued its efforts to license and build a second nuclear unit at its existing Callaway site. As a result of this decision, in the second quarter of 2015, Ameren and Ameren Missouri recognized a $69 million noncash pretax provision for all of the previously capitalized COL costs. Ameren Missouri has withdrawn its COL application with the NRC.

NOTE 3 – SHORT-TERM DEBT AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a description of our indebtedness provisions and other covenants as well as a description of money pool arrangements.

The Missouri Credit Agreement and the Illinois Credit Agreement, both of which expire onin December ~~11, 2019,~~2021, were not utilized for direct borrowings during the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017, but were used to support commercial paper issuances and to issue letters of credit. Based on commercial paper outstanding, as well as letters of credit issued under the Credit Agreements, the aggregate amount of credit capacity available under the Credit Agreements to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at ~~September 30, 2016~~March 31, 2017, was $~~1.5~~1.2 billion. The Ameren Companies were in compliance with the covenants in their credit agreements as of March 31, 2017. As of March 31, 2017, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 53%, 48%, and 46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

The following table presents commercial paper outstanding as of ~~September 30, 2016,~~March 31, 2017, and December 31, ~~2015:~~2016:

The following table summarizes the borrowing activity and relevant interest rates under Ameren’s (parent), Ameren Missouri’s, and Ameren Illinois’ commercial paper programs for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017 and ~~2015:~~2016:

Peak commercial paper during period^(a)

~~Indebtedness Provisions and Other Covenants~~

The information below is a summary of the Ameren Companies’ compliance with financial covenants in the Credit Agreements. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a detailed description of these provisions. The Credit Agreements also contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities.

~~The Credit Agreements require Ameren, Ameren Missouri, and Ameren Illinois to each maintain consolidated indebtedness of not more than~~ ~~65%~~ ~~of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of~~ ~~September 30, 2016~~, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 51%, 48%, and 46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively. In addition, under the Credit Agreements, if Ameren does not have a senior long-term unsecured credit rating of at least Baa3 from Moody’s or BBB- from S&P, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of at least 2.0 to 1.0. As of September 30, 2016, Ameren’s senior long-term unsecured credit rating exceeded the minimum rating requirements; therefore, the interest coverage requirement was not applicable. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable Credit Agreement.

The Credit Agreements contain default provisions that apply separately to each borrower; provided, however, that a default of Ameren Missouri or Ameren Illinois under the applicable Credit Agreement will also be deemed to constitute a default of Ameren under such agreement. Defaults include a cross-default resulting from a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $75 million in the aggregate (including under the other Credit Agreement). However, under the default provisions of the Credit Agreements, any default of Ameren under any Credit Agreement that results solely from a default of Ameren Missouri or Ameren Illinois thereunder does not result in a cross-default of Ameren under the other Credit Agreement. Further, the Credit Agreement default provisions provide that an Ameren default under any of the Credit Agreements does not constitute a default by Ameren Missouri or Ameren Illinois.

None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. The Ameren Companies were in compliance with the covenants in their credit agreements at ~~September 30, 2016~~.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements.

Ameren Missouri, Ameren Illinois, and ATXI may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and Ameren Services may participate in the utility money pool only as lenders. Surplus internal funds are contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the Credit Agreements and the commercial paper programs. The total amount available to the money pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the money pool participants advance surplus funds to the

utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. Participants receiving a loan under the utility money pool must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2017 and 2016, was ~~0.53%~~1.01% and ~~0.54%~~0.47%, ~~respectively (2015 – 0.10% and 0.09%, respectively).~~respectively.

See Note 8 – Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

~~In February 2016, Ameren Missouri's $260 million of 5.40% senior secured notes matured and were repaid with cash on hand and commercial paper borrowings.~~

In June 2016, Ameren Missouri issued $150 million of 3.65% senior secured notes due April 15, 2045, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2016. Ameren Missouri received proceeds of $148 million, which were used to repay commercial paper borrowings.

~~In June 2016, Ameren Illinois’ $54 million of 6.20% senior secured notes and $75 million of 6.25% senior secured notes matured and were repaid with commercial paper borrowings.~~

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures ~~credit facilities,~~ and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to

issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue first mortgage bonds or preferred stock. See Note 5 – Long-Term Debt and Equity Financings under Part II, Item 8, in the Form 10-K for a description of our indenture provisions and other covenants as well as restrictions on the payment of dividends. The ~~following table summarizes the required~~Ameren Companies were in compliance with those indenture provisions and ~~actual interest coverage ratios for interest charges, dividend coverage ratios, and first mortgage bonds and preferred stock issuable~~other covenants as of ~~September 30, 2016, at an assumed annual interest rate of~~ 5% ~~and dividend rate of~~ 6%:

Required Interest
Coverage Ratio^(a)

Actual Interest
Coverage Ratio

Bonds Issuable^(b)

Required Dividend
Coverage Ratio^(c)

Actual Dividend
Coverage Ratio

Preferred Stock
Issuable

Ameren Missouri ≥2.0 4.7 $ 3,838 ≥2.5 105.9 $ 2,357
Ameren Illinois ≥2.0 7.3 3,942
^(d)
≥1.5 3.0 203
^(e)


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


~~(b)~~	Amount of first mortgage bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include first mortgage bonds issuable based on retired bond capacity of ~~$1,206 million~~ ~~and $279 million at Ameren Missouri and Ameren Illinois, respectively.~~


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


~~(d)~~	Amount of first mortgage bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture. The amount of first mortgage bonds issuable by Ameren Illinois is also subject to the lien restrictions contained in the Illinois Credit Agreement.


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

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the

acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including borrowings under the Credit Agreements or the Ameren commercial paper program, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a

~~specified period.~~

Ameren Missouri and Ameren Illinois and certain other 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 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.

~~Ameren Illinois’ articles of incorporation require dividend~~

payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois committed to the FERC to maintain a minimum of ~~30%~~ ~~equity in its capital structure. As of~~ ~~September 30, 2016, Ameren Illinois had 51% equity in its capital structure.~~

~~In order for the Ameren Companies to issue securities in the future, we have to comply with all applicable requirements in effect at the time of any such issuances.~~March 31, 2017.

Off-Balance-Sheet Arrangements

At ~~September 30, 2016~~,March 31, 2017, none of the Ameren Companies had off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 5 – OTHER INCOME AND EXPENSES

The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:

Three Months Nine Months
2016 2015 2016 2015
Ameren:^(a)

Miscellaneous income:
Allowance for equity funds used during construction $ 7
$ 8
$ 20
$ 19

Interest income on industrial development revenue bonds 7
7
20
20

Interest income 3
4
11
12

Other 1
—
3
3

Total miscellaneous income $ 18
$ 19
$ 54
$ 54

Miscellaneous expense:
Donations $ 1
$ —
$ 8
$ 10

Other 7
5
13
12

Total miscellaneous expense $ 8
$ 5
$ 21
$ 22

Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction $ 6
$ 7
$ 16
$ 16

Interest income on industrial development revenue bonds 7
7
20
20

Interest income 1
—
1
1

Other —
—
1
—

Total miscellaneous income $ 14
$ 14
$ 38
$ 37

Miscellaneous expense:
Donations $ —
$ —
$ 2
$ 3

Other 2
3
4
5

Total miscellaneous expense $ 2
$ 3
$ 6
$ 8



	Three Months
	2017	2016
Ameren:^(a)
Miscellaneous income:


	Three Months				Nine Months				Three Months
	2016		2015		2016		2015		2017		2016
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction	$	1	$	1	$	4	$	3	$	6	$	8
Interest income on industrial development revenue bonds									7		7
Interest income	2		3		9		10		2		4
Other	1		—		2		2		—		1
Total miscellaneous income	$	4	$	4	$	15	$	15	$	15	$	20
Miscellaneous expense:
Donations	$	1	$	—	$	6	$	4	$	5	$	5
Other	2		3		5		6		4		2
Total miscellaneous expense	$	3	$	3	$	11	$	10	$	9	$	7
Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction									$	5	$	7
Interest income on industrial development revenue bonds									7		7
Other									—		1
Total miscellaneous income									$	12	$	15
Miscellaneous expense:
Donations									$	—	$	1
Other									2		1
Total miscellaneous expense									$	2	$	2
Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction									$	1	$	1
Interest income									2		4
Total miscellaneous income									$	3	$	5
Miscellaneous expense:
Donations									$	4	$	4
Other									2		1
Total miscellaneous expense									$	6	$	5

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:

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

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

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

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of ~~September 30, 2016,~~March 31, 2017 and December 31, ~~2015.~~2016. As of ~~September 30, 2016,~~March 31, 2017, these contracts extended through October ~~2018,~~2019, March ~~2021,~~2023, May 2032, and February 2020 for fuel oils, natural gas, power, and uranium, respectively.

Fuel oils (in gallons)^(a)

~~Authoritative accounting guidance regarding derivative instruments requires that all~~All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 – Fair Value Measurements for a discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for

regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of ~~September 30, 2016,~~March 31, 2017 and December 31, ~~2015,~~2016, all contracts that met the definition of a derivative and ~~are~~were not eligible for the NPNS exception received regulatory deferral.

~~Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash~~

collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under a master netting arrangement or similar agreement. The Ameren

~~Companies did not elect to adopt this guidance for any eligible derivative instruments.~~

The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of ~~September 30, 2016,~~March 31, 2017 and December 31, ~~2015:~~2016:

Total liabilities ^(d)

Total liabilities ^(c)

Total liabilities ^(d)

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective ~~exchanges and~~exchanges; these contracts have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master netting arrangements or similar agreements, and reporting daily exposure to senior management.

We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar agreement level by counterparty.

The ~~following table provides~~Ameren Companies elect to present the ~~recognized gross derivative balances and the net~~fair value amounts of ~~those derivatives~~derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement ~~as of~~ ~~September 30, 2016~~,gross on the balance sheet. However, if the gross amounts recognized on the balance sheet were netted with derivative instruments and cash collateral received or posted, the net amounts would not be materially different from the gross amounts at March 31, 2017 and December 31, ~~2015~~:2016.

Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset Gross Amounts Recognized in the Balance Sheet Derivative Instruments
Cash Collateral Received/Posted^(a)

Net
Amount
2016
Assets:
Ameren Missouri $ 12
$ 2
$ —
$ 10
Ameren Illinois 3
2
—
1
Ameren $ 15
$ 4
$ —
$ 11
Liabilities:
Ameren Missouri $ 25
$ 2
$ 5
$ 18
Ameren Illinois 190
2
—
188
Ameren $ 215
$ 4
$ 5
$ 206
2015
Assets:
Ameren Missouri $ 17
$ 1
$ —
$ 16
Ameren Illinois 1
—
—
1
Ameren $ 18
$ 1
$ —
$ 17
Liabilities:
Ameren Missouri $ 44
$ 1
$ 8
$ 35
Ameren Illinois 220
—
3
217
Ameren $ 264
$ 1
$ 11
$ 252

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. We calculate maximum exposures based on the gross fair value of financial instruments, including NPNS and other accrual contracts. These exposures are calculated on a gross basis, which include affiliate exposure not eliminated at the consolidated Ameren level. ~~The potential loss on counterparty exposures may be reduced or eliminated by the application of master netting arrangements or similar agreements and collateral held.~~ As of ~~September 30, 2016,~~March 31, 2017, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure would have been immaterial with or without consideration of the application of master netting arrangements or similar agreements and collateral held.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of ~~September 30, 2016~~March 31, 2017, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require. The additional collateral required is the net liability position allowed under the master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered on ~~September 30, 2016~~March 31, 2017, and (2) those counterparties with rights to do so requested collateral.


	Aggregate Fair Value of Derivative Liabilities^(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required^(b)		Aggregate Fair Value of Derivative Liabilities^(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required^(b)
2016
2017
Ameren Missouri	$	69	$	2	$	60	$	58	$	8	$	44
Ameren Illinois	53		—		46		38		—		30
Ameren	$	122	$	2	$	106	$	96	$	8	$	74

NOTE 7 – FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value.

All financial assets and liabilities carried at fair value are classified and disclosed in one of three hierarchy levels. See

Note 8 – Fair Value Measurements under Part II, Item 8, of the Form 10-K for information related to hierarchy levels. We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs utilized by the Ameren Companies for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the periods ended ~~September 30, 2016~~March 31, 2017, and December 31, ~~2015:~~2016:

Fair Value

Weighted Average

Fair Value

Weighted Average

Assets

Liabilities

Valuation Technique(s)

Unobservable Input

Range

Assets

Liabilities

Valuation Technique(s)

Unobservable Input

Range

Level 3 Derivative asset and liability – commodity contracts^(a):

2016

2017

Fuel oils

—

Option model

Volatilities(%)^(b)

25 – 38

Fuel oils

)

Option model

Volatilities(%)^(b)

23 – 35

Discounted cash flow

Counterparty credit risk(%)^(c)(d)

0.22

(e)

Discounted cash flow

Counterparty credit risk(%)^(c)(d)

0.12 – 0.22

0.15

Ameren Missouri credit risk(%)^(c)(d)

0.38

(d)

Power^(f)

(174

)

Discounted cash flow

Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(g)

25 – 42

Estimated auction price for FTRs ($/MW)^(b)

(253) – 3,593

Nodal basis ($/MWh)^(g)

(6) – 0

(2)

Ameren credit risk (%)^(c)(d)

0.38

(e)

Fundamental energy production model

Estimated future gas prices ($/mmbtu)^(b)

3 – 5

Escalation rate (%)^(b)(h)

(e)

Contract price allocation

Estimated renewable energy credit costs ($/credit)^(b)

5 – 7

Uranium

—

)

Option model

Volatilities (%)^(b)

(e)

Discounted cash flow

Average forward uranium pricing ($/pound)^(b)

22 – 26

Ameren Missouri credit risk (%)^(c)(d)

0.38

(e)

Fair Value Weighted Average
Assets Liabilities Valuation Technique(s) Unobservable Input Range
2015
Natural gas $ 1
$ (1 ) Option model
Volatilities (%)^(b)
35 – 55 45

Nodal basis ($/mmbtu)^(c)
(0.30) – 0 (0.20)
Discounted cash flow
Nodal basis ($/mmbtu)^(b)
(0.10) – 0 (0.10)

Counterparty credit risk (%)^(c)(d)
0.40 – 12 7

Ameren Missouri credit risk (%)^(c)(d)
0.40 (e)

Power^(f)
16
(170 ) Discounted cash flow
Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(g)
22 – 39 29

Estimated auction price for FTRs ($/MW)^(b)
(270) – 2,057 211

Nodal basis ($/MWh)^(g)
(10) – (1) (3)

Counterparty credit risk (%)^(c)(d)
0.86 (e)

Ameren Illinois credit risk (%)^(c)(d)
0.40 (e)
Fundamental energy production model
Estimated future gas prices ($/mmbtu)^(b)
3 – 4 4

Escalation rate (%)^(b)(h)
3 (e)
Contract price allocation
Estimated renewable energy credit costs ($/credit)^(b)
5 – 7 6
Uranium —
(1 ) Option model
Volatilities (%)^(b)
20 (e)
Discounted cash flow
Average forward uranium pricing ($/pound)^(b)
35 – 42 37

Ameren Missouri credit risk (%)^(c)(d)
0.40 (e)



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
								Ameren Missouri credit risk(%)^(c)(d)	0.37	(e)
								Escalation rate (%)^(b)(f)	0 – 1	0
	Natural gas	—		(2		)	Discounted cash flow	Nodal basis ($/mmbtu)^(b)	(0.80) – (0.10)	(0.70)
								Counterparty credit risk (%)^(c)(d)	0.45 – 6	0.70
								Ameren Illinois credit risk (%)^(c)(d)	0.37	(e)
	Power^(g)	5		(195		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)	25 – 44	29
								Estimated auction price for FTRs ($/MW)^(b)	(89) – 1,568	164
								Nodal basis ($/MWh)^(h)	(4) – 0	(2)
								Ameren Illinois credit risk (%)^(c)(d)	0.37	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)^(b)	3 – 4	3
								Escalation rate (%)^(b)(i)	3	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)^(b)	5 – 7	6
2016
	Fuel oils	$	1	$	—		Option model	Volatilities (%)^(b)	24 – 66	28
							Discounted cash flow	Counterparty credit risk (%)^(c)(d)	0.13 – 0.22	0.15
								Ameren Missouri credit risk (%)^(c)(d)	0.38	(e)
								Escalation rate (%)^(b)(f)	(2) – 2	0
	Natural gas	1		(1		)	Option model	Volatilities (%)^(b)	31 – 66	36
								Nodal basis ($/mmbtu)^(b)	(0.40) – (0.10)	(0.20)
							Discounted cash flow	Nodal basis ($/mmbtu)^(b)	(0.80) – 0	(0.50)
								Counterparty credit risk (%)^(c)(d)	0.13 – 8	1
								Ameren Illinois credit risk (%)^(c)(d)	0.38	(e)
	Power^(g)	9		(187		)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)	26 – 44	29
								Estimated auction price for FTRs ($/MW)^(b)	(71) – 5,270	125
								Nodal basis ($/MWh)^(h)	(6) – 0	(2)
								Ameren Illinois credit risk (%)^(c)(d)	0.38	(e)
							Fundamental energy production model	Estimated future gas prices ($/mmbtu)^(b)	3 – 4	3
								Escalation rate (%)^(b)(i)	5	(e)
							Contract price allocation	Estimated renewable energy credit costs ($/credit)^(b)	5 – 7	6
	Uranium	—		(4		)	Option model	Volatilities (%)^(b)	24	(e)
							Discounted cash flow	Average forward uranium pricing ($/pound)^(b)	22 – 24	22
								Ameren Missouri credit risk (%)^(c)(d)	0.38	(e)


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


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


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


(d)	Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.


(e)	Not applicable.


(f)	Escalation rate applies to fuel oil prices 2019 and beyond


(g)	Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through ~~2020.~~2021 for March 31, 2017 and through 2020 for December 31, 2016. Valuations beyond 2021 for March 31, 2017 and 2020 for December 31, 2016 use fundamentally modeled pricing by month for peak and off-peak demand.


~~(g)~~(h)	The balance at Ameren is comprised of Ameren Missouri and Ameren Illinois power contracts, which respond differently to unobservable input changes due to their opposing positions.


~~(h)~~(i)	Escalation rate applies to power prices in 2031 and ~~beyond for September 30, 2016, and to power prices in 2026 and beyond for December 31, 2015.~~beyond.

~~In accordance with applicable authoritative accounting guidance, we~~We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in the first ~~nine months~~quarter of ~~2016~~2017 or ~~2015~~2016. At ~~September 30, 2016~~March 31, 2017, and December 31, ~~2015,~~

2016, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of ~~September 30, 2016~~March 31, 2017:


		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total				Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets – commodity contracts^(a):										Derivative assets – commodity contracts^(a):
	Fuel oils	$	—	$	—	$	1	$	1		Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	$	—	$	3	$	—	$	3		Natural gas	1		4		—		5
	Power	—		—		11		11			Power	—		—		5		5
	Total derivative assets – commodity contracts	$	—	$	3	$	12	$	15		Total derivative assets – commodity contracts	$	2	$	4	$	6	$	12
	Nuclear decommissioning trust fund:										Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	3	$	—	$	—	$	3		Cash and cash equivalents	$	1	$	—	$	—	$	1
	Equity securities:										Equity securities:
	U.S. large capitalization	393		—		—		393			U.S. large capitalization	420		—		—		420
	Debt securities:										Debt securities:
	U.S. treasury and agency securities	—		120		—		120			U.S. treasury and agency securities	—		118		—		118
	Corporate bonds	—		64		—		64			Corporate bonds	—		70		—		70
	Other	—		17		—		17			Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	396	$	201	$	—	$	597	^(b)	Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	^(b)
	Total Ameren	$	396	$	204	$	12	$	612		Total Ameren	$	423	$	216	$	6	$	645
Ameren	Derivative assets – commodity contracts^(a):
Missouri	Fuel oils	$	—	$	—	$	1	$	1
Ameren Missouri											Derivative assets – commodity contracts^(a):
	Power	—		—		11		11			Fuel oils	$	1	$	—	$	1	$	2
	Total derivative assets – commodity contracts	$	—	$	—	$	12	$	12		Power	—		—		5		5
	Nuclear decommissioning trust fund:										Total derivative assets – commodity contracts	$	1	$	—	$	6	$	7
	Cash and cash equivalents	$	3	$	—	$	—	$	3		Nuclear decommissioning trust fund:
	Equity securities:										Cash and cash equivalents	$	1	$	—	$	—	$	1
	U.S. large capitalization	393		—		—		393			Equity securities:
	Debt securities:										U.S. large capitalization	420		—		—		420
	U.S. treasury and agency securities	—		120		—		120			Debt securities:
	Corporate bonds	—		64		—		64			U.S. treasury and agency securities	—		118		—		118
	Other	—		17		—		17			Corporate bonds	—		70		—		70
	Total nuclear decommissioning trust fund	$	396	$	201	$	—	$	597	^(b)	Other	—		24		—		24
	Total Ameren Missouri	$	396	$	201	$	12	$	609		Total nuclear decommissioning trust fund	$	421	$	212	$	—	$	633	^(b)
Ameren	Derivative assets – commodity contracts^(a):
Illinois	Natural gas	$	—	$	3	$	—	$	3
											Total Ameren Missouri	$	422	$	212	$	6	$	640
Ameren Illinois											Derivative assets – commodity contracts^(a):
											Natural gas	$	1	$	4	$	—	$	5
Liabilities:
Ameren	Derivative liabilities – commodity contracts^(a):										Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	9	$	—	$	—	$	9		Fuel oils	$	4	$	—	$	1	$	5
	Natural gas	—		27		—		27			Natural gas	—		21		2		23
	Power	—		—		174		174			Power	—		—		195		195
	Uranium	—		—		5		5			Total Ameren	$	4	$	21	$	198	$	223
	Total Ameren	$	9	$	27	$	179	$	215
Ameren	Derivative liabilities – commodity contracts^(a):
Missouri	Fuel oils	$	9	$	—	$	—	$	9
Ameren Missouri											Derivative liabilities – commodity contracts^(a):
	Natural gas	—		9		—		9			Fuel oils	$	4	$	—	$	1	$	5
	Power	—		—		2		2			Natural gas	—		8		—		8
	Uranium	—		—		5		5			Power	—		—		1		1
	Total Ameren Missouri	$	9	$	9	$	7	$	25		Total Ameren Missouri	$	4	$	8	$	2	$	14
Ameren	Derivative liabilities – commodity contracts^(a):
Illinois	Natural gas	$	—	$	18	$	—	$	18
Ameren Illinois											Derivative liabilities – commodity contracts^(a):
	Power	—		—		172		172			Natural gas	$	—	$	13	$	2	$	15
	Total Ameren Illinois	$	—	$	18	$	172	$	190		Power	—		—		194		194
											Total Ameren Illinois	$	—	$	13	$	196	$	209


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


(b)	Balance excludes $2 million of receivables, payables, and accrued income, net.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, ~~2015~~2016:


		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total				Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren	Derivative assets – commodity contracts^(a):										Derivative assets – commodity contracts^(a):
	Natural gas	$	—	$	1	$	1	$	2		Fuel oils	$	2	$	—	$	1	$	3
	Power	—		—		16		16			Natural gas	2		12		1		15
	Total derivative assets – commodity contracts	$	—	$	1	$	17	$	18		Power	—		—		9		9
	Nuclear decommissioning trust fund:										Total derivative assets – commodity contracts	$	4	$	12	$	11	$	27
	Cash and cash equivalents	$	4	$	—	$	—	$	4		Nuclear decommissioning trust fund:
	Equity securities:										Cash and cash equivalents	$	1	$	—	$	—	$	1
	U.S. large capitalization	364		—		—		364			Equity securities:
	Debt securities:										U.S. large capitalization	408		—		—		408
	U.S. treasury and agency securities	—		109		—		109			Debt securities:
	Corporate bonds	—		58		—		58			U.S. treasury and agency securities	—		112		—		112
	Other	—		22		—		22			Corporate bonds	—		67		—		67
	Total nuclear decommissioning trust fund	$	368	$	189	$	—	$	557	^(b)	Other	—		17		—		17
	Total Ameren	$	368	$	190	$	17	$	575		Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	^(b)
Ameren	Derivative assets – commodity contracts^(a):
Missouri	Natural gas	$	—	$	—	$	1	$	1
											Total Ameren	$	413	$	208	$	11	$	632
Ameren Missouri											Derivative assets – commodity contracts^(a):
	Power	—		—		16		16			Fuel oils	$	2	$	—	$	1	$	3
	Total derivative assets – commodity contracts	$	—	$	—	$	17	$	17		Natural gas	—		1		1		2
	Nuclear decommissioning trust fund:										Power	—		—		9		9
	Cash and cash equivalents	$	4	$	—	$	—	$	4		Total derivative assets – commodity contracts	$	2	$	1	$	11	$	14
	Equity securities:										Nuclear decommissioning trust fund:
	U.S. large capitalization	364		—		—		364			Cash and cash equivalents	$	1	$	—	$	—	$	1
	Debt securities:										Equity securities:
	U.S. treasury and agency securities	—		109		—		109			U.S. large capitalization	408		—		—		408
	Corporate bonds	—		58		—		58			Debt securities:
	Other	—		22		—		22			U.S. treasury and agency securities	—		112		—		112
	Total nuclear decommissioning trust fund	$	368	$	189	$	—	$	557	^(b)	Corporate bonds	—		67		—		67
	Total Ameren Missouri	$	368	$	189	$	17	$	574		Other	—		17		—		17
Ameren	Derivative assets – commodity contracts^(a):
Illinois	Natural gas	$	—	$	1	$	—	$	1
											Total nuclear decommissioning trust fund	$	409	$	196	$	—	$	605	^(b)
											Total Ameren Missouri	$	411	$	197	$	11	$	619
Ameren Illinois											Derivative assets – commodity contracts^(a):
											Natural gas	$	2	$	11	$	—	$	13
Liabilities:
Ameren	Derivative liabilities – commodity contracts^(a):										Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	29	$	—	$	—	$	29		Fuel oils	$	5	$	—	$	—	$	5
	Natural gas	1		62		1		64			Natural gas	—		13		1		14
	Power	—		—		170		170			Power	—		1		187		188
	Uranium	—		—		1		1			Uranium	—		—		4		4
	Total Ameren	$	30	$	62	$	172	$	264		Total Ameren	$	5	$	14	$	192	$	211
Ameren	Derivative liabilities – commodity contracts^(a):
Missouri	Fuel oils	$	29	$	—	$	—	$	29
Ameren Missouri											Derivative liabilities – commodity contracts^(a):
	Natural gas	—		13		1		14			Fuel oils	$	5	$	—	$	—	$	5
	Uranium	—		—		1		1			Natural gas	—		6		—		6
	Total Ameren Missouri	$	29	$	13	$	2	$	44		Power	—		1		2		3
Ameren	Derivative liabilities – commodity contracts^(a):
Illinois	Natural gas	$	1	$	49	$	—	$	50
	Power	—		—		170		170			Uranium	—		—		4		4
	Total Ameren Illinois	$	1	$	49	$	170	$	220		Total Ameren Missouri	$	5	$	7	$	6	$	18
Ameren Illinois											Derivative liabilities – commodity contracts^(a):
											Natural gas	$	—	$	7	$	1	$	8
											Power	—		—		185		185
											Total Ameren Illinois	$	—	$	7	$	186	$	193

All costs related to financial assets and liabilities classified as Level 3 in the fair value hierarchy are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2017 and 2016, ~~and 2015,~~ the balances and changes in the fair value of Level 3 financial assets and liabilities associated with fuel oils, natural gas, and uranium were immaterial.

The following table summarizes the changes in the fair value of power financial assets and liabilities classified as Level 3 in the fair value hierarchy:

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
For the three months ended September 30, 2016
Beginning balance at July 1, 2016 $ 14
$ (169 ) $ (155 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities —
(6 ) (6 )
Settlements (5 ) 3
(2 )
Ending balance at September 30, 2016 $ 9
$ (172 ) $ (163 )
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2016 $ —
$ (2 ) $ (2 )
For the three months ended September 30, 2015
Beginning balance at July 1, 2015 $ 27
$ (165 ) $ (138 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities 2
(8 ) (6 )
Settlements (7 ) 3
(4 )
Ending balance at September 30, 2015 $ 22
$ (170 ) $ (148 )
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015 $ 1
$ (7 ) $ (6 )
For the nine months ended September 30, 2016
Beginning balance at January 1, 2016 $ 16
$ (170 ) $ (154 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (4 ) (13 ) (17 )
Purchases 13
—
13
Settlements (16 ) 11
(5 )
Ending balance at September 30, 2016 $ 9
$ (172 ) $ (163 )
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2016 $ —
$ (7 ) $ (7 )
For the nine months ended September 30, 2015
Beginning balance at January 1, 2015 $ 9
$ (142 ) $ (133 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities —
(37 ) (37 )
Purchases 29
—
29
Settlements (16 ) 9
(7 )
Ending balance at September 30, 2015 $ 22
$ (170 ) $ (148 )
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2015 $ 1
$ (35 ) $ (34 )



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
For the three months ended March 31, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		—			(10	)		(10	)
Settlements		(3	)		1			(2	)
Ending balance at March 31, 2017	$	4		$	(194	)	$	(190	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2017	$	—		$	(11	)	$	(11	)
For the three months ended March 31, 2016
Beginning balance at January 1, 2016	$	16		$	(170	)	$	(154	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(21	)		(24	)
Settlements		(7	)		4			(3	)
Ending balance at March 31, 2016	$	6		$	(187	)	$	(181	)
Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2016	$	—		$	(19	)	$	(19	)

Transfers into or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level, but were recategorized to Level 3 because the inputs to the model became unobservable during the period or (2) existing assets and liabilities that were previously classified as Level 3, but were recategorized to a higher level because the lowest significant input became observable during the period. For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2017 and 2016, ~~and 2015,~~ there were no material transfers between Level 1 and Level 2, Level 1 and Level 3, or Level 2 and Level 3 related to derivative commodity contracts.

The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. They are considered to be Level 1 in the fair value hierarchy. The Ameren Companies' short-term borrowings also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered to be Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt, capital lease obligations and preferred stock at ~~September 30, 2016~~March 31, 2017, and December 31, ~~2015~~2016:

NOTE 8 – RELATED PARTY TRANSACTIONS

~~Ameren (parent) and its subsidiaries have engaged in, and may in the future engage in, affiliate transactions in~~

In the normal course of ~~business.~~business, the Ameren Companies engage in affiliate transactions. These transactions primarily consist of power purchases and sales, services received or rendered, and borrowings and lendings.

Transactions between

affiliates are reported as intercompany transactions on their ~~respective~~ financial statements but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 – Related Party Transactions under Part II, Item 8, of the Form 10-K and the

money pool arrangements discussed in Note 3 – Short-term Debt and Liquidity of this report.

Electric Power Supply ~~Agreements~~Agreement

In April ~~and September 2016,~~2017, Ameren Illinois conducted a procurement ~~events,~~event, administered by the IPA, to purchase energy products. Ameren Missouri was among the winning suppliers in ~~these events.~~ this event.

As a result, in April ~~2016,~~2017, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, ~~375,200~~85,600 megawatthours at an average price of ~~$34.71~~$33.64 per megawatthour during the period of ~~June~~March 1, ~~2017,~~2019, through September 30, 2018. In September 2016, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell, and Ameren Illinois agreed to purchase, 82,800 megawatthours at an average price of $34.35 per megawatthour during the period of May ~~1, 2017, through September 30, 2018.~~31, 2020.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:


				Three Months				Nine Months						Three Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois	Income Statement Line Item			Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2016	$	9	$	(a)	$	21	$	(a)	Operating Revenues	2017	$	11	$	(a)
agreements with Ameren Illinois		2015		4		(a)		9		(a)		2016		9		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2016		5		1		18		3	Operating Revenues	2017		7		1
rent and facility services		2015		6		1		19		3		2016		6		1
Ameren Missouri and Ameren Illinois	Operating Revenues	2016		1		(b)		1		(b)
miscellaneous support services		2015		1		(b)		2		(b)
Total Operating Revenues		2016	$	15	$	1	$	40	$	3		2017	$	18	$	1
		2015		11		1		30		3		2016		15		1
Ameren Illinois power supply	Purchased Power	2016	$	(a)	$	9	$	(a)	$	21	Purchased Power	2017	$	(a)	$	11
agreements with Ameren Missouri		2015		(a)		4		(a)		9		2016		(a)		9
Ameren Illinois transmission	Purchased Power	2016		(a)		1		(a)		2	Purchased Power	2017		(a)		(b)
services with ATXI		2015		(a)		1		(a)		2		2016		(a)		(b)
Total Purchased Power		2016	$	(a)	$	10	$	(a)	$	23		2017	$	(a)	$	11
		2015		(a)		5		(a)		11		2016		(a)		9
Ameren Services support services	Other Operations and Maintenance	2016	$	30	$	29	$	96	$	90	Other Operations and Maintenance	2017	$	35	$	32
agreement		2015		30		28		96		87		2016		34		31
Money pool borrowings (advances)	Interest Charges/ Miscellaneous Income	2016	$	(b)	$	(b)	$	(b)	$	(b)	Interest Charges/ Miscellaneous Income	2017	$	(b)	$	(b)
		2015		(b)		(b)		(b)		(b)		2016		(b)		(b)


(a)	Not applicable.


(b)	Amount less than $1 million.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, authorities and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements in this report and in our Form 10-K, will not have a material adverse effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies ~~and Note 16 – Divestiture Transactions and Discontinued Operations~~ under Part II, Item 8, of the Form 10-K. See also Note 2 – Rate and Regulatory Matters, Note 8 – Related Party Transactions, and Note 10 – Callaway Energy ~~Center.~~

~~Callaway Energy~~ Center

~~The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at~~ ~~September 30, 2016. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively,~~ of ~~each year. Both coverages were renewed in 2016.~~

this report.

Type and Source of Coverage Maximum Coverages
Maximum Assessments
for Single Incidents

Public liability and nuclear worker liability:
American Nuclear Insurers $ 375
   $ —

Pool participation 12,986
^(a)
127
^(b)
$ 13,361
^(c)
$ 127

Property damage:
NEIL $ 2,750
^(d)
$ 30
^(e)
European Mutual Association for Nuclear Insurance 450
^(f)
—

$ 3,200
$ 30

Replacement power:
NEIL $ 490
^(g)
$ 7
^(e)


~~(a)~~	~~Provided through mandatory participation in an industrywide retrospective premium assessment program.~~


~~(b)~~	~~Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of~~ ~~$375 million~~ ~~in the event of an incident at any licensed United States commercial reactor, payable at~~ ~~$19 million~~ ~~per year.~~

~~(c)~~

~~Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to~~ ~~$127 million~~ ~~per incident for each licensed reactor it operates with a maximum of~~ ~~$19 million~~ ~~per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.~~


~~(d)~~	~~NEIL provides~~ ~~$2.75 billion~~ ~~in property damage, decontamination, and premature decommissioning insurance for radiation events. NEIL provides $2.3 billion in property damage for nonradiation events.~~


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


~~(f)~~	~~European Mutual Association for Nuclear Insurance provides~~ ~~$450 million~~ ~~in excess of the~~ ~~$2.75 billion~~ ~~and $2.3 billion property coverage for radiation and nonradiation events, respectively, provided by NEIL.~~

~~(g)~~

~~Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to~~ ~~$4.5 million~~ ~~for 52 weeks, which commences after the first twelve weeks of an outage, plus up to~~ ~~$3.6 million~~ ~~per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of~~ ~~$490 million. Nonradiation events are sub-limited to~~ ~~$328 million~~.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every ~~five~~ years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in September 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.

~~Losses resulting from terrorist attacks on nuclear facilities are covered under NEIL’s insurance policies, subject to an industrywide aggregate policy limit of~~ ~~$3.24 billion~~ ~~within a 12-month period, or $1.83 billion for events not involving radiation contamination.~~

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.

Other Obligations

In order to supply a portion of the fuel requirements of Ameren Missouri’s energy centers, Ameren Missouri has entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. Additionally, Ameren Missouri and Ameren Illinois have entered into various long-term commitments for purchased power and natural gas for distribution. At ~~September 30, 2016,~~March 31, 2017, total obligations related to commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren Illinois were ~~$4,328~~$3,824 million, ~~$2,428~~$2,340 million, and ~~$1,859~~$1,418 million, respectively. For additional information regarding our obligations and commitments at December 31, ~~2015,~~2016, see Note 15 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In April ~~and September 2016,~~2017, Ameren Illinois conducted a procurement ~~events,~~event, administered by the IPA, to purchase energy products ~~and capacity~~ through May 31, ~~2019.~~2020. In the April 2017 procurement event, Ameren Illinois contracted to purchase ~~approximately 3,609,800~~4,249,800 megawatthours of energy products for $105 million from June 1, 2016, through May 31, 2019. In the September procurement event, Ameren Illinois contracted to purchase approximately 2,229,800 megawatthours of energy products for $71 million from October 1, 2016, through May 31, 2019. In addition, in the September procurement event, Ameren Illinois contracted to purchase 1,854 MWs of capacity for $96$128 million from June 1, 2017, through May 31, ~~2019. The results of both procurement events are included in Ameren’s and Ameren Illinois’ obligations discussed above.~~2020. See Note 8 – Related Party Transactions for

additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of ~~these~~this procurement ~~events.~~event.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. ~~Such requirements can impact the siting,~~The development and operation of ~~new and existing~~electric generation, transmission, and distribution facilities and natural gas storage, ~~facilities. Such requirements~~transmission, and distribution facilities, can ~~encompass~~trigger compliance obligations with respect to diverse environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy ~~approval~~ processes are required to obtain ~~modify or~~and renew approvals, permits, and licenses for new, existing or ~~existing~~modified facilities. Additionally, the use and handling of various chemicals or hazardous materials ~~at some of our facilities~~ require release prevention plans and emergency response procedures.

The EPA has promulgated ~~several~~ environmental regulations that ~~will~~ have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. ~~Significant new rules~~As of December 31, 2016, Ameren Missouri’s fossil-fueled energy centers represented 18% and 34% of Ameren’s and Ameren Missouri’s rate base, respectively. Recent regulations impacting air emissions from electric utility industry include revised NSPS, the ~~regulation~~CSAPR, the MATS and revised National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants such as SO₂, particulate matter, NO_X, mercury, toxic metals and acid gases. Regulation of CO₂ emissions from existing power plants through the Clean Power Plan have been stayed by the United States Supreme Court. In addition, the EPA recently announced it is re-evaluating the legal and ~~from new power plants through~~policy basis for the ~~revised NSPS; the CSAPR, which requires further reductions of SO~~₂ ~~emissions~~Clean Power Plan. Water intake and NO_x

emissions from power plants; a regulation governing management and storage of CCR; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from power plants; revised NSPS for particulate matter, SO₂~~, and NO~~_x ~~emissions from new sources; new effluent standards applicable to wastewater~~ discharges from power ~~plants; and new regulations~~plants are regulated under the Clean Water Act ~~that~~and could require significant capital expenditures, such as modifications to water intake structures at Ameren Missouri’s energy centers. The ~~EPA also periodically reviews~~management and ~~revises national ambient air quality standards, including those standards associated with emissions from power plants,~~disposal of coal ash is regulated under the CCR Rule, which will require significant capital expenditures, such as ~~particulate matter, ozone, SO~~₂the closure of surface impoundments and NO_x~~. Certain~~the installations of ~~these new~~dry ash handling systems at several of our energy centers. The EPA has initiated an administrative review of several regulations ~~are being~~and rulemaking activities, including the Clean Power Plan, the MATS, and the effluent limitation guidelines, which could ultimately result in the revision of all or ~~are likely to be challenged through litigation, so their ultimate implementation, as well as the timing~~part of ~~any~~ such ~~implementation, is uncertain. Although many details of future regulations are unknown,~~rules. However, the individual or combined effects of ~~new~~existing environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with ~~all of these~~existing environmental laws and regulations could be prohibitively expensive, result in the closure or alteration of the operation of some of Ameren Missouri’s energy centers, or require further capital investment. Ameren and Ameren Missouri expect that ~~these~~such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the ~~nature and~~ timing of costs and their recovery could ~~result in~~be subject to regulatory lag. ~~As of December 31, 2015, Ameren Missouri’s energy centers that emit CO~~₂~~represented approximately 20% and 35% of Ameren’s and Ameren Missouri’s rate base, respectively.~~

Ameren Missouri's current plan for compliance with existing environmental regulations for air emissions includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. Ameren and Ameren Missouri estimate that they will need to make capital expenditures of ~~$600~~$425 million to ~~$700~~$525 million in the aggregate from ~~2016~~2017 through ~~2020~~2021 in order to comply with existing environmental regulations. Ameren Missouri may be required to install additional ~~air emissions~~environmental controls beyond ~~2020.~~2021. This estimate of capital expenditures includes expenditures required for the CCR regulations, the Clean Water Act rule applicable to cooling water intake structures at existing power plants, and the Clean Water Act effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. This estimate does not include the potential impacts of the Clean Power Plan discussed below. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimate ~~due to~~because of uncertainty as to whether the EPA will substantively revise regulatory obligations, the precise compliance strategies that will be used and their ultimate cost, among other things.

The following sections describe the more significant new environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations.

Clean Air Act

Federal and state laws require significant reductions in SO₂and NO_x through either emission source reductions or the use

and retirement of emission allowances. The first phase of the CSAPR emission reduction requirements became effective in ~~2015 and the~~2015. The second phase of emission reduction requirements, which were revised by the EPA in ~~September~~ 2016, ~~will become~~became effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfur coal, operates two scrubbers at its Sioux energy center, and optimizes other existing pollution control equipment. Ameren Missouri ~~does~~did not ~~expect to~~ make additional capital investments to comply with the 2017 CSAPR requirements. However, Ameren Missouri expects to incur additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costs are expected to be recovered from customers through the FAC or higher base rates.

CO₂ Emissions Standards

In 2015, the EPA issued regulations that set CO₂ emissions standards for new power plants. These new standards establish separate emissions limits for new natural-gas-fired combined cycle plants and new coal-fired plants. The Clean Power Plan ~~which~~ sets forth CO₂emissions standards applicable to existing power ~~plants,~~plants. The rule was ~~issued by the EPA in August 2015 but~~ stayed by the United States Supreme Court in February 2016, pending the outcome of various legal ~~challenges, as discussed below.~~challenges. In April 2017, the EPA announced that it is reviewing and, if appropriate, will initiate proceedings to suspend, revise, or rescind the Clean Power Plan. The District of Columbia Circuit Court of Appeals has stayed further action on the litigation that

resulted from the Supreme Court’s February 2016 stay of the Clean Power Plan pending the EPA’s administrative review.

~~If upheld, the~~The Clean Power Plan would require ~~Missouri and Illinois to reduce~~significant reductions in CO₂ emissions from power plants ~~within their states significantly below 2005 levels~~ by ~~2030. The rule contains~~2030 including interim compliance periods commencing in ~~2022 that would require each state~~2022. The EPA has advised all states to ~~demonstrate progress in achieving its CO~~₂ emissions reduction target. Ameren continues to evaluate the Clean Power Plan's potential impacts to its operations, including those related to electric system reliability, and to its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation. Significant uncertainty exists regarding the impact of the Clean Power Plan, as itsdiscontinue implementation ~~will depend upon plans to be developed by the states. Numerous legal challenges are pending, which could result in the rule being declared invalid or the nature and timing of CO~~₂ emissions reductions being revised. All implementation requirements are deferred until such time as these legal challenges are concluded. A decision by the District of Columbia Circuit Court of Appeals is expected to be issued in 2017, and subsequent appeals to the United States Supreme Court are likely.planning. We cannot predict the outcome of ~~such legal challenges or their~~the EPA’s administrative review, nor the resulting impact on our results of operations, financial position, or liquidity. If the rule is ultimately upheld and implemented in substantially similar form to the rule when issued, compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could result in increased operating costs and require Ameren Missouri to make new or accelerated capital expenditures. Ameren Missouri expects substantially all of these increased costs to be recoverable, subject to MoPSC prudence review, through higher rates to customers, which could be significant.

~~In 2015, the EPA also issued final regulations that set CO~~₂ ~~emissions standards for new power plants. These new standards~~

~~establish separate emissions limits for new natural-gas-fired combined cycle plants and new coal-fired plants.~~

~~Federal and state legislation or regulations that mandate limits on the emission of CO~~₂ ~~may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. Mandatory limits on the emission of CO~~₂ could increase costs for Ameren Missouri’s customers or have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity if regulators delay or deny recovery in rates of these compliance costs. The cost of Ameren Illinois’ purchased power and gas purchased for resale could increase. However, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings might benefit from increased investment to comply with CO₂ ~~emission limitations to the extent that the investments are reflected and recovered on a timely basis in rates charged to customers.~~

NSR and Clean Air Litigation

In January 2011, the Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The complaint, as amended in October 2013, ~~alleges~~alleged that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. ~~A trial was held~~The litigation has been divided into two phases: liability and remedy. In January 2017, the district court issued a liability ruling that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceed to the second phase to determine the actions required to remedy the violations found in the ~~third quarter~~liability phase of ~~2016. It is not certain when a final decision will be reached in this case,~~the litigation. The EPA previously withdrew all claims for penalties and ~~subsequent appeals are likely.~~fines. At the conclusion of both phases of the litigation, Ameren Missouri ~~believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that it will be successful~~intends to appeal the liability ruling to the United States Circuit Court of Appeals for the Eighth Circuit. A decision by the district court regarding the remedy phase of the litigation could occur in ~~its efforts.~~2019.

The ultimate resolution of this matter could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri. AAmong other things and subject to economic and regulatory considerations, resolution of this matter could result in increased capital expenditures for the installation of pollution control equipment, ~~and~~as well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of this matter or the costs that might be incurred.

Clean Water Act

In 2014, the EPA issued its final rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing aquatic organisms impinged on the facility’s intake screens or entrained through the plant's cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. Implementation of the rule will occur during the permit renewal process of each energy center’s water discharge permit, which will occur between 2018 and 2023.

Additionally, in 2015, the EPA issued ~~its final~~a rule to revise the effluent limitation guidelines applicable to steam electric generating units. ~~Effluent limitation~~These guidelines ~~are~~established national standards for water discharges that are based on the effectiveness of available control technology. The EPA's 2015 rule prohibits effluent discharges of certain waste streams and imposes more

stringent limitations on certain ~~components in~~ water discharges from power plants. ~~All of Ameren Missouri’s coal-fired~~In April 2017, the EPA announced that it would review and ~~nuclear energy centers are subject to~~

~~the cooling water intake structures rule and all of Ameren Missouri’s coal-fired energy centers are subject to~~reconsider the effluent ~~limitations rule. Implementation of both~~limitation guidelines and administratively stayed all compliance deadlines.

Both the intake and effluent rules, ~~will occur during the renewal process of each energy center’s water discharge permit, which will occur between 2018 and 2023. The rules~~if implemented as enacted, could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity ~~if their~~should such implementation ~~requires~~require extensive modifications to the cooling water systems and water discharge systems at Ameren Missouri’s energy centers, and if ~~those~~such investments are not recovered on a timely basis in electric rates charged to Ameren Missouri’s customers.

Ash Management

In 2015, the EPA issued regulations regarding the management and disposal of ~~CCR.~~CCR from coal fired energy centers. These regulations affect CCR disposal and handling costs at Ameren Missouri's energy centers. The regulations allow for the management of CCR as a solid waste, as well as for its continued beneficial uses, which could reduce the amount to be disposed. The regulations also establish criteria regarding the structural integrity, location, groundwater monitoring, and operation of CCR impoundments and landfills. They require closure of impoundments if ~~the~~performance criteria relating to groundwater impacts and location restrictions are not achieved. Ameren and Ameren Missouri’s AROs associated with CCR storage facilities reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2023.

Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan. ~~The new regulations do not apply to ash ponds at plants no longer in operation.~~

Remediation

The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation ~~actions~~ regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by federal or state governments as a potentially responsible party at several contaminated sites.

As of ~~September 30, 2016,~~March 31, 2017, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois, which are in various stages of investigation, evaluation, remediation, and closure. Ameren Illinois estimates it could substantially conclude remediation efforts by ~~2025.~~2023. The ICC allows Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. Costs are subject to annual review by the ICC. As of ~~September 30, 2016,~~March 31, 2017, Ameren Illinois estimated the obligation related to these former MGP sites at ~~$204~~$193 million to ~~$274~~$258 million. Ameren and Ameren Illinois recorded a liability of ~~$204~~$193 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate.

The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many ~~site-specific~~site-

specific factors can influence the ultimate actual costs, including unanticipated underground structures, the degree to which

groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs may vary substantially from these estimates.

Ameren Missouri participated in the investigation of various sites known as Sauget Area 2, located in Sauget, Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies that former landfills and lagoons at those sites may contain soil and groundwater contamination. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property at Sauget Area 2 that was once used by others as a landfill.

In ~~December~~ 2013, the EPA issued its record of decision for Sauget Area 2, approving the investigation and the remediation actions recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA-approved ~~cleanup~~ remedies. As of ~~September 30, 2016,~~March 31, 2017, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.

Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.

Ameren Missouri Municipal Taxes

The cities of Creve Coeur and Winchester, Missouri, on behalf of themselves and other municipalities in Ameren Missouri’s service area, filed a class action lawsuit in ~~November~~ 2011 against Ameren Missouri in the Circuit Court of St. Louis County, Missouri. The lawsuit alleges that Ameren Missouri failed to collect and pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. Ameren and Ameren Missouri recorded immaterial liabilities on their respective balance sheets as of ~~September 30, 2016,~~March 31, 2017, and December 31, ~~2015,~~2016, representing their estimate of the probable loss due as a result of this lawsuit. Ameren and Ameren Missouri believe there is a remote possibility that a liability relating to this lawsuit could be material to ~~Ameren~~Ameren's and Ameren Missouri’s results of operations, financial position, and liquidity. Ameren Missouri believes its defenses are meritorious and is defending itself vigorously. However, there can be no assurances that Ameren Missouri will be successful in its efforts. A 2018 trial has been set and an order is expected later that year.

NOTE 10 – CALLAWAY ENERGY CENTER

Spent Nuclear Fuel

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. ~~Under~~The NWPA established the ~~NWPA,~~fee that Ameren Missouri and other utilities that own and operate those energy centers ~~are responsible for paying the disposal costs. The NWPA established~~

~~the fee that these utilities~~ pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated and sold by those plants. The NWPA also requires the DOE to review the nuclear waste fee annually against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren Missouri and other utilities have entered into standard contracts with the DOE. Consistent with the NWPA and its standard contract, which stated that the DOE would begin to dispose of spent nuclear fuel by 1998, Ameren Missouri had historically collected one mill from its electric customers for each kilowatthour of electricity that it generated and sold from its Callaway energy center. Because the federal government is not meeting its disposal obligation, the collection of this fee was suspended in May 2014. The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operations of the energy center.

As a result of the DOE's failure to fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners sued the DOE to recover costs ~~such as certain NRC fees and ad valorem taxes,~~ incurred for ongoing storage of their spent fuel. The lawsuit resulted in a settlement agreement that provides for annual reimbursement of additional spent fuel storage and related costs. For the three months ended March 31, 2017 and March 31, 2016, Ameren Missouri did not receive any such reimbursements. Ameren Missouri will continue to apply for reimbursement from the DOE for allowable costs associated with the ongoing storage of spent fuel.

Decommissioning

Electric utility rates charged to customers provide for the recovery of the Callaway energy center's decommissioning costs,

which include decontamination, dismantling, and site restoration costs, over the expected life of the nuclear energy center. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway energy center’s decommissioning. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Annual decommissioning costs of $7 million are included in the costs used to establish electric rates for Ameren Missouri's customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. In April

2016, the MoPSC approved no change in ~~electric service rates for~~the annual decommissioning costs ~~based on Ameren Missouri’s updated cost study and funding analysis filed in April 2015.~~used to establish electric rates.

The fair value of the trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability. If the assumed return on trust assets is not earned, Ameren Missouri believes that it is probable that any such earnings deficiency will be recovered in rates.

Supplier of Fuel Assemblies

The next scheduled refueling and maintenance outage at Ameren Missouri’s Callaway energy center will be in fall 2017. The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse. Westinghouse is currently the only NRC-licensed supplier authorized to provide fuel assemblies to the Callaway energy center. During the first quarter of 2017, Westinghouse filed voluntary petitions for a court-supervised

restructuring process under Chapter 11 of the United States Bankruptcy Code. Westinghouse could petition the bankruptcy court to reject Ameren Missouri’s contracts as part of the restructuring process, and if the bankruptcy court agrees, this could result in Ameren Missouri not having access to the fuel assemblies necessary to operate the Callaway energy center. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, including with respect to the delivery of fuel assembles for the upcoming refueling and maintenance outage, and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. However, Ameren and Ameren Missouri could incur material unexpected costs as a result of the Westinghouse bankruptcy, such as the cost of replacement power, the loss of fuel inventory that is stored at Westinghouse’s facility, and payments made for fuel fabrication. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at March 31, 2017. The property coverage and the nuclear liability coverage renewal dates are April 1 and January 1, respectively, of each year. Both coverages were renewed in 2017.



Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	450		$	—
Pool participation	12,986		^(a)	127		^(b)
	$	13,436	^(c)	$	127
Property damage:
NEIL and EMANI	$	3,200	^(d)	$	29	^(e)
Replacement power:
NEIL	$	490	^(f)	$	7	^(e)


(a)	Provided through mandatory participation in an industrywide retrospective premium assessment program.


(b)	Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year.


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


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


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


(f)	Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first twelve weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in September 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.

Losses resulting from terrorist attacks on nuclear facilities are subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants insured by NEIL or EMANI within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share one full limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month

period for radiation events, or $1.8 billion for events not involving radiation contamination. The EMANI policies have an aggregate limit of €600 million for radiation and nonradiation events within a period of 72 hours.

NOTE 11 – RETIREMENT BENEFITS

The following table presents the components of the net periodic benefit cost (benefit) incurred for Ameren’s pension and postretirement benefit plans for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:


	Pension Benefits												Postretirement Benefits												Pension Benefits						Postretirement Benefits
	Three Months						Nine Months						Three Months						Nine Months						Three Months						Three Months
	2016			2015			2016			2015			2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	20		$	23		$	60		$	69		$	5		$	6		$	15		$	17		$	23		$	20		$	5		$	5
Interest cost	46			43			138			130			12			12			36			36			45			47			12			12
Expected return on plan assets	(63		)	(62		)	(189		)	(186		)	(18		)	(17		)	(54		)	(51		)	(66		)	(63		)	(19		)	(18		)
Amortization of:
Prior service benefit	—			—			—			—			(1		)	(1		)	(3		)	(3		)	—			—			(1		)	(1		)
Actuarial loss (gain)	8			19			24			56			(3		)	1			(8		)	4			14			9			(2		)	(3		)
Settlement loss	—			—			—			1			—			—			—			—
Net periodic benefit cost (benefit)	$	11		$	23		$	33		$	70		$	(5	)	$	1		$	(14	)	$	3		$	16		$	13		$	(5	)	$	(5	)

Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs (benefit) incurred for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:


	Pension Benefits										Postretirement Benefits												Pension Benefits				Postretirement Benefits
	Three Months					Nine Months					Three Months						Nine Months						Three Months				Three Months
	2016			2015		2016			2015		2016			2015			2016			2015			2017		2016		2017			2016
Ameren Missouri^(a)	$	6		$	14	$	19		$	42	$	(1	)	$	2		$	(3	)	$	6		$	6	$	8	$	(1	)	$	(1	)
Ameren Illinois	6			9		17			28		(3		)	—			(10		)	(2		)	10		5		(4		)	(4		)
Other	(1		)	—		(3		)	—		(1		)	(1		)	(1		)	(1		)
Ameren^(a)(b)	$	11		$	23	$	33		$	70	$	(5	)	$	1		$	(14	)	$	3		$	16	$	13	$	(5	)	$	(5	)


(a)	Does not include the impact of the regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.


(b)	Includes amounts for Ameren registrants and nonregistrant subsidiaries.

~~NOTE 12 – DISCONTINUED OPERATIONS~~

There was no net income attributable to Ameren common shareholders from discontinued operations during 2016. The following table presents the components of discontinued operations in Ameren's consolidated statement of income for the three and nine months ended September 30, 2015:

2015 2015
Three Months Nine Months
Operating revenues $ —
$ —
Operating benefits (expenses) (1 ) 2
Operating income (loss) before income tax (1 ) 2
Income tax benefit 1
50
Income from discontinued operations, net of taxes $ —
$ 52

During the second quarter of 2015, based on the completion of the IRS audit for 2013, Ameren removed a previously recorded reserve for unrecognized tax benefits and recognized a tax benefit from discontinued operations. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information related to discontinued operations.

The following table presents the carrying amounts of the components of assets and liabilities of Ameren’s discontinued operations, which consist primarily of AROs and related deferred income tax assets associated with the abandoned Meredosia and Hutsonville energy centers, at September 30, 2016, and December 31, 2015:

September 30, 2016 December 31, 2015
Assets of discontinued operations
Accumulated deferred income taxes, net $ 15
$ 14
Total assets of discontinued operations $ 15
$ 14
Liabilities of discontinued operations
Accounts payable and other current obligations $ 1
$ 1
Asset retirement obligations^(a)
26
28
Total liabilities of discontinued operations $ 27
$ 29


~~(a)~~	~~Ameren has completed its retirement obligations at the Hutsonville energy center. The remaining ARO liabilities relate to the abandoned Meredosia energy center.~~

NOTE 1312 – SEGMENT INFORMATION

Ameren has ~~two reportable~~four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren ~~Illinois. Ameren Missouri and Ameren Illinois each have one reportable segment.~~Transmission. The Ameren Missouri segment ~~for both Ameren and Ameren Missouri~~ includes all of the operations of Ameren ~~Missouri’s business as described in Note 1 – Summary of Significant Accounting Policies. The~~Missouri. Ameren Illinois ~~segment for both~~Electric Distribution consists of the electric distribution business of Ameren ~~and~~Illinois. Ameren Illinois ~~includes all~~Natural Gas consists of the ~~operations~~natural gas business of Ameren ~~Illinois’ business as described in Note 1 – Summary~~Illinois. Ameren Transmission is primarily composed of ~~Significant Accounting Policies.~~the aggregated electric transmission businesses of Ameren Illinois and ATXI, and associated Ameren (parent) interest charges. The category called Other primarily includes Ameren parent company activities and Ameren ~~Services,~~Services.

Ameren Missouri has one segment. Ameren Illinois has three segments: Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and ~~ATXI.~~Ameren Illinois Transmission. See Note 1 – Summary of Significant Accounting Policies for additional information regarding the operations of Ameren Missouri and Ameren Illinois.

Segment operating revenues and a majority of operating expenses are directly recognized and incurred by Ameren Illinois to each Ameren Illinois segment. Common operating expenses, miscellaneous income and expenses, interest charges, and income tax expense are allocated by Ameren Illinois to each Ameren Illinois segment based on certain factors, which primarily relate to the nature of the cost. Additionally, Ameren Illinois Transmission earns revenue from transmission service provided to Ameren Illinois Electric Distribution. The transmission expense for Illinois customers who have elected to purchase their power from Ameren Illinois is recovered through a cost recovery mechanism with no net effect on Ameren Illinois Electric Distribution earnings, as costs are offset by corresponding revenues. Transmission revenues from these transactions are reflected at Ameren Transmission and Ameren Illinois Transmission. An intersegment elimination at Ameren and Ameren Illinois occurs to eliminate these transmission revenues and expenses.

The following ~~table presents~~tables present information about the reported revenues and specified items reflected in net income attributable to ~~Ameren~~ common shareholders ~~from continuing operations~~and capital expenditures at Ameren and Ameren Illinois for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015, and total assets of continuing operations as of~~ ~~September 30,~~ 2016,. Ameren, Ameren

Missouri, and ~~December 31, 2015~~:Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount.

Ameren


Three Months	Ameren Missouri		Ameren Illinois		Other		Intersegment Eliminations			Ameren			Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other				Intersegment Eliminations			Consolidated
2017
External revenues													$	772	$	384	$	264	$	96		$	(2	)		$	—		$	1,514
Intersegment revenues													18		1		—		6		^(a)	—				(25		)	—
Net income attributable to Ameren common shareholders													5		30		33		34			—				—			102
Capital expenditures													196		120		51		134			4			^(b)	(1		)	504
2016
External revenues	$	1,150	$	675	$	34	$	—		$	1,859		$	726	$	351	$	285	$	72		$	—			$	—		$	1,434
Intersegment revenues	15		1		1		(17		)	—			15		1		—		11		^(a)	—				(27		)	—
Net income attributable to Ameren common shareholders from continuing operations	241		119		9		—			369
2015
External revenues	$	1,160	$	654	$	19	$	—		$	1,833
Intersegment revenues	11		1		1		(13		)	—
Net income attributable to Ameren common shareholders from continuing operations	239		98		6		—			343
Nine Months
2016
External revenues	$	2,733	$	1,892	$	95	$	—		$	4,720
Intersegment revenues	40		3		2		(45		)	—
Net income attributable to Ameren common shareholders from continuing operations	347		223		51		—			621
2015
External revenues	$	2,825	$	1,910	$	55	$	—		$	4,790
Intersegment revenues	30		3		2		(35		)	—
Net income attributable to Ameren common shareholders from continuing operations	341		182		26		—			549
As of September 30, 2016:
Total assets	$	13,889	$	9,202	$	1,496	$	(468	)	$	24,119	^(a)
As of December 31, 2015:
Total assets	$	13,851	$	8,903	$	1,139	$	(267	)	$	23,626	^(a)
Net income attributable to Ameren common shareholders													14		11		35		27			18				—			105
Capital expenditures													178		117		35		164			2			^(b)	—			496


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


(b)	Includes the elimination of intercompany transfers.

Ameren Illinois

~~(a) Excludes total assets from discontinued operations of $15 million and $14 million as of September 30, 2016, and December 31, 2015, respectively.~~



	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission			Intersegment Eliminations			Consolidated
2017
External revenues	$	385	$	264	$	54		$	—		$	703
Intersegment revenues	—		—		6		^(a)	(6		)	—
Net income available to common shareholder	30		33		16			—			79
Capital expenditures	120		51		56			—			227
2016
External revenues	$	352	$	285	$	40		$	—		$	677
Intersegment revenues	—		—		11		^(a)	(11		)	—
Net income available to common shareholder	11		35		13			—			59
Capital expenditures	117		35		59			—			211


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

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q, as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

Below is a summary description of Ameren's principal subsidiaries. Ameren also has various other subsidiaries ~~are listed below.~~that conduct other activities, such as the provision of shared services. Ameren is also evaluating competitive electric transmission investment opportunities outside of MISO as they arise.

Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission and distribution business and a rate-regulated natural gas ~~transmission and~~ distribution business in Missouri.

Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution, and natural gas ~~transmission and~~ distribution businesses in Illinois.

~~Additionally, Ameren has a subsidiary,~~ ATXI ~~that~~ operates a FERC rate-regulated electric transmission business. ATXI is developing MISO-approved electric transmission projects, including the Illinois Rivers, Spoon River, and Mark Twain projects. Ameren is also pursuing projects to improve electric transmission system reliability within Ameren Missouri’s and Ameren Illinois’ service territories as well as evaluating competitive electric transmission investment opportunities outside of these territories, including investments outside of MISO. Ameren also has various other subsidiaries that conduct activities such as the provision of shared services.

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 12 – Discontinued Operations under Part I, Item 1, of this report and Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding the divestiture transactions and discontinued operations 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, and therefore their financial statements are not prepared on a consolidated basis.~~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.

OVERVIEW

Net income attributable to Ameren common shareholders ~~from continuing operations~~ was ~~$369 million in the third quarter of 2016, compared with $343 million in the year-ago period. Net income attributable to Ameren common shareholders from continuing operations was $621~~$102 million in the first ~~nine months~~quarter of ~~2016,~~2017, compared with ~~$549~~$105 million in the year-ago period. Net income was unfavorably affected by an increase in the effective tax rate primarily due to a decrease in the income tax benefit recorded at Ameren (parent) related to share-based compensation. Earnings also decreased as a result of milder winter temperatures in 2017 and increased depreciation and amortization expenses. Net income was favorably affected by a change in the ~~third quarter and the first nine months of 2016, compared~~method used to recognize interim period revenue related to Ameren Illinois Electric Distribution’s revenue requirement reconciliation in connection with the ~~year-ago periods,~~decoupling provisions of the FEJA. Additionally, earnings were favorably affected by increased Ameren ~~Illinois and ATXI electric transmission service~~Transmission and Ameren Illinois ~~electric distribution service earnings,~~Electric Distribution investment, reflecting Ameren’s strategy to allocate incremental capital to those ~~businesses; increased demand due to warmer summer temperatures; increased rates for Ameren Illinois’ natural gas distribution service pursuant to a December 2015 order;~~businesses, as well as decreased other operations and maintenance expenses; and the recognition of a MEEIA 2013 performance incentive. Net income was also favorably affected in the first nine months of 2016, compared with the year-ago period, by the absence of a provision recognized in the second quarter of 2015, as a result of Ameren Missouri’s discontinued efforts to license and build a second nuclear unit at its existing Callaway energy center site, as well as an income tax benefit recorded in the first quarter of 2016 at Ameren (parent) pursuant to the adoption of new accounting guidance related to share-based compensation. Net income was unfavorably affected in the third quarter and the first nine months of 2016, compared with the year-ago periods, by decreased electric demand at Ameren Missouri resulting from a reduction in sales to the New Madrid Smelter, decreased Ameren Missouri earnings resulting from the absence in 2016 of MEEIA 2013 net shared benefits, and increased depreciation and amortization expenses, primarily at Ameren Missouri. Additionally, earnings were unfavorably affected in the first nine months of 2016, compared to the year-ago period, by the cost of the Callaway energy center’s scheduled refueling and maintenance outage, the absence in 2016 of a January 2015 ICC order regarding Ameren Illinois’ cumulative power usage cost and its purchased power rider mechanism, and decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues. Net income was also unfavorably affected in the third quarter of 2016, compared to the year-ago period, by decreased Ameren Illinois natural gas distribution earnings due to seasonal rate redesign.

expenses.

~~Ameren remains focused on executing its strategy of~~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 ~~opportunities~~ for the benefit of its customers and shareholders. Ameren ~~continues~~remains focused on disciplined cost management and strategic capital allocation. In the first quarter of 2017, Ameren continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks, ~~that provide predictable and timely cost recovery. Ameren invested approximately $1 billion~~investing more than $300 million of ~~its $1.5 billion in~~ capital expenditures ~~during the first nine months of 2016~~ in ~~FERC-regulated~~its FERC rate-regulated electric transmission ~~projects~~ and ~~Ameren~~ Illinois electric and natural gas distribution ~~service infrastructure.~~businesses.

In March 2017, the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren ~~invested approximately $510~~Missouri’s July 2016 regulatory rate review. The electric rate order resulted in a $92 million ~~during the first nine months of 2016~~increase in ~~FERC-regulated transmission projects, including~~ Ameren ~~Illinois’ continued significant transmission investments to improve reliability. Construction continues on ATXI’s $1.4 billion Illinois Rivers and $150~~Missouri’s revenue requirement, a $54 million ~~Spoon River transmission projects. Pre-construction steps continue to be made on the $225 million Mark Twain project. In October 2016, ATXI filed suit~~decrease in the ~~circuit courts~~base level of each of the five counties where the Mark Twain project will be constructed to obtain assents for road crossings. A decision from each of the county circuit courts is expected in 2017. ATXI plans to complete the project in 2018; however, delays in obtaining the assents could delay the completion date. The completion of the Illinois Rivers, Spoon River,net energy costs, and Mark Twain transmission projects will provide customers with improved reliability and access to additional renewable energy sources, including wind power from the western and northern parts of the MISO region, including northeast Missouri.

~~In September 2016, the FERC issued~~ a ~~final order~~$26 million reduction in the ~~November 2013 complaint case which lowered~~base level of certain tracked expenses, compared to the ~~allowed base return on common equity to 10.32%.~~amounts in the MoPSC’s April 2015 rate order. The new ~~allowed~~rates and base ~~return on common equity is reflected in rates prospectively from the September 2016 effective date~~level of the order. The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. The final order in the February 2015 complaint case will determine the allowed base return on common equity for the 15-month period ended May 2016. The final order in the February 2015 complaint case will also establish the allowed base return on common equity that will apply prospectively from its expected second quarter 2017 effective date, replacing the 10.32% allowed base return on common equity, whichexpenses became effective ~~in September 2016. The 12.38% allowed base return~~ on common equity was effective for the period that began at the conclusion of the 15-month period for the February 2015 complaint case in May 2016 through the September 2016 effective date of the final order in the November 2013 complaint case.April 1, 2017.

Ameren Illinois ~~has~~ invested approximately ~~$480~~$170 million in electric distribution and natural gas ~~distribution~~ infrastructure projects in the first ~~nine months~~quarter of ~~2016. It remains on track to meet~~2017, including those that are part of its ~~remaining investment, reliability, and smart meter goals under the IEIMA.~~modernization action plan. In April ~~2016,~~2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the

revenue requirement used for ~~2017~~2018 rates. Pending ICC approval, ~~Ameren Illinois’~~this update filing will result in a~~$14~~ $16 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018. This update reflects an increase to the annual formula rate based on 2016 actual costs and expected net plant additions for 2017, an increase to include the 2016 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2015 revenue requirement

reconciliation adjustment, which will be fully collected from customers in 2017. An ICC decision on the revenue requirement to be used for ~~2017~~2018 rates is expected by December ~~2016.~~

In July 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The request includes recovery of, and a return on, new infrastructure investments, recovery of fixed costs related to the loss of sales to the New Madrid Smelter, and increased transmission charges. Ameren Missouri also requested continued use of its FAC and the regulatory tracking mechanisms for pension and postretirement benefits and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders. Additionally, Ameren Missouri requested the implementation of a new regulatory tracking mechanism for transmission charges and revenues. A decision by the MoPSC is expected by late April 2017, with new rates effective in late May 2017. ~~Ameren Missouri continues to pursue a modernized regulatory framework that supports investment to upgrade aging electric infrastructure and reduces regulatory lag.~~

In the ~~third~~first quarter of ~~2016,~~2017, Ameren ~~Missouri recognized $19~~Transmission invested approximately $135 million ~~of revenue related~~in FERC rate-regulated electric transmission projects, including the Illinois Rivers project, the Spoon Rivers project, and Ameren Illinois’ transmission projects to ~~the MEEIA 2013 performance incentive based~~maintain and improve reliability. ATXI’s construction activities for its Illinois Rivers and Spoon River projects are continuing on ~~a stipulation agreement between Ameren Missouri~~schedule and ~~the MoPSC staff, which was filed with the MoPSC~~are expected to be completed by 2019 and 2018, respectively. Related to its Mark Twain project, in September 2016. In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a revised stipulation agreement between Ameren Missouri, the MoPSC staff, and the MoOPC. As a result, Ameren Missouri will recognize $9 million of additional revenues in the fourth quarter of 2016 relating to the MEEIA 2013 performance incentive. Further, the revised stipulation agreement included a provision to incorporate the results of the appeal, discussed below, regarding the determination of an input used to calculate the performance incentive. In November 2015, the MoPSC issued an order regarding the determination of an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order withMarch 2017, the Missouri Court of Appeals, Western District, ~~which~~vacated a MoPSC April 2016 order that had granted a certificate of convenience and necessity for the Mark Twain project, and ruled that the MoPSC could not lawfully grant a certificate of convenience and necessity conditioned upon ATXI obtaining the county assents for road crossings. ATXI is ~~expected~~evaluating whether to ~~issue a decision in 2016. If~~appeal this ruling to the Missouri ~~Court of Appeals, Western District, overturns the November 2015 MoPSC order,~~Supreme Court. In April 2017, ATXI reached agreements in principle with a cooperative electric company in northeast Missouri and with Ameren Missouri ~~may recognize additional revenues in excess~~to locate portions of ~~the $28 million approved by the MoPSC in November 2016.~~

~~Reflecting confidence in Ameren’s outlook and long-term strategy, in October 2016, Ameren’s board of directors increased the quarterly common stock dividend to 44 cents per share,~~that project on existing transmission line corridors, resulting in ~~an annualized equivalent dividend rate of $1.76 per share.~~a proposed alternative project route. ATXI will finalize the proposed alternative project route and then request assents for road crossings from the five affected counties. If all five county commissions provide assents for the proposed alternative project route, ATXI will then seek MoPSC approval.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. ~~Weather, economic~~Economic conditions, energy efficiency investments by our customers and us, and the actions of key customers can significantly affect the demand for our services.

~~Our~~ Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling ~~demands. Ameren and Ameren Missouri are also affected~~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, with regulatory frameworks established by our regulators.

Ameren Missouri principally uses coal, nuclear fuel, and natural gas for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, ~~and~~ demand, and many other factors. WeAs 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 changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews, with the remaining 5% of changes retained by Ameren Missouri. Net energy costs, as defined in the FAC, include fuel and purchased power costs net of off-system sales. 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. See the definition of margin in the Electric and Natural Gas Margins section below. 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 Illinois’ electric distribution service business has a cost recovery mechanism for power purchased and transmission services incurred on behalf of its customers. 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.

Under the provisions of Illinois law, Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity. If a given year's revenue requirement is greater than the revenue requirement reflected in that year's customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If a given year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years.

Included in Ameren Illinois' electric distribution service utility business, pursuant to the IEIMA, conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement included in customer rates for that year, with recoveries from, or refunds to,

~~customers made in a subsequent year. Included in Ameren Illinois'~~ revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States Treasury bonds plus 580 basis points. Therefore, Ameren Illinois' annual return on equity for its electric distribution business is directly correlated to yields on United States Treasury bonds. Recoverable electric distribution costs that are not recovered through separate cost recovery mechanisms are also included in a revenue requirement reconciliation which results in corresponding adjustments to electric revenues, with no overall effect on net income. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes

other than income taxes, interest charges, and income taxes. A portion of the electric distribution costs included in those income statement rows are not recoverable based on the IEIMA’s formula rate framework. 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.

The provisions of FERC's electric transmission formula rate framework provide for an annual reconciliation of the electric transmission service revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement in customer rates for that year, including an allowed return on equity. Ameren Illinois and ATXI use a company-specific, forward-looking rate formula framework in setting their transmission rates. These rates are updated each January with forecasted information. ~~A reconciliation during the year, which adjusts for the actual~~If a given year's revenue requirement ~~and actual sales volumes,~~ is ~~used~~greater than the revenue requirement reflected in that year's customer rates, an increase to ~~adjust billing~~electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional amounts from customers within two years. If a given year's revenue requirement is less than the revenue requirement reflected in that year's customer rates, in a ~~subsequent year.~~reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within two years.

The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and ~~Ameren Illinois’~~is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information. Recoverable transmission costs are included in the revenue requirement reconciliations, which result in corresponding adjustments to electric ~~distribution service business operate under~~revenues, with no overall effect on net income. These recoverable transmission costs are included in other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes. A portion of the transmission costs included in those income statement rows are not recoverable based on the FERC formula ratemaking, designed to provide for the recovery of actual costs of service that are prudently incurred as well as a return on equity. While rate-regulated, Ameren Illinois’ natural gas business and Ameren Missouri do not operate under formula ratemaking. Ameren (parent) is not rate-regulated.rate framework.

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 ~~purchased power costs,~~ operations and maintenance costs and capital investment are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.

Earnings Summary

The following table presents a summary of Ameren's earnings for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015:~~2016:



	Three Months
	2017		2016
Net income attributable to Ameren common shareholders	$	102	$	105
Earnings per common share – basic and diluted	0.42		0.43

Three Months Nine Months
2016 2015 2016 2015
Net income attributable to Ameren common shareholders $ 369
$ 343
$ 621
$ 601

Earnings per common share – diluted
1.52
1.41
2.56
2.47

Net income attributable to Ameren common shareholders – continuing operations
$ 369
$ 343
$ 621
$ 549

Earnings per common share – diluted – continuing operations
1.52
1.41
2.56
2.26

Net income attributable to Ameren common shareholders ~~from continuing operations increased $26~~decreased $3 million, or 11 cents per diluted share, in the third quarter of 2016 compared with the same period in 2015. The increase between periods was due to a $21 million increase in net income from the Ameren Illinois segment, a $3 million increase in net income from Ameren (parent) and nonregistrant subsidiaries, which included an increase in ATXI’s net income of $8 million, and a $2 million increase in net income from the Ameren Missouri segment.

~~Net income attributable to Ameren common shareholders from continuing operations increased $72 million, or 30 cents~~1 cent per diluted share, in the first nine months of 2016 compared to the same period in 2015. The increase between periods was due to a $41 million increase in net income from the Ameren Illinois segment, a $25 million increase in net income from continuing

operations at Ameren (parent) and nonregistrant subsidiaries, which included an increase in ATXI’s net income of $20 million, and a $6 million increase in net income from the Ameren Missouri segment.

There was no net income attributable to Ameren common shareholders from discontinued operations in both the third quarter and the first nine months of 2016, compared with no net income and $52 million, respectively, in the year-ago periods. During the second quarter of 2015, based on the completion of the IRS audit for 2013, Ameren removed a previously recorded reserve for unrecognized tax benefits of $53 million related to the divestiture of New AER and recognized a tax benefit from discontinued operations.

~~Earnings per share from continuing operations were favorably affected in the third quarter and the first nine months of 2016,~~2017 compared with the year-ago period. The decrease between periods ~~(except where~~was partially due to a ~~specific period is referenced), by:~~

~~the absence~~decrease in net income of $18 million for activity not reported as part of a ~~provision recognized in the second quarter of 2015 as a result of~~segment, primarily at Ameren ~~Missouri’s discontinued efforts to license and build a second nuclear unit~~(parent). Additionally, net income decreased at ~~its existing Callaway energy center site (18 cents per share for the nine months ended September 30, 2016);~~

~~increased~~ Ameren ~~Illinois and ATXI electric transmission service~~Missouri and Ameren Illinois ~~electric distribution service earnings under formula ratemaking due to additional rate base investment (7 cents per share~~Natural Gas by $9 million and 16 cents per share, respectively). Additionally, Ameren Illinois and ATXI electric transmission service third quarter earnings benefited from a temporarily higher allowed base return on common equity, recognizing an allowed base return on common equity of 12.38% from mid-May, as a result of the expiration of the refund period in the February 2015 complaint case, to nearly the end of September. This earnings increase$2 million, respectively. The decrease was ~~partially~~mostly offset by ~~a lower allowed base return on common equity recognized through mid-May 2016~~increases in the nine month period as well as a lower return on equity related to Ameren Illinois electric distribution service investments due to a reduction in the 30-year United States Treasury bond yields (2 cents per sharenet income of $19 million and ~~1 cent per share, respectively);~~

~~increased demand due to warmer summer temperatures in 2016, partially offset by milder winter temperatures (estimated at 11 cents per share and 9 cents per share, respectively);~~

~~higher natural gas distribution rates~~$7 million at Ameren Illinois ~~pursuant to a December 2015 order (3 cents~~Electric Distribution and Ameren Transmission, respectively.

Compared with 2016, 2017 earnings per diluted share ~~and 9 cents per share, respectively);~~were unfavorably affected by:

~~a decrease~~an increase in the effective tax rate primarily due to ana decrease in the income tax benefit recorded at Ameren (parent) ~~pursuant to the adoption of new accounting guidance~~ related to share-based compensation (7 cents per share);

decreased demand primarily at Ameren Missouri due to milder winter temperatures in 2017 (estimated at 3 cents per share); and

increased depreciation and amortization expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri resulting from additional electric property, plant, and equipment, as multiple projects were completed in 2016 (2 cents per share).

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

a change in the ~~nine months ended September 30, 2016)~~method used to recognize Ameren Illinois Electric Distribution’s interim period revenue, in connection with the decoupling provisions of the FEJA as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report (8 cents per share);

increased Ameren Transmission earnings under formula ratemaking, primarily due to additional rate base (2 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 (1 cent per share); and

decreased other operations and maintenance expenses not subject to riders, regulatory tracking mechanisms, or formula ratemaking, primarily at Ameren Missouri ~~(2 cents~~(1 cent per share and 5 cents per share, respectively). 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

~~the recognition of a MEEIA 2013 performance incentive (5 cents per share for both periods).~~

Earnings per share from continuing operations were unfavorably affected in the third quarter and the first nine months of 2016, compared with the year-ago periods (except where a specific period is referenced), by:

~~decreased electric demand at Ameren Missouri resulting from a reduction in sales to the New Madrid Smelter (5 cents per share and 13 cents per share, respectively);~~

~~decreased Ameren Missouri earnings resulting from the absence in 2016 of MEEIA net shared benefits due to the expiration of MEEIA 2013 (5 cents per share and 12 cents per share, respectively);~~

the cost of the Callaway energy center's scheduled refueling and maintenance outage in the second quarter of 2016. There was no Callaway refueling and maintenance outage in 2015 (8 cents per share for the nine months ended September 30, 2016);

decreased Ameren Illinois 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 for the nine months ended September 30, 2016);

~~decreased Ameren Missouri electric margins resulting from increased transmission charges, net of transmission revenues (3 cents per share for the nine months ended September 30, 2016);~~

increased depreciation and amortization expenses not subject to riders, regulatory tracking mechanisms, or formula ratemaking, primarily because of electric system capital additions at Ameren Missouri (2 cents per share and 3 cents per share, respectively); and

decreased Ameren Illinois natural gas distribution earnings due to seasonal rate redesign, which is not expected to materially affect earnings comparisons on an annual basis (2 cents per share for the three months ended September 30, 2016)share).

The cents per share information presented ~~in the explanations above~~ is based on the average diluted shares outstanding in the ~~third~~first quarter ~~and first nine months~~ of ~~2015.~~2016. Pretax amounts have been presented net of income taxes, using Ameren’s 2016 statutory tax rate of 39%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, ~~Provision for Callaway Construction and Operating License,~~ Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, and Income Taxes, see the major headings below.

Below is aAmeren’s table of income statement components by segment for the three months ended March 31, 2017 and 2016:



	Ameren Missouri			Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Transmission			Other / Intersegment Eliminations			Total
Three Months 2017:
Electric margins	$	449		$	278		$	—		$	102		$	(9	)	$	820
Natural gas margins	24			—			154			—			—			178
Other operations and maintenance	(212		)	(131		)	(53		)	(16		)	7			(405		)
Depreciation and amortization	(133		)	(59		)	(14		)	(14		)	(1		)	(221		)
Taxes other than income taxes	(75		)	(18		)	(21		)	(1		)	(3		)	(118		)
Other income (expense)	10			(1		)	(2		)	—			(1		)	6
Interest charges	(54		)	(18		)	(10		)	(15		)	(2		)	(99		)
Income taxes	(3		)	(20		)	(21		)	(22		)	9			(57		)
Net income	6			31			33			34			—			104
Noncontrolling interests – preferred stock dividends	(1		)	(1		)	—			—			—			(2		)
Net income attributable to Ameren common shareholders	$	5		$	30		$	33		$	34		$	—		$	102
Three Months 2016:
Electric margins	$	449		$	237		$	—		$	83		$	(8	)	$	761
Natural gas margins	26			—			154			—			—			180
Other operations and maintenance	(212		)	(130		)	(52		)	(15		)	9			(400		)
Depreciation and amortization	(127		)	(54		)	(14		)	(10		)	(2		)	(207		)
Taxes other than income taxes	(73		)	(16		)	(21		)	(1		)	(3		)	(114		)
Other income (expense)	13			—			(1		)	1			—			13
Interest charges	(52		)	(18		)	(9		)	(13		)	(3		)	(95		)
Income taxes	(9		)	(7		)	(22		)	(18		)	25			(31		)
Net income	15			12			35			27			18			107
Noncontrolling interests – preferred stock dividends	(1		)	(1		)	—			—			—			(2		)
Net income attributable to Ameren common shareholders	$	14		$	11		$	35		$	27		$	18		$	105

Below is Ameren Illinois' table of income statement components by segment for the three ~~and~~ ~~nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015:~~

Ameren
Missouri

Ameren
Illinois

Other /
Intersegment
Eliminations
Ameren
Three Months 2016:
Electric margins $ 862
$ 452
$ 28
$ 1,342
Natural gas margins 14
86
—
100
Other revenues 1
—
(1 ) —
Other operations and maintenance (220 ) (198 ) 7
(411 )
Depreciation and amortization (130 ) (80 ) (1 ) (211 )
Taxes other than income taxes (96 ) (30 ) (3 ) (129 )
Other income (expense) 12
1
(3 ) 10
Interest charges (53 ) (35 ) (9 ) (97 )
Income taxes (148 ) (77 ) (8 ) (233 )
Income from continuing operations 242
119
10
371
Income from discontinued operations, net of tax —
—
—
—
Net income 242
119
10
371
Noncontrolling interests – preferred dividends
(1 ) —
(1 ) (2 )
Net income attributable to Ameren common shareholders $ 241
$ 119
$ 9
$ 369
Three Months 2015:
Electric margins $ 863
$ 412
$ 13
$ 1,288
Natural gas margins 14
82
(1 ) 95
Other revenues 1
—
(1 ) —
Other operations and maintenance (233 ) (202 ) 7
(428 )
Depreciation and amortization (125 ) (74 ) (2 ) (201 )
Taxes other than income taxes (97 ) (29 ) (2 ) (128 )
Other income 11
1
2
14
Interest charges (54 ) (33 ) —
(87 )
Income taxes (140 ) (59 ) (9 ) (208 )
Income from continuing operations 240
98
7
345
Income from discontinued operations, net of tax —
—
—
—
Net income 240
98
7
345
Noncontrolling interests – preferred dividends
(1 ) —
(1 ) (2 )
Net income attributable to Ameren common shareholders $ 239
$ 98
$ 6
$ 343

2016:

Ameren
Missouri

Ameren
Illinois

Other /
Intersegment
Eliminations
Ameren
Nine Months 2016:
Electric margins $ 1,939
$ 1,061
$ 76
$ 3,076
Natural gas margins 57
336
(1 ) 392
Other revenues 1
—
(1 ) —
Other operations and maintenance (670 ) (592 ) 16
(1,246 )
Depreciation and amortization (384 ) (237 ) (7 ) (628 )
Taxes other than income taxes (252 ) (98 ) (8 ) (358 )
Other income (expense) 32
4
(3 ) 33
Interest charges (158 ) (105 ) (24 ) (287 )
Income (taxes) benefit (215 ) (144 ) 3
(356 )
Income from continuing operations 350
225
51
626
Income from discontinued operations, net of tax —
—
—
—
Net income 350
225
51
626
Noncontrolling interests – preferred dividends
(3 ) (2 ) —
(5 )
Net income attributable to Ameren common shareholders $ 347
$ 223
$ 51
$ 621
Nine Months 2015:
Electric margins $ 1,995
$ 999
$ 36
$ 3,030
Natural gas margins 58
320
(1 ) 377
Other revenues 2
—
(2 ) —
Other operations and maintenance (673 ) (606 ) 23
(1,256 )
Provision for Callaway construction and operating license (69 ) —
—
(69 )
Depreciation and amortization (367 ) (220 ) (7 ) (594 )
Taxes other than income taxes (262 ) (101 ) (6 ) (369 )
Other income (expense) 29
5
(2 ) 32
Interest charges (164 ) (99 ) (1 ) (264 )
Income taxes (205 ) (114 ) (14 ) (333 )
Income from continuing operations 344
184
26
554
Income from discontinued operations, net of tax —
—
52
52
Net income 344
184
78
606
Noncontrolling interests – preferred dividends
(3 ) (2 ) —
(5 )
Net income attributable to Ameren common shareholders $ 341
$ 182
$ 78
$ 601



	Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas			Ameren Illinois Transmission			Total
Three Months 2017:
Electric and natural gas margins	$	278		$	154		$	60		$	492
Other operations and maintenance	(131		)	(53		)	(13		)	(197		)
Depreciation and amortization	(59		)	(14		)	(10		)	(83		)
Taxes other than income taxes	(18		)	(21		)	(1		)	(40		)
Other income (expense)	(1		)	(2		)	—			(3		)
Interest charges	(18		)	(10		)	(9		)	(37		)
Income taxes	(20		)	(21		)	(11		)	(52		)
Net income	31			33			16			80
Preferred stock dividends	(1		)	—			—			(1		)
Net income attributable to common shareholder	$	30		$	33		$	16		$	79
Three Months 2016:
Electric and natural gas margins	$	237		$	154		$	51		$	442
Other operations and maintenance	(130		)	(52		)	(12		)	(194		)
Depreciation and amortization	(54		)	(14		)	(9		)	(77		)
Taxes other than income taxes	(16		)	(21		)	(1		)	(38		)
Other income (expense)	—			(1		)	1			—
Interest charges	(18		)	(9		)	(8		)	(35		)
Income taxes	(7		)	(22		)	(9		)	(38		)
Net income	12			35			13			60
Preferred stock dividends	(1		)	—			—			(1		)
Net income attributable to common shareholder	$	11		$	35		$	13		$	59

Electric and Natural Gas Margins

The following table presents the favorable (unfavorable) variations by Ameren segment for electric and natural gas margins infor the ~~three and nine months ended September 30, 2016,~~first quarter of 2017, compared with the year-ago ~~periods.~~period. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as natural gas revenues less natural gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other ~~companies'~~companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months
Ameren
Missouri

Ameren
Illinois

Other^(a)
Ameren
Electric revenue change:
Effect of weather (estimate)^(b)
$ 41
$ 14
$ —
$ 55
Base rates (estimate) —
8
—
8
Sales volume (excluding the New Madrid Smelter and the estimated effect of weather) —
6
—
6
New Madrid Smelter revenues (42 ) —
—
(42 )
Off-system sales 50
—
—
50
MEEIA 2013 net shared benefits (19 ) —
—
(19 )
MEEIA 2013 performance incentive 19
—
—
19
Transmission services revenues 1
18
16
35
Other (11 ) (8 ) (6 ) (25 )
Cost recovery mechanisms – offset in fuel and purchased power:^(c)

Power supply costs —
(25 ) —
(25 )
Transmission services recovery mechanism —
3
—
3
Recovery of FAC under-recovery (39 ) —
—
(39 )
Other cost recovery mechanisms:^(d)

Bad debt, energy efficiency programs, and environmental remediation cost riders —
6
—
6
MEEIA 2013 and 2016 program costs (7 ) —
—
(7 )
Total electric revenue change $ (7 ) $ 22
$ 10
$ 25
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather) $ (48 ) $ —
$ —
$ (48 )
New Madrid Smelter energy costs 22
—
—
22
Effect of weather (estimate)^(b)
(7 ) (6 ) —
(13 )
Transmission services charges (3 ) —
—
(3 )
Other 3
2
5
10
Cost recovery mechanisms – offsets in electric revenue:^(c)

Power supply costs —
25
—
25
Transmission services recovery mechanism —
(3 ) —
(3 )
Recovery of FAC under-recovery 39
—
—
39
Total fuel and purchased power change $ 6
$ 18
$ 5
$ 29
Net change in electric margins $ (1 ) $ 40
$ 15
$ 54
Natural gas revenue change:
Effect of weather (estimate)^(b)
$ —
$ 1
$ —
$ 1
Base rates (estimate) —
9
—
9
Seasonal rate redesign —
(6 ) —
(6 )
Other —
(1 ) 1
—
Cost recovery mechanism – offset in gas purchased for resale:^(c)

Purchased gas costs 1
(6 ) —
(5 )
Other cost recovery mechanisms:^(d)

Bad debt, energy efficiency programs, and environmental remediation cost riders —
2
—
2
Total natural gas revenue change $ 1
$ (1 ) $ 1
$ 1
Gas purchased for resale change:
Effect of weather (estimate)^(b)
$ —
$ (1 ) $ —
$ (1 )
Cost recovery mechanism – offset in natural gas revenue:^(c)

Purchased gas costs (1 ) 6
—
5
Total gas purchased for resale change $ (1 ) $ 5
$ —
$ 4
Net change in natural gas margins $ —
$ 4
$ 1
$ 5


Nine Months	Ameren Missouri			Ameren Illinois			Other^(a)			Ameren
													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)	$	33		$	9		$	—		$	42		$	(20	)	$	6		$	—		$	—	$	—		$	(14	)
Base rates (estimate)(c)	48			30			—			78			—			6			—			19		—			25
Sales volume (excluding the New Madrid Smelter and the estimated effect of weather)	3			(1		)	—			2
FEJA impact on IEIMA													—			32			—			—		—			32
Sales volume (excluding the New Madrid Smelter and estimated effect of weather)													(2		)	—			—			—		—			(2		)
New Madrid Smelter revenues	(101		)	—			—			(101		)	(8		)	—			—			—		—			(8		)
Off-system sales	85			—			—			85			79			—			—			—		—			79
MEEIA 2013 net shared benefits	(45		)	—			—			(45		)
MEEIA 2013 performance incentive	19			—			—			19
Transmission services revenues	1			42			40			83
Purchased power rider order in 2015	—			(15		)	—			(15		)
Other	(1		)	(4		)	(11		)	(16		)	5			(4		)	—			—		—			1
Cost recovery mechanisms – offset in fuel and purchased power:^(c)
Cost recovery mechanisms – offset in fuel and purchased power:^(d)
Power supply costs	—			(15		)	—			(15		)	—			(6		)	—			—		—			(6		)
Transmission services recovery mechanism				3			—			3			—			(3		)	—			—		—			(3		)
Recovery of FAC under-recovery	(88		)	—			—			(88		)	(11		)	—			—			—		—			(11		)
Other cost recovery mechanisms:^(d)	—
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and environmental remediation cost riders													—			2			—			—		—			2
Gross receipts tax	(4		)	—			—			(4		)	1			—			—			—		—			1
MEEIA 2013 and 2016 program costs	(20		)	—			—			(20		)
MEEIA program costs													8			—			—			—		—			8
Total electric revenue change	$	(70	)	$	49		$	29		$	8		$	52		$	33		$	—		$	19	$	—		$	104
Fuel and purchased power change:
Energy costs (excluding the New Madrid Smelter and estimated effect of weather)	$	(77	)	$	—		$	—		$	(77	)	$	(79	)	$	—		$	—		$	—	$	—		$	(79	)
New Madrid Smelter energy costs	50			—			—			50			8			—			—			—		—			8
Effect of weather (estimate)^(b)	(2		)	(2		)	—			(4		)	6			(3		)	—			—		—			3
Effect of higher net energy costs included in base rates	(34		)	—			—			(34		)
Transmission services charges	(14		)	—			—			(14		)
Other	3			3			11			17			2			2			—			—		(1		)	3
Cost recovery mechanisms – offsets in electric revenue:^(c)
Cost recovery mechanisms – offset in electric revenue:^(d)
Power supply costs	—			15			—			15			—			6			—			—		—			6
Transmission services recovery mechanism	—			(3		)	—			(3		)	—			3			—			—		—			3
Recovery of FAC under-recovery	88			—			—			88			11			—			—			—		—			11
Total fuel and purchased power change	$	14		$	13		$	11		$	38		$	(52	)	$	8		$	—		$	—	$	(1	)	$	(45	)
Net change in electric margins	$	(56	)	$	62		$	40		$	46		$	—		$	41		$	—		$	19	$	(1	)	$	59
Natural gas revenue change:
Effect of weather (estimate)^(b)	$	(8	)	$	(25	)	$	—		$	(33	)	$	(5	)	$	—		$	—		$	—	$	—		$	(5	)
Base rates (estimate)	—			34			—			34
Other	1			(2		)	—			(1		)	(1		)	—			—			—		—			(1		)
Cost recovery mechanism – offset in gas purchased for resale:^(c)
Purchased gas costs	(3		)	(61		)	—			(64		)
Other cost recovery mechanisms:^(d)
Purchased natural gas costs – offset in natural gas purchased for resale:^(d)													3			—			(21		)	—		—			(18		)
Other cost recovery mechanisms:^(e)
Bad debt, energy efficiency programs, and environmental remediation cost riders	—			(11		)	—			(11		)	—			—			1			—		—			1
Gross receipts tax	(1		)	(2		)	—			(3		)	—			—			(1		)	—		—			(1		)
Total natural gas revenue change	$	(11	)	$	(67	)	$	—		$	(78	)	$	(3	)	$	—		$	(21	)	$	—	$	—		$	(24	)
Gas purchased for resale change:
Natural gas purchased for resale change:
Effect of weather (estimate)^(b)	$	7		$	22		$	—		$	29		$	4		$	—		$	—		$	—	$	—		$	4
Cost recovery mechanism – offset in natural gas revenue:^(c)
Purchased gas costs	3			61			—			64
Total gas purchased for resale change	$	10		$	83		$	—		$	93
Purchased natural gas costs – offset in natural gas revenue:^(d)													(3		)	—			21			—		—			18
Total natural gas purchased for resale change													$	1		$	—		$	21		$	—	$	—		$	22
Net change in natural gas margins	$	(1	)	$	16		$	—		$	15		$	(2	)	$	—		$	—		$	—	$	—		$	(2	)

Ameren ~~Corporation~~

Ameren's electric margins increased ~~$54~~$59 million, or 4%8%, ~~and $46 million, or 2%, for~~in the three and nine months ended September 30, 2016, respectively, compared with the year-ago periods. Ameren's natural gas margins increased $5 million, or 5%, and $15 million, or 4%, for the three and nine months ended September 30, 2016, respectively, compared with the year-ago periods. Ameren’s results were primarily driven by Ameren Missouri’s, Ameren Illinois’, and ATXI’s resultsfirst quarter of operations, as discussed below. ATXI’s transmission services revenues increased $16 million and $40 million for the three and nine months ended September 30, 2016, respectively, compared with the year-ago periods, because of higher rate base investment and recoverable costs under formula ratemaking. ATXI’s results for the three months ended September 30, 2016, also benefited from a temporarily higher allowed return on common equity,2017, compared with the year-ago period, ~~reflecting the May expiration~~primarily because of ~~the 15-month refund period for the February 2015 complaint case. See Note 2~~ – ~~Rate~~increased margins at Ameren Illinois Electric Distribution and ~~Regulatory Matters under Part 1, Item 1, of this report for information regarding the allowed return on common equity for FERC-regulated transmission rate base.~~Ameren Transmission. Ameren's natural gas margins were comparable between periods.

Ameren ~~Missouri~~Transmission

Ameren ~~Missouri has a FAC cost recovery mechanism that allows it to recover~~Transmission's margins increased $19 million, or refund, through customer rates, 95% of changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews, with the remaining 5% of changes absorbed by Ameren Missouri.

~~Net energy costs, as defined~~23%, in the ~~FAC, include fuel and purchased power costs, including transportation, net~~first quarter of off-system sales. As of May 30, 2015, transmission revenues and substantially all transmission charges are excluded from net energy costs as a result of the April 2015 MoPSC electric rate order, which unfavorably affected margins as discussed below. Ameren Missouri accrues as a regulatory asset net energy costs that exceed the amount set in base rates (FAC under-recovery). Net recovery of these costs through customer rates does not affect Ameren Missouri’s electric margins, as any change in revenue is offset by a corresponding change in fuel expense to reduce the previously recognized FAC regulatory asset.

Ameren Missouri's electric margins for the three months ended September 30, 2016 were comparable with the year-ago period, and decreased $56 million, or 3%, for the nine months ended September 30, 2016,2017 compared with the year-ago period. The ~~following items had an unfavorable effect on Ameren Missouri's electric~~increase in margins ~~for the three and nine months ended September 30, 2016, compared with the year-ago periods:~~

~~The New Madrid Smelter operations were suspended~~was primarily due to capital investment, which increased rate base by 18%, as well as higher recoverable costs in the first quarter of ~~2016, which decreased margins by $20 million and $51 million, respectively. The change in margins due to lower New Madrid Smelter sales is~~2017, compared with the ~~sum of New Madrid Smelter revenues (-$42 million and -$101 million, respectively) and New Madrid Smelter energy costs (+$22 million and +$50 million, respectively) in the above table.~~

year-ago period, under forward-looking formula ratemaking.

~~New Madrid Smelter energy costs include the impact of a provision in the FAC tariff that, under certain circumstances, allows~~ Ameren Missouri to retain a portion of the revenues from any off-system sales it makes as a result of reduced sales to the New Madrid Smelter. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the New Madrid Smelter.

The absence in 2016 of net shared benefits due to the expiration of MEEIA 2013, which decreased margins by $19 million and $45 million, respectively. Net shared benefits compensated Ameren Missouri for lower sales volumes from energy-efficiency related volume reductions in current and future periods.

Increased transmission services charges resulting from additional MISO-approved electric transmission investments made by other entities, which decreased margins by $3 million and $14 million, respectively.

~~The following items had a favorable effect on~~ Ameren Missouri's electric margins ~~for the three and nine months ended September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):~~

~~Summer temperatures for the third quarter of 2016~~ were warmer as cooling degree-days increased 11%, compared with the year-ago period. Temperatures in the first nine months of 2016 were warmer as cooling degree-days increased 12%, while heating degree-days decreased 17%, compared with the year-ago period. The net effect of weather increased margins by an estimated $34 million and $31 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$41 million and +$33 million, respectively) and the effect of weather (estimate) on fuel and purchased power (-$7 million and -$2 million, respectively) in the above table.

~~The MEEIA 2013 performance incentive increased margins by $19 million for both~~comparable between periods. ~~See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the MEEIA 2013 performance incentive.~~

Higher electric base rates, effective May 30, 2015, as a result of the April 2015 MoPSC electric rate order, increased margins by an estimated $14 million for the nine months ended September 30, 2016. The change in electric base rates is the sum of the change in base rates (estimate) (+$48 million) and the effect of higher net energy costs included in base rates (-$34 million) in the above table.

Lower net energy costs as a result of the 5% of changes absorbed by Ameren Missouri through the FAC, primarily due to higher MISO capacity revenues, which increased margins by $2 million and $8 million, respectively. The change in net energy costs is the sum of the change in off-system sales (+$50 million and +$85 million, respectively) and the change in energy costs (-$48 million and -$77 million, respectively) in the above table.

~~Excluding the effect of reduced sales to the New Madrid Smelter and the estimated effect of weather, total~~Decreased retail sales volumes, ~~increased by less than 1% for the nine months~~

~~ended September 30, 2016, which increased revenues by $3 million,~~largely due to ~~an additional day as a result of the leap year and growth partially~~milder winter temperatures, were offset by ~~the carryover effect of~~increased MEEIA ~~2013 on sales volumes.~~

program cost revenues and other revenues. Ameren Missouri’s natural gas margins were comparable between periods.

Ameren Missouri 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 they are offset by a corresponding amount in revenues.

~~Ameren~~ Illinois

The provisions of the IEIMA’s and the FERC’s electric transmission formula rate frameworks provide for annual reconciliations of the electric distribution and electric transmission service revenue requirements necessary to reflect the actual costs incurred in a given year with the revenue requirements in customer rates for that year, including an allowed return on equity. See Operations and Maintenance Expenses in this section for additional information regarding the components of the revenue requirements. In each of those electric jurisdictions, if the current year's revenue requirement is greater than the revenue requirement reflected in that year’s customer rates, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. In each jurisdiction, if the current year's revenue requirement is less than the revenue requirement reflected in that year’s customer rates, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. The increases or reductions to electric operating revenues are shown in base rates (estimate) and transmission services revenues, in the above table, for the electric distribution and electric transmission service revenues, respectively. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.

Ameren Illinois has a cost recovery mechanism for power purchased, and transmission services incurred, on behalf of its electric customers. These pass-through costs do not affect Ameren Illinois’ electric margins, as they are offset by a corresponding amount in revenues.

Ameren Illinois' electric margins increased ~~$40~~by $50 million, or ~~10%~~17%, ~~and $62 million, or 6%, for~~in the ~~three and nine months ended September 30, 2016, respectively,~~first quarter of 2017 compared with the year-ago period, driven by increases in Ameren Illinois Electric Distribution ($41 million) and Ameren Illinois Transmission ($9 million) margins. Ameren Illinois Natural Gas’ margins were comparable between periods.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $41 million, or 17%, in the first quarter of 2017, compared with the year-ago period. The following items had a favorable effect on Ameren ~~Illinois’ electric~~Illinois Electric Distribution’s margins ~~for~~in the ~~three and nine months ended September 30, 2016,~~first quarter of 2017, compared with the year-ago ~~periods (except where a specific~~period:

A change in the method used to recognize interim period ~~is referenced):~~

~~Transmission services revenues increased by $18 million and $42 million, respectively, primarily due to increased rate base investment and higher recoverable costs under formula~~

~~ratemaking. Transmission services for the three months ended September 30, 2016, also benefited from a temporarily higher allowed return on common equity, compared~~revenue, in connection with the ~~year-ago period reflecting the May expiration~~decoupling provisions of the ~~15-month refund period for the February 2015 complaint case. See Note 2~~ – ~~Rate and Regulatory Matters under Part 1, Item 1, of this report for information regarding the allowed return on common equity for FERC-regulated transmission rate base.~~

Electric distribution service revenues increased by an estimated $8 million and $30 million, respectively, primarily due to increased rate base investment and higher recoverable costs under formula ratemaking pursuant to the IEIMA, partially offset by a lower return on equity due to a reduction in the 30-year United States Treasury bond yields.

Summer temperatures for the third quarter of 2016 were warmer as cooling degree-days increased 13%, compared with the year-ago period. Temperatures in the first nine months of 2016 were warmer as cooling degree-days increased 10%, while heating degree-days decreased 15%, compared with the year-ago period. The net effect of weather increased margins by an estimated $8 million and $7 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (+$14 million and +$9 million, respectively) and the effect of weather (estimate) on fuel and purchased power (-$6 million and -$2 million, respectively) in the above table.

~~Excluding the estimated effect of weather, total retail sales volumes increased by 3% for the three months ended September 30, 2016, primarily due to the commercial sector,~~FEJA, which increased margins by ~~an estimated $6~~$32 million.

Ameren Illinois’ electric 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 the first nine months of 2015.

Ameren Illinois' natural gas margins increased $4 million, or 5%, and $16 million, or 5%, for the three and nine months ended September 30, 2016, respectively, compared with the year-ago periods. Ameren Illinois’ natural gas margins were favorably affected by higher natural gas base rates in 2016, which increased margins by an estimated $9 million and $34 million, respectively.

The following items had an unfavorable effect on Ameren Illinois’ natural gas margins for the three and nine months ended September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

The absence of colder-than-normal winter temperatures and the application of the VBA in the first nine months of 2016, which decreased margins by $3 million compared with the year-ago period. The VBA, which was approved by the ICC in December 2015, eliminated the This change will not impact ~~of weather on natural gas margins for residential and small nonresidential customers in the first nine months of 2016. The change in~~

margins due to weather is the sum of the effect of weather (estimate) on natural gas revenues (-$25 million) and the effect of weather (estimate) on gas purchased for resale (+$22 million) in the above table.

The implementation of redesigned seasonal rates in 2016, which decreased margins by $6 million for the third quarter of 2016, compared with the year-ago period. These redesigned rates have an effect on quarterly earnings comparisons but are not expected to materially affect annual earnings.

Ameren Illinois has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased gas costs do not affect Ameren Illinois’ natural gas margins, as they are offset by a corresponding amount in revenues.

~~Other Operations and Maintenance Expenses~~

~~Ameren Corporation~~

~~Other operations and maintenance expenses decreased $17 million and $10 million in the~~ ~~third quarter~~ ~~and the first nine months of 2016, respectively, as compared with the year-ago periods, primarily because of decreased expenses at Ameren Missouri and Ameren Illinois.~~

~~Ameren Missouri~~

Other operations and maintenance expenses were $13 million and $3 million lower in the third quarter and the first nine months of 2016, respectively, compared with the year-ago periods. The following items decreased other operations and maintenance expenses for the three and nine months ended September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

MEEIA customer energy efficiency program costs decreased by $7 million and $20 million, respectively, due to the expiration of MEEIA 2013, partially offset by costs incurred for MEEIA 2016. Electric revenues decreased by a corresponding amount, with no overall effect on net income.

Energy center maintenance costs, excluding refueling and maintenance outage costs at the Callaway energy center, decreased by $6 million and $18 million, respectively, primarily due to fewer major outages, partially offset by higher coal handling charges.

~~Electric distribution maintenance expenditures decreased by $7 million and $12 million, respectively, primarily related to reduced system repair and vegetation management work.~~

Employee benefit costs decreased by $7 million in the nine months ended September 30, 2016, primarily due to a change in pension and postretirement expenses allowed in rates, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers decreased electric revenues by a corresponding amount, with no overall effect on net income.

~~An unrealized MTM gain in 2016 compared with an unrealized MTM loss in 2015, resulting from changes in the~~

~~market value of company-owned life insurance investments, decreased expense by $6 million in both periods.~~

The following items increased other operations and maintenance expenses for the three and nine months ended September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Refueling and maintenance outage costs at the Callaway energy center increased by $31 million in the nine months ended September 30, 2016, due to costs for the scheduled refueling and maintenance outage that occurred in the second quarter of 2016. There was no scheduled outage in 2015.

Amortization of previously deferred solar rebate costs increased by $10 million in the nine months ended September 30, 2016, as a result of the April 2015 MoPSC electric rate order. Electric base rates billed to customers increased electric revenues by a corresponding amount, with no overall effect on net income.

~~Litigation costs increased by $8 million and $10 million, respectively, primarily related to increases in estimated obligations for pending legal claims.~~

~~Storm-related repair costs increased by $4 million and $7 million, respectively.~~

~~Ameren Illinois~~

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

Other operations and maintenance expenses were $4 million and $14 million lower in the third quarter and the first nine months of 2016, respectively, compared with the year-ago periods. The following items decreased other operations and maintenance expenses for the three and nine months ended September 30, 2016, compared with the year-ago periods (except where a specific period is referenced):

Employee benefit costs decreased by $5 million and $12 million, respectively, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets.

Bad debt, customer energy efficiency, and environmental remediation costs decreased by $11 million in the nine months ended September 30, 2016. These expenses are included in cost riders that result in lower electric and natural gas revenues, with no overall effect on net income.

Electric distribution and transmission maintenance expenditures decreased by $7 million and $5 million, respectively, primarily related to the timing of system repair work and reduced circuit maintenance work.

An unrealized MTM gain in 2016 compared with an unrealized MTM loss in 2015, resulting from changes in the market value of company-owned life insurance investments, decreased expense by $4 million in both periods.

Labor costs, other than those incorporated into other explanations presented, increased by $3 million and $7 million, respectively, primarily because of staff additions to meet enhanced standards and goals related to the IEIMA.

~~Storm-related repair costs increased by $4 million in the nine months ended September 30, 2016.~~

~~Litigation costs increased by $2 million in the nine months ended September 30, 2016.~~

Bad debt, customer energy efficiency, and environmental remediation costs increased by $8 million in the third quarter of 2016. These expenses are included in cost riders that result in higher electric and natural gas revenues, with no overall effect on net income.

~~Provision for Callaway Construction and Operating License~~

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

~~Depreciation and Amortization~~

~~Ameren Corporation~~

Depreciation and amortization expenses increased $10 million and $34 million in the third quarter and the first nine months of 2016, respectively, compared with the year-ago periods, because of increased expenses at Ameren Missouri and Ameren Illinois, as discussed below.

~~Ameren Missouri~~

Depreciation and amortization expenses increased $5 million in the third quarter of 2016, primarily because of electric system capital additions. Depreciation and amortization expenses increased $17 million in the first nine months of 2016, primarily because of increased depreciation rates resulting from the April 2015 MoPSC electric rate order and electric system capital additions.

~~Ameren Illinois~~

Depreciation and amortization expenses increased $6 million and $17 million in the third quarter and the first nine months of 2016, respectively, primarily because of electric system capital additions.

~~Taxes Other Than Income Taxes~~

~~Ameren Corporation~~

~~Taxes other than income taxes were comparable in the third quarter of 2016 with the year-ago period. Taxes other than income taxes decreased $11 million in the first nine months of 2016~~, compared with the year-ago period, primarily because of decreased expenses at Ameren Missouri and Ameren Illinois, as discussed below. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information.

~~Ameren Missouri~~

Taxes other than income taxes were comparable in the third quarter of 2016 with the year-ago period. Taxes other than income taxes decreased $10 million in the first nine months of 2016, primarily because of decreased gross receipts taxes resulting from lower electric sales and natural gas volumes and decreased property taxes resulting from lower assessed property values. Electric revenues for gross receipts taxes decreased by an amount corresponding to the reduction in gross receipts taxes, with no overall effect on net income.

~~Ameren Illinois~~

Taxes other than income taxes were comparable in the third quarter of 2016 with the year-ago period. Taxes other than income taxes decreased $3 million in the first nine months of 2016, primarily because of decreased gross receipts taxes, resulting from lower natural gas sales volumes and prices, and because of a decrease in property taxes between periods. Natural gas revenues for gross receipts taxes decreased by an amount corresponding to the reduction in gross receipts taxes, with no overall effect on net income.

~~Other Income and Expenses~~

~~Details of other income and expenses for the Ameren Companies are provided in Note 5 – Other Income and Expenses under Part I, Item 1, of this report.~~

~~Interest Charges~~

~~Ameren Corporation~~

Interest charges increased $10 million and $23 million in the third quarter and the first nine months of 2016, respectively, compared with the year-ago periods, due to an approximately $500 million increase in average outstanding debt and an increase in the cost of debt at Ameren (parent). Ameren (parent) issued senior unsecured notes in November 2015 to repay lower-cost short-term debt. A decrease in interest charges in the first nine months of 2016 at Ameren Missouri was partially offset by an increase in interest charges in both periods at Ameren Illinois,

~~as discussed below.~~

~~Ameren Missouri~~

Interest charges were comparable in the third quarter of 2016 with the year-ago period. Interest charges decreased $6 million in the first nine months of 2016, primarily because of a decrease in average outstanding debt.

~~Ameren Illinois~~

Interest charges were comparable in the third quarter of 2016 with the year-ago period. Interest charges increased $6 million in the first nine months of 2016, primarily because of an increase in average outstanding debt and interest on refunds for the November 2013 and February 2015 complaint cases. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information ~~about~~on FEJA and IEIMA.

Revenues increased by $6 million, primarily due to increased rate base and a higher 30-year United States Treasury bond yield under formula ratemaking.

The absence of the ~~complaint cases.~~impact of warmer-than-normal 2016 weather and the decoupling of revenues in 2017, which increased margins by $3 million compared with the year-ago period. The change in margins due to weather is the sum of

the effect of weather (estimate) on electric revenues (+$6 million) and the effect of weather (estimate) on fuel and purchased power (-$3 million) in the Electric and Natural Gas Margins table above.

Ameren Illinois Transmission

Ameren Illinois Transmission's margins increased $9 million, or 18%, in the first quarter of 2017 compared with the year-ago period. The increase in margins was primarily due to capital investment, which increased rate base by 22%, as well as higher recoverable costs in the first quarter of 2017, compared with the year-ago period, under forward-looking formula ratemaking.

Other Operations and Maintenance Expenses

Ameren

Other operations and maintenance expenses were $5 million higher in the first quarter of 2017, compared with the year-ago period, as discussed below.

Ameren Transmission

Other operations and maintenance expenses were comparable in the first quarter of 2017 with the year-ago period.

Ameren Missouri

Other operations and maintenance expenses were comparable in the first quarter of 2017 with the year-ago period. Increased MEEIA customer energy efficiency program costs were offset by decreased refueling and maintenance outage costs at the Callaway energy center and increased MTM gains resulting from changes in the market value of company-owned life insurance. Electric revenues related to MEEIA program costs increased by a corresponding amount, with no overall effect on net income.

Ameren Illinois

Other operations and maintenance expenses were $3 million higher in the first quarter of 2017, compared with the year-ago period, primarily because of higher estimated litigation costs at Ameren Illinois Electric Distribution and higher pension costs at each Ameren Illinois segment, caused by changes in actuarial assumptions and the performance of plan assets. Other operations and maintenance expenses were comparable between periods at each Ameren Illinois segment.

Depreciation and Amortization

Ameren

Depreciation and amortization expenses increased $14

million in the first quarter of 2017, compared with the year-ago period, as discussed below.

Ameren Transmission

Depreciation and amortization expenses increased $4 million, primarily because of additional ATXI property, plant, and equipment.

Ameren Missouri

Depreciation and amortization expenses increased $6 million, primarily because of additional electric property, plant, and equipment, as multiple projects were completed in 2016.

Ameren Illinois

Depreciation and amortization expenses increased $6 million, primarily because of increased expenses at Ameren Illinois Electric Distribution, as discussed below. Depreciation and amortization expenses were comparable between periods at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Depreciation and amortization expenses increased $5 million, primarily because of additional property, plant, and equipment.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $4 million at Ameren in the first quarter of 2017, compared with the year-ago period, primarily because of higher property taxes at Ameren Missouri and Ameren Illinois Electric Distribution. Taxes other than income taxes were comparable between periods at Ameren Illinois, as well as the Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Illinois Transmission segments.

Other Income and Expenses

Ameren

Other income, net of expenses, decreased $7 million in the first quarter of 2017, compared with the year-ago period, as discussed below. See Note 5 – Other Income and Expenses under Part I, Item 1, of this report for additional information.

Ameren Transmission

Other income, net of expenses, was comparable between periods.

Ameren Missouri

Other income, net of expenses, decreased $3 million, primarily because of a decrease in the allowance for equity funds used during construction, as multiple electric projects were completed in 2016.

Ameren Illinois

Other income, net of expenses, decreased $3 million, primarily because of lower interest income on IEIMA revenue requirement reconciliation regulatory assets and a decrease in the allowance for equity funds used during construction, resulting from lower eligible construction work in progress balances. Other income, net of expenses, was comparable between periods at each Ameren Illinois segment.

Interest Charges

Interest charges increased $4 million at Ameren in the first quarter of 2017, compared with the year-ago period, primarily because of a decrease in the allowance for borrowed funds used during construction at Ameren Missouri and Ameren Transmission, resulting from lower eligible construction work in progress balances. Interest charges were comparable between periods at Ameren Illinois and each of its segments.

Income Taxes

The following table presents effective income tax rates for the three ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2017 and ~~2015:~~2016:


	Three Months^(a)				Nine Months^(a)				Three Months^(a)
	2016		2015		2016		2015		2017		2016
Ameren	39	%	38	%	36	%	38	%	35	%	22	%
Ameren Transmission									39	%	40	%
Ameren Missouri	38	%	37	%	38	%	37	%	38	%	38	%
Ameren Illinois	39	%	38	%	39	%	38	%	39	%	39	%
Ameren Illinois Electric Distribution									40	%	38	%
Ameren Illinois Natural Gas									39	%	39	%
Ameren Illinois Transmission									39	%	38	%


(a)	~~Based on the current estimate~~Estimate of the annual effective tax rate adjusted to reflect the tax effect of items discrete to the ~~relevant period.~~first quarter.

Ameren ~~Corporation~~

The effective tax rate was higher in the first quarter of 2017, compared with the year-ago period, primarily because of a decrease in the recognition of tax benefits associated with share-based compensation.

Ameren Transmission

The effective tax rate was comparable ~~in the third quarter of 2016 with the year-ago period.~~between periods.

Ameren Missouri

The effective tax rate was ~~lower~~comparable between periods.

Ameren Illinois

The effective tax rate was comparable between periods at Ameren Illinois. The effective tax rate was higher at Ameren Illinois Electric Distribution, as discussed below. The effective tax rate was comparable between periods at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

The effective tax rate was higher in the first ~~nine months~~quarter of ~~2016, as~~2017, compared with the year-ago period, primarily because of the ~~recognition~~decreased effect of ~~excess~~ 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. See Accounting and Reporting Developments in Note 1 – Summary of Significant Accounting Policies under Part I, Item 1, of this report for additional information.

~~Ameren Missouri~~

~~The effective tax rate was comparable~~on higher pretax income in the ~~third quarter~~current year from certain depreciation differences on property-related items, tax credits, and ~~the first nine months of 2016 with the year-ago periods.~~

~~Ameren Illinois~~

~~The effective tax rate was comparable in the third quarter and the first nine months of 2016 with the year-ago periods.~~company-owned life insurance.

LIQUIDITY AND CAPITAL RESOURCES

~~Our~~Collections from our tariff-based ~~gross margins~~revenues are our principal source of cash ~~from~~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 ~~generated from~~provided by operating activities, we use available cash, ~~credit agreement~~ borrowings under the Credit Agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, ~~money pool~~short-term intercompany borrowings ~~and other short-term borrowings from affiliates~~ to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash ~~from~~provided by operations or, at our discretion, with long-term borrowings, or, in the case of

Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). We expect to make significant capital expenditures over the next five years as we invest in our electric and natural gas utility infrastructure to support overall system reliability, environmental compliance, and other improvements. We intend to fund those capital expenditures primarily with ~~available~~ cash ~~on hand, cash generated from~~provided by operating activities ~~commercial paper borrowings~~ and short-term and long-term debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.

The use of cash ~~from~~provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at ~~September 30, 2016~~March 31, 2017, for the Ameren ~~and Ameren Illinois.~~Companies. The working capital deficit as of ~~September 30, 2016~~, March 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 and money pool borrowings.~~issuances. With the credit capacity available under the Credit Agreements, ~~and our cash and cash equivalents,~~ the Ameren Companies had access to ~~$1.5~~$1.2 billion of liquidity at ~~September 30, 2016.~~March 31, 2017.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:

Net Cash Provided By (Used In)

Operating Activities

Investing Activities

Net Cash Provided by (Used In)

Financing Activities

Net Cash Provided By

Operating Activities

Investing Activities

Net Cash Provided by (Used In)

Financing Activities

Ameren^(a) – continuing operations

Ameren^(a) – discontinued operations

Cash Flows from Operating Activities

~~Ameren Corporation~~

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 paid 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 impact the amount and timing of our cash provided by operating activities.

Ameren

Ameren’s cash from operating activities ~~associated with continuing operations increased $12~~decreased $18 million in the first ~~nine months~~quarter of ~~2016,~~2017, compared ~~with~~to the ~~same period in~~ ~~2015~~.year-ago period. The following items contributed to the ~~increase:~~decrease:

The absence of a $42 million insurance receipt at Ameren Missouri related to the Taum Sauk ~~breach. See~~breach received in 2016.

Refunds of $21 million associated with the November 2013 FERC complaint case, as discussed in Note 152 – ~~Commitments~~Rate and ~~Contingencies~~Regulatory Matters under Part ~~II,~~I, Item 8,1, of this report.

An $11 million increase in natural gas held in storage caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the ~~Form 10-K for additional information.~~prior year.

~~A $32~~An $8 million ~~increase~~decrease in cash associated with the recovery of Ameren Illinois' IEIMA revenue requirement reconciliation adjustments. The ~~2014~~2015 revenue requirement reconciliation adjustment, which is being recovered from customers in ~~2016,~~2017, was ~~greater~~less than the ~~2013~~2014 revenue requirement reconciliation adjustment, which was recovered from customers in ~~2015.~~

~~A $30 million decrease in coal inventory at Ameren Missouri, as additional coal was purchased in 2015 to compensate for delivery disruptions experienced in 2014.~~

~~A $25 million decrease in payments for purchased power compared with amounts collected from Ameren Illinois customers.~~

~~A $17 million decrease in expenditures for customer energy efficiency programs compared with amounts collected from Ameren Illinois customers.~~

~~A $15 million increase in cash associated with Ameren Illinois' transmission revenue requirement reconciliation adjustments, as $7 million was collected from customers in 2016 comparedto $8 million refunded to customers in 2015.~~

Income tax refunds of $7 million in 2016, compared with income tax payments of $6 million in 2015. In 2016, Ameren generated net operating losses due to bonus depreciation, resulting in no current federal income tax liability.

A net $8 million decrease in collateral postings with counterparties, primarily at Ameren Missouri, resulting from changes in the market prices of power and natural gas and in contracted commodity volumes.2016.

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

~~A $54 million decrease in net energy costs collected from Ameren Missouri customers under the FAC.~~

A $36 million increase ~~in payments to purchase stock associated with share-based compensation plan awards.~~

~~A $26 million increase in payments for the nuclear refueling and maintenance outage at the Ameren Missouri Callaway energy center. There was no refueling and maintenance outage in 2015.~~

~~An $18 million increase in the cost of natural gas held in storage caused primarily by fewer withdrawals as a result of milder winter temperatures compared with the prior year.~~

~~A $16 million increase in interest payments, primarily due to an increase in the cost of Ameren (parent) debt, and an increase in the average outstanding debt at Ameren Illinois.~~

~~A $12 million decrease~~ resulting from ~~the change in customer receivable balances, partially offset by an increase in electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items.~~

~~A $4 million increase in storm restoration costs.~~

~~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 $152 million in the first nine months of 2016, compared with the same period in~~ ~~2015. The following items contributed to the decrease:~~

~~A $104 million decrease resulting from a reduction in~~ electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.

Income tax payments of $11 million to Ameren (parent) pursuant to the tax allocation agreement in 2016, compared with income tax refunds of $52 million in 2015 primarily related to an audit settlement.

~~A $54~~

An $18 million decrease in ~~net energy costs collected from customers under the FAC.~~Ameren Missouri’s coal inventory as a result of increased generation levels.

~~A $26 million increase in payments for nuclear refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2015.~~Ameren Missouri

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

decreased $76 million in the first quarter of 2017, compared to the year-ago period. The following items contributed to the decrease:

AThe absence of a $42 million insurance receipt related to the Taum Sauk ~~breach. See Note 15 – Commitments and Contingencies under Part II, Item 8,~~breach received in ~~the Form 10-K for additional information.~~2016.

A ~~$30~~$17 million decrease ~~in coal inventory, as additional coal was purchased in 2015 to compensate for delivery disruptions experienced in 2014.~~

~~A net $5 million decrease in collateral postings with counterparties, primarily~~ resulting from ~~changes in the market prices of power and natural gas and in contracted commodity volumes.~~

~~A $4 million decrease in pension and postretirement benefit plan contributions caused by a change in actuarial assumptions.~~

~~Ameren Illinois~~

~~Ameren Illinois’ cash from operating activities increased $86 million in the first nine months of 2016, compared with the same period in~~ ~~2015. The following items contributed to the increase:~~

~~A $53 million increase resulting from an increase in~~ electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, ~~partially offset by~~as well as the change in customer receivable balances.

~~A $32~~An increase of $14 million ~~increase~~ in ~~cash associated with~~income tax payments paid to Ameren (parent) pursuant to the ~~recovery~~tax allocation agreement, primarily related to the timing of IEIMA revenue requirement reconciliation adjustments. The 2014 revenue requirement reconciliation adjustment, which is being recovered from customers in 2016, was greater than the 2013 revenue requirement reconciliation adjustment, which was recovered from customers in 2015.payments.

~~A $25~~An $18 million decrease in ~~payments for purchased power compared with amounts collected from customers.~~

~~A $17 million decrease in expenditures for customer energy efficiency programs compared with amounts collected from customers.~~

~~A $15 million increase in cash associated with transmission revenue requirement reconciliation adjustments,~~coal inventory as ~~$7 million was collected from customers in 2016 comparedto $8 million refunded to customers in 2015.~~

~~The following items~~a result of increased generation levels partially offset the ~~increase~~decrease in Ameren Missouri’s cash from operating activities between periods.

Ameren Illinois

Ameren Illinois’ cash from operating activities ~~between periods:~~decreased $17 million in the first quarter of 2017, compared to the year-ago period. The following items contributed to the decrease:

Refunds of $17 million associated with the November 2013 FERC complaint case, as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.

A ~~$14~~$10 million increase in ~~the cost of~~ natural gas held in storage caused primarily by ~~fewer~~reduced withdrawals as a result of milder winter temperatures compared with the prior year.

An $8 million decrease in cash associated with the recovery of IEIMA revenue requirement reconciliation adjustments. The 2015 revenue requirement reconciliation adjustment, which is being recovered from customers in 2017, was less than the 2014 revenue requirement reconciliation adjustment, which was recovered from customers in 2016.

An $8 million increase in interest payments, primarily due to an increase in the average outstanding ~~debt, including senior secured notes issued in December 2015.~~debt.

A $7$5 million increase in ~~pension and postretirement benefit plan contributions caused by the timing of payments.~~expenditures for customer energy efficiency programs compared with amounts collected from customers.

A $4 million increase in ~~storm restoration costs.~~payments for purchased power compared with amounts collected from customers.

Ameren Illinois’ decrease in cash from operating activities was partially offset by a $48 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, offset by the change in customer receivable balances.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities ~~associated with continuing operations~~ increased ~~$189~~$29 million in the first ~~nine~~three months of ~~2016,~~2017, compared with the ~~same period in~~ year-

~~2015~~.ago period. Capital expenditures increased $~~164~~8 million ~~principally~~primarily as a result of the

activity at Ameren Missouri and Ameren Illinois, as discussed below, ~~and~~offset by a ~~$43~~$27 million ~~increase~~decrease in ATXI’s capital expenditures which primarily related to the Illinois Rivers ~~and Spoon River projects.~~project.

Ameren Missouri’s cash used in investing activities decreased ~~$15~~$102 million in the first ~~nine~~three months of ~~2016,~~2017, compared with the ~~same~~year-ago period, due to a $125 million increase in ~~2015, due in part to an $85 million decrease in net~~the return of money pool ~~advances. These items were~~advances.This was partially offset by ~~increased~~an $18 million increase in capital expenditures ~~of $56 million~~ primarily related to electric distribution system reliability and energy center projects as well as ~~an $11~~a $6 million increase in nuclear fuel expenditures.

Ameren Illinois’ cash used in investing activities ~~increased $64~~decreased $42 million due to ana $58 million decrease in money pool advances partially offset by a $16 million increase in capital expenditures primarily related to ~~qualified investments in natural gas infrastructure under the QIP rider, smart meter investments made pursuant to IEIMA,~~electric distribution and ~~storm restoration costs.~~

~~Ameren Missouri continually reviews its generation portfolio~~transmission system reliability 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, changes in laws or regulations, 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 impairment losses, which could be material. Compliance with environmental regulations could also have significant impacts on the level of capital expenditures. See Note 9 – Commitments and Contingencies in Part I, Item 1, of this report for additional information.substation upgrades.

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.

Ameren’s ~~cash used in~~ financing activities ~~associated with continuing operations increased $169~~provided net cash of $207 million during the first ~~nine~~three months of ~~2016,~~2017, compared towith using net cash of $118 million during the ~~same period~~year-ago period. An increase in ~~2015. Short-term and long-term~~short-term debt issuances ~~net~~as well as the absence in 2017 of long-term debt ~~repayments,~~maturities resulted in ~~$137~~$336 million ~~less~~more cash provided by financing activities in the first ~~nine~~three months of ~~2016,~~2017, compared with the year-ago period. ~~Additionally, there was a $20 million increase in employee withholding taxes related to share-based payments in the first nine months of 2016, compared to the same period in 2015.~~

Ameren Missouri’s cash used in financing activities ~~increased $129~~decreased $173 million in the first ~~nine~~three months of ~~2016,~~2017, compared with the ~~same period in 2015. Cash used in net short-term and~~

~~long-term debt activity was $111 million in 2016, compared with providing cash of $38 million in the~~ year-ago period. ~~Cash~~During the first three months of 2017, cash paid to Ameren (parent) as dividends, net of capital contributions ~~received~~ from parent, decreased ~~$19~~$42 million, ~~between~~compared to the ~~two nine-month periods.~~year ago period. Additionally, Ameren Missouri repaid $260 million in long-term debt in 2016, compared with no maturities in 2017. The decrease was partially offset by $129 million less cash provided by short-term debt in the first three months of 2017, compared with the year-ago period.

Ameren Illinois’ financing activities ~~used net~~provided cash of ~~$16~~$15 million during the first ~~nine~~three months of ~~2016,~~2017, compared to ~~providing net~~using cash of ~~$73~~$31 million during the same period in ~~2015.~~

2016. Ameren Illinois ~~paid~~did not pay Ameren (parent) dividends during the first three months of ~~$95 million,~~2017, compared with ~~no dividend payments~~$30 million in ~~2015.~~dividends paid in the year-ago period. Additionally, cash provided by ~~net~~ short-term ~~and long-term~~ debt ~~activity, as well as money pool borrowings,~~ increased $7$17 million in ~~2016,~~2017, compared with the year-ago period.

See Long-term Debt and Equity in this section for additional information on maturities and issuances of long-term debt.

Credit Facility Borrowings and Liquidity

The liquidity needs of Ameren, Ameren Missouri, and Ameren Illinois are typically supported through the use of available cash, commercial paper issuances, short-term intercompany borrowings, or drawings under ~~committed credit agreements.~~the Credit Agreements. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on ~~credit agreements,~~the Credit Agreements, short-term borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s money pool arrangements.

The following table presents Ameren’s consolidated liquidity as of ~~September 30, 2016~~March 31, 2017:


Ameren and Ameren Missouri:
Missouri Credit Agreement (a) – borrowing capacity	$	1,000
Missouri Credit Agreement – borrowing capacity			$	1,000
Less: Ameren (parent) commercial paper outstanding	263		472
Less: Ameren Missouri commercial paper outstanding	—		36
Missouri Credit Agreement – credit available	737		492
Ameren and Ameren Illinois:
Illinois Credit Agreement (a) – borrowing capacity	1,100
Illinois Credit Agreement – borrowing capacity			1,100
Less: Ameren (parent) commercial paper outstanding	188		338
Less: Ameren Illinois commercial paper outstanding	157		68
Less: Letters of credit	4		4
Illinois Credit Agreement – credit available	751		690
Total Credit Available	$	1,488	$	1,182
Cash and cash equivalents	18		8
Total Liquidity	$	1,506	$	1,190


~~(a)~~	~~Expires in December 2019.~~

The Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren’s (parent), Ameren Missouri’s, and Ameren Illinois’ commercial paper programs. Both of the Credit Agreements are available to Ameren to support issuances under Ameren’s commercial paper program, subject to borrowing sublimits. The Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. The Illinois Credit Agreement is available to support issuances under Ameren Illinois’ commercial paper program. Issuances under the Ameren (parent), Ameren Missouri, and Ameren Illinois commercial paper programs were available at lower interest rates than the interest rates available under the Credit Agreements. ~~As such, commercial~~Commercial paper issuances were thus preferred to credit facility borrowings as a ~~preferred~~ source of third-party short-term ~~debt relative to credit facility borrowings.~~debt.

In addition, Ameren Missouri and Ameren Illinois may borrow cash from the utility money pool when funds are available. The

rate of interest depends on the composition of internal and external funds in the utility money pool. 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~~offers the lowest interest rates.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by the FERC under the Federal Power Act. In February 2016, the FERC issued an order authorizing Ameren Missouri to issue up to $1 billion of short-term debt securities through March 2018. In August 2016, the FERC issued an order authorizing Ameren Illinois to issue up to $1 billion of short-term debt securities through September 2018.

The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements given 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 the issuances (net of any issuance discounts), maturities, and redemptions of long-term debt for the Ameren Companies for the nine months ended September 30, 2016 and 2015. The Ameren Companies did not issue any common stock during the first ~~nine~~three months of ~~2016~~2017 or ~~2015.~~2016. In March 2016, ~~and 2015,~~ Ameren Missouri received cash capital contributions of $38 million ~~and $224 million, respectively,~~ from Ameren (parent).

Month Issued, Redeemed, or Matured 2016 2015
Issuances of Long-term Debt
Ameren Missouri:
3.65% Senior secured notes due 2045 June $ 149
$ —
3.65% Senior secured notes due 2045 April —
249
Total Ameren long-term debt issuances $ 149
$ 249
Redemptions 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
Ameren Illinois:
6.20% Senior secured notes due 2016 June 54
—
6.25% Senior secured notes due 2016 June 75
—
Total Ameren long-term debt redemptions and maturities $ 389
$ 114

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

See Note 3 – Short-term Debt and Liquidity and Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements and in certain of the Ameren Companies’ indentures and articles of incorporation.

At ~~September 30, 2016~~March 31, 2017, the Ameren Companies were in compliance with the provisions and covenants contained in their credit agreements, indentures, and articles of incorporation.

We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by cash generated from 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

The amount and timing of Ameren’s common stock dividends 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 ~~October 14, 2016,~~April 28, 2017, Ameren’s board of

directors declared a quarterly common stock dividend of 44 cents per share payable on ~~December~~June 30, ~~2016,~~2017, to shareholders of record on December 7, 2016, resulting in an annualized equivalent dividend rate of $1.76 per share. The previous annualized equivalent dividend rate, based on the common stock dividend declared and paid in the third quarter of 2016, was $1.70 per share.June 14, 2017.

See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for additional discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain

circumstances. At ~~September 30, 2016~~March 31, 2017, none of these circumstances existed at Ameren, Ameren Missouri, or Ameren Illinois and, as a result, these companies were not restricted from paying dividends.

The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren Missouri and Ameren Illinois to their parent, Ameren Corporation, for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016:


	Nine Months				Three Months
	2016		2015		2017		2016
Ameren Missouri	$	285	$	490	$	60	$	140
Ameren Illinois	95		—		—		30
Ameren	309		298		107		103

Contractual Obligations

For a listing of our obligations and commitments, see Other Obligations in Note 9 – Commitments and Contingencies under Part I, Item 1, of this report. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

At ~~September 30, 2016~~March 31, 2017, total obligations related to commitments for coal, natural gas, nuclear fuel, purchased power, methane gas, equipment, and meter reading services, among other agreements, at Ameren, Ameren Missouri, and Ameren Illinois were ~~$4,328~~$3,824 million, ~~$2,428~~$2,340 million, and ~~$1,859~~$1,418 million, respectively.

Off-Balance-Sheet Arrangements

At ~~September 30, 2016~~March 31, 2017, none of the Ameren Companies had off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Credit Ratings

The credit ratings of the Ameren Companies assigned by Moody’s and S&P can affect our liquidity, access to the capital markets and credit markets, cost of borrowing under credit facilities and commercial paper programs, and 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

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 Ameren, Ameren Missouri, and Ameren Illinois at ~~September 30, 2016.~~March 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 ~~September 30, 2016,~~March 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 ~~$106~~$74 million, ~~$60~~$44 million, and ~~$46~~$30 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at ~~September 30, 2016,~~March 31, 2017, if market prices were 15% higher or lower than ~~September 30, 2016~~March 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 other assurances for certain trade obligations.

OUTLOOK

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

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

Below are some key trends, events, and uncertainties that are reasonably likely to affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for ~~2016~~2017 and beyond.

Operations

Our strategy for earning competitive returns on our investments involves meeting customer energy needs in an efficient fashion, working to enhance regulatory frameworks, making timely and well-supported rate case filings, and aligning overall spending with rate case outcomes, economic conditions, and return opportunities.

Ameren continues ~~to pursue its plans~~ to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The ~~first project,~~ Illinois Rivers project involves the construction of a transmission line from western Indiana across the state of Illinois to eastern Missouri. ~~The~~Construction activities for the Illinois Rivers project are continuing on schedule and the last section of this project is expected to be completed by 2019. The Spoon River project, located in northwest Illinois, and the Mark Twain project, located in northeast Missouri, are the other two MISO-approved projects to be constructed by ATXI. ~~These two projects~~Construction activities for the Spoon River project are continuing on schedule and the project is expected to be completed in 2018. ~~The Illinois Rivers~~See Note 2 – Rate and ~~the Spoon River projects have received all~~Regulatory Matters under Part I, Item 1, of ~~the necessary commission approvals to authorize their construction.~~ ~~In April 2016, the MoPSC granted ATXI a certificate of convenience and necessity~~this report for information regarding the Mark Twain project. Before starting construction, ATXI must obtain assents for road crossings from the five counties where the line will be constructed. None of the five county commissions approved ATXI’s requests for the assents. In October 2016, ATXI filed suit in each of the five county circuit courts to obtain the assents. A decision from each of the county circuit courts is expected in 2017. ~~ATXI is planning to complete the~~ project ~~in 2018; however, delays in obtaining the assents could delay the completion date.~~and its approval process. The total investment in all three projects is expected to be more than ~~$1.0 billion~~$575 million from ~~2016~~2017 through 2019. ~~This total includes over $60 million of investment by Ameren Illinois to construct connections to its existing transmission system. In addition to its investment in the MISO-approved projects,~~ Ameren Illinois expects to invest ~~$1.9~~$2.2 billion in electric transmission assets from ~~2016~~2017 through ~~2020~~2021 to ~~address load growth~~replace aging infrastructure and ~~reliability requirements.~~improve reliability.

Both Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. ~~With~~Based on the rates that ~~will become~~became effective on January 1, 2017, and the currently allowed 10.82% return on common equity, ~~which includes a 50 basis point incentive adder,~~ the 2017 revenue requirement for Ameren Illinois’ electric transmission business ~~would be~~is $258 ~~million, which~~million. The 2017 revenue requirement represents a ~~$17~~$33 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a ~~12.38%~~10.82% return on common ~~equity, primarily due to rate base growth.~~equity. These January 2017 rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.4 billion. ~~With~~Based on the rates that ~~will become~~became effective on January 1, 2017, and the currently allowed 10.82% return on equity, ~~which includes a 50 basis point incentive adder,~~ the 2017 revenue requirement for ATXI’s electric transmission business ~~would be~~is $171 ~~million, which~~million. The 2017 revenue requirement represents a ~~$31~~$44 million increase over the revised 2016 revenue requirement, which became effective in September 2016, and was based on a ~~12.38%~~10.82% return on common ~~equity, primarily due to rate base growth as a result of the Illinois Rivers project.~~equity. These January 2017 rates reflect a capital structure comprised of ~~56.2%~~56.3% common equity and a projected average rate base of $1.1 ~~billion.~~billion, reflecting additional investment in the Illinois Rivers project.

The return on common equity was the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each ~~challenge~~challenged the allowed base return on common equity for MISO transmission ~~owners.~~owners, including Ameren Illinois and ATXI. In September 2016, the FERC issued a final order in the November 2013 complaint case, which lowered the allowed base return on common equity for the 15-month period of November 2013 to February 2015 to 10.32%., or a 10.82% total allowed return on common equity with the

inclusion of the 50 basis point incentive adder for participation in an RTO. The order ~~was consistent with the initial decision an administrative law judge issued in December 2015 and requires~~required customer refunds, with interest, to be issued for that 15-month period. Refunds for the ~~15-month period ended February 2015. In addition, the new allowed base return on common equity is reflected in rates prospectively from the September 2016 effective date of the order.Refunds are expected to be~~November 2013 complaint case were issued in the first ~~half~~quarter of 2017. In June 2016, an administrative law judge issued an initial decision in the February 2015 complaint case, which if approved by the FERC, would lower ~~the allowed base return on common equity to~~ ~~9.70%~~ ~~and would require customer refunds, with interest, to be issued for the 15-month period ended May 2016.The FERC is expected to issue a final order in the February 2015 complaint case in the second quarter of 2017. The final order in the February 2015 complaint case will determine~~ the allowed base return on common equity for the 15-month period ~~ended~~of February 2015 to May ~~2016.~~2016 to 9.70%, or a 10.20% total allowed return on equity with the inclusion of the 50 basis point incentive adder for participation in an RTO and require customer refunds, with interest, for that 15-month period. The timing of the issuance of the final order in the February 2015 complaint case, which will ~~also establish~~prospectively replace the current 10.82% allowed return on equity, is uncertain for two reasons. First, at this time the FERC lacks a quorum of three commissioners. Second, the United States Court of Appeals for the District of Columbia recently vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity ~~that will apply prospectively from its expected second quarter 2017 effective date, replacing~~methodology used in the ~~10.32% allowed base return on common equity, which became effective in September 2016.~~two MISO complaint cases described above. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren's and Ameren Illinois' ~~net income~~annual earnings by an estimated $7 million and $4 million, respectively, based on each company’s 2017 projected ~~average~~ rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective ~~September 30, 2016~~March 31, 2017 balance sheets, representing their

estimate of the expected refunds.

On July 1, 2016, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $206 million. The electric rate increase request is based on a 9.9% return on equity, a capital structure comprised of 51.8% equity, a rate base of $7.2 billion, and a test year ended

In March 31, 2016, with certain pro-forma adjustments through the anticipated true-up date of December 31, 2016. As a part of its filing, Ameren Missouri requested the amortization over ten years of an estimated $81 million of lost fixed cost recovery due to lower sales, as discussed below, to the New Madrid Smelter during the period April 2015 through May 2017. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by late April 2017, and new rates effective in late May 2017. A 50 basis point change in Ameren Missouri’s return on common equity would result in an estimated $18 million change in Ameren’s and Ameren Missouri’s net income, based on Ameren Missouri’s current electric rate base.

~~In April 2015,~~ the MoPSC issued an order approving ana 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 ~~revenues~~revenue requirement for electric ~~service. The order also approved Ameren Missouri’s request for continued use of~~service, compared to its prior revenue requirement established in the FAC; however, it changed the FAC to exclude all transmission revenues and substantially all transmission charges. This change to Ameren Missouri’s FAC is contributing to regulatory lag. For example, theMoPSC's April 2015 ~~MoPSC~~ electric rate ~~order included $29~~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 decrease by $54 million ~~of transmission charges in~~from the base ~~rates that were previously included~~level established in the ~~FAC. Ameren Missouri expects transmission charges to increase to $50~~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, reduce expenses by $26 million ~~in 2016, with further cost increases expected~~from the base levels established in the ~~foreseeable future. However, transmission revenues included in base rates in the~~MoPSC's April 2015 ~~MoPSC~~ electric rate order totaled $34 million and are expected to remain relatively constant in 2016 and into the near future. In its July 2016 electric rate case, in an effort to mitigate the regulatory lag resulting from the changes to the FAC in the April 2015 order, Ameren Missouri requested the implementation of a new tracking mechanism for transmission charges and revenues.

Ameren Missouri supplies electricity to the New Madrid Smelter. In the first quarter of 2016, operations at the New Madrid Smelter were suspended. In addition, Noranda filed voluntary petitions for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. In October 2016, Noranda sold the New Madrid Smelter to ARG International AG. As a result of these events in 2016, actual sales volumes to the New Madrid Smelter will be significantly below the sales volumes reflected in rates and, therefore, Ameren Missouri has not fully recovered and will not fully recover its revenue requirement, which included $78 million for sales to the New Madrid Smelter, until rates are adjusted prospectively by the MoPSC in the July 2016 electric rate case to accurately reflect the smelter’s actual sales volumes. Ameren Missouri estimates a $38 million reduction in 2016 earnings, compared to 2015, relating to the significantly lower expected electric sales to the New Madrid Smelter after

consideration of the FAC-tariff provision that allows Ameren Missouri to retain a portion of its off-system sales. In the first five months of 2017, Ameren Missouri estimates an $8 million reduction in earnings related to the continuation of significantly lower expected electric sales to the New Madrid Smelter. However, the expected adjustment of rates in May 2017 to accurately reflect the smelter’s actual sales volumes is estimated to result in a $30 million increase in 2017 earnings, compared to 2016 earnings. Operations at the New Madrid Smelter remain suspended and Ameren Missouri is uncertain of future sales to the smelter.

In November 2016, the MoPSC approved a $28 million MEEIA 2013 performance incentive based on a revised stipulation agreement between Ameren Missouri, the MoPSC staff, and the MoOPC. As a result, Ameren Missouri will recognize $9 million of additional revenues in the fourth quarter of 2016 relating to the MEEIA 2013 performance incentive. Further, the revised stipulation agreement included a provision to incorporate the results of the appeal, discussed below, regarding the determination of an input used to calculate the performance incentive.In November 2015, the MoPSC issued an order regarding the determination of an input used to calculate the performance incentive. Ameren Missouri filed an appeal of the order with the Missouri Court of Appeals, Western District, which is expected to issue a decision in 2016. If the Missouri Court of Appeals, Western District, overturns the November 2015 MoPSC order, Ameren Missouri may recognize additional revenues in excess of the $28 million approved by the MoPSC in November 2016.order.

The throughput disincentive recovery under MEEIA 2016 replaced the net shared benefits that were collected under MEEIA 2013. Net shared benefits compensated Ameren Missouri for the current year and longer-term financial impacts of customer energy efficiency programs in each year of the program from 2013 through 2015. The throughput disincentive included in MEEIA 2016, however, is designed to be earnings neutral each year by compensating Ameren Missouri for the lost sales volumes from its customer energy efficiency programs that occur in that year, but does not compensate for the longer-term financial impacts of these programs until sales volumes are lost in a future year. The unfavorable on-going effects of sales volume reductions from the MEEIA 2013 energy efficiency programs were previously recognized during 2013 through 2015 as net shared benefits, and therefore, any such lost sales volumes have impacted and will continue to negatively impact Ameren and Ameren Missouri earnings until the date that new rates in the July 2016 rate case become effective in May 2017.

~~The IEIMA~~Illinois law provides for an annual reconciliation of the electric distribution revenue requirement 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' ~~2016~~2017 electric distribution service revenues will be based on its ~~2016~~2017 actual recoverable costs, rate base, and return on common equity as calculated under the ~~IEIMA's~~Illinois performance-based formula ratemaking framework. The ~~2016~~2017 revenue requirement is expected to be higher

than the ~~2015~~2016 revenue

requirement because of an expected increase in recoverable costs, ~~and~~expected rate base ~~growth.~~growth of 5%, and an expected increase in the monthly average of United States treasury bonds. The 2017 revenue requirement reconciliation is expected to result in a regulatory asset that will be collected from customers in 2019. A 50 basis point change in the average monthly yields of the 30-year United States Treasury bonds would result in an estimated $6$7 million change in Ameren's and Ameren Illinois' net income, based on Ameren Illinois’ ~~2016~~2017 projected year-end rate base.

In December 2015, the ICC issued an order with respect to Ameren Illinois’ annual update filing. The ICC approved a $106 million increase in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2016. These rates have affected and will continue to affect Ameren Illinois' cash receipts during 2016, but will not be the sole determinant of its electric distribution service operating revenues, which will instead be largely determined by the IEIMA's 2016 revenue requirement reconciliation. The 2016 revenue requirement reconciliation, as discussed above, is expected to result in a regulatory asset that will be collected from customers in 2018.

In April ~~2016,~~2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for ~~2017~~2018 rates. Pending ICC approval, ~~Ameren Illinois’~~this update filing will result in a ~~$14~~$16 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January ~~2017.~~2018. This update reflects an increase to the annual formula rate based on 2015 actual costs and expected net plant additions for 2016, an increase to include the 2015 revenue requirement reconciliation adjustment, and a decrease for the conclusion of the 2014 revenue requirement reconciliation adjustment, which will be fully collected from customers in 2016. These rates will affect Ameren Illinois' cash receipts during ~~2017,~~2018, but will not ~~be the sole determinant of~~determine its electric distribution service operating revenues, which will instead be ~~largely determined by~~based on its 2018 actual recoverable costs, rate base, and return on common equity as calculated under the ~~IEIMA's 2017 revenue requirement reconciliation.~~ ~~In October 2016, an administrative law judge issued a proposed order that reflected a decrease to Ameren Illinois’ electric distribution service revenue requirement of $14 million.~~ Illinois performance-based formula ratemaking framework. An ICC decision on the revenue requirement used for ~~2017~~2018 rates is expected by December ~~2016.~~2017.

•

~~As of December 31, 2015, Ameren Missouri’s energy centers~~

Beginning in 2017, the FEJA provides that ~~emit CO~~₂ ~~represented approximately 20% and 35% of Ameren’s and Ameren Missouri’s rate base, respectively. Ameren and Ameren Missouri estimate their investments in energy centers that emit CO~~₂~~will represent approximately 15% and 31% of Ameren’s and Ameren Missouri’s rate base by December 31, 2020.~~

Ameren ~~Missouri's~~Illinois recovers, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. In connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize its interim period revenue. Ameren Illinois will now recognize revenues consistent with the timing of incurred electric distribution recoverable costs and recognize revenue associated with the expected return on its rate base ratably over the year. As a result of this change in recognition of the interim period revenue for the IEIMA formula rate framework, as modified by FEJA, Ameren Illinois expects quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first, second, and fourth quarters and a decrease to earnings in the third quarter. The change in interim period revenue recognition will not impact 2017’s annual earnings.

Beginning as early as June 2017, the FEJA will allow Ameren Illinois to earn a return on its electric energy efficiency program investments. Ameren Illinois electric energy efficiency investments will be deferred as a regulatory asset and will earn a return at the company’s weighted average cost of capital, with the equity return based on the monthly average yield of the 30-year United States Treasury bonds plus 580 basis points. The equity portion of Ameren Illinois’ return on electric energy efficiency investments can also be increased or decreased by 200 basis points based on the achievement of annual energy savings goals. Based on a formula provided in the act, Ameren Illinois estimates it can annually invest up to $100 million from 2018 through 2021, up to $107 million annually

from 2022 through 2025, and up to $114 million annually from 2026 through 2030. The ICC has the ability to lower the electric energy efficiency saving goals if there are insufficient cost effective measures available or if achieving the savings goals would require investment levels that exceed the formula amounts shown above. The electric energy efficiency program investments and the return on those investments will be recovered through a rider, and will not be included in the IEIMA formula rate process.

In 2018, Ameren Illinois expects to file for a natural gas regulatory rate review with the ICC. Ameren Illinois’ current allowed return on equity for natural gas delivery service is 9.60%, with a capital structure of 50% common equity, a rate base of $1.2 billion, and a 2016 future test year.

The next scheduled refueling and maintenance outage at ~~its~~Ameren Missouri’s Callaway energy center will be in fall 2017. Ameren Missouri expects to incur $32 million of maintenance expenses, which approximates the ~~fall~~cost of ~~2017.~~the spring 2016 outage. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri's purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale

are included in the FAC, which results in limited impacts to earnings.

As we continue to experience cost increases and to make infrastructure investments, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek legislative solutions, as necessary, ~~legislative solutions~~ to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, customer conservation efforts, the impacts of additional customer energy efficiency programs, increased customer use of innovative and increasingly cost-effective technological advances including private generation and storage, increased investments and expected future investments for environmental compliance, system reliability improvements, and new generation capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs and higher property ~~and income~~ taxes, among other costs.

For additional information regarding recent rate orders, ~~and related appeals~~lawsuits, the Westinghouse bankruptcy filing, and pending requests filed with state and federal regulatory commissions, see Note 2 – Rate and Regulatory Matters and Note 10 – Callaway Energy Center under Part I, Item 1, of this report and Note 2 –

Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.

Liquidity and Capital Resources

Through ~~2020,~~2021, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure with a major portion directed to our transmission and distribution systems. We estimate that we will invest in total up to ~~$11.5~~$11.2 billion (Ameren Missouri – up to ~~$4.3~~$4.2 billion; Ameren Illinois – up to ~~$6.2~~$6.4 billion; ATXI – up to ~~$1.0~~$0.6 billion) of capital expenditures during ~~2016~~the period from 2017 through ~~2020.~~2021.

•

Environmental regulations, including those related to CO₂emissions, 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 and increased operating costs for Ameren and Ameren Missouri. These costs ~~could be prohibitive, which~~ could result in the closure of some of Ameren Missouri's coal-fired energy centers. Ameren Missouri's capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren's and Ameren Missouri's earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in ~~rates charged to customers.~~customer rates.

~~Ameren continues to evaluate the Clean Power Plan's potential impacts to its operations, including those related to~~

electric system reliability, and its level of investment in customer energy efficiency programs, renewable energy, and other forms of generation investment. In February 2016, the United States Supreme Court stayed the Clean Power Plan and all implementation requirements until the legal appeals are concluded. If the rule is ultimately upheld and implemented in substantially its current form, Ameren Missouri expects to incur increased net fuel and operating costs, and make new or accelerated capital expenditures, in addition to the costs of making modifications to existing operations in order to achieve compliance. Compliance measures could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and natural-gas-fired energy centers, which could result in increased operating costs.

Ameren Missouri files a nonbinding integrated resource plan with the MoPSC every three ~~years.~~years and will file its next plan in October 2017. Ameren Missouri’s integrated resource plan filed with the MoPSC in October 2014, prior to the issuance of the Clean Power Plan, was a 20-year plan that supported a more ~~fuel-diverse~~diverse energy portfolio in Missouri, including coal, solar, wind, natural gas, hydro and nuclear power. The plan involves expanding renewable generation, retiring coal-fired generation as those energy centers reach the end of their useful lives, ~~continuation and expansion of the then-existing~~expanding customer energy efficiency programs, and adding natural gas-fired combined cycle generation.

The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through December ~~2019,~~2021, subject to a 364-day repayment term in the case of Ameren Missouri and Ameren Illinois. See Note 34 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the Credit Agreements. By the end of 2018, $803 million and $707 million of senior secured notes are scheduled to mature at

Ameren Missouri and Ameren Illinois, respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes. In addition, the Ameren Companies may refinance a portion of their outstanding short-term debt with long-term debt in 2017. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

In December 2015, a federal tax law was enacted that authorized the continued use of bonus depreciation ~~that~~which allows for an acceleration of deductions for tax purposes at a rate of 50% ~~for 2015, 2016, and~~through 2017. The rate will be reduced to 40% in 2018 and ~~then~~ to 30% in 2019. Bonus depreciation will be phased out in 2020 unless a new law is enacted. ~~Bonus depreciation is expected to reduce or eliminate federal income tax payments through at least 2020.~~ Ameren expects to use this incremental cash flow to make capital investments in utility infrastructure for the benefit of its customers. Without these investments, bonus depreciation would reduce rate base, which reduces our revenue requirements and future earnings growth. The impact of bonus depreciation on the Ameren ~~Missouri, Ameren Illinois, and ATXI~~Companies will vary based on investment levels at each company.

As of ~~September 30, 2016,~~March 31, 2017, Ameren had ~~$511~~$598 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – ~~$39~~$41 million and Ameren

Illinois – ~~$132~~$155 million) and ~~$135~~$131 million in federal and state income tax credit carryforwards (Ameren Missouri – ~~$28~~$29 million and Ameren Illinois – $1 million). In addition, Ameren has ~~$37~~$34 million of expected state income tax refunds and state overpayments. Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities for Ameren Missouri ~~until~~through 2019 and Ameren Illinois until ~~2018.~~2021. Based on existing tax laws, Ameren does not expect to make material federal income tax payments until 2021. These tax benefits, primarily at the Ameren (parent) level, when realized, would be available to support funding ~~ATXI transmission~~Ameren Transmission investments.

Ameren expects its cash used for capital expenditures and dividends to exceed cash provided by operating activities over the next several years. Ameren expects to use debt to fund such cash shortfalls; it does not currently expect to issue equity over the next several years.

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

strategies may include acquisitions, divestitures, 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 I, Item 1, of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risk in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.

Our risk management objectives are to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers, with Ameren board of directors oversight.

~~There~~With the exception of the following, there have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, equity price risk, commodity price risk, and commodity supplier risk included in the Form 10-K. ~~Regarding commodity supplier risk, in April 2016,~~In the first quarter of 2017, Ameren Missouri’s ~~primary~~ supplier of ~~ultra-low sulfur coal announced that it had~~nuclear fuel assemblies, Westinghouse, filed a voluntary petition for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believe the

restructuring proceeding will not affect ~~the supplier’s~~Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, and therefore do not expect any material impact to Ameren Missouri’s operations as a result of this restructuring proceeding. See Note 10 – Callaway Energy Center under Part I, Item 1, of this report for additional information. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risk.

Fair Value of Contracts

We use derivatives principally to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three ~~and nine~~ months ended ~~September 30, 2016.~~March 31, 2017. We use various methods to determine the

fair value of our contracts. In accordance with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). See Note 7 – Fair Value Measurements under Part I, Item 1, of this report for additional information regarding the methods used to determine the fair value of these contracts.


	Three Months									Nine Months
	Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren			Ameren Missouri			Ameren Illinois			Ameren
Fair value of contracts at beginning of period, net	$	(12	)	$	(181	)	$	(193	)	$	(27	)	$	(219	)	$	(246	)	$	(4	)	$	(180	)	$	(184	)
Contracts realized or otherwise settled during the period	2			7			9			8			35			43			(2		)	2			—
Fair value of new contracts entered into during the period	—			(1		)	(1		)	9			(1		)	8			—			(1		)	(1		)
Other changes in fair value	(3		)	(12		)	(15		)	(3		)	(2		)	(5		)	(1		)	(25		)	(26		)
Fair value of contracts outstanding at end of period, net	$	(13	)	$	(187	)	$	(200	)	$	(13	)	$	(187	)	$	(200	)	$	(7	)	$	(204	)	$	(211	)

The following table presents maturities of derivative contracts as of ~~September 30, 2016~~March 31, 2017, based on the hierarchy levels used to determine the fair value of the contracts:


Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess of 5 Years			Total Fair Value			Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess of 5 Years			Total Fair Value
Ameren Missouri:
Level 1	$	(8	)	$	(1	)	$	—		$	—		$	(9	)	$	(3	)	$	—		$	—		$	—		$	(3	)
Level 2^(a)	(3		)	(6		)	—			—			(9		)	(3		)	(5		)	—			—			(8		)
Level 3^(b)	7			(2		)	—			—			5			4			—			—			—			4
Total	$	(4	)	$	(9	)	$	—		$	—		$	(13	)	$	(2	)	$	(5	)	$	—		$	—		$	(7	)
Ameren Illinois:
Level 1	$	—		$	—		$	—		$	—		$	—		$	1		$	—		$	—		$	—		$	1
Level 2^(a)	(7		)	(8		)	—			—			(15		)	(2		)	(7		)	—			—			(9		)
Level 3^(b)	(12		)	(26		)	(27		)	(107		)	(172		)	(12		)	(28		)	(29		)	(127		)	(196		)
Total	$	(19	)	$	(34	)	$	(27	)	$	(107	)	$	(187	)	$	(13	)	$	(35	)	$	(29	)	$	(127	)	$	(204	)
Ameren:
Level 1	$	(8	)	$	(1	)	$	—		$	—		$	(9	)	$	(2	)	$	—		$	—		$	—		$	(2	)
Level 2^(a)	(10		)	(14		)	—			—			(24		)	(5		)	(12		)	—			—			(17		)
Level 3^(b)	(5		)	(28		)	(27		)	(107		)	(167		)	(8		)	(28		)	(29		)	(127		)	(192		)
Total	$	(23	)	$	(43	)	$	(27	)	$	(107	)	$	(200	)	$	(15	)	$	(40	)	$	(29	)	$	(127	)	$	(211	)


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


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

ITEM 4. CONTROLS AND PROCEDURES.


(a)	Evaluation of Disclosure Controls and Procedures

As of ~~September 30, 2016~~March 31, 2017, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those

evaluations, as of ~~September 30, 2016~~March 31, 2017, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and its principal financial officers, to allow timely decisions regarding required disclosure.


(b)	Changes in Internal Controls over Financial Reporting

There has been no change in any of the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, each of their internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings,

except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. Material legal and administrative proceedings, which are discussed in Note 2 – Rate and Regulatory Matters, Note 9 – Commitments and Contingencies, and Note 10 – Callaway Energy Center, under Part I, Item 1, of this report include the following:

Ameren ~~Missouri’s electric rate case filed with the MoPSC in July 2016;~~

~~Ameren Missouri's appeal to the Missouri Court of Appeals, Western District, regarding the calculation of the MEEIA 2013 performance incentive;~~

~~Ameren~~ Illinois’ annual electric distribution service formula rate update filed with the ICC in April ~~2016;~~2017;

ATXI’s lawsuits filed in October 2016 in the circuit courts of each of Adair, Knox, Marion, Schuyler, and Shelby counties in Missouri to obtain assents for road crossings in the counties where the Mark Twain transmission project will be constructed;

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

~~the EPA's Clean Air Act-related~~ litigation against Ameren ~~Missouri;~~Missouri related to the EPA Clean Air Act;

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

the class action lawsuit against Ameren Missouri relating to municipal taxes.

ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors disclosed in Part I, Item 1A, Risk Factors in the Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:



Period	(a) Total Number of Shares (or Units) Purchased ^(a)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1 – January 31, 2017	12,030	52.55		—	—
February 1 – February 28, 2017	—	—		—	—
March 1 – March 31, 2017	446,934	54.65		—	—
Total	458,964	$	54.59	—	—

(a)

The January shares of Ameren common stock were purchased in open-market transactions pursuant to the 2014 Incentive Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. The March shares of Ameren common stock were purchased in open-market transactions pursuant to the 2014 Incentive Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities repurchase plans or programs.

Ameren Missouri and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from ~~July~~January 1, ~~2016~~2017 to ~~September 30, 2016~~March 31, 2017.

ITEM 6. EXHIBITS.

The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.



Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Statement re: Computation of Ratios
12.1	Ameren	Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	Ameren Missouri	Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	Ameren Illinois	Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri
31.4	Ameren Missouri	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri
31.5	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois
31.6	Ameren Illinois	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	Ameren Missouri	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri
32.3	Ameren Illinois	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois
Interactive Data Files
101.INS	Ameren Companies	XBRL Instance Document
101.SCH	Ameren Companies	XBRL Taxonomy Extension Schema Document
101.CAL	Ameren Companies	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	Ameren Companies	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	Ameren Companies	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	Ameren Companies	XBRL Taxonomy Extension Definition Document

The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; Ameren Missouri, 1-2967; and Ameren Illinois, 1-3672.

Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

SIGNATURES

Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

AMEREN ILLINOIS COMPANY

(Registrant)

/s/ Martin J. Lyons, Jr.

Martin J. Lyons, Jr.

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

Date: ~~November 4, 2016~~May 5, 2017

6252



		Page
Glossary of Terms and Abbreviations		1

Forward-looking Statements		1

PART I Financial Information

Item 1.	Financial Statements (Unaudited)	3
	Ameren Corporation	3
	Consolidated Statement of Income	3
	Consolidated Statement of Comprehensive Income	4
	Consolidated Balance Sheet	5
	Consolidated Statement of Cash Flows	6
	Union Electric Company (d/b/a Ameren Missouri)	7
	Statement of Income and Comprehensive Income	7
	Balance Sheet	8
	Statement of Cash Flows	9
	Ameren Illinois Company (d/b/a Ameren Illinois)	10
	Statement of Income and Comprehensive Income	10
	Balance Sheet	11
	Statement of Cash Flows	12
	~~Combined Notes to Financial Statements~~Note 1. Summary of Significant Accounting Policies	13
	Note 2. Rate and Regulatory Matters	15
	Note 3. Short-term Debt and Liquidity	16
	Note 4. Long-term Debt and Equity Financings	17
	Note 5. Other Income and Expenses	17
	Note 6. Derivative Financial Instruments	18
	Note 7. Fair Value Measurements	21
	Note 8. Related Party Transactions	25
	Note 9. Commitments and Contingencies	26
	Note 10. Callaway Energy Center	29
	Note 11. Retirement Benefits	31
	Note 12. Segment Information	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3733
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5848
Item 4.	Controls and Procedures	5949

PART II Other Information

Item 1.	Legal Proceedings	6049
Item 1A.	Risk Factors	6050
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6050
Item 6.	Exhibits	6151

Signatures		6252


	September 30, 2016			December 31, 2015			March 31, 2017			December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	18		$	292		$	8		$	9
Accounts receivable – trade (less allowance for doubtful accounts of $19 and $19, respectively)	543			388			457			437
Unbilled revenue	240			239			228			295
Miscellaneous accounts receivable	49			98			67			63
Materials and supplies	551			538
Inventories							467			527
Current regulatory assets	107			260			118			149
Other current assets	76			88			105			113
Assets of discontinued operations	15			14
Total current assets	1,599			1,917			1,450			1,593
Property and Plant, Net	19,647			18,799
Property, Plant, and Equipment, Net							20,298			20,113
Investments and Other Assets:
Nuclear decommissioning trust fund	599			556			635			607
Goodwill	411			411			411			411
Regulatory assets	1,312			1,382			1,485			1,437
Other assets	566			575			532			538
Total investments and other assets	2,888			2,924			3,063			2,993
TOTAL ASSETS	$	24,134		$	23,640		$	24,811		$	24,699
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	431		$	395		$	681		$	681
Short-term debt	608			301			914			558
Accounts and wages payable	513			777			460			805
Taxes accrued	159			43			77			46
Interest accrued	110			89			100			93
Customer deposits	104			100			106			107
Current regulatory liabilities	87			80			144			110
Other current liabilities	252			279			280			274
Liabilities of discontinued operations	27			29
Total current liabilities	2,291			2,093			2,762			2,674
Long-term Debt, Net	6,607			6,880			6,597			6,595
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,255			3,885			4,321			4,264
Accumulated deferred investment tax credits	56			60			53			55
Regulatory liabilities	1,974			1,905			1,982			1,985
Asset retirement obligations	636			618			641			635
Pension and other postretirement benefits	499			580			768			769
Other deferred credits and liabilities	481			531			481			477
Total deferred credits and other liabilities	7,901			7,579			8,246			8,185
Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6	2			2
Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding							2			2
Other paid-in capital, principally premium on common stock	5,550			5,616			5,522			5,556
Retained earnings	1,643			1,331			1,563			1,568
Accumulated other comprehensive loss	(2		)	(3		)	(23		)	(23		)
Total Ameren Corporation shareholders’ equity	7,193			6,946			7,064			7,103
Noncontrolling Interests	142			142			142			142
Total equity	7,335			7,088			7,206			7,245
TOTAL LIABILITIES AND EQUITY	$	24,134		$	23,640		$	24,811		$	24,699


	September 30, 2016		December 31, 2015		March 31, 2017		December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	199	$	—	$	—
Advances to money pool	201		36		—		161
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $7, respectively)	272		174
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $7, respectively)					175		187
Accounts receivable – affiliates	20		54		15		12
Unbilled revenue	144		128		126		154
Miscellaneous accounts receivable	33		78		23		14
Materials and supplies	392		387
Inventories					381		392
Current regulatory assets	47		89		23		35
Other current assets	37		41		45		49
Total current assets	1,147		1,186		788		1,004
Property and Plant, Net	11,294		11,183
Property, Plant, and Equipment, Net					11,471		11,478
Investments and Other Assets:
Nuclear decommissioning trust fund	599		556		635		607
Regulatory assets	514		605		606		619
Other assets	335		321		314		327
Total investments and other assets	1,448		1,482		1,555		1,553
TOTAL ASSETS	$	13,889	$	13,851	$	13,814	$	14,035
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	431	$	266	$	431	$	431
Short-term debt					36		—
Accounts and wages payable	209		417		191		444
Accounts payable – affiliates	89		56		54		68
Taxes accrued	149		31		63		30
Interest accrued	66		59		53		54
Current regulatory liabilities	11		28		8		12
Other current liabilities	116		120		128		123
Total current liabilities	1,071		977		964		1,162
Long-term Debt, Net	3,569		3,844		3,564		3,563
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	3,003		2,844		3,017		3,013
Accumulated deferred investment tax credits	54		58		51		53
Regulatory liabilities	1,211		1,172		1,240		1,215
Asset retirement obligations	630		612		635		629
Pension and other postretirement benefits	183		234		292		291
Other deferred credits and liabilities	21		28		16		19
Total deferred credits and other liabilities	5,102		4,948		5,251		5,220
Commitments and Contingencies (Notes 2, 8, 9, and 10)
Shareholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding	511		511		511		511
Other paid-in capital, principally premium on common stock	1,824		1,822		1,828		1,828
Preferred stock	80		80		80		80
Retained earnings	1,732		1,669		1,616		1,671
Total shareholders’ equity	4,147		4,082		4,035		4,090
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	13,889	$	13,851	$	13,814	$	14,035


	Performance Share Units				Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit		Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2016	1,024,870		$	46.08
Nonvested at January 1, 2017					1,059,639		$	48.04
Granted^(a)	587,197		44.13		496,068		59.16
Forfeitures	(15,949	)	45.07		(3,192	)	49.13
Vested^(b)	(23,114	)	44.41		(3,779	)	52.88
Nonvested at September 30, 2016	1,573,004		$	45.39
Nonvested at March 31, 2017					1,548,736		$	51.59


	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated			Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2017
Average daily commercial paper outstanding													$	682		$	4		$	50		$	736
Weighted-average interest rate													1.07		%	0.93		%	0.95		%	1.06		%
Peak commercial paper during period^(a)													$	810		$	45		$	74		$	914
Peak interest rate													1.30		%	1.15		%	1.15		%	1.30		%
2016
Average daily commercial paper outstanding	$	435		$	80		$	48		$	563		$	349		$	68		$	—		$	417
Weighted-average interest rate	0.81		%	0.74		%	0.72		%	0.79		%	0.82		%	0.80		%	—		%	0.81		%
Peak commercial paper during period^(a)	$	574		$	208		$	195		$	839		$	482		$	208		$	—		$	581
Peak interest rate	0.95		%	0.85		%	0.85		%	0.95		%	0.95		%	0.85		%	—		%	0.95		%
2015
Average daily commercial paper outstanding	$	770		$	56		$	6		$	832
Weighted-average interest rate	0.56		%	0.50		%	0.44		%	0.56		%
Peak commercial paper during period^(a)	$	874		$	294		$	48		$	1,108
Peak interest rate	0.70		%	0.60		%	0.60		%	0.70		%


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2016		2015		2016		2015		2017		2016
Operating Revenues:
Electric	$	1,725	$	1,700	$	4,101	$	4,093	$	1,206	$	1,102
Gas	134		133		619		697		308		332
Total operating revenues	1,859		1,833		4,720		4,790		1,514		1,434
Operating Expenses:
Fuel	205		259		574		670		206		203
Purchased power	178		153		451		393		180		138
Gas purchased for resale	34		38		227		320		130		152
Other operations and maintenance	411		428		1,246		1,256		405		400
Provision for Callaway construction and operating license (Note 2)	—		—		—		69
Depreciation and amortization	211		201		628		594		221		207
Taxes other than income taxes	129		128		358		369		118		114
Total operating expenses	1,168		1,207		3,484		3,671		1,260		1,214
Operating Income	691		626		1,236		1,119		254		220
Other Income and Expense:
Other Income and Expenses:
Miscellaneous income	18		19		54		54		15		20
Miscellaneous expense	8		5		21		22		9		7
Total other income	10		14		33		32		6		13
Interest Charges	97		87		287		264		99		95
Income Before Income Taxes	604		553		982		887		161		138
Income Taxes	233		208		356		333		57		31
Income from Continuing Operations	371		345		626		554
Income from Discontinued Operations, Net of Taxes	—		—		—		52
Net Income	371		345		626		606		104		107
Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests	2		2		5		5
Net Income Attributable to Ameren Common Shareholders:
Continuing Operations	369		343		621		549
Discontinued Operations	—		—		—		52
Less: Net Income Attributable to Noncontrolling Interests									2		2
Net Income Attributable to Ameren Common Shareholders	$	369	$	343	$	621	$	601	$	102	$	105

Earnings per Common Share – Basic:
Continuing Operations	$	1.52	$	1.42	$	2.56	$	2.27
Discontinued Operations	—		—		—		0.21
Earnings per Common Share – Basic	$	1.52	$	1.42	$	2.56	$	2.48

Earnings per Common Share – Diluted:
Continuing Operations	$	1.52	$	1.41	$	2.56	$	2.26
Discontinued Operations	—		—		—		0.21
Earnings per Common Share – Diluted	$	1.52	$	1.41	$	2.56	$	2.47
Earnings per Common Share – Basic and Diluted									$	0.42	$	0.43

Dividends per Common Share	$	0.425	$	0.41	$	1.275	$	1.23	$	0.44	$	0.425
Average Common Shares Outstanding – Basic	242.6		242.6		242.6		242.6		242.6		242.6
Average Common Shares Outstanding – Diluted	242.9		243.9		243.0		243.8


(a)	Performance share units granted to certain executive and nonexecutive officers and other eligible employees under the 2014 Incentive Plan.


(a)	The timing of peak commercial paper issuances varies by ~~company; therefore,~~company. Therefore, the sum of peak ~~amounts~~commercial paper issuances presented by company ~~might~~does not equal the Ameren Consolidated peak commercial paper issuances for the period.



	Required Interest Coverage Ratio^(a)	Actual Interest Coverage Ratio		Bonds Issuable^(b)		Required Dividend Coverage Ratio^(c)	Actual Dividend Coverage Ratio		Preferred Stock Issuable
Ameren Missouri	≥2.0	4.7	$	3,838		≥2.5	105.9	$	2,357
Ameren Illinois	≥2.0	7.3		3,942	^(d)	≥1.5	3.0		203	^(e)


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


	Quantity (in millions, except as indicated)						Quantity (in millions, except as indicated)
	2016			2015			2017			2016
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)^(a)	25	(b)	25	35	(b)	35	36	(b)	36	30	(b)	30
Natural gas (in mmbtu)	26	128	154	30	151	181	28	149	177	25	129	154
Power (in megawatthours)	1	9	10	1	10	11	1	9	10	1	9	10
Uranium (pounds in thousands)	445	(b)	445	494	(b)	494	345	(b)	345	345	(b)	345


	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren		Balance Sheet Location	Ameren Missouri			Ameren Illinois		Ameren
2016
2017								2017
Fuel oils	Other assets	$	1	$	—	$	1	Other current assets	$	1		$	—	$	1
								Other assets	1			—		1
Natural gas	Other current assets	—		2		2		Other current assets	—			5		5
	Other assets	—		1		1
Power	Other current assets	11		—		11		Other current assets	5			—		5
	Total assets ^(a)	$	12	$	3	$	15	Total assets ^(a)	$	7		$	5	$	12
Fuel oils	Other current liabilities	$	8	$	—	$	8	Other current liabilities	$	5		$	—	$	5
	Other deferred credits and liabilities	1		—		1
Natural gas	MTM derivative liabilities	(b)		9		(b)		MTM derivative liabilities	(b)			6		(b)
	Other current liabilities	3		—		12		Other current liabilities	2			—		8
	Other deferred credits and liabilities	6		9		15		Other deferred credits and liabilities	6			9		15
Power	MTM derivative liabilities	(b)		12		(b)		MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	2		—		14		Other current liabilities	1			—		13
	Other deferred credits and liabilities	—		160		160		Other deferred credits and liabilities	—			182		182
Uranium	Other current liabilities	2		—		2		Other deferred credits and liabilities	—		^(c)	—		—		^(c)
	Other deferred credits and liabilities	3		—		3		Total liabilities ^(d)	$	14		$	209	$	223
2016								2016
Fuel oils								Other current assets	$	2		$	—	$	2
	Total liabilities ^(c)	$	25	$	190	$	215	Other assets	1			—		1
2015
Natural gas	Other current assets	$	—	$	1	$	1	Other current assets	1			11		12
	Other assets	1		—		1		Other assets	1			2		3
Power	Other current assets	16		—		16		Other current assets	9			—		9
	Total assets ^(a)	$	17	$	1	$	18	Total assets ^(a)	$	14		$	13	$	27
Fuel oils	Other current liabilities	$	22	$	—	$	22	Other current liabilities	$	5		$	—	$	5
	Other deferred credits and liabilities	7		—		7
Natural gas	MTM derivative liabilities	(b)		32		(b)		MTM derivative liabilities	(b)			3		(b)
	Other current liabilities	6		—		38		Other current liabilities	1			—		4
	Other deferred credits and liabilities	8		18		26		Other deferred credits and liabilities	5			5		10
Power	MTM derivative liabilities	(b)		13		(b)		MTM derivative liabilities	(b)			12		(b)
	Other current liabilities	—		—		13		Other current liabilities	3			—		15
	Other deferred credits and liabilities	—		157		157		Other deferred credits and liabilities	—			173		173
Uranium	Other current liabilities	1		—		1		Other deferred credits and liabilities	4			—		4
	Total liabilities ^(c)	$	44	$	220	$	264	Total liabilities ^(d)	$	18		$	193	$	211


(a)	The cumulative amount of pretax net gains on all derivative instruments is deferred as a regulatory liability.


(c)	Beginning in 2017, as a result of rulebook amendments at the Chicago Mercantile Exchange, the fair value of uranium derivative liabilities are offset by certain settlement payments made to the exchange previously characterized as collateral and included within “Other assets” on Ameren’s and Ameren Missouri’s balance sheet.


(d)	The cumulative amount of pretax net losses on all derivative instruments is deferred as a regulatory asset.



			Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted^(a)		Net Amount
2016
Assets:
Ameren Missouri	$	12	$	2	$	—	$	10
Ameren Illinois	3		2		—		1
Ameren	$	15	$	4	$	—	$	11
Liabilities:
Ameren Missouri	$	25	$	2	$	5	$	18
Ameren Illinois	190		2		—		188
Ameren	$	215	$	4	$	5	$	206
2015
Assets:
Ameren Missouri	$	17	$	1	$	—	$	16
Ameren Illinois	1		—		—		1
Ameren	$	18	$	1	$	—	$	17
Liabilities:
Ameren Missouri	$	44	$	1	$	8	$	35
Ameren Illinois	220		—		3		217
Ameren	$	264	$	1	$	11	$	252


~~(a)~~	Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.


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


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


(b)	Balance excludes ~~$(1)~~$2 million of receivables, payables, and accrued income, net.


(a)	Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.


(a)	~~Primarily includes amounts for ATXI and intercompany eliminations.~~Includes an increase in transmission margins of $9 million at Ameren Illinois.


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


~~(c)~~(d)	Electric and natural gas revenue changes are offset by corresponding changes in Fuel, Purchased power, and ~~Gas~~Natural gas purchased for resale, resulting in no change to electric and natural gas margins.


~~(d)~~(e)	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.


	Net Cash Provided By (Used In) Operating Activities								Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities									Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2016		2015			Variance			2016			2015			Variance			2016			2015			Variance			2017		2016		Variance			2017			2016			Variance			2017			2016			Variance
Ameren^(a) – continuing operations	$	1,559	$	1,547		$	12		$	(1,551	)	$	(1,362	)	$	(189	)	$	(282	)	$	(113	)	$	(169	)
Ameren^(a) – discontinued operations	—		(5		)	5			—			—			—			—			—			—
Ameren^(a)																											$	331	$	349	$	(18	)	$	(539	)	$	(510	)	$	(29	)	$	207		$	(118	)	$	325
Ameren Missouri	888		1,040			(152		)	(724		)	(739		)	15			(362		)	(233		)	(129		)	93		169		(76		)	(68		)	(170		)	102			(25		)	(198		)	173
Ameren Illinois	627		541			86			(679		)	(615		)	(64		)	(16		)	73			(89		)	212		229		(17		)	(227		)	(269		)	42			15			(31		)	46



	Month Issued, Redeemed, or Matured	2016		2015
Issuances of Long-term Debt
Ameren Missouri:
3.65% Senior secured notes due 2045	June	$	149	$	—
3.65% Senior secured notes due 2045	April	—		249
Total Ameren long-term debt issuances		$	149	$	249
Redemptions 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
Ameren Illinois:
6.20% Senior secured notes due 2016	June	54		—
6.25% Senior secured notes due 2016	June	75		—
Total Ameren long-term debt redemptions and maturities		$	389	$	114