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

BALANCE SHEET

(Unaudited) (In millions)

September 30, 2017 December 31, 2016
ASSETS
Current Assets:
Cash and cash equivalents $ —
$ —
Accounts receivable – trade (less allowance for doubtful accounts of $12 and $12, respectively) 219
242
Accounts receivable – affiliates 21
10
Unbilled revenue 111
141
Miscellaneous accounts receivable 31
22
Inventories 151
135
Current regulatory assets 51
108
Other current assets 18
25
Total current assets 602
683
Property, Plant, and Equipment, Net 7,987
7,469
Investments and Other Assets:
Goodwill 411
411
Regulatory assets 921
816
Other assets 101
95
Total investments and other assets 1,433
1,322
TOTAL ASSETS $ 10,022
$ 9,474
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt $ 394
$ 250
Short-term debt 169
51
Borrowings from money pool 11
—
Accounts and wages payable 247
264
Accounts payable – affiliates 50
63
Taxes accrued 8
16
Interest accrued 37
33
Customer deposits 69
69
Current environmental remediation 43
38
Current regulatory liabilities 85
78
Other current liabilities 153
109
Total current liabilities 1,266
971
Long-term Debt, Net 2,196
2,338
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net 1,874
1,631
Accumulated deferred investment tax credits 1
2
Regulatory liabilities 766
768
Pension and other postretirement benefits 322
346
Environmental remediation 143
162
Other deferred credits and liabilities 229
222
Total deferred credits and other liabilities 3,335
3,131
Commitments and Contingencies (Notes 2, 8, and 9)

Shareholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding —
—
Other paid-in capital 2,005
2,005
Preferred stock 62
62
Retained earnings 1,158
967
Total shareholders’ equity 3,225
3,034
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 10,022
$ 9,474

~~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)~~

Nine Months Ended September 30,
2017 2016
Cash Flows From Operating Activities:
Net income $ 193
$ 225
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 254
236
Amortization of debt issuance costs and premium/discounts 10
11
Deferred income taxes and investment tax credits, net 161
141
Other (1 ) (8 )
Changes in assets and liabilities:
Receivables 59
(36 )
Inventories (17 ) (8 )
Accounts and wages payable (24 ) (17 )
Taxes accrued (22 ) 5
Regulatory assets and liabilities 45
75
Assets, other (9 ) 11
Liabilities, other (2 ) 6
Pension and other postretirement benefits (19 ) (14 )
Net cash provided by operating activities 628
627
Cash Flows From Investing Activities:
Capital expenditures (760 ) (683 )
Other 6
4
Net cash used in investing activities (754 ) (679 )
Cash Flows From Financing Activities:
Dividends on common stock —
(95 )
Dividends on preferred stock (2 ) (2 )
Short-term debt, net 118
157
Money pool borrowings, net 11
54
Maturities of long-term debt —
(129 )
Other (1 ) (1 )
Net cash provided by (used in) financing activities 126
(16 )
Net change in cash and cash equivalents —
(68 )
Cash and cash equivalents at beginning of year —
71
Cash and cash equivalents at end of period $ —
$ 3


	March 31, 2021		December 31, 2020
ASSETS
Current Assets:
Cash and cash equivalents	$	0	$	0

Accounts receivable – trade (less allowance for doubtful accounts of $32 and $34, respectively)	293		234
Accounts receivable – affiliates	71		64
Unbilled revenue	101		136
Miscellaneous accounts receivable	5		12
Inventories	105		135
Restricted cash	125		6
Current regulatory assets	217		37

Other current assets	24		23
Total current assets	941		647
Property, Plant, and Equipment, Net	11,358		11,201
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	820		742
Other assets	442		534
Total investments and other assets	1,673		1,687
TOTAL ASSETS	$	13,972	$	13,535
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:

Short-term debt	$	323	$	0
Borrowings from money pool	0		19
Accounts and wages payable	255		363
Accounts payable – affiliates	43		51


Customer deposits	70		74


Current regulatory liabilities	200		88
Other current liabilities	207		221
Total current liabilities	1,098		816
Long-term Debt, Net	3,947		3,946
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net	1,430		1,367

Regulatory liabilities	1,988		2,063
Pension and other postretirement benefits	67		69
Environmental remediation	51		57
Other deferred credits and liabilities	249		251
Total deferred credits and other liabilities	3,785		3,807
Commitments and Contingencies (Notes 2, 8 and 9)	0		0
Shareholders' Equity:
Common stock, 0 par value, 45.0 shares authorized – 25.5 shares outstanding	0		0
Other paid-in capital	2,692		2,652
Preferred stock	49		62
Retained earnings	2,401		2,252

Total shareholders' equity	5,142		4,966
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	13,972	$	13,535

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)


	Three Months Ended March 31,
	2021		2020
Cash Flows From Operating Activities:
Net income	$	150	$	121
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	115		106
Amortization of debt issuance costs and premium/discounts	3		2
Deferred income taxes and investment tax credits, net	53		22

Other	3		(2)
Changes in assets and liabilities:
Receivables	(24)		(6)
Inventories	30		41
Accounts and wages payable	(40)		(20)
Taxes accrued	3		16
Regulatory assets and liabilities	(255)		(28)
Assets, other	(15)		(4)
Liabilities, other	(9)		(14)
Pension and other postretirement benefits	(1)		(2)


Net cash provided by operating activities	13		232
Cash Flows From Investing Activities:
Capital expenditures	(337)		(324)

Other	0		1
Net cash used in investing activities	(337)		(323)
Cash Flows From Financing Activities:

Dividends on preferred stock	(1)		(1)
Short-term debt, net	323		7
Money pool borrowings, net	(19)		0



Capital contributions from parent	40		100
Redemption of preferred stock	(13)		0


Other	(4)		0
Net cash provided by financing activities	326		106
Net change in cash, cash equivalents, and restricted cash	2		15
Cash, cash equivalents and restricted cash at beginning of year	147		125
Cash, cash equivalents, and restricted cash at end of period	$	149	$	140

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 SHAREHOLDERS’ EQUITY

(Unaudited) (In millions)


	Three Months Ended March 31,
		2021		2020
Common Stock		$	0	$	0

Other Paid-in Capital:
Beginning of year		2,652		2,188
Capital contribution from parent		40		100

Other paid-in capital, end of period		2,692		2,288


Preferred Stock:
Beginning of year		62		62
Redemptions of preferred stock		(13)		0

Preferred stock, end of period		49		62

Retained Earnings:
Beginning of year		2,252		1,882
Net income		150		121

Dividends on preferred stock		(1)		(1)

Retained earnings, end of period		2,401		2,002














Total Shareholders’ Equity		$	5,142	$	4,352

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, 2017~~March 31, 2021

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries ~~Ameren Missouri, Ameren Illinois, and ATXI,~~ are ~~described~~listed below. Ameren ~~also~~ has other subsidiaries that conduct other activities, such as ~~the provision of~~providing shared services. ~~Ameren evaluates 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 distribution business in Missouri.

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

•ATXI operates a FERC rate-regulated electric transmission ~~business. ATXI~~business in the MISO.

We continue to assess the impacts the COVID-19 pandemic is ~~developing MISO-approved~~having on our businesses, including but not limited to impacts on our liquidity; demand for residential, commercial, and industrial electric and natural gas services; changes in deferred payment arrangements for customers; the timing and extent to which recovery of incremental costs incurred, net of savings, and forgone customer late fee revenues at Ameren Missouri is allowed by the MoPSC; changes in our ability to disconnect customers for nonpayment; bad debt expense; supply chain operations; the availability of our employees and contractors; counterparty credit; capital construction; infrastructure operations and maintenance; energy-efficiency programs; and pension valuations. In March 2021, the MoPSC approved accounting authority orders that allowed Ameren Missouri to accumulate $9 million of certain costs incurred related to the COVID-19 pandemic, net of savings, as well as forgone customer late fees and reconnection fee revenues from March 2020 to March 2021, for potential recovery in the current electric and natural gas service regulatory rate reviews. While the revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission ~~projects, including~~businesses are decoupled from changes in sales volumes, earnings at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers are exposed to such changes. Regarding uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri does not expect a material impact to earnings from increases in bad debt expense. As of March 31, 2021, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 27%, 19%, and 32%, or $137 million, $33 million, and $104 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. As of March 31, 2020, these percentages were 21%, 16%, and 25%, or $99 million, $29 million, and $70 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. For information regarding Ameren Illinois’ suspension and subsequent reinstatement of customer disconnections and late fee charges for nonpayment and Ameren Missouri’s accounting authority orders related to the ~~Illinois Rivers, Spoon River,~~COVID-19 pandemic, see Note 2 – Rate and ~~Mark Twain projects.~~

Regulatory Matters below.

Ameren’s financial statements are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri and Ameren Illinois have no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated. ~~Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.~~

As of September 30, 2017 and December 31, 2016, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, totaling $14 million and $9 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly impact the activities of these variable interest entities. As of September 30, 2017, the maximum exposure to loss related to these variable interests is limited to the investment in these partnerships of $14 million plus associated outstanding funding commitments of $23 million.

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~~accompanying notes ~~thereto~~ included in the Form 10-K.

~~Discontinued operations were immaterial to all periods presented in Ameren’s financial statements.~~ Variable Interest Entities

As ~~such, the “Assets~~ of ~~discontinued operations”~~March 31, 2021, and ~~“Liabilities of discontinued operations” included on the~~ December 31, ~~2016 balance sheet have been reclassified~~2020, Ameren had unconsolidated variable interests as a limited partner in ~~this report to~~various equity method investments, totaling $41 million and $37 million, respectively, included in “Other ~~current~~ assets” ~~and “Other current liabilities,” respectively. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information.~~

~~Asset Retirement Obligations~~

~~The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the nine months ended September 30, 2017:~~

Ameren
Missouri

Ameren
Illinois^(a)
Ameren
Balance at December 31, 2016 $ 644
^(b)
$ 6
$ 650
^(b)
Liabilities settled (4 ) (1 ) (5 )
Accretion^(c)
20
(d)
20

Change in estimates^(e)
(18 ) (1 ) (19 )
Balance at September 30, 2017 $ 642
^(b)
$ 4
$ 646
^(b)


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


~~(b)~~	~~Balance included $15 million in “Other current liabilities” on the balance sheet as of both December 31, 2016 and September 30, 2017, respectively.~~


~~(c)~~	~~Accretion expense was recorded as a decrease to regulatory liabilities.~~


~~(d)~~	~~Less than $1 million.~~


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

~~Share-based Compensation~~

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

Performance Share Units
Share Units Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017 1,059,639
$ 48.04
Granted^(a)
500,943
59.16
Forfeitures (48,661 ) 52.54
Vested^(b)
(27,446 ) 52.88
Nonvested at September 30, 2017 1,484,475
$ 51.55


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


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

~~The fair value of each performance share unit awarded in 2017 under the 2014 Incentive Plan was determined to be~~ ~~$59.16, which was based~~ on Ameren’s ~~closing common share price~~consolidated balance sheet. Ameren is not the primary beneficiary of ~~$52.46~~ at ~~December~~these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of March 31, ~~2016, and lattice simulations. Lattice simulations are used~~2021, the maximum exposure to ~~estimate expected share payout based on Ameren’s total shareholder return for a~~ ~~three-year performance period beginning January 1, 2017, relative~~loss related to these variable interests is limited to the designated peer 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 scenariosinvestment 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~~these partnerships of ~~1.47%, volatility~~$41 million plus associated outstanding funding commitments of ~~15%~~ to ~~21%~~ ~~for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.~~$33 million.

~~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 from the end of the year.

~~Excise Taxes~~Company-owned Life Insurance

Ameren ~~Missouri~~ and Ameren Illinois ~~collect certain excise taxes from customers~~have company-owned life insurance, which is recorded at the net cash surrender value. The net cash surrender value is the amount that ~~are levied on~~can be realized under the ~~sale or distribution~~insurance policies at the balance sheet date. As 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 – Natural gas” and “Operating Expenses – Taxes other than income taxes” onMarch 31, 2021, the ~~statement~~cash surrender value 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 not included in Ameren Illinois’ revenues and expenses. The following table presents

excise taxes recorded in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” for the three and nine months ended September 30, 2017 and ~~2016~~:

Three Months Nine Months
2017 2016 2017 2016
Ameren Missouri $ 51
$ 52
$ 122
$ 122
Ameren Illinois 10
9
40
40
Ameren $ 61
$ 61
$ 162
$ 162

~~Earnings Per Share~~

Basic earnings per share is computed by dividing “Net Income Attributable to Ameren Common Shareholders” by the weighted-average number 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 dilution that would occur if certain stock-based performance share units were settled. The number of performance share units assumed to be settled was 2.1 million and 1.4 million in the three and nine months ended September 30, 2017, respectively, and 0.3 million and 0.4 million, respectively, in the year-ago periods. There were no potentially dilutive securities excluded from the earnings per diluted share calculations for the three and nine months ended September 30, 2017 and 2016.

~~Income Taxes~~

~~In July 2017, Illinois enacted a law that increased the state's corporate income tax rate from 7.75% to 9.5% as of July 1, 2017. The law made the increase in the state’s corporate income taxrate, which was previously scheduled to decrease to 7.3% in 2025, permanent. In July 2017, Ameren recorded an expense of $14 million~~company-owned life insurance at Ameren ~~(parent) due~~and Ameren Illinois was $275 million (December 31, 2020 – $272 million) and $117 million (December 31, 2020 – $115 million), respectively, while total borrowings against the policies were $107 million (December 31, 2020 – $107 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the ~~revaluation of accumulated deferred taxes and~~borrowings against the estimated state apportionment of such taxes. Beyond this expense, Ameren does not expect this tax increase to have a material impact on its consolidated net income prospectively. The tax increase is not expected to materially impact the earningscash surrender value of the Ameren Illinois Electric Distribution, the Ameren Transmission, or the Ameren Illinois Transmission segments, since these businesses operate under formula ratemaking frameworks. The tax increase is expected to unfavorably affect 2017 net income of the Ameren Illinois Natural Gas segment by less than $1 million. In addition, in the third quarter of 2017, Ameren’spolicies and, Ameren Illinois’ accumulated deferred tax balances were revalued using the state’s new corporate income tax rate, which resulted in a net increase to the liability balances of $97 million and $79 million, respectively. These increased liabilities were offset by a regulatory asset, as well as income tax expense, as discussed above.

~~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 relating to leases, financial instruments, and restricted cash.

~~Revenue from Contracts with Customers~~

In May 2014, the FASB issued authoritative 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 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, as well as separate presentation of alternative revenue programs on the income statement. Entities can apply the guidance to each reporting period presented (the full retrospective method) or by recording a cumulative effect adjustment to retained earnings in the period of initial adoption (the modified retrospective method).

We have substantially completed the evaluation of our contracts and do not expect material changes to the amount or timing of revenue recognition. We will finalize our contract assessments by the end of 2017. We will apply the guidance using the full retrospective method and include disaggregated revenue disclosures by segment and customer class in the combined notes to the financial statements in the first quarter of 2018.

~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~

In March 2017, the FASB issued authoritative guidance that requires an entity to retrospectively report the 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 period and toconsequently, present the ~~other components of~~ net ~~benefit cost~~asset 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,“Other assets” on ~~a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization.~~their respective balance sheets.

This change in the capitalization of net benefit costs will not affect our ability to continue to obtain recovery of net benefit costs through customer rates. See Note 11 – Retirement Benefits for the components of net benefit cost. This guidance will be effective for the Ameren Companies in the first quarter of 2018. We are currently assessing the impacts of this guidance on our results of operations, financial position, and disclosures.

NOTE 2 – RATE AND REGULATORY MATTERS

Below is a summary of updates to significant regulatory proceedings and related ~~lawsuits.~~legal proceedings. See ~~also~~ Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form ~~10-K.~~10-K for additional information and a summary of our regulatory frameworks. 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

~~March 2017~~2021 Electric Service Regulatory Rate ~~Order~~Review

In March ~~2017,~~2021, Ameren Missouri filed a request with the MoPSC issued an order approving a unanimous stipulation and agreement in Ameren Missouri’s July 2016 regulatory rate review. The order resulted in a $3.4 billion revenue requirement, which is a $92 millionseeking approval to increase ~~in Ameren Missouri’s~~its annual ~~revenue requirement~~revenues for electric service ~~compared to its prior revenue requirement established in the MoPSC's April 2015~~by $299 million. The electric rate ~~order. The new rates,~~increase request is based on a 9.9% ROE, a capital structure composed of 51.9% common equity, a rate base ~~level~~ of ~~expenses,~~$10.0 billion, and ~~amortizations became effective on April 1, 2017.~~

~~The order authorized~~a test year ended December 31, 2020, with certain pro-forma adjustments expected through an anticipated true-up date of September 30, 2021. Ameren Missouri also requested the continued use of the FAC and ~~the regulatory tracking mechanisms~~trackers for pension and postretirement benefits, uncertain income tax positions, and ~~renewable energy standards~~certain excess deferred income taxes that the MoPSC previously authorized in earlier electric rate orders. ~~These~~Additionally, Ameren Missouri requested to recover certain estimated costs associated with the Meramec Energy Center, which is expected to be retired in 2022, over a five-year period. Ameren Missouri requested the use of a tracker for any variances between certain costs collected in customer rates associated with the Meramec Energy Center and actual costs incurred after the date new rates become effective, which would be considered for recovery or refund in a future electric regulatory ~~tracking mechanisms provide~~rate review. The electric rate increase request reflects the following:

•increased infrastructure investments made under Ameren Missouri’s Smart Energy Plan;

•the impact of the transition to a cleaner generation portfolio, including advancing the retirement dates of the Sioux and Rush Island energy centers consistent with Ameren Missouri’s 2020 IRP and 700 MWs of wind generation investment for the High Prairie and Atchison renewable energy centers, which are mitigated by reductions resulting from the request to recover certain Meramec Energy Center costs over a ~~base~~five-year period and the associated tracker;

•decreased weather-normalized customer sales volumes; and

•increased pension and other post-retirement benefits and tax amortization expenses, partially offset by decreased other operations and maintenance expenses.

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 February 2022 and new rates effective by March 2022. Ameren Missouri cannot predict the level of ~~expense~~any electric service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be approved, or whether

any rate change 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 rate change goes into effect.

Wind Generation Facility

In January 2021, Ameren Missouri acquired an up-to 300-MW wind generation project located in northwestern Missouri and partially placed it in service as the Atchison Renewable Energy Center. As of the date of this filing, Ameren Missouri has placed approximately half of the project in service, representing a purchase price of approximately $250 million, including an immaterial amount of transaction costs. Ameren Missouri expects the remaining MWs of the project to be ~~reflected~~ in service by the end of September 2021. The Atchison Renewable Energy Center will support Ameren Missouri’s compliance with the Missouri renewable energy standard.

2021 Natural Gas Delivery Service Regulatory Rate Review

In March 2021, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for natural gas delivery service by $9 million. The natural gas rate increase request is based on a 9.8% ROE, a capital structure composed of 51.9% common equity, a rate base of $310 million, and a test year ended December 31, 2020, with certain pro-forma adjustments expected through an anticipated true-up date of September 30, 2021. The request includes the continued use of the PGA, ISRS, and DCA and trackers for pension and other postretirement benefits and certain excess deferred taxes that the MoPSC previously authorized in earlier natural gas rate orders.

The MoPSC proceeding relating to the proposed natural gas delivery service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by February 2022 and new rates effective by March 2022. Ameren Missouri cannot predict the level of any natural gas delivery service rate change the MoPSC may approve, or whether any rate change 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 rate change goes into effect.

Accounting Authority Orders Related to COVID-19 Pandemic Costs

In March 2021, the MoPSC issued orders approving nonunanimous stipulation and agreements related to Ameren Missouri’s electric ~~rates with differences~~and natural gas service accounting authority order requests. The orders allowed Ameren Missouri to accumulate $9 million of certain costs incurred related to the COVID-19 pandemic, net of cost savings, as well as forgone customer late fee and reconnection fee revenues from March 2020 to March 2021, for potential recovery in the ~~actual~~electric and natural gas service regulatory rate reviews discussed above. As of March 31, 2021, Ameren Missouri deferred other operations and maintenance expenses ~~incurred recorded~~of $5 million as a regulatory asset ~~or liability. Excluding cost reductions~~related to the accounting authority orders. If approved for recovery, Ameren Missouri would recognize the remaining $4 million associated with ~~reduced sales volumes, the base level of net energy costs decreased by $54 million from the base level established in the MoPSC's April 2015 electric rate order. Changes in amortizations~~forgone customer late fee and the base level of expenses for the other regulatory tracking mechanisms, including extending the amortization period of certain regulatory assets, reduced expenses by $26 million from the base levels established in the MoPSC's April 2015 electric rate order.

~~ATXI’s Mark Twain Project~~

~~The Mark Twain project is a MISO-approved transmission line~~reconnection fee revenue when billed to be located in northeast Missouri. In the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with a cooperative electric company in northeast Missouri and Ameren Missouri to locate nearly all of the Mark Twain project on existing transmission line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. ATXI had previously filed suit in the circuit courts to obtain assents for the original project route. ATXI has since withdrawn one of the lawsuits. The other lawsuits remain pending but have been stayed until the first quarter of 2018. In September 2017, ATXI filed for a certificate of convenience and necessity with the MoPSC and anticipates a decision from the MoPSC in the first half of 2018. ATXI plans to complete the project in December 2019; however, delays in obtaining approval from the MoPSC could delay completion.customers.

Illinois

~~IEIMA & FEJA~~

Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity under a formula ratemaking process effective through 2022. This formula ratemaking framework 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 and investment return. As of September 30, 2017, Ameren Illinois had recorded regulatory assets of $24 million to reflect its 2016 revenue requirement reconciliation adjustment, which was included in the April 2017 formula rate update discussed below, and $16 million for the approved 2015 revenue requirement reconciliation adjustment, each with interest. As of September 30, 2017, Ameren Illinois had recorded a regulatory liability of $1 million to reflect the difference between Ameren Illinois’ estimate of its 2017 revenue requirement and the revenue requirement reflected in customer rates, including interest.Electric Distribution Service Rates

In April ~~2017,~~2021, Ameren Illinois filed ~~with the ICC~~ its annual electric distribution service performance-based formula rate update ~~to establish the revenue requirement used for 2018 rates. In June 2017,~~with the ICC, ~~staff submitted its calculation~~requesting an increase of ~~the revenue requirement, which Ameren Illinois supported~~$64 million in its revised July 2017 filing, and recommended a decrease to the electric distribution service revenue requirement. Pending ICC approval, this update filing will result in a $17 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018.rates. This update reflects an increase to the annual performance-based formula rate based on ~~2016~~2020 actual costs, ~~and expected net plant additions for 2017, as well as~~ an increase to include the ~~2016~~2020 revenue requirement reconciliation ~~adjustment. The increases in the update filing are more than offset by a decrease~~adjustment, and an increase for the conclusion of the ~~2015~~2019 revenue requirement reconciliation adjustment, which will be fully ~~collected from~~

refunded to customers in ~~2017,~~2021, consistent with the ICC’s December ~~2016~~2020 annual update filing order. ~~In November 2017,~~It also reflects an ~~administrative law judge issued a proposed order that was consistent with Ameren Illinois’ revised July 2017 filing.~~increase based on expected net plant additions for 2021. An ICC decision ~~regarding the revenue requirement to be used for customer rates~~ in ~~2018~~this proceeding is expected by December ~~2017.~~2021, with new rates effective January 2022.

~~The FEJA revised certain portions of~~Electric Distribution Service Rate Reconciliation Tariff

In March 2021, the ~~IEIMA, including extending the IEIMA formula ratemaking process through 2022 and clarifying that a common equity ratio of up~~ICC issued an order approving Ameren Illinois’ requested tariff to ~~and including, 50% is prudent. Beginning in 2017, the FEJA provides that Ameren Illinois will recover, within the following two years,~~reconcile its electric distribution service revenue requirement for a ~~given~~period of up to two years after the final customer rate update under performance-based formula ratemaking. To utilize the reconciliation, the ICC-approved tariff requires Ameren Illinois to file a traditional regulatory rate review for its electric distribution service, which may be based on a future test year, ~~independent~~by the end of ~~actual sales volumes. Prior~~March in the year following the last year in which an annual performance-based formula rate update was permitted. Pursuant to ~~the FEJA,~~this order, and without legislative change or Ameren Illinois’ ~~interim period revenue recognition was volume-based, as~~election to no longer use performance-based formula ratemaking, Ameren Illinois’ 2022 and 2023 revenues ~~were affected by~~would reflect each year’s actual costs, year-end rate base, and a return at 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 connectionapplicable WACC, with the ~~decoupling provisions~~ROE based on the annual average of the ~~FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois now recognizes revenue consistent with~~monthly yields of the timing of actual incurred electric distribution recoverable costs and recognizes revenue associated with the expected return on its rate base ratably over the year. Ameren Illinois recognized a reduction to electric revenue to reflect the difference between the estimate of its30-year United States Treasury bonds plus 580 basis points. The revenue requirement ~~and~~adjustment will be collected from, or refunded to, customers within two years from the ~~revenue requirement reflected in customer rates~~end of ~~$76 million and $1 million for~~ the three and nine months ended September 30, 2017, respectively. Comparative electric revenues at Ameren Illinois for the three and nine months ended September 30, 2016, were increased $11 million and $24 million, respectively, for the difference between the estimate of its revenue requirement and the revenue requirement reflected in customer rates.reconciled year.

Electric Energy Efficiency Plan

In ~~June 2017, pursuant to the FEJA,~~March 2021, Ameren Illinois filed with the ICC an ~~energy efficiency~~energy-efficiency plan ~~for 2018 through 2021. In September 2017, the ICC issued an order approving Ameren Illinois' implementation of FEJA~~which includes annual investments in electric ~~energy efficiency savings targets and investments. Ameren Illinois plans to invest~~energy-efficiency programs up to ~~$99~~approximately $100 million ~~in electric energy efficiency programs~~ per year from ~~2018~~2022 through ~~2021 that will earn a return.~~2025. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric ~~energy efficiency~~energy-efficiency program investments and the return on those investments ~~will be~~are collected from customers through a rider and ~~will~~are not be included in the ~~IEIMA~~electric distribution service performance-based formula ratemaking ~~process.~~framework. A decision by the ICC in this proceeding is expected by September 2021.

~~ATXI’s Illinois Rivers Project~~QIP Reconciliation Order

In ~~August 2017,~~March 2021, the ICC issued an order approving Ameren Illinois’ QIP reconciliation for 2018. The ICC also found that Ameren Illinois’ natural gas capital investments recovered under the QIP during 2018 were accurate and prudent. The ICC order effectively dismissed the Illinois ~~Circuit Court~~Attorney General’s challenge with respect to 2018 capital investments.

Service Disconnection Moratorium

From March 2020 through March 2021, the ICC limited disconnection activities and late fees for ~~Edgar County dismissed several of ATXI’s condemnation cases~~customer nonpayment to varying degrees based on customer class. In March 2021, the ICC issued an order allowing Ameren Illinois to resume disconnection activities for all residential customers through a phased-in approach, which began in April 2021 for customers with the largest past due balances and will resume by June 2021 for all remaining residential customers. The March 2021 order also requires Ameren Illinois to offer deferred payment arrangements, extending to 18 months, to all residential customers through June 2021. In addition, the order requires Ameren Illinois to extend the financial assistance program established by a June 2020 ICC order through 2021. Ameren Illinois is allowed to recover up to $4 million in costs incurred during 2021 related to ~~one segment~~this financial assistance program. These costs will be deferred as regulatory assets and the portion associated with Ameren Illinois’ electric distribution business will be recovered through its bad debt rider and the portion associated with its natural gas distribution business will be recovered through a special purpose rider.

Federal

Transmission Formula Rate Revisions

In February 2020, the MISO, on behalf of Ameren Missouri, Ameren Illinois, and ATXI, filed requests with the FERC to revise each company’s transmission formula rate calculations with respect to the calculation used for materials and supplies inventories included in rate base. In May 2020, the FERC issued orders approving the revisions prospectively. In addition, the FERC declined to order refunds for earlier periods, as requested by intervenors in Ameren Illinois’ filing, but directed its audit staff to review historical rate recovery in connection with an ongoing FERC audit. In June 2020, Ameren Missouri, Ameren Illinois, and ATXI filed requests for rehearing arguing, among other things, the revisions should be applied retrospectively to include the period January 1, 2019, to June 1, 2020, and that the FERC should not require refunds for periods prior to 2019. In July 2020, the FERC denied the rehearing requests without addressing the issues raised. In July 2020, Ameren Missouri, Ameren Illinois, and ATXI filed an appeal of the July 2020 rehearing denials to the United States Court of Appeals for the District of Columbia Circuit, which is under no deadline to address the appeal. In October 2020, the FERC issued an order reaffirming its May 2020 order and denying the arguments raised in the rehearing requests filed by Ameren Missouri, Ameren Illinois, ~~Rivers project, which has~~and ATXI. Regardless of the outcome of the appeal, the impacts of the May 2020 and October 2020 orders are not expected to be material to Ameren’s, Ameren Missouri’s, or Ameren Illinois’ results of operations, financial position, or liquidity.

In March 2021, the FERC issued an ~~estimated segment cost~~order related to an intervenor challenge to Ameren Illinois’ 2020 transmission formula rate update. As a result of ~~approximately $85~~this order, in March 2021, Ameren Illinois recorded a regulatory liability of $9 million, largely as a reduction of ~~which $32 million was invested as of September 30, 2017. These cases had been filed in order~~electric operating revenues, to ~~obtain necessary easements and rights of way to complete the segment. The court found that required notice was not given~~reflect expected refunds, including interest, primarily related to the ~~relevant landowners during the underlying ICC proceeding. ATXI intends to appeal this decision. ATXI plans to complete the project~~historical rate recovery of materials and supplies inventories included in ~~2019; however, delays associated~~rate base. In April 2021, Ameren Illinois filed a request for rehearing with the condemnation proceedings or an appeal arising from the order dismissing the Edgar County cases could delay the completion date. The other eight segments of the Illinois Rivers project are not affected by these proceedings.

~~Federal~~FERC regarding its March 2021 order.

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~~ROE for FERC-regulated transmission rate base under the MISO tariff from 12.38% to 9.15%. In September 2016, the FERC issued ~~a final~~an 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~~ROE to 10.32%, or a 10.82% total allowed return on common equity with the inclusion of a 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. In the first six months of 2017, Ameren and Ameren Illinois refunded $21 million and $17 million, respectively, related to the November 2013 complaint case. In addition, the 10.82% allowed return on common equity has been reflected in rates since September 2016. The 10.82% allowed return on common equity may be replaced prospectively after the FERC issues a final order in the February 2015 complaint case, discussed below.

Since 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. MISO transmission owners have since filed a motion to dismiss the February 2015 complaint. See below for additional information about the motion. The February 2015 complaint case seeks a further reduction in the allowed base return on common equity for FERC-regulated transmission rate base under the MISO 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 for the 15-month period of February 2015 to May 2016 to 9.70%, or a 10.20% total allowed return on equityROE with the inclusion of a 50 basis point incentive adder for participation in an RTO, that was effective from late September 2016 forward. The September 2016 order also required refunds for the period November 2013 to February 2015, which were paid in 2017. In November 2019, the FERC issued an order addressing the November 2013 complaint case, which set the allowed base ROE at 9.88%, superseding the 10.32% previously ordered, and ~~require customer~~required refunds, with interest, for ~~that 15-month period. The timing~~the periods November 2013 to February 2015 and from late September 2016 forward. In December 2019, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed requests for rehearing with the FERC. In May 2020, the FERC issued an order addressing the requests for rehearing, which set the allowed base ROE at 10.02%, superseding the 9.88%

previously ordered, and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. In June 2020, various parties filed requests for rehearing with the FERC, challenging the new ROE methodology established by the May 2020 order. In July 2020, the FERC denied the rehearing requests without addressing the issues raised, and indicated it will address the requests for rehearing in a future order. Also in July 2020, Ameren Missouri, Ameren Illinois, and ATXI filed an appeal of the ~~issuance of the final~~May 2020 order in the February 2015 complaint case is uncertain for two reasons. First, while the FERC reestablished a quorum of commissioners in August 2017 after six months without a quorum, the FERC is under no deadline to ~~issue a final order. Second, in the second quarter of 2017,~~ the United States Court of Appeals for the District of Columbia Circuit ~~vacated and remanded to~~challenging the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. Ameren is unable to predict the impact of the outcome of the United States Court of Appealsrefunds required for the ~~District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time.~~

Inperiod from September ~~2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion~~2016 to ~~dismiss the February 2015 complaint case with the FERC.~~May 2020. The MISO transmission owners maintain that the February 2015 complaint was predicated on the now superseded 12.38% allowed base return on common equity being an unjust and unreasonable return and is not applicable given the currently effective 10.32% allowed base return on common equity. The MISO transmission owners further maintain that the currently effective 10.32% allowed base return on common equity has not been proven to be unjust and unreasonable based on information provided, including the base return on common equity methodology ranges set forth in the February 2015 complaint case and the initial decision issued by an administrative law judge in June 2016. Additionally, the MISO transmission owners maintain that the February 2015 complaint should be dismissed because the approach utilized in the case to assert that a return on common equity was unjust and unreasonable is insufficient. That same approach was rejected by the United States Court of Appeals for the District of Columbia Circuit, as discussed above. FERCcourt is under no deadline to ~~issue an order on this motion.~~address the appeal.

As of ~~September 30, 2017,~~March 31, 2021, Ameren and Ameren Illinois had recorded current regulatory liabilities of ~~$41~~$17 million and ~~$24~~$9 million, respectively, to reflect the expected refunds, including interest, associated with the ~~reduced~~ allowed ~~returns on common equity~~base ROE set by the May 2020 order in the ~~initial decision in the February 2015~~November 2013 complaint case. ~~Ameren Missouri does not expect that a reduction~~The increase in the FERC-allowed base ~~return on common equity would be~~ROE resulting from the May 2020 order is not material to ~~its~~Ameren Missouri’s results of operations, financial position, or liquidity.

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,~~and, in the case of Ameren Missouri and Ameren Illinois, short-term ~~intercompany~~affiliate 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.

Short-Term Borrowings

The Missouri Credit Agreement and the Illinois Credit Agreement ~~both of which expire in December 2021, were not utilized for direct borrowings during the~~ ~~nine months ended September 30, 2017, but were used~~are available to support issuances under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper ~~issuances~~programs, respectively, subject to borrowing sublimits, and ~~to issue~~the issuance of letters of credit. ~~Based~~As of March 31, 2021, based on commercial paper outstanding ~~as well as~~and letters of credit issued under the Credit Agreements, along with cash and cash equivalents, the ~~aggregate amount of credit capacity~~net liquidity available ~~under the Credit Agreements~~ to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, at ~~September 30, 2017~~, was ~~$1.7 billion~~.$1.4 billion. The Ameren Companies were in compliance with the covenants in their Credit Agreements as of ~~September 30, 2017.~~March 31, 2021. As of ~~September 30, 2017,~~March 31, 2021, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were ~~51%~~57%, ~~47%~~49%, and 46% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

~~Commercial Paper~~

The following table presents commercial paper outstanding, net of issuance discounts, as of ~~September 30, 2017,~~March 31, 2021, and December 31, ~~2016:~~2020. There were no borrowings outstanding under the Credit Agreements as of March 31, 2021, or December 31, 2020.


	March 31, 2021		December 31, 2020
Ameren (parent)	$	362	$	490
Ameren Missouri	204		0
Ameren Illinois	323		0
Ameren consolidated	$	889	$	490

2017 2016
Ameren (parent) $ 277
$ 507
Ameren Missouri —
—
Ameren Illinois 169
51
Ameren Consolidated $ 446
$ 558

The following table summarizes the ~~borrowing~~ activity and relevant interest rates ~~under Ameren’s~~for Ameren (parent),’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper ~~programs~~issuances and borrowings under the Credit Agreements in the aggregate for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2021 and ~~2016:~~2020:


	Ameren (parent)			Ameren Missouri				Ameren Illinois			Ameren Consolidated
2021
Average daily amount outstanding	$	454		$	99			$	96		$	649

Weighted-average interest rate	0.25		%	0.22		%		0.21		%	0.24		%
Peak amount outstanding during period(a)	$	650		$	206			$	353		$	916
Peak interest rate	0.33		%	0.25		%		0.25		%	0.33		%
2020
Average daily amount outstanding	$	157		$	395			$	76		$	628

Weighted-average interest rate	1.94		%	1.86		%		1.99		%	1.89		%
Peak amount outstanding during period(a)	$	425		$	573			$	150		$	908
Peak interest rate	3.30		%	5.05		%	(b)	3.40		%	5.05		%	(b)

(a)The timing of peak outstanding commercial paper issuances and borrowings under the Credit Agreements varies by company. Therefore, the sum of individual company peak amounts may not equal the Ameren consolidated peak for the period.

(b)Ameren’s and Ameren Missouri’s peak interest rate was affected by temporary disruptions in the commercial paper market in the first quarter of 2020.

Ameren
(parent)
Ameren
Missouri
Ameren
Illinois
Ameren Consolidated
2017
Average daily commercial paper outstanding $ 669
$ 7
$ 78
$ 754
Weighted-average interest rate 1.27 % 1.20 % 1.28 % 1.27 %
Peak commercial paper during period^(a)
$ 841
$ 64
$ 193
$ 948
Peak interest rate 1.50 % 1.41 % 1.50 % 1.50 %
2016
Average daily commercial paper outstanding $ 435
$ 80
$ 48
$ 563
Weighted-average interest rate 0.81 % 0.74 % 0.72 % 0.79 %
Peak commercial paper during period^(a)
$ 574
$ 208
$ 195
$ 839
Peak interest rate 0.95 % 0.85 % 0.85 % 0.95 %


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

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. The average interest rate for ~~borrowing~~borrowings under the utility money pool for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2021, was ~~1.24%~~ ~~and 1.18%, respectively (2016~~0.22% (2020 – ~~0.53% and 0.54%, respectively)~~1.93%). See Note 8 – ~~Related Party~~Related-party Transactions for the amount of interest income and expense from the utility money pool arrangements recorded by ~~the~~ Ameren ~~Companies~~Missouri and Ameren Illinois for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~.2020.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren ~~Missouri~~

For the three months ended March 31, 2021, Ameren issued a total of 0.1 million shares of common stock under its DRPlus and 401(k) plan, and received proceeds of $12 million. In addition, in the first quarter of 2021, Ameren issued 0.5 million shares of common stock valued at $33 million upon the vesting of stock-based compensation.

In ~~June 2017,~~February 2021, Ameren ~~Missouri~~settled the remainder of the forward sale agreement by physically delivering 1.6 million shares of common stock for cash proceeds of $113 million. The proceeds were used to fund a portion of Ameren Missouri’s wind generation investments. See Note 2 - Rate and Regulatory Matters for additional information about the wind generation investments.

In March 2021, Ameren (parent) issued ~~$400~~$450 million ~~principal amount~~ of ~~2.95%~~1.75% senior ~~secured~~unsecured notes due ~~June 2027,~~March 2028, with interest payable semiannually on ~~June~~March 15 and ~~December~~September 15 of each year, beginning ~~in December 2017.~~September 15, 2021. Ameren ~~Missouri~~ received net proceeds of ~~$396~~$447 million, which were used ~~in conjunction with other available funds, to repay at maturity in June 2017 $425~~for general corporate purposes, including the repayment of short-term debt.

Ameren Missouri

Ameren Missouri received capital contributions totaling $113 million ~~principal amount of its 6.40% senior secured notes.~~from Ameren (parent) during the three months ended March 31, 2021.

~~ATXI~~Ameren Illinois

In ~~June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450~~March 2021, Ameren Illinois redeemed its 6.625% and 7.75% series preferred stock at par for $12 million ~~principal amount~~and $1 million, respectively. The preferred stock of 3.43% senior unsecured notes, due 2050, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notesAmeren Illinois is reflected in ~~June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI~~“Noncontrolling Interests” on Ameren’s consolidated balance sheet.

Ameren Illinois received ~~proceeds of $449~~capital contributions totaling $40 million from ~~the notes, which were used by ATXI to repay existing short-term and long-term affiliate debt owed to~~ Ameren (parent).

~~ATXI may prepay at any time not less than 5% of~~ during the principal amount of notes then outstanding at 100% of the principal amount plus a make-whole premium. In the event of a change of control, as defined in the agreement, each holder of notes may require ATXI to prepay the entire unpaid principal amount of the notes held by such holder at a price equal to 100% of the principal amount of such notes together with accrued and unpaid interest thereon. The following table presents the principal maturities schedule for the notes:

Payment Date Principal Payment
August 2022 $ 49.5
August 2024 49.5
August 2027 49.5
August 2030 49.5
August 2032 49.5
August 2038 49.5
August 2043 76.5
August 2050 76.5
Total Principal Amount of Notes $ 450.0

The note purchase agreement includes financial covenants that require ATXI to not permit at any time: (i) debt to exceed 70% of total capitalization or (ii) secured debt to exceed 10% of total assets. The note purchase agreement also contains restrictive covenants that, among other things, restrict the ability of ATXI to: (i) enter into transactions with affiliates; (ii) consolidate, merge, transfer or lease all or substantially all of its assets; and (iii) create liens.three months ended March 31, 2021.

Indenture Provisions and Other Covenants

Ameren Missouri’s and Ameren Illinois’ indentures 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. ~~See the discussion above for covenants related to ATXI’s note purchase agreement.~~ At ~~September 30, 2017,~~March 31, 2021, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.

~~Off-Balance-Sheet~~Off-balance-sheet Arrangements

At ~~September 30, 2017,~~March 31, 2021, none of the Ameren Companies had any significant off-balance-sheet financing arrangements, other than ~~operating leases~~variable interest entities. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.

~~entered into in the ordinary course of business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries.~~

NOTE 5 – OTHER INCOME, ~~AND EXPENSES~~NET

The following table presents the components of “Other Income, ~~and Expenses”~~Net” in the Ameren Companies’ statements of income for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~:2020:


	Three Months
		2021		2020
Ameren:

Allowance for equity funds used during construction		$	7	$	4
Interest income on industrial development revenue bonds		6		6
Other interest income		1		1

Non-service cost components of net periodic benefit income(a)		34		23
Miscellaneous income		4		2
Donations		(3)		(13)		(b)
Miscellaneous expense		(3)		(2)
Total Other Income, Net		$	46	$	21
Ameren Missouri:

Allowance for equity funds used during construction		$	4	$	2
Interest income on industrial development revenue bonds		6		6

Non-service cost components of net periodic benefit income(a)		14		5
Miscellaneous income		1		1
Donations		0		(8)		(b)
Miscellaneous expense		(2)		(2)
Total Other Income, Net		$	23	$	4
Ameren Illinois:

Allowance for equity funds used during construction		$	3	$	2
Interest income		1		1

Non-service cost components of net periodic benefit income		14		13
Miscellaneous income		0		1
Donations		(3)		(4)
Miscellaneous expense		(1)		(2)
Total Other Income, Net		$	14	$	11

(a)For the three months ended March 31, 2021 and 2020, the non-service cost components of net periodic benefit income were adjusted by amounts deferred of less than $(1) million and $6 million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates.

(b)Includes $8 million pursuant to Ameren Missouri’s March 2020 electric rate order. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, in the Form 10-K for additional information.

Three Months Nine Months
2017 2016 2017 2016
Ameren:^(a)

Miscellaneous income:
Allowance for equity funds used during construction $ 6
$ 7
$ 16
$ 20

Interest income on industrial development revenue bonds 7
7
20
20

Interest income —
3
5
11

Other —
1
1
3

Total miscellaneous income $ 13
$ 18
$ 42
$ 54

Miscellaneous expense:
Donations $ —
$ 1
$ 7
$ 8

Other 2
7
9
13

Total miscellaneous expense $ 2
$ 8
$ 16
$ 21

Ameren Missouri:
Miscellaneous income:
Allowance for equity funds used during construction $ 6
$ 6
$ 15
$ 16

Interest income on industrial development revenue bonds 7
7
20
20

Interest income —
1
—
1

Other —
—
1
1

Total miscellaneous income $ 13
$ 14
$ 36
$ 38

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

Other 2
2
4
4

Total miscellaneous expense $ 2
$ 2
$ 6
$ 6

Ameren Illinois:
Miscellaneous income:
Allowance for equity funds used during construction $ —
$ 1
$ 1
$ 4

Interest income 1
2
5
9

Other —
1
1
2

Total miscellaneous income $ 1
$ 4
$ 7
$ 15

Miscellaneous expense:
Donations $ —
$ 1
$ 5
$ 6

Other —
2
3
5

Total miscellaneous expense $ —
$ 3
$ 8
$ 11


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

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives to manage the risk of changes in market prices for natural gas ~~power,~~ and ~~uranium,~~power, 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.~~outlays; and

•actual off-system sales revenues that differ from anticipated revenues

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, 2017, and December 31, 2016. As of September 30, 2017, these contracts extended through October 2019, March 2023, May 2032, and March 2020 for fuel oils, natural gas, power, and uranium, respectively.

Quantity (in millions, except as indicated)
2017 2016
Commodity Ameren Missouri Ameren Illinois Ameren Ameren Missouri Ameren Illinois Ameren
Fuel oils (in gallons)^(a)
30
(b)
30
30
(b)
30
Natural gas (in mmbtu) 24
145
169
25
129
154
Power (in megawatthours) 2
9
11
1
9
10
Uranium (pounds in thousands) 370
(b)
370
345
(b)
345


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


~~(b)~~	~~Not applicable.~~

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. The following disclosures exclude NPNS contracts and other non-derivative commodity contracts that are accounted for under the accrual method of accounting.

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, 2017,~~March 31, 2021, and December 31, ~~2016,~~2020, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Cash flows for all derivative financial instruments are classified in cash flows from operating activities.

The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of March 31, 2021, and December 31, 2020. As of March 31, 2021, these contracts extended through October 2023, October 2026, and May 2032 for fuel oils, natural gas and power, respectively.


	Quantity (in millions, except as indicated)
	March 31, 2021			December 31, 2020
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)	36	0	36	43	0	43
Natural gas (in mmbtu)	34	114	148	33	114	147
Power (in MWhs)	7	7	14	6	7	13

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, 2017,~~March 31, 2021, and December 31, ~~2016:~~

2020:

Balance Sheet Location
Ameren
Missouri

Ameren
Illinois
Ameren
2017
Fuel oils Other current assets $ 2
$ —
$ 2

Other assets 1
—
1

Natural gas Other current assets —
1
1

Other assets —
1
1

Power Other current assets 10
—
10

Other assets 1
—
1

Total assets ^(a)
$ 14
$ 2
$ 16

Fuel oils Other current liabilities $ 2
$ —
$ 2

Natural gas Other current liabilities 3
8
11

Other deferred credits and liabilities 4
6
10

Power Other current liabilities 1
13
14

Other deferred credits and liabilities —
179
179

Uranium Other deferred credits and liabilities —
^(b)
—
—
^(b)

Total liabilities ^(c)
$ 10
$ 206
$ 216

2016
Fuel oils Other current assets $ 2
$ —
$ 2

Other assets 1
—
1

Natural gas Other current assets 1
11
12

Other assets 1
2
3

Power Other current assets 9
—
9

Total assets ^(a)
$ 14
$ 13
$ 27

Fuel oils Other current liabilities $ 5
$ —
$ 5

Natural gas Other current liabilities 1
3
4

Other deferred credits and liabilities 5
5
10

Power Other current liabilities 3
12
15

Other deferred credits and liabilities —
173
173

Uranium Other deferred credits and liabilities 4
—
4

Total liabilities ^(c)
$ 18
$ 193
$ 211


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


~~(b)~~	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.


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

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; 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.


			March 31, 2021					December 31, 2020
	Balance Sheet Location		Ameren Missouri		Ameren Illinois		Ameren			Ameren Missouri		Ameren Illinois		Ameren









Fuel oils	Other current assets	$	2	$	0	$	2		$	2	$	0	$	2
	Other assets		3		0		3			0		0		0


Natural gas	Other current assets		2		10		12			1		8		9
	Other assets		2		4		6			2		2		4


Power	Other current assets		4		0		4			7		0		7
	Other assets		1		0		1			0		0		0


	Total assets	$	14	$	14	$	28		$	12	$	10	$	22





Fuel oils	Other current liabilities	$	3	$	0	$	3		$	7	$	0	$	7
	Other deferred credits and liabilities		0		0		0			2		0		2


Natural gas	Other current liabilities		0		0		0			1		1		2
	Other deferred credits and liabilities		0		0		0			0		1		1


Power	Other current liabilities		9		16		25			3		17		20
	Other deferred credits and liabilities		5		169		174			8		181		189



	Total liabilities	$	17	$	185	$	202		$	21	$	200	$	221

The Ameren Companies elect to present the fair value amounts of derivative assets and derivative liabilities subject to an enforceable master netting arrangement or similar agreement at the gross amounts 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 ~~September 30, 2017,~~March 31, 2021, and ~~December~~ December��31, ~~2016.~~2020.

~~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. As of ~~September 30, 2017,~~March 31, 2021, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets 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~~Certain of our derivative instruments contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded below investment grade, 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~~additional collateral required is the net liability position allowed under master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered and (2) those counterparties with rights to do so requested collateral. As of ~~September 30, 2017~~,March 31, 2021, 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 arrangementsrequire were ~~triggered on~~ ~~September 30, 2017~~,each immaterial to Ameren, Ameren

Missouri, and ~~(2) those counterparties with rights to do so requested collateral.~~Ameren Illinois.

Aggregate Fair Value of
Derivative Liabilities^(a)

Cash
Collateral Posted

Potential Aggregate Amount of
Additional Collateral Required^(b)
2017
Ameren Missouri $ 59
$ 3
$ 48
Ameren Illinois 48
—
41
Ameren $ 107
$ 3
$ 89


~~(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.

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~~Fair value ~~including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use~~measurements are classified in ~~pricing~~three levels based on 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.~~as defined by GAAP. 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~~levels 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, 2017~~ ~~and December 31, 2016:~~techniques.

Fair Value Weighted Average
Assets Liabilities
Valuation Technique(s) Unobservable Input Range
Level 3 Derivative asset and liability – commodity contracts^(a):

2017
Fuel oils $ 1
$ (1 ) Option model
Volatilities(%)^(b)
24 – 32 26
Discounted cash flow
Counterparty credit risk(%)^(c)(d)
0.12 – 0.22 0.17

Ameren Missouri credit risk(%)^(c)(d)
0.37 (e)
Natural gas —
(2 ) Discounted cash flow
Nodal basis ($/mmbtu)^(b)
(1.10) – (0.10) (0.80)

Counterparty credit risk (%)^(c)(d)
0.34 – 6 0.73

Ameren Illinois credit risk (%)^(c)(d)
0.37 (e)

Power^(g)
$ 11
$ (193 ) Discounted cash flow
Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)
25 – 41 28

Estimated auction price for FTRs ($/MW)^(b)
(324) – 1,194 269

Nodal basis ($/MWh)^(h)
(3) – 0 (2)

Fair Value Weighted Average
Assets Liabilities
Valuation Technique(s) Unobservable Input Range

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

Ameren Illinois credit risk (%)^(c)(d)
0.37 (e)
Fundamental energy production model
Estimated future natural 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 natural 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 2021 for September 30, 2017, and through 2020 for December 31, 2016. Valuations beyond 2021 for September 30, 2017, and 2020 for December 31, 2016 use fundamentally modeled pricing by month for peak and off-peak demand.


~~(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.~~


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

We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by 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 material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 or ~~2016.~~2020. At ~~September 30, 2017,~~March 31, 2021, and December 31, ~~2016,~~2020, 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, 2017~~:March 31, 2021, and December 31, 2020:


		March 31, 2021									December 31, 2020
		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets:
Ameren Missouri
	Derivative assets – commodity contracts:
	Fuel oils	$	4	$	0	$	1	$	5		$	0	$	0	$	2	$	2
	Natural gas	0		4		0		4			0		3		0		3
	Power	2		0		3		5			2		0		5		7

	Total derivative assets – commodity contracts	$	6	$	4	$	4	$	14		$	2	$	3	$	7	$	12
	Nuclear decommissioning trust fund:

	Equity securities:
	U.S. large capitalization	$	679	$	0	$	0	$	679		$	680	$	0	$	0	$	680
	Debt securities:
	U.S. Treasury and agency securities	0		133		0		133			0		115		0		115
	Corporate bonds	0		128		0		128			0		115		0		115


	Other	0		63		0		63			0		67		0		67
	Total nuclear decommissioning trust fund	$	679	$	324	$	0	$	1,003	(a)	$	680	$	297	$	0	$	977	(a)
	Total Ameren Missouri	$	685	$	328	$	4	$	1,017		$	682	$	300	$	7	$	989
Ameren Illinois
	Derivative assets – commodity contracts:
	Natural gas	$	0	$	10	$	4	$	14		$	0	$	6	$	4	$	10


Ameren
	Derivative assets – commodity contracts(b)	$	6	$	14	$	8	$	28		$	2	$	9	$	11	$	22
	Nuclear decommissioning trust fund(c)	679		324		0		1,003		(a)	680		297		0		977		(a)
	Total Ameren	$	685	$	338	$	8	$	1,031		$	682	$	306	$	11	$	999
Liabilities:
Ameren Missouri
	Derivative liabilities – commodity contracts:
	Fuel oils	$	1	$	0	$	2	$	3		$	6	$	0	$	3	$	9
	Natural gas	0		0		0		0			0		1		—		1
	Power	8		0		6		14			8		0		3		11

	Total Ameren Missouri	$	9	$	0	$	8	$	17		$	14	$	1	$	6	$	21
Ameren Illinois
	Derivative liabilities – commodity contracts:
	Natural gas	$	0	$	0	$	0	$	0		$	0	$	1	$	1	$	2
	Power	0		0		185		185			0		0		198		198
	Total Ameren Illinois	$	0	$	0	$	185	$	185		$	0	$	1	$	199	$	200
Ameren
	Derivative liabilities – commodity contracts(b)	$	9	$	0	$	193	$	202		$	14	$	2	$	205	$	221

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):

Fuel oils $ 2
$ —
$ 1
$ 3

Natural gas 1
1
—
2

Power —
—
11
11

Total derivative assets – commodity contracts
$ 3
$ 1
$ 12
$ 16

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 2
$ —
$ —
$ 2

Equity securities:
U.S. large capitalization 445
—
—
445

Debt securities:
U.S. treasury and agency securities —
119
—
119

Corporate bonds —
82
—
82

Other —
24
—
24

Total nuclear decommissioning trust fund $ 447
$ 225
$ —
$ 672

Total Ameren $ 450
$ 226
$ 12
$ 688

Ameren Missouri
Derivative assets – commodity contracts^(a):

Fuel oils $ 2
$ —
$ 1
$ 3

Power —
—
11
11

Total derivative assets – commodity contracts
$ 2
$ —
$ 12
$ 14

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 2
$ —
$ —
$ 2

Equity securities:
U.S. large capitalization 445
—
—
445

Debt securities:
U.S. treasury and agency securities —
119
—
119

Corporate bonds —
82
—
82

Other —
24
—
24

Total nuclear decommissioning trust fund $ 447
$ 225
$ —
$ 672

Total Ameren Missouri $ 449
$ 225
$ 12
$ 686

Ameren Illinois
Derivative assets – commodity contracts^(a):

Natural gas $ 1
$ 1
$ —
$ 2

Liabilities:
Ameren
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 1
$ —
$ 1
$ 2

Natural gas —
19
2
21

Power —
—
193
193

Total Ameren $ 1
$ 19
$ 196
$ 216

Ameren Missouri
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 1
$ —
$ 1
$ 2

Natural gas —
7
—
7

Power —
—
1
1

Total Ameren Missouri $ 1
$ 7
$ 2
$ 10

Ameren Illinois
Derivative liabilities – commodity contracts^(a):

Natural gas $ —
$ 12
$ 2
$ 14

Power —
—
192
192

Total Ameren Illinois $ —
$ 12
$ 194
$ 206


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

(a)Balance excludes $7 million and $5 million of cash and cash equivalents, receivables, payables, and accrued income, net, for March 31, 2021, and December 31, 2020, respectively.

~~The following~~(b)See the Ameren Missouri and Ameren Illinois sections of the table ~~sets forth, by level within~~for a breakout of the fair value ~~hierarchy, our~~of Ameren’s derivative assets and liabilities by type of commodity.

(c)See the Ameren Missouri section of the table for a breakout of the fair value of Ameren's nuclear decommissioning trust fund by investment type.

Level 3 fuel oils and natural gas derivative contract assets and liabilities measured at fair value on a recurring basis aswere immaterial for all periods presented. The following table presents the fair value reconciliation of ~~December 31, 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
Assets: ��
Ameren
Derivative assets – commodity contracts^(a):

Fuel oils $ 2
$ —
$ 1
$ 3

Natural gas 2
12
1
15

Power —
—
9
9

Total derivative assets – commodity contracts
$ 4
$ 12
$ 11
$ 27

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 1
$ —
$ —
$ 1

Equity securities:
U.S. large capitalization 408
—
—
408

Debt securities:
U.S. treasury and agency securities —
112
—
112

Corporate bonds —
67
—
67

Other —
17
—
17

Total nuclear decommissioning trust fund $ 409
$ 196
$ —
$ 605
^(b)
Total Ameren $ 413
$ 208
$ 11
$ 632

Ameren Missouri
Derivative assets – commodity contracts^(a):

Fuel oils $ 2
$ —
$ 1
$ 3

Natural gas —
1
1
2

Power —
—
9
9

Total derivative assets – commodity contracts
$ 2
$ 1
$ 11
$ 14

Nuclear decommissioning trust fund:
Cash and cash equivalents $ 1
$ —
$ —
$ 1

Equity securities:
U.S. large capitalization 408
—
—
408

Debt securities:
U.S. treasury and agency securities —
112
—
112

Corporate bonds —
67
—
67

Other —
17
—
17

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):

Fuel oils $ 5
$ —
$ —
$ 5

Natural gas —
13
1
14

Power —
1
187
188

Uranium —
—
4
4

Total Ameren $ 5
$ 14
$ 192
$ 211

Ameren Missouri
Derivative liabilities – commodity contracts^(a):

Fuel oils $ 5
$ —
$ —
$ 5

Natural gas —
6
—
6

Power —
1
2
3

Uranium —
—
4
4

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


~~(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.~~

~~All costs related to financial~~Level 3 power derivative contract assets and liabilities ~~classified as~~measured at fair value on a recurring basis for the three months ended March 31, 2021 and 2020:


	2021						2020
	Ameren Missouri		Ameren Illinois		Ameren			Ameren Missouri		Ameren Illinois		Ameren
For the three months ended March 31:
Beginning balance at January 1	$	2	$	(198)	$	(196)		$	13	$	(224)	$	(211)
Realized and unrealized gains/(losses) included in regulatory assets/liabilities	(5)		9		4			11		(21)		(10)


Settlements	0		4		4			(7)		4		(3)


Ending balance at March 31	$	(3)	$	(185)	$	(188)		$	17	$	(241)	$	(224)
Change in unrealized gains/(losses) related to assets/liabilities held at March 31	$	(3)	$	9	$	6		$	10	$	(21)	$	(11)

All gains or losses related to our Level 3 ~~in the fair value hierarchy~~derivative commodity contracts are expected to be ~~recoverable~~recovered or returned through customer rates; therefore, there is no impact to either net income or other comprehensive income resulting from changes in the fair value of these instruments. ~~For~~

The following table describes the ~~three~~valuation techniques and ~~nine months ended September 30, 2017 and 2016, the balances and changes in~~significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of March 31, 2021, and December 31, 2020:


			Fair Value						Weighted Average(b)
	Commodity		Assets		Liabilities	Valuation Technique(s)	Unobservable Input(a)	Range









2021	Power(c)	$	3	$	(191)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)	23 – 40	29

							Nodal basis ($/MWh)	(5) – 0	(1)


							Trend rate (%)	2 – 5	3








































2020	Power(c)	$	5	$	(201)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)	23 – 37	29

							Nodal basis ($/MWh)	(6) – 0	(2)


							Trend rate (%)	2 – 6	3

(a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.

(b)Unobservable inputs were weighted by relative fair value.

(c)Valuations through 2029 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2029 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.

The following table sets forth the carrying amount and, by level within the fair value hierarchy, the fair value of financial assets and liabilities ~~associated with fuel oils, natural gas,~~disclosed, but not recorded, at fair value as of March 31, 2021, and ~~uranium~~December 31, 2020:


	Carrying Amount			Fair Value
				Level 1		Level 2		Level 3			Total
	March 31, 2021
Ameren:
Cash, cash equivalents, and restricted cash	$	172		$	172	$	0	$	0		$	172
Investments in industrial development revenue bonds(a)	256			0		256		0			256
Short-term debt	889			0		889		0			889
Long-term debt (including current portion)(a)	11,535		(b)	0		12,233		507		(c)	12,740
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	12		$	12	$	0	$	0		$	12

Investments in industrial development revenue bonds(a)	256			0		256		0			256
Short-term debt	204			0		204		0			204
Long-term debt (including current portion)(a)	5,104		(b)	0		5,685		0			5,685
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	149		$	149	$	0	$	0		$	149
Short-term debt	323			0		323		0			323

Long-term debt (including current portion)	3,947		(b)	0		4,401		0			4,401
	December 31, 2020
Ameren:
Cash, cash equivalents, and restricted cash	$	301		$	301	$	0	$	0		$	301
Investments in industrial development revenue bonds(a)	256			0		256		0			256
Short-term debt	490			0		490		0			490
Long-term debt (including current portion)(a)	11,086		(b)	0		12,778		537		(c)	13,315
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	145		$	145	$	0	$	0		$	145
Advances to money pool	139			0		139		0			139
Investments in industrial development revenue bonds(a)	256			0		256		0			256

Long-term debt (including current portion)(a)	5,104		(b)	0		6,160		0			6,160
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	147		$	147	$	0	$	0		$	147
Borrowings from money pool	19			0		19		0			19
Long-term debt (including current portion)	3,946		(b)	0		4,822		0			4,822

(a)Ameren and Ameren Missouri have investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the finance obligations for the Peno Creek and Audrain CT energy centers. As of March 31, 2021, and December 31, 2020, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value.

(b)Included unamortized debt issuance costs, which were ~~immaterial.~~

~~The following table summarizes the changes in~~excluded from the fair value measurement, of ~~power financial assets~~$86 million, $36 million, and ~~liabilities classified~~$36 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as ~~Level 3 in~~of March 31, 2021. Included unamortized debt issuance costs, which were excluded from the fair value ~~hierarchy:~~measurement, of $84 million, $36 million, and $36 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2020.

Net derivative commodity contracts

Ameren
Missouri

Ameren
Illinois
Ameren
For the three months ended September 30, 2017
Beginning balance at July 1, 2017 $ 14
$ (192 ) $ (178 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (2 ) (3 ) (5 )
Sales 1
—
1
Settlements (3 ) 3
—
Ending balance at September 30, 2017 $ 10
$ (192 ) $ (182 )
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2017 $ —
$ (2 ) $ (2 )
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 nine months ended September 30, 2017
Beginning balance at January 1, 2017 $ 7
$ (185 ) $ (178 )
Realized and unrealized gains (losses) included in regulatory assets/liabilities (3 ) (14 ) (17 )
Purchases 15
—
15
Sales 1
—
1
Settlements (10 ) 7
(3 )
Ending balance at September 30, 2017 $ 10
$ (192 ) $ (182 )
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2017 $ —
$ (15 ) $ (15 )
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 )

~~Transfers into or out of~~(c)The 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, 2017 and 2016, 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, accounts receivable, unbilled revenue, accounts payable, and other current financial instruments approximate~~ fair value ~~because~~amount consists 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.ATXI’s senior unsecured notes.

~~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, 2017, and~~ ~~December 31, 2016~~:

September 30, 2017 December 31, 2016

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value
Ameren:
Long-term debt and capital lease obligations (including current portion) $ 7,699
$ 8,234
$ 7,276
$ 7,772
Preferred stock^(a)
142
131
142
131
Ameren Missouri:
Long-term debt and capital lease obligations (including current portion) $ 3,967
$ 4,312
$ 3,994
$ 4,304
Preferred stock 80
79
80
79
Ameren Illinois:
Long-term debt (including current portion) $ 2,590
$ 2,759
$ 2,588
$ 2,765
Preferred stock 62
52
62
52


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

NOTE 8 – ~~RELATED PARTY~~RELATED-PARTY TRANSACTIONS

In the ~~normal~~ordinary course of business, Ameren Missouri and Ameren Illinois have engaged in, and may in the ~~Ameren Companies~~future engage in, affiliate transactions. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between ~~affiliates~~Ameren’s subsidiaries are reported as ~~intercompany~~affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. For a discussion of ~~our~~ material ~~related party~~related-party agreements and money pool arrangements, see Note 1413 – ~~Related Party~~Related-party Transactions and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of the Form ~~10-K~~10-K. For information Ameren Missouri’s and ~~the money pool arrangements discussed in~~Ameren Illinois’ capital contributions, see Note 34 – ~~Short-term~~Long-term Debt and ~~Liquidity of this report.~~Equity Financings.

Electric Power Supply Agreement

In April ~~2017,~~2021, Ameren Illinois conducted a procurement event, administered by the IPA, to purchase energy products. Ameren Missouri was among the winning suppliers in this event. As a result, in April ~~2017,~~2021, Ameren Missouri and Ameren Illinois entered into an energy product agreement by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase, ~~85,600 megawatthours~~33,600 MWhs at an average price of $34 per ~~megawatthour~~MWh during the period of ~~March 2019~~July 2022 through ~~May 2020.~~November 2022.

Tax Allocation Agreement

See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for a discussion of the tax allocation agreement. The following table presents the ~~impact~~affiliate balances related to income taxes for Ameren Missouri and Ameren Illinois as of March 31, 2021, and December 31, 2020:


	March 31, 2021				December 31, 2020
	Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Income taxes payable to parent(a)	$	0	$	6	$	0	$	6
Income taxes receivable from parent(b)	14		18		9		15

(a)Included in “Accounts payable – affiliates” on the balance sheet.

(b)Included in “Accounts receivable – affiliates” on the balance sheet.

Effects of Related-party Transactions on the Statement of Income

The following table presents the effect on Ameren Missouri and Ameren Illinois of ~~related party~~related-party transactions for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~:2020:


			Three Months
Agreement	Income Statement Line Item				Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2021		$	2	$	(a)
agreements with Ameren Illinois		2020			3		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2021		$	7	$	(b)
rent and facility services		2020			7		1
Ameren Missouri and Ameren Illinois miscellaneous	Operating Revenues	2021		$	(b)	$	(b)
support services and services provided to ATXI		2020			(b)		(b)
Total Operating Revenues		2021		$	9	$	(b)
		2020			10		1
Ameren Illinois power supply	Purchased Power	2021		$	(a)	$	2
agreements with Ameren Missouri		2020			(a)		3
Ameren Missouri and Ameren Illinois	Purchased Power	2021		$	1	$	(b)
transmission services from ATXI		2020			(a)		(b)
Total Purchased Power		2021		$	1	$	2
		2020			(a)		3
Ameren Missouri and Ameren Illinois	Other Operations and Maintenance	2021		$	(b)	$	1
rent and facility services		2020			(b)		1
Ameren Services support services	Other Operations and Maintenance	2021		$	35	$	33
agreement		2020			35		33
Total Other Operations and		2021		$	35	$	34
Maintenance		2020			35		34
Money pool borrowings (advances)	(Interest Charges)/Other Income, Net	2021		$	(b)	$	(b)
		2020			(b)		(b)

(a)Not applicable.

(b)Amount less than $1 million.

Three Months Nine Months
Agreement
Income Statement
Line Item

Ameren
Missouri

Ameren
Illinois

Ameren
Missouri

Ameren
Illinois
Ameren Missouri power supply Operating Revenues 2017 $ 4
$ (a)
$ 21
$ (a)
agreements with Ameren Illinois 2016 9
(a)
21
(a)
Ameren Missouri and Ameren Illinois Operating Revenues 2017 7
1
20
3
rent and facility services 2016 5
1
18
3
Ameren Missouri and Ameren Illinois Operating Revenues 2017 (b)
(b)
(b)
1
miscellaneous support services 2016 1
(b)
1
(b)
Total Operating Revenues 2017 $ 11
$ 1
$ 41
$ 4
2016 15
1
40
3
Ameren Illinois power supply Purchased Power 2017 $ (a)
$ 4
$ (a)
$ 21
agreements with Ameren Missouri 2016 (a)
9
(a)
21
Ameren Illinois transmission Purchased Power 2017 (a)
(b)
(a)
1
services with ATXI 2016 (a)
1
(a)
2
Total Purchased Power 2017 $ (a)
$ 4
$ (a)
$ 22
2016 (a)
10
(a)
23
Ameren Services support services Other Operations and Maintenance 2017 $ 34
$ 33
$ 103
$ 99
agreement 2016 30
29
96
90
Money pool borrowings (advances) Interest Charges/ Miscellaneous Income 2017 $ (b)
$ (b)
$ (b)
$ (b)
2016 (b)
(b)
(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 the 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 149 – ~~Related Party~~Callaway Energy Center, Note 13 – Related-party Transactions, and Note 1514 – Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 8 – ~~Related Party~~Related-party Transactions, and Note 10 – Callaway Energy Center of this report.

~~Other Obligations~~

In April and September 2017, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products through May 2020. In the April 2017 procurement event, Ameren Illinois contracted to purchase 4,249,800 megawatthours of energy products for $128 million from June 2017 through May 2020. In the September 2017 procurement event, Ameren Illinois contracted to purchase approximately 1,950,200 megawatthours of energy products for $57 million from October 2017 through May 2020. The results of both procurement events are reflected in the below table. See Note 8 – Related Party Transactions for additional information regarding energy product agreements between Ameren Missouri and Ameren Illinois as a result of the April procurement event.

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. Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated minimum fuel, purchased power, and other commitments for fuel at September 30, 2017. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services, among other agreements, at September 30, 2017.

Coal
Natural
Gas^(a)

Nuclear
Fuel

Purchased
Power^(b)(c)

Methane
Gas
Other Total
Ameren:^(d)

2017 $ 162
$ 65
$ 19
$ 59
$ 1
$ 33
$ 339
2018 453
200
67
170
4
57
951
2019 356
148
27
63
4
39
637
2020 79
94
39
13
5
39
269
2021 27
36
45
2
5
26
141
Thereafter —
47
58
20
64
123
312
Total $ 1,077
$ 590
$ 255
$ 327
$ 83
$ 317
$ 2,649
Ameren Missouri:
2017 $ 162
$ 14
$ 19
$ —
$ 1
$ 20
$ 216
2018 453
42
67
—
4
44
610
2019 356
34
27
—
4
25
446
2020 79
26
39
—
5
25
174
2021 27
13
45
—
5
26
116
Thereafter —
22
58
—
64
100
244
Total $ 1,077
$ 151
$ 255
$ —
$ 83
$ 240
$ 1,806
Ameren Illinois:
2017 $ —
�� $ 51
$ —
$ 59
$ —
$ 13
$ 123
2018 —
158
—
170
—
13
341
2019 —
114
—
63
—
14
191
2020 —
68
—
13
—
14
95
2021 —
23
—
2
—
—
25
Thereafter —
25
—
20
—
—
45
Total $ —
$ 439
$ —
$ 327
$ —
$ 54
$ 820


~~(a)~~	~~Includes amounts for generation and for distribution.~~


~~(b)~~	The purchased power amounts for Ameren and Ameren Illinois exclude agreements for renewable energy credits through 2032 with various renewable energy suppliers due to the contingent nature of the payment amounts.


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


~~(d)~~	~~Includes amounts for Ameren registrant and nonregistrant subsidiaries.~~

Environmental Matters

~~We are subject to various~~Our electric and gas generation, transmission, distribution and gas storage operations must comply with a variety of environmental ~~laws~~statutory and ~~regulations enforced by~~regulatory requirements, including permitting programs implemented via federal, state, and local authorities. ~~The development~~Depending upon the specific business activity of the facility, such laws address air emissions; discharges to water bodies; the storage, handling, and ~~operation~~disposal of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect to diverse environmental laws and regulations. These laws and regulations address emissions, discharges into water, water usage, impacts to air, land, and water, and chemicalhazardous substances and waste ~~handling.~~materials; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. We employ dedicated personnel knowledgeable in environmental matters to oversee our business activities’ compliance with regulatory requirements.

~~The EPA has promulgated environmental~~Environmental regulations ~~that~~ have a significant impact on the electric utility ~~industry. Over time,~~industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. As of December 31, 2016, Ameren Missouri’s fossil fuel-fired energy centers represented 18% and 34% of Ameren’s and Ameren Missouri’s rate base, respectively. Regulations impacting air emissions fromClean Air Act regulations that apply to the electric utility industry include the ~~revised~~ NSPS, the CSAPR, the MATS, and the ~~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,NOx, mercury, toxic metals, and acid ~~gases.~~gases, and CO2 emissions from new power plants. Clean Water Act regulations applicable to coal-fired power plants govern both intake and discharges ~~from power plants are regulated under~~of water and require evaluation of the ~~Clean Water Act. Modifications~~ecological and biological impact of our operations and could require modifications to water intake structures ~~and~~or more stringent limitations ~~or prohibitions against~~on wastewater ~~discharges at Ameren Missouri’s energy centers~~discharges. Depending upon the scope of modifications ultimately required by state regulators, these capital expenditures could ~~result in significant capital expenditures.~~be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR ~~Rule, which will require~~rule and requires the closure of our surface impoundments ~~and the installations of dry ash handling systems~~ at ~~several of~~ Ameren Missouri’s coal-fired energy ~~centers, resulting in significant capital expenditures.~~centers. The individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of ~~the operation of~~operations at some of Ameren Missouri’s energy ~~centers, or require further capital investment.~~centers. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.

~~Ameren Missouri's current plan for compliance with existing air emission regulations 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 ~~$425~~$175 million to ~~$525~~$225 million ~~in the aggregate~~ from ~~2017~~2021 through ~~2021~~2025 in order to comply with existing environmental regulations. Additional environmental controls beyond ~~2021~~2025 could be required. This estimate of capital expenditures includes ~~expenditures~~ash pond closure and corrective action measures required ~~for~~by the CCR regulations, ~~Clean Water Act rules applicable~~potential modifications to cooling water intake structures at existing power plants under Clean Water Act rules, and by effluent limitation guidelines applicable to steam electric generating units, all of which are discussed below. ~~The EPA has proposed to repeal~~This estimate does not include capital expenditures that may be required as a result of the NSR and Clean ~~Power Plan, which would have regulated CO~~₂~~emissions from power plants. The above capital expenditure amounts exclude estimated impacts from the Clean Power Plan.~~Air Act litigation discussed below. Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning low-sulfur coal and installing new or optimizing existing air pollution control equipment. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above ~~estimate~~estimates because of uncertainty as to ~~whether~~future permitting requirements made by state regulators and the EPA, ~~will substantively revise~~potential revisions to regulatory obligations, and the ~~precise~~cost of potential compliance strategies, ~~that will be used and their ultimate cost,~~ among other things.

The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of several regulations and ~~rulemaking activities,~~proposed amendments to regulations and guidelines, including to the effluent limitation guidelines and the CCR ~~rule,~~Rule, which could ultimately result in the revision of all or part of such rules.

Clean Air Act

Federal and state laws, ~~require significant reductions in~~including CSAPR, regulate emissions of SO₂and NO_x through ~~either emission~~the reduction of emissions at their source ~~reductions or~~and the use and retirement of emission allowances. ~~The first~~CSAPR is implemented through a series of phases, and the second phase ~~of the CSAPR emission reduction requirements~~ became effective in ~~2015. The second phase of emission reduction requirements, which were revised by the EPA in 2016, became effective in 2017; additional~~2017. Additional emission reduction requirements may apply in subsequent years. ~~To achieve compliance with the CSAPR,~~ Ameren Missouri ~~burns ultra-low-sulfur~~complies with current CSAPR requirements by minimizing emissions through the use of low-sulfur coal, ~~operates two~~operation of 2 scrubbers at its Sioux ~~energy center,~~Energy Center, and ~~optimizes~~optimization of other existing air pollution control equipment. Ameren Missouri ~~did not make additional capital investments to comply with the 2017 CSAPR requirements. However, Ameren Missouri expects to~~could incur additional costs to lower its emissions at one or more of its energy centers to comply ~~with the~~additional CSAPR requirements in future years. These ~~higher~~additional costs for compliance are expected to be recovered from customers through the FAC or higher base rates.

CO₂ Emissions Standards

~~In 2015, the EPA issued the~~The EPA’s Affordable Clean ~~Power Plan, which sets forth CO~~₂~~emissions standards applicable to existing power plants. In October 2017, the EPA announced a proposal to repeal~~Energy Rule repealed the Clean Power Plan and ~~will seek public comment~~replaced it with a new rule that established emission guidelines for states to follow in developing plans to limit CO2 emissions and identified certain efficiency measures as to the ~~scope~~best system of ~~future regulations~~

~~under~~emission reduction for coal-fired electric generating units. In January 2021, the ~~Clean Air Act. The~~ United States Court of Appeals for the District of Columbia Circuit vacated the Affordable Clean Energy Rule, and ruled that the EPA had the discretion to consider emission reduction measures that include efficiency measures and generation shifting to lower carbon emissions. The United States Supreme Court has ~~stayed further action pending~~extended the ~~EPA’s administrative review.~~

Wedeadline for seeking review, and a decision on whether the Supreme Court will review the circuit court's ruling could occur in fall 2021. Regardless of the outcome of those legal challenges, the EPA is likely to develop new regulations to address carbon emissions from coal and natural gas electric generating units. At this time, Ameren Missouri cannot predict the outcome of ~~the EPA’s future rulemaking, the outcome of~~ legal challenges ~~relating~~ to ~~either~~ the ~~repeal of~~vacated Affordable Clean

Energy Rule or future rulemakings. As such, the ~~Clean Power Plan or such future rulemakings, nor the resulting~~ impact on ~~our~~the results of operations, financial position, ~~or liquidity.~~and liquidity of Ameren and Ameren Missouri is uncertain.

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, alleged~~Missouri alleging that in performing projects at its coal-fired Rush Island ~~coal-fired energy center~~Energy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. ~~The litigation has been divided into two phases: liability and remedy.~~ In January 2017, the district court issued a liability ruling and, in September 2019, entered a final order that required Ameren Missouri to install a flue gas desulfurization system at the ~~projects violated provisions~~Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. There were no fines in the order as the Department of Justice previously dismissed claims for penalties. The district court stayed implementation 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 liability phase~~majority of the ~~litigation. The EPA previously withdrew all claims for penalties and fines. No date has been set by~~requirements of its order while the ~~district court for a trial on the remedy phase of the litigation. At the conclusion of both phases of the litigation, Ameren Missouri intends to~~case is under appeal ~~the liability ruling~~ to the United States Court of Appeals for the Eighth Circuit. In December 2020, the court of appeals heard oral arguments presented by the parties. The court is under no deadline to issue a ruling in this case and Ameren Missouri is unable to predict the ultimate resolution of this matter. Ameren Missouri expects a ruling by the court of appeals during 2021.

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. Among other things and subject to economic and regulatory considerations, resolution of this matter could result in increased capital expenditures for the installation of air pollution control equipment, as well as increased operations and maintenance expenses. WeBased upon engineering studies from October 2019, capital expenditures to comply with the district court’s order for installation of a flue gas desulfurization system at the Rush Island Energy Center are ~~unable~~estimated at approximately $1 billion. Further, the flue gas desulfurization system would result in additional operation and maintenance expenses of $30 million to ~~predict~~$50 million annually for the ~~ultimate resolution~~life of ~~this matter~~the energy center. Engineering studies required to develop estimated capital expenditures and estimated additional operation and maintenance expenses for the Labadie Energy Center to comply with the district court’s order will not be undertaken while the case is under appeal. As a result of the district court’s stay, Ameren Missouri does not expect to make significant capital expenditures or incur operations and maintenance expenses related to the ~~costs that might be incurred.~~district court’s order while the case is under appeal.

Clean Water Act

~~In 2014, the EPA issued its final rule applicable~~The EPA’s Section 316(b) Rule requires power plant operators to evaluate cooling water intake structures ~~at existing power plants. The rule requires a case-by-case evaluation~~ and ~~plan~~identify measures for reducing the number of aquatic organisms impinged on ~~the facility’s~~a power plant’s cooling water intake screens or entrained through the ~~plant's~~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~~Requirements of the rule ~~will occur during~~are implemented by state regulators through the permit renewal process of each energy center’s water discharge permit, which ~~will occur between 2018 and~~is expected to be completed by 2023.

~~Additionally, in~~In 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines 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 water discharges from power plants. ~~In September 2017,~~To meet the ~~EPA published a rule that postponed~~requirements of the ~~compliance dates by two years for the limitations applicable to two specific waste streams so that it could potentially revise those standards.~~

~~Both the intake and effluent rules, if implemented as enacted, could have an adverse effect on Ameren’s and~~guidelines, Ameren ~~Missouri’s results of operations, financial position, and liquidity should such implementation require extensive modifications to the cooling water~~Missouri installed dry ash handling systems and ~~water discharge systems~~in 2020 completed construction of wastewater treatment facilities at ~~Ameren Missouri’s~~3 of its 4 coal-fired energy ~~centers,~~centers. The Meramec Energy Center is scheduled to close permanently in 2022, and ~~if such investments~~as a result, does not require new wastewater and dry ash handling systems. Estimated capital expenditures to complete these projects are ~~not recovered on a timely basis~~included in ~~electric rates charged to Ameren Missouri’s customers.~~the CCR management compliance plan, discussed below.

~~Ash~~CCR Management

~~In 2015, the EPA issued regulations regarding~~The EPA’s CCR rule establishes requirements for the management and disposal of CCR from coal-fired power plants and will result in the closure of surface impoundments at Ameren Missouri’s energy centers. ~~These regulations affect CCR disposal~~Ameren Missouri is in the process of closing surface impoundments at all of its facilities, and ~~handling costs at Ameren Missouri's energy centers. They require closure~~is scheduled to complete the last of ~~impoundments if performance criteria relating~~such closures in 2023. The EPA has issued a series of revisions to groundwater impacts and location restrictions are not achieved. In September 2017, the EPA granted petitions filed on behalf of coal-fired electricity generators in which the EPA agreed to reconsider provisions of the CCR ~~rules.~~rule; however, none of those revisions is expected to materially impact our closure schedule. Ameren and Ameren ~~Missouri’s~~Missouri have AROs of $103 million recorded on their respective balance sheets as of March 31, 2021, associated with CCR storage ~~facilities reflect the regulations issued in 2015.~~facilities. Ameren ~~plans~~Missouri estimates it will need to ~~close these~~make capital expenditures of $75 million to $100 million from 2021 through 2025 to implement its CCR ~~storage facilities between 2018~~management compliance plan, which includes installation of groundwater monitoring equipment and ~~2024. Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan.~~water treatment facilities.

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 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, 2017,~~March 31, 2021, Ameren Illinois ~~owned or was otherwise responsible for~~has remediated the majority of the 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 at the remaining sites by

2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs ~~associated with its former MGP sites~~ from its electric and natural gas utility customers through environmental ~~adjustment rate riders. Costs~~cost riders that are subject to annual prudence review by the ICC. As

of ~~September 30, 2017,~~March 31, 2021, Ameren Illinois estimated the remaining obligation related to these former MGP sites at ~~$184~~$90 million to ~~$255~~$150 million. Ameren and Ameren Illinois recorded a liability of ~~$184~~$90 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 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 and timing of completion 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 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 remedies. As of September 30, 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 historical 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 2011 against Ameren Missouri in the Circuit Court of St. Louis County, Missouri. The lawsuit alleges that Ameren Missouri failed to pay gross receipts taxes or license fees on certain revenues, including revenues from wholesale power and interchange sales. In the third quarter of 2017, the court issued an order preliminarily approving a settlement between Ameren Missouri and the plaintiffs, with final resolution of the case expected in the first quarter of 2018. Ameren and Ameren Missouri recorded immaterial liabilities on their respective balance sheets as of September 30, 2017, and December 31, 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's and Ameren Missouri’s results of operations, financial position, and liquidity.

NOTE 10 – CALLAWAY ENERGY CENTER

~~Spent Nuclear Fuel~~

~~Under~~See Note 9 – Callaway Energy Center under Part II, Item 8, of the ~~NWPA, the DOE is responsible~~Form 10-K for ~~disposing of~~information regarding spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. The NWPA established the fee that Ameren Missouri and other utilities that own and operate those energy centers 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 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. Ameren Missouri received reimbursements from the DOE of $3 million and $24 million in October 2017 and September 2016, respectively. 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, 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. An updated cost study and funding analysis was filed with the MoPSC in September 2017 and reflected within the ARO. Ameren Missouri’s filing supported no change in electric service rates for decommissioning costs. There is no deadline by which the MoPSC must issue an order regarding the filing.

fund. The fair value of the trust fund for Ameren ~~Missouri's~~Missouri’s Callaway ~~energy center~~Energy Center is reported as ~~"Nuclear~~“Nuclear decommissioning trust ~~fund"~~fund” in ~~Ameren's~~Ameren’s and Ameren ~~Missouri's~~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~~

Ameren Missouri received all necessary fuel assemblies for the fourth quarter 2017 refueling and maintenance outage. The Callaway energy center uses nuclear fuel assemblies fabricated by Westinghouse, which is 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 refuel the Callaway energy center in future scheduled refueling and maintenance outages. At this time, Ameren and Ameren Missouri ~~believe~~have recorded an ARO for the ~~restructuring proceeding will not affect Westinghouse’s performance under~~Callaway Energy Center decommissioning costs at fair value, which represents the ~~terms~~present value of ~~its existing contracts with~~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 ~~therefore do not expect any material impact to~~funding analysis for decommissioning its Callaway Energy Center. An updated cost study and funding analysis was filed with the MoPSC in November 2020 and reflected within the ARO. In February 2021, the MoPSC approved no change in electric rates for decommissioning costs based on Ameren Missouri’s ~~operations as a result of this restructuring proceeding. However,~~updated cost study funding analysis. See Note 13 – Supplemental Information for more information on Ameren ~~and Ameren Missouri could incur material unexpected costs as a result~~Missouri’s AROs.

Maintenance Outage

During its return to full power after the completion of the Westinghouse bankruptcy, such as the loss of fuel inventory that is stored at Westinghouse’s facility and the cost of replacement power if nuclear fuel assemblies were not available for a future scheduledlast refueling and maintenance ~~outage. A change of fuel suppliers or a change~~outage in ~~the type of fuel assembly design that is currently licensed for use at~~late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was conducted. Work continues to replace certain key components of the generator in order to return the energy center ~~could take an estimated three years~~to service. Ameren Missouri expects generator repairs of ~~analysis~~approximately $65 million, which are expected to be largely capital expenditures. Due to the long lead time for the manufacture, repair, and ~~NRC licensing efforts~~installation of the components, the energy center is expected to ~~implement.~~return to service in July 2021. In April 2021, Ameren Missouri’s insurance claims were accepted by NEIL, which are expected to cover a significant portion of the capital expenditures and replacement power costs. Replacement power costs of up to $4.5 million weekly are covered by insurance after March 17, 2021. Insurance recoveries related to replacement power costs will be reflected in electric operating revenues and included in net energy costs under the FAC. Insurance recoveries related to the capital expenditures will be reflected as a reduction to property, plant, and equipment. Ameren Missouri continues to review other legal remedies available.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway ~~energy center~~Energy Center at ~~September 30, 2017. The property coverage and the nuclear liability coverage renewal dates are~~ April 1, 2021:


Type and Source of Coverage	Most Recent Renewal Date	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	January 1, 2021	$	450		$	0
Pool participation	(a)	13,210		(a)	138		(b)
		$	13,660	(c)	$	138
Property damage:
NEIL and EMANI	April 1, 2021	$	3,200	(d)	$	25	(e)
Replacement power:
NEIL	April 1, 2021	$	490	(f)	$	7	(e)

(a)Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.

(b)Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $21 million per year.

(c)Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and ~~January 1, respectively,~~changes in the number of ~~each year. Both coverages were renewed in 2017.~~licensed power reactors.

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 insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events.


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


~~(f)~~	Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 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.

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

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

(f)Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million.

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.~~November 2018. 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 insured by NEIL 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~~the 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.~~contamination, resulting from terrorist attacks. The EMANI policies ~~have an aggregate limit~~are not subject to industrywide aggregates in the event of ~~€600 million for radiation and nonradiation events within a period of 72 hours.~~terrorist attacks on nuclear facilities.

If losses from a nuclear incident at the Callaway ~~energy center~~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.

NOTE 11 – RETIREMENT BENEFITS

The following table presents the components of the net periodic benefit cost ~~(benefit), prior to capitalization,~~(income) incurred for Ameren’s pension and postretirement benefit plans for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~:2020:


	Pension Benefits					Postretirement Benefits
	Three Months					Three Months
		2021		2020			2021		2020
Service cost(a)		$	33	$	27		$	6	$	4
Non-service cost components:
Interest cost		38		43			8		10
Expected return on plan assets		(75)		(73)			(20)		(20)
Amortization of:

Prior service benefit		0		0			(1)		(1)
Actuarial loss (gain)		17		14			(1)		(2)
Total non-service cost components(b)		$	(20)	$	(16)		$	(14)	$	(13)

Net periodic benefit cost (income)		$	13	$	11		$	(8)	$	(9)

Pension Benefits Postretirement Benefits
Three Months Nine Months Three Months Nine Months
2017 2016 2017 2016 2017 2016 2017 2016
Service cost $ 24
$ 20
$ 70
$ 60
$ 6
$ 5
$ 16
$ 15

Interest cost 44
46
134
138
12
12
35
36

Expected return on plan assets (65 ) (63 ) (196 ) (189 ) (19 ) (18 ) (56 ) (54 )
Amortization of:
Prior service benefit (1 ) —
(1 ) —
(2 ) (1 ) (4 ) (3 )
Actuarial loss (gain) 14
8
41
24
(2 ) (3 ) (5 ) (8 )
Net periodic benefit cost (benefit) $ 16
$ 11
$ 48
$ 33
$ (5 ) $ (5 ) $ (14 ) $ (14 )
(a)Service cost, net of capitalization, is reflected in “Operating Expenses – Other operations and maintenance” on Ameren’s statement of income.

(b)Non-service cost components are reflected in “Other Income, Net” on Ameren’s statement of income. See Note 5 – Other Income, Net, for additional information.

Ameren Missouri and Ameren Illinois are responsible for their respective ~~shares~~share of Ameren’s pension and other postretirement costs. The following table presents the respective share of net periodic pension ~~costs~~ and ~~the~~other postretirement benefit costs ~~(benefit)~~(income) incurred for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~:2020:


	Pension Benefits					Postretirement Benefits
	Three Months					Three Months
		2021		2020			2021		2020
Ameren Missouri(a)		$	6	$	4		$	(1)	$	(1)
Ameren Illinois		8		7			(7)		(8)
Other		(1)		0			0		0
Ameren(a)		$	13	$	11		$	(8)	$	(9)

(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.

Funding

Based on its assumptions at March 31, 2021, its investment performance in 2021, and its pension funding policy, the estimated aggregate contributions through 2025 has not changed from the $60 million expected aggregate contributions at December 31, 2020.

Pension Benefits Postretirement Benefits
Three Months Nine Months Three Months Nine Months
2017 2016 2017 2016 2017 2016 2017 2016
Ameren Missouri^(a)
$ 6
$ 6
$ 18
$ 19
$ (1 ) $ (1 ) $ (3 ) $ (3 )
Ameren Illinois 10
6
30
17
(3 ) (3 ) (10 ) (10 )
Other —
(1 ) —
(3 ) (1 ) (1 ) (1 ) (1 )
Ameren^(a)(b)
$ 16
$ 11
$ 48
$ 33
$ (5 ) $ (5 ) $ (14 ) $ (14 )


~~(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 – INCOME TAXES

The following table presents a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the three months ended March 31, 2021 and 2020:


	Ameren		Ameren Missouri		Ameren Illinois
	2021	2020	2021	2020	2021	2020












Three Months
Federal statutory corporate income tax rate:	21%	21%	21%	21%	21%	21%
Increases (decreases) from:
Amortization of deferred investment tax credit	(1)	0	(1)	(1)	0	0
Amortization of excess deferred taxes	(9)	(9)	(17)	(15)	(2)	(3)
Depreciation differences	0	(1)	1	0	(1)	(1)

Renewable and other tax credits	(6)	0	(11)	0	0	0
State tax	6	6	3	3	7	7
Stock-based compensation	(1)	(5)	0	0	0	0

Effective income tax rate	10%	12%	(4)%	8%	25%	24%

NOTE 13 – SUPPLEMENTAL INFORMATION

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows as of March 31, 2021, and December 31, 2020:


	March 31, 2021						December 31, 2020
	Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois
Cash and cash equivalents	$	6	$	1	$	0	$	139	$	136	$	0
Restricted cash	134		—		125		17		—		6
Restricted cash included in “Other current assets”	—		3		—		—		5		—
Restricted cash included in “Other assets”	24		0		24		141		0		141
Restricted cash included in “Nuclear decommissioning trust fund”	8		8		0		4		4		0
Total cash, cash equivalents, and restricted cash	$	172	$	12	$	149	$	301	$	145	$	147

Restricted cash included in “Other current assets” primarily represents funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees. As of December 31, 2020, restricted cash included in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets primarily represents amounts collected under a cost recovery rider restricted for use in the procurement of renewable energy credits and amounts in a trust fund restricted for the use of funding certain asbestos-related claims. As of March 31, 2021, the amounts collected under a cost recovery rider restricted for use in Ameren Illinois’ procurement of renewable energy credits was reclassified to current as the amount is expected to be refunded to customers within a year.

Accounts Receivable

“Accounts receivable – trade” on Ameren’s and Ameren Illinois’ balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At March 31, 2021, and December 31, 2020, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $31 million and $28 million, respectively.

The following table provides a reconciliation of the beginning and ending amount of the allowance for doubtful accounts for the three months ended March 31, 2021 and 2020:


	Three Months
		2021		2020
Ameren:
Beginning of period		$	50	$	17
Bad debt expense		4		3

Net write-offs		(7)		(1)

End of period		$	47	$	19
Ameren Missouri:
Beginning of period		$	16	$	7
Bad debt expense		1		2

Net write-offs		(2)		(1)
End of period		$	15	$	8
Ameren Illinois:(a)
Beginning of Period		$	34	$	10
Bad debt expense		3		1

Net write-offs		(5)		0

End of Period		$	32	$	11

(a)Ameren Illinois has rate-adjustment mechanisms that allow it to recover the difference between its actual net bad debt write-offs under GAAP, including those associated with receivables purchased from alternative retail electric suppliers, and the amount of net bad debt write-offs included in its base rates.

Net write-offs increased for the three months ended March 31, 2021, compared with the year-ago period, due to the resumption of disconnection activities for nonpayment. See Note 2 – Rate and Regulatory Matters for additional information.

Supplemental Cash Flow Information

The following table provides noncash financing and investing activity excluded from the statements of cash flows for the three months ended March 31, 2021 and 2020:


	March 31, 2021						March 31, 2020
	Ameren		Ameren Missouri				Ameren Illinois	Ameren		Ameren Missouri		Ameren Illinois
Investing


Accrued capital expenditures, including wind generation expenditures	$	271	$	141	$	139		$	235	$	97	$	127
Accrued nuclear fuel expenditures	0		0		0			7		7		0
Net realized and unrealized gain (loss) – nuclear decommissioning trust fund	22		22		0			(111)		(111)		0
Financing

Issuance of common stock for stock-based compensation	33		0		0			38		0		0

Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the three months ended March 31, 2021:


	Ameren Missouri			Ameren Illinois			Ameren
Balance at December 31, 2020	$	751		$	5	(a)	$	756	(b)
Liabilities incurred (c)	10			0			10
Liabilities settled	(3)			0			(3)
Accretion	8		(d)	0			8		(d)
Change in estimates	(7)		(e)	0			(7)		(e)
Balance at March 31, 2021	$	759		$	5	(a)	$	764	(b)

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

(b)Balance included $59 million and $60 million in “Other current liabilities” on the balance sheet as of March 31, 2021, and December 31, 2020, respectively.

(c)In the first quarter of 2021, Ameren Missouri recorded an ARO related to the decommissioning for the Atchison Renewable Energy Center.

(d)Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.

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

Stock-based Compensation

On January 1, 2021, Ameren granted 293,058 performance share units with a grant date fair value of $25 million and 125,562 restricted share units with a grant date fair value of $10 million. Awards vest approximately 38 months after the grant date or on a pro-rata basis upon death or eligible retirement. The performance share units vest based on the achievement of certain specified market performance measures (251,177 performance share units) or based on the achievement of renewable generation and energy storage installation targets (41,881 performance share units). The exact number of shares issued pursuant to a performance share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.

For the three months ended March 31, 2021 and 2020, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $5 million and $8 million, respectively.

Deferred Compensation

As of both March 31, 2021, and December 31, 2020, the present value of benefits to be paid for deferred compensation obligations was $90 million, which was primarily reflected in “Other deferred credits and liabilities” on Ameren's consolidated balance sheet.

Operating Revenues

As of March 31, 2021 and 2020, our remaining performance obligations for contracts with a term greater than one year were immaterial. The Ameren Companies elected not to disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less.

See Note 14 – Segment Information for disaggregated revenue information.

Excise Taxes

Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes that are levied on the sale or distribution of natural gas and electricity. The following table presents the excise taxes recorded on a gross basis in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income for the three months ended March 31, 2021 and 2020:


	Three Months
	2021		2020
Ameren Missouri	$	31	$	30
Ameren Illinois	39		35
Ameren	$	70	$	65

Earnings per Share

The following table reconciles the basic weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three months ended March 31, 2021 and 2020:


	Three Months
		2021	2020


Weighted-average Common Shares Outstanding – Basic		254.4	246.4
Assumed settlement of performance share units and restricted stock units		1.5	1.1
Dilutive effect of forward sale agreement		0	0.6
Weighted-average Common Shares Outstanding – Diluted(a)		255.9	248.1

(a)There were 0 potentially dilutive securities excluded from the earnings per diluted share calculations for the three months ended March 31, 2021 and 2020.

NOTE 1214 – SEGMENT INFORMATION

Ameren has four segments: Ameren Missouri, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Transmission. The Ameren Missouri segment includes all of the operations of Ameren Missouri. Ameren Illinois Electric Distribution consists of the electric distribution business of Ameren Illinois. Ameren Illinois Natural Gas consists of the natural gas business of Ameren Illinois. Ameren Transmission is primarily composed of the aggregated electric transmission businesses of Ameren Illinois and ATXI. The category called Other primarily includes Ameren parent company activities and Ameren Services.

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

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 tables present revenues, net income (loss) attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~.2020. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount. For additional information about our segments, see Note 16 – Segment Information under Part II, Item 8, of the Form 10-K.

Ameren


	Ameren Missouri			Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission			Other		Intersegment Eliminations		Ameren










Three Months 2021:
External revenues	$	695		$	411	$	347	$	113		$	—	$	—	$	1,566
Intersegment revenues	9			0		0		17			—		(26)		—
Net income attributable to Ameren common shareholders	47			46		75		47		(a)	18		—		233
Capital expenditures	534		(b)	157		48		141			1		6		887		(b)
Three Months 2020:
External revenues	$	670		$	389	$	271	$	110		$	—	$	—	$	1,440
Intersegment revenues	10			1		0		13			—		(24)		—
Net income (loss) attributable to Ameren common shareholders	(10)			37		55		47		(a)	17		—		146
Capital expenditures	278			123		61		170			3		1		636

Three Months
Ameren
Missouri
Ameren Illinois Electric Distribution Ameren Illinois Natural Gas Ameren Transmission Other
Intersegment
Eliminations
Consolidated
2017
External revenues $ 1,104
$ 405
$ 111
$ 105
$ (2 )    $ —
$ 1,723

Intersegment revenues 11
—
1
14
^(a)
—
   (26 ) —

Net income attributable to Ameren common shareholders 234
31
2
38
^(b)
(17 ) —
288

Capital expenditures 178
112
71
173
(2 ) (7 ) 525

2016
External revenues $ 1,150
$ 502
$ 113
$ 94
$ —
$ —
$ 1,859

Intersegment revenues 15
1
1
14
^(a)
—
(31 ) —

Net income attributable to Ameren common shareholders 241
93
2
39
^(b)
(6 ) —
369

Capital expenditures 147
123
50
175
1
—
496

Nine Months
2017
External revenues $ 2,799
$ 1,176
$ 509
$ 293
$ (2 ) $ —
$ 4,775

Intersegment revenues 41
3
1
33
^(a)
—
(78 ) —

Net income attributable to Ameren common shareholders 359
94
40
106
^(b)
(16 ) —
583

Capital expenditures 533
354
180
463
3
(10 ) 1,523

2016
External revenues $ 2,733
$ 1,210
$ 529
$ 247
$ 1
$ —
$ 4,720

Intersegment revenues 40
3
1
36
^(a)
—
(80 ) —

Net income attributable to Ameren common shareholders 347
122
44
98
^(b)
10
—
621

Capital expenditures 500
359
130
503
4
—
1,496


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


~~(b)~~	~~Ameren Transmission earnings include an allocation of financing costs from Ameren (parent).~~

(a)Ameren Transmission earnings reflect an allocation of financing costs from Ameren (parent).

(b)Includes $193 million at Ameren and Ameren Missouri for wind generation expenditures for the three months ended March 31, 2021.

Ameren Illinois


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations		Ameren Illinois










Three Months 2021:
External revenues	$	411	$	347	$	65	$	—	$	823
Intersegment revenues	0		0		16		(16)		—
Net income available to common shareholder	46		75		28		—		149
Capital expenditures	157		48		132		—		337
Three Months 2020:
External revenues	$	390	$	271	$	62	$	—	$	723
Intersegment revenues	0		0		12		(12)		—
Net income available to common shareholder	37		55		28		—		120
Capital expenditures	123		61		140		—		324

Three Months Ameren Illinois Electric Distribution Ameren Illinois Natural Gas Ameren Illinois Transmission
Intersegment
Eliminations
Consolidated
2017
External revenues $ 405
$ 112
$ 58
$ —
$ 575
Intersegment revenues —
—
14
^(a)
(14 ) —
Net income available to common shareholder 31
2
22
—
55
Capital expenditures 112
71
93
—
276
2016
External revenues $ 503
$ 114
$ 59
$ —
$ 676
Intersegment revenues —
—
14
^(a)
(14 ) —
Net income available to common shareholder 93
2
24
—
119
Capital expenditures 123
50
68
—
241
Nine Months
2017
External revenues $ 1,179
$ 510
$ 165
$ —
$ 1,854
Intersegment revenues —
—
32
^(a)
(32 ) —
Net income available to common shareholder 94
40
57
—
191
Capital expenditures 354
180
226
—
760
2016
External revenues $ 1,213
$ 530
$ 152
$ —
$ 1,895
Intersegment revenues —
—
35
^(a)
(35 ) —
Net income available to common shareholder 122
44
57
—
223
Capital expenditures 359
130
194
—
683


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

The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the three months ended March 31, 2021 and 2020. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission and off-system revenues.

Ameren


	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Intersegment Eliminations		Ameren
























Three Months 2021:
Residential	$	312	$	229	$	0	$	0	$	0	$	541
Commercial	216		132		0		0		0		348
Industrial	52		34		0		0		0		86
Other	61		16		0		130		(26)		181
Total electric revenues	$	641	$	411	$	0	$	130	$	(26)	$	1,156
Residential	$	34	$	0	$	251	$	0	$	0	$	285
Commercial	15		0		64		0		0		79
Industrial	1		0		14		0		0		15
Other	13		0		18		0		0		31
Total natural gas revenues	$	63	$	0	$	347	$	0	$	0	$	410
Total revenues(a)	$	704	$	411	$	347	$	130	$	(26)	$	1,566
Three Months 2020:
Residential	$	297	$	220	$	0	$	0	$	—	$	517
Commercial	221		126		0		0		0		347
Industrial	53		35		0		0		0		88
Other	60		9		0		123		(24)		168
Total electric revenues	$	631	$	390	$	0	$	123	$	(24)	$	1,120
Residential	$	33	$	0	$	213	$	0	$	0	$	246
Commercial	13		0		54		0		0		67
Industrial	1		0		3		0		0		4
Other	2		0		1		0		0		3
Total natural gas revenues	$	49	$	0	$	271	$	0	$	0	$	320
Total revenues(a)	$	680	$	390	$	271	$	123	$	(24)	$	1,440

(a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the three months ended March 31, 2021 and 2020:


	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Ameren








Three Months 2021:
Revenues from alternative revenue programs	$	(10)	$	61	$	3	$	(1)	$	53
Other revenues not from contracts with customers	(2)		3		1		0		2

Three Months 2020:
Revenues from alternative revenue programs	$	(3)	$	46	$	11	$	12	$	66
Other revenues not from contracts with customers	8		1		1		0		10

Ameren Illinois


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations		Ameren Illinois












Three Months 2021:
Residential	$	229	$	251	$	0	$	0	$	480
Commercial	132		64		0		0		196
Industrial	34		14		0		0		48
Other	16		18		81		(16)		99
Total revenues(a)	$	411	$	347	$	81	$	(16)	$	823
Three Months 2020:
Residential	$	220	$	213	$	0	$	0	$	433
Commercial	126		54		0		0		180
Industrial	35		3		0		0		38
Other	9		1		74		(12)		72
Total revenues(a)	$	390	$	271	$	74	$	(12)	$	723

(a)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the three months ended March 31, 2021 and 2020:


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Ameren Illinois








Three Months 2021:
Revenues from alternative revenue programs	$	61	$	3	$	(1)	$	63
Other revenues not from contracts with customers	3		1		0		4

Three Months 2020:
Revenues from alternative revenue programs	$	46	$	11	$	10	$	67
Other revenues not from contracts with customers	1		1		0		2

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 and Risk Factors 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.

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

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

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per ~~diluted~~ share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per ~~diluted~~ 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 was $288 million~~shareholders in the three months ended ~~September 30, 2017,~~March 31, 2021, was $233 million, or $0.91 per diluted share, compared with ~~$369~~$146 million, or $0.59 per diluted share, in the year-ago period. Net income ~~attributable to Ameren common shareholders was $583 million in nine~~for the three months ended ~~September 30, 2017, compared with $621 million in the year-ago period. Net income was unfavorably affected in the three and nine months ended September 30, 2017,~~March 31, 2021, compared to the year-ago ~~periods, by milder temperatures in 2017 and decreased Ameren Illinois Electric Distribution earnings due to a change in the method used to recognize interim~~ period, revenue related to Ameren Illinois Electric Distribution’s revenue requirement reconciliation in connection with the decoupling provisions of the FEJA. Earnings were also unfavorably affected in the three and nine months ended September 30, 2017, compared to the year-ago periods, by the absence of the recognition in 2016 of a MEEIA 2013 performance incentive award at Ameren Missouri. Net income in the three and nine months ended September 30, 2017, compared to the year-ago periods, was favorably affected by ~~an increase in base rates and lower base level~~the results of ~~tracked expense at~~ Ameren ~~Missouri pursuant to the MoPSC’s~~Missouri’s March ~~2017~~2020 electric rate order, ~~and increased~~infrastructure investments ~~in infrastructure~~that drove higher earnings at ~~the~~Ameren Transmission and Ameren Illinois Electric Distribution, and increased earnings at Ameren Illinois Natural Gas as a result of a change in rate design, which concentrates more revenues in the winter heating season due to an increase in volumetric rates and a decrease in fixed customer rates, and higher delivery service rates. Earnings for the three months ended March 31, 2021, compared to the year-ago period, were also favorably affected by lower other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms, primarily due to changes in the value of company owned life insurance and disciplined cost management; increased Ameren Missouri electric retail sales, primarily resulting from colder winter temperatures experienced in 2021; and increased income tax benefit at Ameren (parent) and Ameren Missouri due to timing differences associated with certain income tax benefits, which is not expected to materially impact full year results. Net income for the three months ended March 31, 2021, compared to the year-ago period, was unfavorably affected by the result of the March 2021 FERC order, primarily related to the historical recovery of materials and supplies inventories, which decreased Ameren Transmission ~~segments reflecting Ameren’s strategy to allocate incremental capital to those businesses.~~earnings; the effect of dilution; and higher financing costs at Ameren (parent).

Ameren’s strategic plan includes investing ~~in,~~ and operating its utilities in a manner consistent with existing regulatory frameworks, enhancing those frameworks, and advocating for responsible energy and economic policies, as well as creating and capitalizing on opportunities for investment for the benefit of its customers, shareholders, and ~~shareholders.~~the environment. Ameren remains focused on disciplined cost management and strategic capital allocation. Ameren invested $0.9 billion in its rate-regulated businesses in the three months ended March 31, 2021.

The COVID-19 pandemic continues to affect our results of operations, financial position, and liquidity, but we expect a gradual improvement in sales volumes in 2021, compared to 2020. In the first ~~nine~~three months of ~~2017, Ameren~~2021, our sales volumes were comparable to the same period in 2020, excluding the estimated effects of weather and customer energy-efficiency programs. However, we experienced an increase in our accounts receivable balances that were past due or that were a part of a deferred payment arrangement, and a decline in our cash collections from customers. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions. In general, restrictions on social activities and nonessential businesses implemented in our service territories in 2020 have been relaxed. However, certain restrictions remain in place that limit individual activities and the operation of nonessential businesses and additional restrictions may be imposed in the future. We continue to ~~allocate significant amounts of capital to those~~assess the impacts the COVID-19 pandemic is having on our businesses, ~~that are supported by constructive regulatory frameworks, investing $1 billion of capital expenditures in its FERC rate-regulated electric transmission and Illinois~~including impacts on electric and natural gas ~~distribution businesses.~~sales volumes, liquidity, bad debt expense, and supply chain operations. For further discussion of these and other matters, see Note 2 – Rate and Regulatory Mattersunder Part I, Item 1, of this report, and Results of Operations, Liquidity and Capital Resources, and Outlook sections below. In addition, for information regarding Ameren Illinois’ suspension and subsequent reinstatement of customer disconnection activities and late fee charges for nonpayment, see Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.

In ~~March 2017,~~January 2021, Ameren Missouri acquired an up-to 300-MW wind generation project located in northwestern Missouri and partially placed it in service as the ~~MoPSC issued~~Atchison Renewable Energy Center. As of the date of this filing, Ameren Missouri has placed approximately half of the project in service, representing a purchase price of approximately $250 million, including an ~~order approving a unanimous stipulation and agreement~~immaterial amount of transaction costs. Ameren Missouri expects the remaining MWs of the project to be in service by the end of September 2021. The Atchison Renewable Energy Center will support Ameren Missouri’s ~~July 2016 regulatory rate review. The electric rate order resulted in a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in~~compliance with the ~~base level of net~~Missouri renewable energy costs, and a $26 million reduction in the base level of certain tracked expenses, compared to the amounts in the MoPSC’s April 2015 rate order. The new rates and base level of expenses became effective on April 1, 2017. standard.

In ~~September 2017,~~February 2021, Ameren Missouri filed an update to its ~~non-binding 20-year integrated resource plan~~Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2021. The plan is designed to upgrade Ameren Missouri’s ~~preferred~~electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4 billion over the five-year period from 2021 through 2025, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 and 2025 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028.

In March 2021, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for ~~meeting customers’ projected long-term energy needs in~~electric service by $299 million. The electric rate increase request is based on a ~~cost-effective fashion that maintains system reliability as it targets cleaner~~9.9% ROE, a capital structure composed of 51.9% common equity, a rate base of $10.0 billion and ~~more diverse sources~~a test year ended December 31, 2020, with certain pro-forma adjustments expected through an anticipated true-up date of ~~energy generation. These~~September 30, 2021. 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 February 2022 and new ~~renewable energy sources would also support~~rates effective by March 2022. See Note 2 – Rate and Regulatory Mattersunder Part I, Item 1, of this report for additional information.

In March 2021, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for natural gas delivery service by $9 million. The natural gas rate increase request is based on a 9.8% ROE, a capital structure composed of 51.9% common equity, a rate base of $310 million, and a test year ended December 31, 2020, with certain pro-forma adjustments expected through an anticipated true-up date of September 30, 2021. The MoPSC proceeding relating to the proposed natural gas delivery service rate changes will take place over a period of up to 11 months with a decision by the MoPSC expected by February 2022 and new rates effective by March 2022.

In March 2021, the MoPSC issued orders approving nonunanimous stipulation and agreements related to Ameren Missouri’s ~~compliance~~

~~with~~electric and natural gas service accounting authority order requests. The orders allowed Ameren Missouri to accumulate $9 million of certain costs incurred related to the ~~state~~COVID-19 pandemic, net of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to customer rate increase limitations. Ameren Missouri’s plan contemplates adding at least 700 megawatts of wind generation by 2020,cost savings, as well as ~~100 megawatts~~forgone customer late fee and reconnection fee revenues from March 2020 to March 2021, for potential recovery in the electric and natural gas service regulatory rate reviews discussed above. As of solar generation over the next 10 years, with 50 megawatts anticipated to come online by 2025. The new wind generation is expected to be located in Missouri and neighboring states. The source, location, and cost of the new wind generation, among other items, remain subject to reaching agreements with developers.~~Based on current and projected market prices for energy, and for wind and solar generation technologies, among other factors,~~March 31, 2021, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost alternative for customers. The plan also includes expected implementation of continued customer energy efficiency programs. Ameren Missouri’s plan for the addition of renewable resources could be impacted by, among other factors: the availability of federal production tax creditsdeferred $5 million as a regulatory asset related to ~~renewable energy and its ability to use such credits;~~ the cost of wind and solar generation technologies, as well as energy prices; Ameren Missouri’s ability to obtain interconnection agreements with MISO or other RTOs, including the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSCaccounting authority orders. If approved for projects located in Missouri, or any other required project approvals. The wind generation identified in Ameren Missouri’s plan could represent incremental investments of approximately $1 billion. In connection with the integrated resource plan filing,recovery, Ameren Missouri ~~established~~would recognize the remaining $4 million associated with forgone customer late fee and reconnection fee revenue when billed to customers.

In March 2021, the ICC issued an order approving Ameren Illinois’ requested tariff to reconcile its electric distribution service revenue requirement for a ~~goal~~period of ~~reducing CO~~₂ ~~emissions 80%~~up to two years after the final customer rate update under performance-based formula ratemaking. To utilize the reconciliation, the ICC-approved tariff requires Ameren Illinois to file a traditional regulatory rate review for its electric distribution service, which may be based on a future test year, by ~~2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO~~₂ ~~emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at~~ the end of ~~its useful life.~~

~~Ameren Illinois invested approximately $535 million in electric distribution and natural gas infrastructure projects~~March in the ~~first nine months~~year following the last year in which an annual performance-based formula rate update was permitted. Pursuant to this order, and without legislative change or Ameren Illinois’ election to no longer use performance-based formula ratemaking, Ameren Illinois’ 2022 and 2023 revenues would reflect each year’s actual costs, year-end rate base, and a return at the applicable WACC, with the ROE based on the annual average of ~~2017.~~ the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The revenue requirement adjustment will be collected from, or refunded to, customers within two years from the end of the reconciled year.

In ~~April 2017,~~March 2021, Ameren Illinois filed with the ICC an energy-efficiency plan which includes annual investments in electric energy-efficiency programs up to approximately $100 million per year from 2022 through 2025. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not included in the electric distribution service performance-based formula ratemaking framework. A decision by the ICC in this proceeding is expected by September 2021.

In April 2021, Ameren Illinois filed its annual electric distribution service performance-based formula rate update ~~to establish the revenue requirement used for 2018 rates. In June 2017,~~with the ICC, ~~staff submitted its calculation~~requesting an increase of ~~the revenue requirement, which Ameren Illinois supported~~$64 million in its revised July 2017 filing, and recommended a decrease to the electric distribution service revenue requirement. Pending ICC approval, this update filing will result in a $17 million decrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018.rates. This update reflects an increase to the annual performance-based formula rate based on ~~2016~~2020 actual costs, ~~and expected net plant additions for 2017, as well as~~ an increase to include the ~~2016~~2020 revenue requirement reconciliation ~~adjustment. The increases in the update filing are more than offset by a decrease~~adjustment, and an increase for the conclusion of the ~~2015~~2019 revenue requirement reconciliation adjustment, which will be fully ~~collected from~~refunded to customers in ~~2017.~~2021, consistent with the ICC’s December 2020 annual update filing order. It also reflects an increase based on expected net plant additions for 2021. An ICC decision ~~on the revenue requirement to be used for 2018 rates~~in this proceeding is expected by December ~~2017.~~2021, with new rates effective January 2022.

In the first nine months of 2017, Ameren Transmission invested approximately $460 million in FERC rate-regulated electric transmission projects, including the Illinois Rivers project, the Spoon River project, and Ameren Illinois’ transmission projects to maintain and improve reliability. ATXI’s construction activities for its Illinois Rivers and Spoon River projects are continuing on schedule and are expected to be completed by 2019 and 2018, respectively. Related to its Mark Twain project, in the third quarter of 2017, ATXI finalized an alternative project route and reached agreements with a cooperative electric company in northeast Missouri and Ameren Missouri to locate nearly all of the project on existing transmission line corridors. It also received assents for road crossings from the five affected counties in northeast Missouri. ATXI filed for a certificate of convenience and necessity with the MoPSC and anticipates a decision from the MoPSC in the first half of 2018. ATXI plans to complete the project in December 2019; however, delays in obtaining approval from the MoPSC could delay completion.

In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes, due 2050, through a private placement offering. ATXI issued $150 million principal amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes which were used by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, ~~energy efficiency~~including those resulting from the COVID-19 pandemic discussed below, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands, as well as by ~~nuclear refueling and other~~non-nuclear 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~~rates we charge customers 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~~the frameworks established by our regulators. See Note 2 – Rate and Regulatory Matters 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 for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory mechanisms.

We continue to assess the impacts of the COVID-19 pandemic on our businesses, including impacts on electric and natural gas sales volumes, supply chain operations, and bad debt expense.Regarding uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri does not expect a material impact to earnings from increases in bad debt expense. As of March 31, 2021, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 27%, 19%, and 32%, or $137 million, $33 million, and $104 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’

customer trade receivables before allowance for doubtful accounts, respectively. As of March 31, 2020, these percentages were 21%, 16%, and 25%, or $99 million, $29 million, and $70 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. Ameren Missouri's electric sales volumes have been, and continue to be, affected by the COVID-19 pandemic. In the three months ended March 31, 2021, compared to the same period in 2020, Ameren Missouri experienced a reduction in commercial and industrial electric sales volumes, offset by increased electric sales volumes to higher margin residential customers, excluding the estimated effects of weather and customer energy-efficiency programs. The following table provides the increases and (decreases) in Ameren Missouri electric sales volumes by customer class for the three months ended March 31, 2021, compared to the same period in 2020, excluding the estimated effects of weather and customer energy-efficiency programs:


	Three months ended March 31, 2021, versus same period in 2020
Ameren Missouri Customer Class
Residential		2.7	%
Commercial		(2.8)	%
Industrial		(1.2)	%
Total		(0.1)	%

Ameren Missouri principally uses coal ~~nuclear fuel,~~ and ~~natural gas~~enriched uranium for fuel in its electric operations and purchases natural gas for its customers. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, and many other factors. ~~As described below, we~~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'~~Illinois’ electric distribution ~~service~~ business, and a FAC for Ameren ~~Missouri's~~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. In addition, Ameren Missouri’s MEEIA customer energy efficiency program costs, throughput disincentive, and any performance incentive are recoverable through the MEEIA cost recovery mechanism without a traditional rate proceeding. Ameren Missouri also has a cost recovery mechanism for natural gas purchased on behalf of its customers. These pass-through purchased gas costs do not affect Ameren Missouri’s natural gas margins as any change in costs is offset by a corresponding change in revenues. Ameren Missouri employs other cost recovery mechanisms, including a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a renewable energy standards cost tracker, and a solar rebate program tracker. Each of these trackers allows Ameren Missouri to record the difference between the level of incurred costs under GAAP and the level of such costs included in rates as a regulatory asset or regulatory liability, which will be reflected in base rates in a subsequent MoPSC rate order.

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

Ameren Illinois’ electric distribution service rates are subject to an annual revenue requirement reconciliation to its actual recoverable costs and allowed return on equity under a formula ratemaking process effective through 2022. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes. These recoverable costs do not include those costs recovered through separate cost recovery mechanisms. A portion of the electric distribution costs included in those income statement line items are not recoverable. 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.

Ameren Illinois’ electric distribution service revenue requirement is based on recoverable costs, year-end rate base, a capital structure of 50% common equity, and a return on equity. The return on equity 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. 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, which reflects the actual recoverable costs incurred and the 13-month average rate base for a given year, with the revenue requirement in customer rates, including an allowed return on equity. 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 line items are not recoverable. 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. 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. The total return on equity currently allowed for Ameren Illinois’ and ATXI’s electric transmission service businesses is 10.82% and is subject to a FERC complaint case. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information.

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

Earnings Summary

The following table presents a summary of ~~Ameren's~~Ameren’s earnings for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016:~~2020:


	Three Months				Nine Months					Three Months
	2017		2016		2017		2016			2021		2020
Net income attributable to Ameren common shareholders	$	288	$	369	$	583	$	621	Net income attributable to Ameren common shareholders	$	233	$	146
Earnings per common share – diluted	1.18		1.52		2.39		2.56		Earnings per common share – diluted	0.91		0.59

Net income attributable to Ameren common shareholders ~~decreased $81~~increased $87 million ~~or 34 cents per diluted share,~~ in the three months ended ~~September 30, 2017,~~March 31, 2021, compared with the year-ago period. The ~~decrease~~increase was ~~principally~~ due to net income ~~decreases~~increases of ~~$62~~$20 million, $9 million, and $7$1 million at Ameren Illinois Natural Gas, Ameren Illinois Electric Distribution, and ~~Ameren Missouri, respectively, and an increase in net loss of $11 million for~~ activity not reported as part of a segment, primarily at Ameren (parent).

~~Net income attributable to~~, respectively. Additionally, Ameren ~~common shareholders decreased $38 million, or 17 cents per diluted share, in the nine months ended September 30, 2017, compared with the year-ago period. The decrease was due to~~Missouri had net income ~~decreases~~ of ~~$28~~$47 million, ~~and $4 million at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively. Additionally, activity not reported as part of~~compared to a ~~segment, primarily Ameren (parent), had a $16 million~~ net loss ~~in the first nine months of 2017, compared with net income~~ of $10 million in the same period in ~~2016. The decrease was partially offset by an increase in net income of $12 million and $8 million at Ameren Missouri and Ameren Transmission, respectively.~~2020.

~~Earnings per diluted share were unfavorably affected in the three and nine months ended September 30, 2017, compared to the year-ago periods (except where a specific period is referenced), by:~~

~~decreased demand primarily at Ameren Missouri due to milder winter and summer temperatures in 2017 (estimated at 8 cents per share and 16 cents per share, respectively);~~

a change in the 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 (24 cents per share and 12 cents per share, respectively);

an increase in income tax expense due to an increase in the Illinois corporate income tax rate recorded at Ameren (parent) as discussed in Note 1 – Summary of Significant Accounting Policies under Part I, Item 1, of this report (6 cents per share for both periods);

~~the absence in 2017 of the MEEIA 2013 performance incentive at Ameren Missouri recognized in the third quarter of 2016 (5 cents per share for both periods);~~

increased depreciation and amortization expenses, primarily at Ameren Missouri, resulting from additional electric property, plant, and equipment (2 cents per share and 5 cents per share, respectively);

an increase in the effective tax rate, excluding the effect of the increase in the Illinois corporate income tax rate discussed above, primarily due to a decrease in the income tax benefit recorded at Ameren (parent) related to share-based compensation (4 cents per share for the nine months ended September 30, 2017);

the absence of increased Ameren Missouri electric margins in 2016 resulting from the suspension of operations at the New Madrid Smelter in the first quarter of 2016 and the elimination of recovery under the FAC tariff effective April 1, 2017, which had allowed Ameren Missouri to retain a portion of the revenues from off-system sales it made as a result of reduced sales to the New Madrid Smelter as discussed in the Electric and Natural Gas Margins section below (1 cent per share and 2 cents per share, respectively); and

increased other operations and maintenance expenses not subject to riders or regulatory tracking mechanisms at Ameren Missouri, primarily due to increased repairs and compliance expenditures (2 cents per share for the nine months ended September 30, 2017).

Earnings per diluted share were favorably affected in the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2021, compared to the year-ago ~~periods (except where a specific~~ period ~~is referenced)~~, by:

~~an increase in base rates and lower base level~~•the results of ~~expenses at Ameren Missouri pursuant to~~ the ~~MoPSC’s~~ March ~~2017~~2020 MoPSC electric rate order, as discussed in Note 2 – Rate and Regulatory Matters under Part I,II, Item 1,8, of ~~this report (15~~the Form 10-K, which reduced the base level of expenses at Ameren Missouri, partially offset by lower base rates, net of recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs and recoverable depreciation under the PISA (10 cents per share);

•decreased other operations and maintenance expense not subject to riders and trackers, primarily due to changes in the cash surrender value of company-owned life insurance and disciplined cost management, partially offset by 2 cents per share ~~and 26 cents per share, respectively);~~

~~the absence in 2017~~due to amortization of costs associated with the Callaway ~~energy center’s~~Energy Center’s scheduled refueling and maintenance outage completed in ~~the second quarter of 2016, partially offset by costs incurred to prepare for the scheduled outage that began in October 2017 (7~~2020 (6 cents per ~~share for the nine months ended September 30, 2017)~~share);

•increased rate base investments and a higher recognized ROE, which increased earnings at Ameren Transmission ~~earnings under formula ratemaking, primarily due to additional rate base partially offset by a lower recognized return on equity (1 cent per share~~ and ~~5 cents per share, respectively); and~~

~~increased~~ Ameren Illinois Electric Distribution ~~earnings under formula ratemaking,~~(5 cents per share);

•increased income tax benefit at Ameren (parent), primarily due to ~~additional~~increased interim period income tax benefits in 2021 related to wind generation facilities, and at Ameren Missouri primarily due to year-over-year timing differences associated with the recognition of excess deferred income taxes, both of which are not expected to materially impact full year results (4 cents per share);

•the impact of weather on electric retail sales at Ameren Missouri, primarily resulting from colder winter temperatures experienced in 2021 (estimated at 4 cents per share);

•a change in rate design pursuant to the ICC's January 2021 natural gas rate order that concentrates more revenues in the winter heating season due to an increase in volumetric rates, which increased margins at Ameren Illinois Natural Gas for the three months ended March 31, 2021, but is not expected to materially impact full year results (4 cents per share);

•higher base ~~investment as well as a higher recognized return on equity~~rates pursuant to the ICC's January 2021 natural gas rate order, which increased margins at Ameren Illinois Natural Gas (3 cents per share); and

•increased other income, net, at Ameren Missouri due to the absence of charitable donations made in 2020 pursuant to the March 2020 electric rate order (2 cents per share).

Earnings per diluted share were unfavorably affected in the three months ended March 31, 2021, compared to the year-ago period, by:

•increased weighted-average basic common shares outstanding and 4the effect of dilution (4 cents per ~~share, respectively).~~share);

•the result of the March 2021 FERC order, primarily related to the historical recovery of materials and supplies inventories, which decreased Ameren Transmission earnings (3 cents per share); and

•increased net financing costs at Ameren (parent), primarily due to higher long-term debt balances (2 cents per share).

The cents per share information presented is based on the ~~average diluted~~weighted-average basic common shares outstanding in the three ~~and nine~~ months ended ~~September 30, 2016.~~March 31, 2020, and does not reflect any change in earnings per share resulting from dilution, unless otherwise noted. Amounts other than variances related to income taxes have been presented net of income taxes using Ameren’s ~~2016~~2021 statutory tax rate of ~~39%~~26%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization Expenses, Taxes Other Than Income Taxes, Other Income, ~~and Expenses,~~Net, Interest Charges, and Income Taxes, see the major headings below.

Below is Ameren’s table of income statement components by segment for the three ~~and~~ ~~nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016:~~2020:


	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Other / Intersegment Eliminations		Ameren
































Three Months 2021:
Electric margins	$	488	$	289	$	—	$	130	$	(7)	$	900
Natural gas margins	32		—		213		—		—		245

Other operations and maintenance expenses	(225)		(125)		(56)		(16)		2		(420)

Depreciation and amortization expenses	(156)		(75)		(22)		(28)		—		(281)
Taxes other than income taxes	(77)		(20)		(25)		(2)		(4)		(128)
Other income, net	23		8		3		3		9		46
Interest charges	(39)		(18)		(10)		(23)		(10)		(100)
Income (taxes) benefit	2		(12)		(28)		(17)		28		(27)


Net income	48		47		75		47		18		235
Noncontrolling interests – preferred stock dividends	(1)		(1)		—		—		—		(2)
Net income attributable to Ameren common shareholders	$	47	$	46	$	75	$	47	$	18	$	233
Three Months 2020:
Electric margins	$	452	$	280	$	—	$	123	$	(9)	$	846
Natural gas margins	31		—		182		—		—		213

Other operations and maintenance expenses	(239)		(130)		(57)		(14)		2		(438)

Depreciation and amortization expenses	(139)		(71)		(21)		(24)		—		(255)
Taxes other than income taxes	(79)		(19)		(22)		(2)		(3)		(125)
Other income, net	4		7		2		2		6		21
Interest charges	(40)		(18)		(10)		(21)		(4)		(93)
Income (taxes) benefit	1		(11)		(19)		(17)		25		(21)


Net income (loss)	(9)		38		55		47		17		148
Noncontrolling interests – preferred stock dividends	(1)		(1)		—		—		—		(2)
Net income (loss) attributable to Ameren common shareholders	$	(10)	$	37	$	55	$	47	$	17	$	146

Ameren
Missouri

Ameren
Illinois
Electric
Distribution

Ameren
Illinois
Natural Gas
Ameren Transmission
Other /
Intersegment
Eliminations
Total
Three Months 2017:
Electric margins $ 857
$ 267
$ —
$ 119
$ (10 ) $ 1,233
Natural gas margins 13
—
91
—
—
104
Other operations and maintenance (224 ) (118 ) (52 ) (16 ) 8
(402 )
Depreciation and amortization (134 ) (60 ) (15 ) (15 ) (1 ) (225 )
Taxes other than income taxes (95 ) (20 ) (12 ) (1 ) (1 ) (129 )
Other income (expense) 11
1
—
—
(1 ) 11
Interest charges (50 ) (19 ) (8 ) (18 ) (2 ) (97 )
Income taxes (143 ) (20 ) (2 ) (31 ) (9 ) (205 )
Net income (loss) 235
31
2
38
(16 ) 290
Noncontrolling interests – preferred stock dividends
(1 ) —
—
—
(1 ) (2 )
Net income (loss) attributable to Ameren common shareholders $ 234
$ 31
$ 2
$ 38
$ (17 ) $ 288
Three Months 2016:
Electric margins $ 862
$ 379
$ —
$ 108
$ (7 ) $ 1,342
Natural gas margins 14
—
86
—
—
100
Other revenues 1
—
—
—
(1 ) —
Other operations and maintenance (220 ) (132 ) (52 ) (17 ) 10
(411 )
Depreciation and amortization (130 ) (57 ) (13 ) (10 ) (1 ) (211 )
Taxes other than income taxes (96 ) (20 ) (10 ) (1 ) (2 ) (129 )
Other income (expense) 12
2
(1 ) —
(3 ) 10
Interest charges (53 ) (17 ) (8 ) (17 ) (2 ) (97 )
Income (taxes) benefit (148 ) (62 ) —
(24 ) 1
(233 )
Net income (loss) 242
93
2
39
(5 ) 371
Noncontrolling interests – preferred stock dividends
(1 ) —
—
—
(1 ) (2 )
Net income (loss) attributable to Ameren common shareholders $ 241
$ 93
$ 2
$ 39
$ (6 ) $ 369
Nine Months 2017:
Electric margins $ 1,962
$ 834
$ —
$ 326
$ (24 ) $ 3,098
Natural gas margins 54
—
343
—
(1 ) 396
Other revenues —
1
—
—
(1 ) —
Other operations and maintenance (655 ) (391 ) (159 ) (47 ) 23
(1,229 )
Depreciation and amortization (399 ) (178 ) (44 ) (44 ) (3 ) (668 )
Taxes other than income taxes (255 ) (56 ) (43 ) (4 ) (6 ) (364 )
Other income (expense) 30
1
(2 ) —
(3 ) 26
Interest charges (157 ) (55 ) (27 ) (49 ) (7 ) (295 )
Income (taxes) benefit (218 ) (61 ) (27 ) (76 ) 6
(376 )
Net income (loss) 362
95
41
106
(16 ) 588
Noncontrolling interests – preferred dividends
(3 ) (1 ) (1 ) —
—
(5 )
Net income (loss) attributable to Ameren common shareholders $ 359
$ 94
$ 40
$ 106
$ (16 ) $ 583
Nine Months 2016:
Electric margins $ 1,939
$ 874
$ —
$ 283
$ (20 ) $ 3,076
Natural gas margins 57
—
336
—
(1 ) 392
Other revenues 1
—
—
—
(1 ) —
Other operations and maintenance (670 ) (399 ) (153 ) (47 ) 23
(1,246 )
Depreciation and amortization (384 ) (169 ) (40 ) (30 ) (5 ) (628 )
Taxes other than income taxes (252 ) (54 ) (42 ) (3 ) (7 ) (358 )
Other income (expense) 32
5
(2 ) 1
(3 ) 33
Interest charges (158 ) (54 ) (26 ) (43 ) (6 ) (287 )
Income (taxes) benefit (215 ) (80 ) (28 ) (63 ) 30
(356 )
Net income 350
123
45
98
10
626
Noncontrolling interests – preferred dividends
(3 ) (1 ) (1 ) —
—
(5 )
Net income attributable to Ameren common shareholders $ 347
$ 122
$ 44
$ 98
$ 10
$ 621

Below is Ameren ~~Illinois'~~Illinois’ table of income statement components by segment for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016:~~2020:


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Ameren Illinois































Three Months 2021:
Electric and natural gas margins	$	289	$	213	$	81	$	583


Other operations and maintenance expenses	(125)		(56)		(13)		(194)
Depreciation and amortization expenses	(75)		(22)		(18)		(115)
Taxes other than income taxes	(20)		(25)		(1)		(46)
Other income, net	8		3		3		14
Interest charges	(18)		(10)		(14)		(42)
Income taxes	(12)		(28)		(10)		(50)


Net income	47		75		28		150
Preferred stock dividends	(1)		—		—		(1)
Net income attributable to common shareholder	$	46	$	75	$	28	$	149
Three Months 2020:
Electric and natural gas margins	$	280	$	182	$	74	$	536


Other operations and maintenance expenses	(130)		(57)		(12)		(199)
Depreciation and amortization expenses	(71)		(21)		(15)		(107)
Taxes other than income taxes	(19)		(22)		(1)		(42)
Other income, net	7		2		2		11
Interest charges	(18)		(10)		(11)		(39)
Income taxes	(11)		(19)		(9)		(39)


Net income	38		55		28		121
Preferred stock dividends	(1)		—		—		(1)

Net income attributable to common shareholder	$	37	$	55	$	28	$	120

Ameren
Illinois
Electric
Distribution

Ameren
Illinois
Natural Gas

Ameren
Illinois Transmission
Total
Three Months 2017:
Electric and natural gas margins $ 267
$ 91
$ 72
$ 430
Other operations and maintenance (118 ) (52 ) (13 ) (183 )
Depreciation and amortization (60 ) (15 ) (11 ) (86 )
Taxes other than income taxes (20 ) (12 ) (1 ) (33 )
Other income 1
—
—
1
Interest charges (19 ) (8 ) (9 ) (36 )
Income taxes (20 ) (2 ) (16 ) (38 )
Net income 31
2
22
55
Preferred stock dividends —
—
—
—
Net income attributable to common shareholder $ 31
$ 2
$ 22
$ 55
Three Months 2016:
Electric and natural gas margins $ 379
$ 86
$ 73
$ 538
Other operations and maintenance (132 ) (52 ) (14 ) (198 )
Depreciation and amortization (57 ) (13 ) (10 ) (80 )
Taxes other than income taxes (20 ) (10 ) —
(30 )
Other income (expense) 2
(1 ) —
1
Interest charges (17 ) (8 ) (10 ) (35 )
Income taxes (62 ) —
(15 ) (77 )
Net income 93
2
24
119
Preferred stock dividends —
—
—
—
Net income attributable to common shareholder $ 93
$ 2
$ 24
$ 119
Nine Months 2017:
Electric and natural gas margins $ 834
$ 343
$ 197
$ 1,374
Other revenues 1
— — 1
Other operations and maintenance (391 ) (159 ) (40 ) (590 )
Depreciation and amortization (178 ) (44 ) (32 ) (254 )
Taxes other than income taxes (56 ) (43 ) (2 ) (101 )
Other income (expense) 1
(2 ) —
(1 )
Interest charges (55 ) (27 ) (27 ) (109 )
Income taxes (61 ) (27 ) (39 ) (127 )
Net income 95
41
57
193
Preferred stock dividends (1 ) (1 ) —
(2 )
Net income attributable to common shareholder $ 94
$ 40
$ 57
$ 191
Nine Months 2016:
Electric and natural gas margins $ 874
$ 336
$ 187
$ 1,397
Other operations and maintenance (399 ) (153 ) (40 ) (592 )
Depreciation and amortization (169 ) (40 ) (28 ) (237 )
Taxes other than income taxes (54 ) (42 ) (2 ) (98 )
Other income (expense) 5
(2 ) 1
4
Interest charges (54 ) (26 ) (25 ) (105 )
Income taxes (80 ) (28 ) (36 ) (144 )
Net income 123
45
57
225
Preferred stock dividends (1 ) (1 ) —
(2 )
Net income attributable to common shareholder $ 122
$ 44
$ 57
$ 223

Electric and Natural Gas Margins

The following table presents the favorable (unfavorable) variations by Ameren segment for electric and natural gas margins for the three and nine months ended September 30, 2017, compared with the year-ago periods. 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~~to complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months 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 )
Base rates (estimate)^(c)
29
10
—
11
—
50
FEJA impact on IEIMA – timing of revenue recognition
—
(94 ) —
—
—
(94 )
Recovery of power restoration efforts provided to other utilities 5
1
—
—
—
6
Sales volume (excluding the effect of weather and the New Madrid Smelter) 8
—
—
—
—
8
New Madrid Smelter revenues (1 ) —
—
—
—
(1 )
MEEIA 2013 performance incentive (19 ) —
—
—
—
(19 )
Off-system sales (38 ) —
—
—
—
(38 )
Transmission services revenues 2
—
—
—
—
2
Other (8 ) (4 ) —
—
2
(10 )
Cost recovery mechanisms – offset in fuel and purchased power:^(d)

Power supply costs —
(7 ) —
—
—
(7 )
Renewable energy adjustment —
4
—
—
—
4
Zero-emission credits —
21
—
—
—
21
Recovery of FAC under-recovery 3
—
—
—
—
3
Other cost recovery mechanisms:^(e)

Bad debt, energy efficiency programs, and remediation cost riders —
(20 ) —
—
—
(20 )
MEEIA program costs 6
—
—
—
—
6
Total electric revenue change $ (46 ) $ (98 ) $ —
$ 11
$ 2
$ (131 )
Fuel and purchased power change:
Energy costs (excluding the effect of weather and the New Madrid Smelter) $ 37
$ —
$ —
$ —
$ —
$ 37
New Madrid Smelter energy costs (6 ) —
—
—
—
(6 )
Effect of weather (estimate)^(b)
7
2
—
—
—
9
Effect of lower net energy costs included in base rates 20
—
—
—
—
20
Transmission services charges (5 ) —
—
—
—
(5 )
Other (9 ) 2
—
—
(5 ) (12 )
Cost recovery mechanisms – offset in electric revenue:^(d)

Power supply costs —
7
—
—
—
7
Renewable energy adjustment —
(4 ) —
—
—
(4 )
Zero-emission credits —
(21 ) —
—
—
(21 )
Recovery of FAC under-recovery (3 ) —
—
��
—
(3 )
Total fuel and purchased power change $ 41
$ (14 ) $ —
$ —
$ (5 ) $ 22
Net change in electric margins $ (5 ) $ (112 ) $ —
$ 11
$ (3 ) $ (109 )
Natural gas revenue change:
QIP rider —
—
3
—
—
3
Other —
—
(1 ) —
—
(1 )
Purchased natural gas costs – offset in natural gas purchased for resale^(d)
(2 ) —
(7 ) —
—
(9 )
Other cost recovery mechanisms:^(e)

Bad debt, energy efficiency programs, and remediation cost riders —
—
2
—
—
2
Gross receipts tax (1 ) —
1
—
—
—
—
Total natural gas revenue change $ (3 ) $ —
$ (2 ) $ —
$ —
$ (5 )
Natural gas purchased for resale change:
Purchased natural gas costs – offset in natural gas revenue^(d)
2
—
7
—
—
9
Total natural gas purchased for resale change $ 2
$ —
$ 7
$ —
$ —
$ 9
Net change in natural gas margins $ (1 ) $ —
$ 5
$ —
$ —
$ 4
Electric Margins

Nine Months 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)
$ (72 ) $ (7 ) $ —
$ —
$ —
$ (79 )
Base rates (estimate)^(c)
53
31
—
43
—
127
FEJA impact on IEIMA – timing of revenue recognition

—
(47 ) —
—
—
(47 )
Recovery of power restoration efforts provided to other utilities 5
1
—
—
—
6
Sales volume (excluding the effect of weather and the New Madrid Smelter) (4 ) —
—
—
—
(4 )
New Madrid Smelter revenues (9 ) —
—
—
—
(9 )
MEEIA 2013 performance incentive (19 ) —
—
—
—
(19 )
Off-system sales 94
—
—
—
—
94
Transmission services revenues 3
—
—
—
—
3
Other 8
(4 ) —
—
(1 ) 3
Cost recovery mechanisms – offset in fuel and purchased power:^(d)

Power supply costs —
(18 ) —
—
—
(18 )
Renewable energy adjustment —
4
—
—
—
4
Zero-emission credits —
21
—
—
—
21
Transmission services recovery mechanism —
1
—
—
—
1
Recovery of FAC under-recovery (7 ) —
—
—
—
(7 )
Other cost recovery mechanisms:^(e)

Bad debt, energy efficiency programs, and remediation cost riders —
(17 ) —
—
—
(17 )
Gross receipts tax 1
—
—
—
—
1
MEEIA program costs 22
—
—
—
—
22
Total electric revenue change $ 75
$ (35 ) $ —
$ 43
$ (1 ) $ 82
Fuel and purchased power change:
Energy costs (excluding the effect of weather and the New Madrid Smelter) $ (91 ) $ —
$ —
$ —
$ —
$ (91 )
New Madrid Smelter energy costs 1
—
—
—
—
1
Effect of weather (estimate)^(b)
16
—
—
—
—
16
Effect of lower net energy costs included in base rates 32
—
—
—
—
32
Transmission service charges (7 ) —
—
—
—
(7 )
Other (10 ) 3
—
—
(3 ) (10 )
Cost recovery mechanisms – offset in electric revenue:^(d)

Power supply costs —
18
—
—
—
18
Renewable energy adjustment —
(4 ) —
—
—
(4 )
Zero-emission credits —
(21 ) —
—
—
(21 )
Transmission services recovery mechanism —
(1 ) —
—
—
(1 )
Recovery of FAC under-recovery 7
—
—
—
—
7
Total fuel and purchased power change $ (52 ) $ (5 ) $ —
$ —
$ (3 ) $ (60 )
Net change in electric margins $ 23
$ (40 ) $ —
$ 43
$ (4 ) $ 22
Natural gas revenue change:
Effect of weather (estimate)^(b)
$ (6 ) $ —
$ —
$ —
$ —
$ (6 )
QIP rider —
—
6
—
—
6
Other (1 ) —
(2 ) —
—
(3 )
Purchased natural gas costs – offset in natural gas purchased for resale^(d)
1
—
(27 ) —
—
(26 )
Other cost recovery mechanisms:^(e)

Bad debt, energy efficiency programs, and remediation cost riders —
—
3
—
—
3
Gross receipts tax (1 ) —
—
—
—
(1 )
Total natural gas revenue change $ (7 ) $ —
$ (20 ) $ —
$ —
$ (27 )
Natural gas purchased for resale change:
Effect of weather (estimate)^(b)
$ 5
$ —
$ —
$ —
$ —
$ 5
Purchased natural gas costs – offset in natural gas revenue^(d)
(1 ) —
27
—
—
26
Total natural gas purchased for resale change $ 4
$ —
$ 27
$ —
$ —
$ 31
Net change in natural gas margins $ (3 ) $ —
$ 7
$ —
$ —
$ 4

~~(a)~~

~~Includes a decrease in transmission margins~~

Increase (Decrease) by Segment

Total by Segment(a)

Overall Ameren Increase of ~~$1 million and an increase of $10 million for the three- and nine-month periods, respectively, at Ameren Illinois.~~$54 Million

~~(b)~~

Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the prior year; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. Beginning in 2017, FEJA eliminated the impact of weather on

Ameren Missouri

Ameren Illinois Electric ~~Distribution’s electric margins.~~Distribution

Ameren Transmission

Other/Intersegment Eliminations

Natural Gas Margins

~~(c)~~

~~For~~

Increase (Decrease) by Segment

Total by Segment

Overall 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.Increase of $32 Million

~~(d)~~

~~Electric and natural gas revenue changes are offset by corresponding changes in Fuel, Purchased power, and~~

Ameren Missouri

Ameren Illinois Natural ~~gas purchased for resale, resulting in no change to electric and natural gas margins.~~Gas

The following table present the favorable (unfavorable) variations by Ameren segment for electric and natural gas margins for the three months ended March 31, 2021, compared with the year-ago period:



Three Months	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)	$	18	$	—	$	—	$	—	$	—	$	18
Base rates (estimate)(c)	(6)		3		—		7		—		4

Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)	(3)		—		—		—		—		(3)


Off-system sales, capacity and FAC revenues, net	(4)		—		—		—		—		(4)
Energy-efficiency program investments	—		3		—		—		—		3
Other	(4)		4		—		—		(2)		(2)
Cost recovery mechanisms – offset in fuel and purchased power(d)	3		12		—		—		—		15
Other cost recovery mechanisms(e)	6		(1)		—		—		—		5
Total electric revenue change	$	10	$	21	$	—	$	7	$	(2)	$	36
Fuel and purchased power change:

Effect of weather (estimate)(b)	$	(5)	$	—	$	—	$	—	$	—	$	(5)
Effect of lower net energy costs included in base rates	36		—		—		—		—		36

Other	(2)		—		—		—		4		2
Cost recovery mechanisms – offset in electric revenue(d)	(3)		(12)		—		—		—		(15)
Total fuel and purchased power change	$	26	$	(12)	$	—	$	—	$	4	$	18
Net change in electric margins	$	36	$	9	$	—	$	7	$	2	$	54
Natural gas revenue change:
Effect of weather (estimate)(b)	$	(3)	$	—	$	—	$	—	$	—	$	(3)
Base rates (estimate)	—		—		12		—		—		12
Change in rate design	—		—		12		—		—		12


Other	—		—		3		—		—		3
Cost recovery mechanisms – offset in natural gas purchased for resale(d)	17		—		45		—		—		62
Other cost recovery mechanisms(e)	—		—		4		—		—		4
Total natural gas revenue change	$	14	$	—	$	76	$	—	$	—	$	90
Natural gas purchased for resale change:
Effect of weather (estimate)(b)	$	4	$	—	$	—	$	—	—		$	4

Cost recovery mechanisms – offset in natural gas revenue(d)	(17)		—		(45)		—		—		(62)
Total natural gas purchased for resale change	$	(13)	$	—	$	(45)	$	—	$	—	$	(58)
Net change in natural gas margins	$	1	$	—	$	31	$	—	$	—	$	32

~~(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.

(a)Includes an increase in transmission margins of $7 million at Ameren Illinois for the three months ended March 31, 2021, compared with the year-ago period.

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

(c)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates. For Ameren Missouri, base rates exclude an increase of $7 million for the recovery of lost electric margins for the three months ended March 31, 2021, compared with the year-ago period, resulting from the MEEIA 2016 and 2019 customer energy-efficiency programs. This amount is included in the “sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” line item.

(d)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of income, resulting in no change to electric and natural gas margins.

(e)Offsetting expense increases or decreases are reflected in “Other operations and maintenance,” “Depreciation and amortization,” or in “Taxes other than income taxes,” within the “Operating Expenses” section and "Income Taxes" in the statement of income. These items have no overall impact on earnings.

Ameren

~~Ameren's~~Ameren’s electric margins ~~decreased $109~~increased $54 million, or 8%6%, for the three months ended September 30, 2017, compared with the year-ago period, primarily because of decreased margins at Ameren Illinois Electric Distribution. Ameren’s electric margins increased $22 million, or 1%, for the nine months ended September 30, 2017,March 31, 2021, compared with the year-ago period, primarily because of increased margins at Ameren ~~Transmission and Ameren~~ Missouri, ~~partially offset by decreased margins at~~ Ameren Illinois Electric ~~Distribution.~~

~~Ameren's~~Distribution, and Ameren Transmission, as discussed below. Ameren’s natural gas margins increased $4$32 million, or ~~4%, and $4 million, or 1%~~15%, for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2021, compared with the year-ago ~~periods,~~period, primarily because of increased margins at Ameren Illinois Natural Gas, ~~partially offset by decreased margins at Ameren Missouri.~~as discussed below.

Ameren Transmission

Ameren ~~Transmission's~~Transmission’s margins increased ~~$11~~$7 million, or ~~10%, and $43 million, or 15%~~6%, for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2021, compared with the year-ago ~~periods. Margins~~period. Base rate revenues were favorably affected by increased capital investment, as evidenced by a ~~22%~~11% increase in rate base used to calculate the revenue requirement at September 30, 2017, compared to September 30, 2016, as well as higher recoverable costs for the three and nine months ended September 30, 2017, compared with the year-ago periods, under forward-looking formula ratemaking. Margins were unfavorably affected for the three and nine months ended September 30, 2017, compared with the year-ago periods, by the absence of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 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.

~~Ameren Missouri~~

Ameren Missouri's electric margins decreased $5 million, or 1%, for the three months ended September 30, 2017, compared with the year-ago period. Ameren Missouri’s electric margins increased $23 million, or 1%, for the nine months ended September 30, 2017, compared with the year-ago period. Ameren Missouri’s natural gas margins were comparable for the three months ended September 30, 2017, compared with the year-ago period. Ameren Missouri’s natural gas margins decreased $3 million, or 5%, for the nine months ended September 30, 2017, compared with the year-ago period.

The following items had a favorable effect on Ameren Missouri's electric margins for the three and nine months ended September 30, 2017, compared with the year-ago periods (except where a specific period is referenced):

Higher electric base rates, effective April 1, 2017, as a result of the March 2017 electric rate order, increased margins by an estimated $49 million and $85 million, respectively. The change in electric base rates is the sum of the change in base rates (estimate) (+$29 million and +$53 million, respectively) and the effect of lower net energy costs included in base rates (+$20 million and +$32 million, respectively) in the Electric and Natural Gas Margins table above.

Excluding the estimated effect of weather, residential sales volumes increased by less than 1% for the three months ended September 30, 2017, compared with the year-ago period, which increased margins by $8 million, as a result of customer growth.

The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts primarily caused by hurricane damage, which increased revenues by $5 million for both periods and was fully offset by a related increase in operations and maintenance costs, with no overall impact on net income.

~~Increased transmission services revenues due to additional rate base investment, which increased margins by~~ ~~$2 million~~ ~~and~~ ~~$3 million, respectively.~~

The following items had an unfavorable effect on Ameren Missouri's electric margins for the three and nine months ended September 30, 2017, compared with the year-ago periods (except where a specific period is referenced):

Summer temperatures were milder as cooling degree days decreased 11% and 8% for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, and winter temperatures were milder as heating degree days decreased 15% for the nine months ended September 30, 2017, compared with the year-ago period. The effect of weather decreased margins by an estimated $26 million and $56 million, respectively. The change in margins due to weather is the sum of the effect of weather (estimate)

on electric revenues (-$33 million and -$72 million, respectively) and the effect of weather (estimate) on fuel and purchased power (+$7 million and +$16 million, respectively) in the Electric and Natural Gas Margins table above.

~~The absence in 2017 of the MEEIA 2013 performance incentive, which increased margins by $19 million for the three and nine months ended September 30, 2016.~~

Suspension of operations at the New Madrid Smelter in the first quarter of 2016 and the elimination of recovery under the FAC tariff effective April 1, 2017, which had allowed Ameren Missouri to retain a portion of the revenues from off-system sales it made as a result of reduced sales to the New Madrid Smelter, which decreased margins by $7 million and $8 million, respectively. As of April 1, 2017, higher electric base rates offset the absence of these revenues recovered under the FAC tariff. The decrease in margins due to the suspension of operations and elimination of the provision in the FAC tariff is the sum of New Madrid Smelter revenues (-$1 million and -$9 million, respectively) and New Madrid Smelter energy costs (-$6 million and +$1 million, respectively).

Increased transmission services charges resulting from additional MISO-approved electric transmission investments made by other entities and shared by all MISO participants, which decreased margins by $5 million and $7 million, respectively.

Excluding the estimated effect of weather and reduced sales to the New Madrid Smelter, total retail sales volumes decreased by less than 1% for the nine months ended September 30, 2017, compared with the year-ago period, which decreased margins by $4 million due to the absence of the leap year benefit experienced in 2016 and the effects of the MEEIA programs,requirement, partially offset by ~~growth. The throughput disincentive~~the March 2021 FERC order, which required refunds related to historical recovery ~~as part~~ of ~~MEEIA 2016, ensures that electric margins are not affected by reduced sales volumes as a result of MEEIA programs. Lower sales volumes led to a decrease~~materials and supplies inventories. See Transmission Formula Rate Revisions in net energy costs of $3 million for nine months ended September 30, 2017, compared with the year-ago period. The change in net energy costs is the sum of the change in off-system sales (+$94 million for the nine months ended September 30, 2017) and the change in energy costs (excluding the effect of weather and the New Madrid Smelter) (-$91 million for the nine months ended September 30, 2017) in the Electric and Natural Gas Margins table above.

~~Ameren Illinois~~

Ameren Illinois' electric margins decreased by $113 million, or 25%, and $30 million, or 3%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, driven by a decrease in Ameren Illinois Electric Distribution ($112 million and $40 million, respectively). Ameren Illinois Natural Gas’ margins increased by $5 million, or 6%, and $7 million, or 2%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily due to increased rate base in 2017 under the QIP rider, which increased margins by $3 million and $6 million, respectively.

~~Ameren Illinois Electric Distribution~~

Ameren Illinois Electric Distribution’s margins decreased $112 million, or 30%, and $40 million or 5%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods. The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s margins for the three and nine months ended September 30, 2017, compared with the year-ago periods:

A change in the method used to recognize interim period revenue, in connection with the decoupling provisions of the FEJA, which decreased margins by $94 million and $47 million, respectively. This change will not impact annual earnings. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information ~~on FEJA and IEIMA.~~regarding the March 2021 FERC order.

Ameren Missouri

Ameren Missouri’s electric margins increased $36 million, or 8%, for the three months ended March 31, 2021, compared with the year ago period.

The ~~absence~~following items had a favorable effect on Ameren Missouri’s electric margins between periods:

•The March 2020 MoPSC electric rate order that resulted in lower net energy costs included in base rates partially offset by lower electric base rates increased margins $30 million. The change in electric base rates is the sum of the ~~impact~~change in base rates (estimate) (-$6 million) and the effect of ~~warmer-than-normal summer temperatures experienced~~lower net energy costs included in base rates (+$36 million) in the ~~third quarter~~table above.

•Winter temperatures were colder as heating degree days increased 12%. The aggregate effect of ~~2016 and the decoupling of revenues in 2017, which decreased~~weather increased margins ~~by $7 million for both periods.~~an estimated $13 million. The change in margins due to weather is the sum of the effect of weather (estimate) on electric revenues (-(+$~~9 million and -$7 million, respectively)~~18 million) and the effect of weather (estimate) on fuel and purchased power (+(-$~~2 million and flat, respectively)~~5 million) in the ~~Electric~~table above.

The following items had an unfavorable effect on Ameren Missouri’s electric margins between periods:

•The absence of the Callaway Energy Center generation and ~~Natural Gas Margins~~the extremely cold weather in mid-February 2021 drove net energy costs higher than those reflected in base rates, which reduced margins by $4 million, resulting from Ameren Missouri’s 5% exposure to net energy cost variances under the FAC. The change in net energy costs is the sum of the revenue change in “Off-system sales, capacity and FAC revenues, net” (-$4 million) in the table ~~above.~~above, and the change in “energy costs” (comparable between periods).

•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues decreased an estimated $3 million. The decrease was primarily due to a reduction in the average retail price per kilowatthour due to changes in customer usage patterns and shifts in commercial and industrial usage between rate classes. While the MEEIA customer energy-efficiency programs reduced retail sales volumes, the recovery of lost electric margins under the MEEIA ensured that electric margins were not affected.

Ameren Missouri’s natural gas margins were comparable between periods. Purchased gas costs increased $17 million, primarily resulting from the significant increase in customer demand and prices for natural gas experienced in mid-February 2021 due to the extremely cold weather. The increased purchased gas costs are fully offset by an increase in natural gas revenues under the PGA rider, resulting in no impact to margin. The increase in purchased gas cost is reflected in “cost recovery mechanisms - offset in natural gas revenue” and the associated recoverability from customers is reflected in “cost recovery mechanisms - offset in natural gas purchased for resale”.

Ameren Illinois Electric Distribution’s base rates were favorably affected by increased recoverable expenses and rate base, as well as a higher 30-year United States Treasury bond yield under formula ratemaking, which collectively increased margins by $10 million and $31 million, respectively.

Ameren ~~Illinois Transmission~~

~~Ameren Illinois Transmission's~~Illinois’ electric margins ~~decreased $1~~increased $16 million, or 1%5%, for the three months ended ~~September 30, 2017,~~March 31, 2021, compared towith the year-ago period, driven by increased margins at Ameren Illinois Electric Distribution and Ameren Illinois Transmission. Ameren Illinois Natural Gas’ margins increased $31 million, or 17%, between periods.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $9 million, or 3%, for the three months ended March 31, 2021, compared with the year-ago period. Purchased power costs increased $12 million, primarily resulting from the significant increase in customer demand and prices for electricity experienced in mid-February 2021 due to the extremely cold weather. The increased purchased power costs are fully offset by an increase in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin. The increase in purchased power cost is reflected in “cost recovery mechanisms - offset in electric revenue” and the associated recoverability

from customers is reflected in “cost recovery mechanisms - offset in fuel and purchased power”. The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins between periods:

•Margins increased due to a higher recognized ROE (+$4 million), as evidenced by an increase of 72 basis points in the estimated annual average of the monthly yields of the 30-year United States Treasury bonds, and increased capital investment (+$2 million), as evidenced by a 6% increase in rate base used to calculate the revenue requirement, partially offset by lower recoverable non-purchased power expenses (-$3 million). The sum of these changes collectively increased margins $3 million.

•Revenues increased $3 million due to recovery of increased energy-efficiency program investments under performance-based formula ratemaking.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins increased $31 million, or 17%, for the three months ended March 31, 2021, compared with the year-ago period. Purchased gas costs increased $45 million, primarily resulting from the significant increase in customer demand and prices for natural gas experienced in mid-February 2021 due to the extremely cold weather. The increased purchased gas costs are fully offset by an increase in natural gas revenues under the PGA rider, resulting in no impact to margin. The increase in purchased gas cost is reflected in “cost recovery mechanisms - offset in natural gas revenue” and the associated recoverability from customers is reflected in “cost recovery mechanisms - offset in natural gas purchased for resale”. The following items had a favorable effect on Ameren Illinois Natural Gas’ margins between periods:

•Revenues increased $12 million due to higher natural gas base rates as a result of the January 2021 natural gas rate order.

•The implementation of a change in rate design pursuant to the January 2021 natural gas rate order, which increased margins $12 million. This change in rate design concentrates more revenues in the winter heating season due to an increase in volumetric rates and a decrease in fixed customer rates. As such, the change is not expected to materially affect annual earnings comparisons.

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins increased ~~$10~~$7 million, or 5%9%, for the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2021, compared with the year-ago period. Margins were unfavorably affected for the three and nine months ended September 30, 2017, compared with the year-ago periods, by the absence of a temporarily higher allowed return on common equity of 12.38% for nearly four months in 2016 as a result of the expiration of the refund period in the February 2015 complaint case. Margins were favorably affected by increased capital investment, as evidenced by a ~~15%~~17% increase in rate base used to calculate the revenue requirement, ~~at September 30, 2017, compared~~partially offset by the March 2021 FERC order, which required refunds related to ~~September 30, 2016, as well as higher recoverable costs~~historical recovery of materials and supplies inventories. See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the ~~three and nine months ended September 30, 2017, compared with the year-ago periods, under forward-looking formula ratemaking.~~

March 2021 FERC order.

Other Operations and Maintenance Expenses

Increase (Decrease) by Segment

Total by Segment(a)

Overall Ameren Decrease of $18 Million

(a)Includes other/intersegment eliminations of $(2) million and $(2) million in the three months ended March 31, 2021and 2020, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Ameren

Other operations and maintenance expenses ~~were $9~~decreased $18 million ~~and $17 million lower~~ in the three ~~and nine~~ months ended ~~September 30, 2017, respectively, as~~March 31, 2021, compared with the year-ago ~~periods, as~~period, due to changes discussed below.

Ameren Transmission

Other operations and maintenance expenses were comparable ~~in the three and nine months ended September 30, 2017, with the year-ago~~between periods.

Ameren Missouri

~~Other operations and maintenance expenses were $4~~The $14 million ~~higher and $15 million lower~~decrease in ~~the three and nine months ended September 30, 2017, respectively, as compared with the year-ago periods. The following items decreased~~ other operations and maintenance expenses ~~for~~in the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2021, compared with the year-ago ~~periods (except where a specific~~ period, ~~is referenced):~~was primarily due to the following items:

~~Refueling and maintenance outage costs at the Callaway energy center were lower by $27~~•The cash surrender value of company-owned life insurance increased $8 million, primarily because of unfavorable market returns in the ~~nine-month period, as~~year-ago period.

•Amortization of costs, primarily solar rebate costs incurred prior to the ~~current year refueling and maintenance outage began in October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.~~

~~Pension and benefit costs~~RESRAM, decreased ~~by $5~~$6 million ~~and $10 million, respectively, primarily as a result of~~pursuant to the March ~~2017~~2020 MoPSC electric rate order.

~~Solar rebate amortization~~•Deferral to a regulatory asset of $5 million of certain costs ~~decreased by $3 million and $6 million, respectively, primarily as a result of~~incurred related to the COVID-19 pandemic, pursuant to the March ~~2017~~2021 MoPSC ~~electric rate order.~~orders.

~~Estimated litigation costs~~•Transmission and distribution expenditures decreased ~~by $3 million and~~ $5 million, ~~respectively.~~primarily resulting from less maintenance due to recent capital improvements and disciplined cost management.

The following items ~~increased~~partially offset the above decreases in other operations and maintenance expenses ~~for the three and nine months ended September 30, 2017, compared with the year-ago~~between periods:

MEEIA customer energy efficiency program costs increased by $6 million and $22 million, respectively. Electric revenues related to MEEIA program costs increased by a corresponding amount, with no overall effect on net income.

Ameren Missouri incurred $5 million of labor and benefit costs in both periods for crews assisting other utilities with power restoration, primarily caused by hurricane damage. These costs are being recovered from the other utilities, with no overall effect on net income.

•Energy center maintenance costs ~~excluding~~increased $8 million, primarily because of the amortization of Callaway refueling and maintenance ~~outage~~ costs atdeferred as a regulatory asset in the ~~Callaway energy center,~~year-ago period, pursuant to the February 2020 MoPSC order.

•Customer energy-efficiency program costs increased ~~by $5~~$6 million ~~in both periods, primarily~~ because of ~~higher coal handling charges.~~increased participation in the MEEIA programs in the current period.

Ameren Illinois

Other operations and maintenance expenses ~~were $15~~decreased $5 million ~~lower~~ in the three months ended ~~September 30, 2017,~~March 31, 2021, compared with the year-ago period, as discussed below. Other operations and maintenance expenses were comparable in the nine months ended September 30, 2017, with the year-ago period. Other operations and maintenance expenses were comparable in the three and nine months ended September 30, 2017, with the year-agobetween periods at Ameren Illinois Natural Gas and Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses decreased ~~$14~~$5 million and $8 million in the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because of decreased customer energy efficiency and environmental remediation costs, which are included in cost recovery mechanisms resulting in decreased electric revenues, with no overall effect on net income. These decreases were partially offset by an increase in storm-related repair costs, as well as increased wages and staffing additions.

~~Ameren Illinois Natural Gas~~

~~Other operations and maintenance expenses were comparable~~ in the three months ended ~~September 30, 2017,~~March 31, 2021, compared with the year-ago period, primarily because of a $4 million increase in the cash surrender value of company-owned life insurance due to unfavorable market returns in the year-ago period. Other operations and maintenance expenses ~~increased $6~~also decreased because of a $3 million reduction in distribution expenditures, resulting from disciplined cost management and timing of expenditures. These decreases were partially offset by a $2 million increase in the amortization of energy-efficiency program investments under performance-based ratemaking.

Depreciation and Amortization Expenses

Increase (Decrease) by Segment

Total by Segment(a)

Overall Ameren Increase of $26 Million

(a)Includes other/intersegment eliminations of $— million and $— million in the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2021and 2020, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Depreciation and amortization expenses increased $26 million, $17 million, and $8 million in the three months ended March 31, 2021, compared with the year-ago period, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment investments across their respective segments. Ameren’s and Ameren Missouri’s depreciation and amortization expenses reflected a deferral to a regulatory asset of depreciation and amortization expenses pursuant to the PISA and RESRAM. The PISA and RESRAM deferrals of depreciation and amortization expenses were $19 million and $13 million for the three months ended March 31, 2021 and 2020, respectively.

Taxes Other Than Income Taxes

Increase (Decrease) by Segment

Total by Segment(a)

Overall Ameren Increase of $3 Million

(a)Includes $2 million and $2 million at Ameren Transmission in the three months ended March 31, 2021 and 2020, respectively, and other/intersegment eliminations of $4 million and $3 million in the three months ended March 31, 2021 and 2020, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Taxes other than income taxes increased $3 million in the three months ended March 31, 2021, compared with the year-ago period, primarily because of ~~increased bad debt, customer energy efficiency, and environmental remediation costs, which are included~~a $3 million increase in ~~cost recovery mechanisms resulting in increased natural gas revenues, with no overall effect on net income. In addition, higher gas pipeline compliance costs contributed to the increase.~~

~~Depreciation and Amortization~~

~~Depreciation and amortization expenses increased $14 million and $40 million at Ameren, $4 million and $15 million at Ameren Missouri, and $6 million and $17 million~~excise taxes at Ameren Illinois ~~in the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because~~Natural Gas, as a result of ~~additional property, plant, and equipment across their respective segments.~~increased sales.

~~Taxes~~

Other ~~Than~~ Income, ~~Taxes~~Net

~~Taxes other than~~

Increase (Decrease) by Segment

Total by Segment

Overall Ameren Increase of $25 Million

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Other income, ~~taxes were comparable at each of the Ameren Companies and their respective segments~~net, increased $25 million in the three months ended ~~September 30, 2017, with the year-ago period. Taxes other than income taxes increased $6 million at Ameren in the nine months ended September 30, 2017,~~March 31, 2021, compared with the year-ago period, primarily because of ~~higher property taxes~~a $9 million increase in the non-service cost components of net periodic benefit income at Ameren Missouri and ~~at each Ameren Illinois segment.~~

~~Other Income and Expenses~~

~~Ameren~~

an $8 million decrease in charitable donations due to the absence of charitable donations made in the year-ago period pursuant to the March 2020 MoPSC electric rate order. Other income, net, also increased $3 million for activity not reported as part of ~~expenses, was comparable in the three months ended September 30, 2017, with the year-ago period. Other~~a segment primarily because of increased income ~~net of expenses, decreased $7 million in the nine months ended September 30, 2017, compared with the year-ago period, as discussed below.~~ from equity investments.

See Note 5 – Other Income, ~~and Expenses~~Net, under Part I, Item 1, of this report for additional information.

~~Ameren Transmission~~

~~Other income, net of expenses, was comparable in the three and nine months ended September 30, 2017, with the year-ago periods.~~

~~Ameren Missouri~~Interest Charges

~~Other income, net of expenses, was comparable in the three and nine months ended September 30, 2017, with the year-ago periods.~~

Increase (Decrease) by Segment

Total by Segment

Overall Ameren Increase of $7 Million

~~Ameren Illinois~~

~~Other income, net of expenses, was comparable~~

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Interest charges increased $7 million in the three months ended ~~September 30, 2017, with the year-ago period, for Ameren Illinois and each of its segments. Other income, net of expenses, decreased $5 million in the nine months ended September 30, 2017,~~March 31, 2021, compared with the year-ago period, primarily ~~because of lower interest income associated with the IEIMA revenue requirement reconciliation~~due to a long-term debt issuance at Ameren ~~Illinois Electric Distribution. Other income, net of expenses, was comparable~~(parent) in ~~the nine months ended September 30, 2017, with the year-ago period, for the remaining Ameren Illinois segments.~~

~~Interest Charges~~

~~Ameren~~

April 2020, which increased interest charges by $7 million. Interest charges at Ameren and Ameren Missouri reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM. The PISA and RESRAM deferrals of interest charges were ~~comparable in~~$15 million and $9 million for the three months ended ~~September 30, 2017, with the year-ago period. Interest charges increased $8 million in the nine months ended September 30, 2017, compared with the year-ago period, as discussed below.~~March 31, 2021 and 2020, respectively.

~~Ameren Transmission~~

Interest charges were comparable in the three months ended September 30, 2017, with the year-ago period. Interest charges increased $6 million in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of an increase in average outstanding debt at Ameren Illinois and ATXI.

~~Ameren Missouri~~

~~Interest charges were comparable in the three and nine months ended September 30, 2017, with the year-ago periods.~~

~~Ameren Illinois~~

Interest charges were comparable in the three months ended September 30, 2017, with the year-ago period, for Ameren Illinois and each of its segments. Interest charges increased $4 million in the nine months ended September 30, 2017, compared with the year-ago period, primarily because of an increase in average outstanding debt at Ameren Illinois.

Income Taxes

The following table presents effective income tax rates for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 and ~~2016:~~2020:


	Three Months(a)
		2021		2020
Ameren		10	%	12	%
Ameren Missouri		(4)	%	8	%
Ameren Illinois		25	%	24	%
Ameren Illinois Electric Distribution		22	%	22	%
Ameren Illinois Natural Gas		27	%	26	%
Ameren Illinois Transmission		25	%	24	%
Ameren Transmission		27	%	26	%

Three Months^(a)

Nine Months^(a)
2017 2016 2017 2016
Ameren 41 % 39 % 39 % 36 %
Ameren Missouri 38 % 38 % 38 % 38 %
Ameren Illinois 40 % 39 % 40 % 39 %
Ameren Illinois Electric Distribution 38 % 40 % 39 % 39 %
Ameren Illinois Natural Gas 51 % 20 % 40 % 39 %
Ameren Illinois Transmission 42 % 38 % 40 % 38 %
Ameren Transmission 44 % 38 % 41 % 39 %


~~(a)~~	(a)Estimate of the annual ~~effective income tax rate adjusted to reflect the tax effect of items discrete to the three and nine months ended September 30, 2017 and 2016.~~

~~Ameren~~

~~The~~ effective income tax rate ~~was higher in~~adjusted to reflect the tax effect of items discrete to the three ~~and nine~~ months ended ~~September 30, 2017, compared with~~March 31, 2021 and 2020.

See Note 12 – Income Taxes under Part I, Item 1, of this report for a reconciliation of the ~~year-ago periods, because of an increase in the Illinois~~federal statutory corporate income tax rate ~~which became effective on July 1, 2017. Additionally,~~to the effective income tax rate ~~was higher in~~for the ~~nine-month period because of a decrease in the recognition of income tax benefits associated with share-based compensation.~~Ameren Companies.

~~Ameren Transmission~~

The effective income tax rate was higher in the three and nine months ended September 30, 2017, compared with the year-ago periods, primarily because of the decreased effect of income tax benefits from certain depreciation differences on property-related items, along with the increase in the Illinois statutory income tax rate.

~~Ameren Missouri~~

~~The effective income tax rate was comparable in the three and nine months ended September 30, 2017, with the year-ago periods.~~

~~Ameren Illinois~~

The effective income tax rate was comparable in the three and nine months ended September 30, 2017, with the year-ago periods at Ameren Illinois, Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, except as discussed below.

~~Ameren Illinois Electric Distribution~~

The effective income tax rate was lower in the three months ended September 30, 2017, compared with the year-ago period, primarily because of the increased effect of income tax benefits on lower pretax income in the current year from certain depreciation differences on property-related items, partially offset by the increase in the Illinois statutory income tax rate.

~~Ameren Illinois Natural Gas~~

The effective income tax rate was higher in the three months ended September 30, 2017, compared with the year-ago period, primarily because of the decreased effect of income tax benefits on higher pretax income in the current year from certain depreciation differences on property-related items, as well as the increase in the Illinois statutory income tax rate. Due to the small amount of pretax income in the third quarter of each year, the effective income tax rates in both periods can vary significantly.

~~Ameren Illinois Transmission~~

The effective income tax rate was higher in the three months ended September 30, 2017, compared with the year-ago period, primarily because of a decrease in the income tax benefits from certain depreciation differences on property-related items, along with the increase in the Illinois statutory income tax rate.

LIQUIDITY AND CAPITAL RESOURCES

Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source

of cash. In addition to using cash provided by operating activities, we use available cash, ~~borrowings~~drawings under ~~the Credit Agreements,~~committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term ~~intercompany~~affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our

discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). We expect to make significant capital expenditures over the next five years, supported by a combination of long-term debt and equity, as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy targets requirements, environmental compliance, and other improvements. ~~We intend~~As part of its plan to fund ~~those~~the cash requirements for capital expenditures, ~~primarily~~Ameren is using newly issued shares of common stock, rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2025. Ameren expects these issuances to provide equity of about $100 million annually. In addition to the issuance of common shares in connection with ~~cash provided by operating activities~~the 2021 settlement of the remaining portion of the forward sale agreement, Ameren plans to issue incremental equity of about $150 million in 2021 and ~~short-term~~about $300 million each year from 2022 to 2025. Ameren expects to establish an at-the-market equity program that will allow Ameren to meet equity needs through 2023, subject to market conditions and other factors. Ameren expects its equity to total capitalization to be about 45% through December 31, 2025, with the long-term ~~debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.~~intent to support solid investment-grade credit ratings. See Long-term Debt and Equity below and Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information on the 2021 settlement of the remaining portion of the forward sale agreement.

The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments ~~may periodically result~~at the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at ~~September 30, 2017~~,March 31, 2021, for ~~the~~ Ameren ~~Companies. The working capital deficit as of September 30, 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.~~Ameren Illinois. With the credit capacity available under the Credit Agreements, ~~the~~and cash and cash equivalents, Ameren ~~Companies~~(parent), Ameren Missouri, and Ameren Illinois, collectively, had ~~access to $1.7~~net available liquidity of $1.4 billion ~~of liquidity~~ at~~September 30, 2017.~~March 31, 2021. See Credit Facility Borrowings and Liquidity for additional information.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~:2020:


	Net Cash Provided By (Used In) Operating Activities						Net Cash Used In Investing Activities						Net Cash Provided By Financing Activities
	2021		2020		Variance		2021		2020		Variance		2021		2020		Variance
Ameren	$	(35)	$	290	$	(325)	$	(889)	$	(684)	$	(205)	$	795	$	421	$	374

Ameren Missouri	(51)		41		(92)		(398)		(328)		(70)		316		272		44
Ameren Illinois	13		232		(219)		(337)		(323)		(14)		326		106		220

Net Cash Provided By
Operating Activities

Net Cash Used In
Investing Activities

Net Cash Provided by (Used In)
Financing Activities
2017 2016 Variance 2017 2016 Variance 2017 2016 Variance
Ameren^(a)
$ 1,643
$ 1,559
$ 84
$ (1,585 ) $ (1,551 ) $ (34 ) $ (58 ) $ (282 ) $ 224
Ameren Missouri 819
888
(69 ) (455 ) (724 ) 269
(364 ) (362 ) (2 )
Ameren Illinois 628
627
1
(754 ) (679 ) (75 ) 126
(16 ) 142


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

Cash Flows from Operating Activities

Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional rate proceeding. Similar regulatory mechanisms exist for certain other operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash ~~paid~~payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by seasonal customer rates and changes in customer demand due to weather, significantly ~~impact~~affects the amount and timing of our cash provided by operating activities.

Ameren

Ameren’s cash ~~from~~provided by operating activities ~~increased $84~~decreased $325 million in the first ~~nine~~three months of ~~2017, compared with the year-ago period. The following items contributed to the increase:~~

~~A $160 million increase resulting from electric and natural gas margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.~~

A $26 million decrease in payments for scheduled nuclear refueling and maintenance outages at Ameren Missouri’s Callaway energy center, as the current year refueling and maintenance outage began in October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.

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

~~A $21 million increase in cash collected from Ameren Illinois customers related to zero-emission credits pursuant to the FEJA.~~

~~A $12 million increase in net energy costs collected from Ameren Missouri customers under the FAC.~~

~~An increase of $12 million in income tax refunds primarily as a result of higher tax credit sales and the receipt of a 2010 Illinois income tax refund.~~

~~The following items partially offset the increase in Ameren's cash from operating activities between periods:~~

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

~~A $35 million increase in expenditures for customer energy efficiency programs at Ameren Illinois compared with amounts collected from customers.~~

A $30 million decrease in cash recoveries associated with Ameren Illinois' 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.

~~Refunds of $21 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.~~

~~An $18 million increase in purchased power costs collected from Ameren Illinois customers under the PGA.~~

~~A $13 million increase in payments related to natural gas held in storage caused primarily by reduced withdrawals as a result of milder winter temperatures compared with the prior year.~~

~~Ameren Missouri~~

~~Ameren Missouri’s cash from operating activities decreased $69 million in the first nine months of 2017,~~2021, compared with the year-ago period. The following items contributed to the decrease:

An•A $309 million decrease resulting from increased purchases in natural gas for resale and purchased power costs as a result of the significant increase in ~~income~~customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, which are recovered under the PGA, FAC, and Ameren Illinois’ purchased power rider; a net decrease attributable to other regulatory recovery mechanisms; and a decrease in customer collections at Ameren Illinois, primarily due to an increase in accounts receivable balances, which reflected an increase in amounts that were 30 days or greater past due or that were a part of a deferred payment arrangement. These items were partially offset by increased customer collections resulting from base rate increases related to sales volumes and PISA at Ameren Missouri and increased natural gas revenues at Ameren Illinois as a result of the January 2021 rate order.

•A $26 million increase in interest payments, primarily due to an increase in the average outstanding debt at Ameren (parent) and Ameren Missouri.

•A $16 million increase in major storm restoration costs at Ameren Illinois due to a January 2021 storm.

•A $9 million increase in property tax payments at Ameren Missouri primarily due to higher assessed property tax values.

•A $7 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of ~~$115~~power, natural gas, and other fuels.

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

•A $35 million increase resulting from a decrease in coal inventory levels at Ameren Missouri due to ~~Ameren (parent) pursuant~~increased consumption levels, compared with the year-ago period.

•An $11 million decrease in payments to ~~the tax allocation agreement,~~settle ARO liabilities, primarily related to ~~higher taxable income~~the closure of Ameren Missouri’s CCR storage facilities.

Ameren Missouri

Ameren Missouri’s cash provided by operating activities decreased $92 million in ~~2017,~~the first three months of 2021, compared with the year-ago period. The following items contributed to the decrease:

•A $111 million decrease resulting from increased purchases in natural gas for resale and purchased power costs as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to ~~significantly lower property-related deductions.~~

~~The absence of~~extremely cold weather, which are recovered under the PGA and FAC and a ~~$42 million insurance receipt~~net decrease attributable to other regulatory recovery mechanisms. These items were partially offset by increased customer collections resulting from base rate increases related to sales volumes and PISA.

•A $10 million increase in interest payments, primarily due to an increase in the ~~Taum Sauk breach received~~average outstanding debt.

•A $9 million increase in ~~2016.~~property tax payments primarily due to higher assessed property tax values.

•An $8 million decrease in net collateral activity with counterparties, primarily resulting from changes in the market prices of power, natural gas, and other fuels.

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

•A ~~$62~~$35 million increase resulting from ~~electric and natural gas margins, as discussed~~a decrease in ~~Results of Operations, excluding certain noncash items, as well as~~coal inventory levels due to increased consumption levels, compared with the ~~change in customer receivable balances.~~year-ago period.

~~A $26~~•An $11 million decrease in payments ~~for scheduled nuclear refueling and maintenance outages at~~to settle ARO liabilities, primarily related to the ~~Callaway energy center, as the current year refueling and maintenance outage began in October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.~~

~~A $12 million increase in net energy costs collected from customers under the FAC.~~closure of CCR storage facilities.

Ameren Illinois

Ameren Illinois’ cash ~~from~~provided by operating activities ~~increased $1~~decreased $219 million in the first ~~nine~~three months of ~~2017,~~2021, compared with the year-ago period. The following items contributed to the ~~increase:~~decrease:

~~An $84~~•A $202 million ~~increase~~decrease resulting from ~~electric and~~increased purchases in natural gas ~~margins, as discussed in Results of Operations, excluding certain noncash items, as well as the change in customer receivable balances.~~

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

~~A $21 million increase in cash collected from customers related to zero-emission credits pursuant to the FEJA.~~

An increase of $15 million in income tax refunds from Ameren (parent) pursuant to the tax allocation agreement, primarily related to a larger taxable loss in 2017, due to higher property-related deductionsresale and ~~use of net operating losses.~~

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

~~A $35 million increase in expenditures for customer energy efficiency programs compared with amounts collected from customers.~~

A $30 million decrease in cash recoveries associated with 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 $18 million increase in~~ purchased power costs ~~collected from customers~~as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, which are recovered under the ~~PGA.~~

~~Refunds of $17 million associated with the November 2013 FERC complaint case, as discussed~~PGA and purchased power rider; a net decrease attributable to other regulatory recovery mechanisms; and a decrease in ~~Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.~~

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

~~A $12 million~~accounts receivable balances, which reflected an increase in ~~payments related to~~amounts that were 30 days or greater past due or that were a part of a deferred payment arrangement. These items were partially offset by increased natural gas ~~held in storage caused primarily by reduced withdrawals~~revenues as a result of ~~milder winter temperatures compared with~~ the ~~prior year.~~January 2021 rate order.

•A $5$16 million increase in ~~payments~~major storm restoration costs due to ~~contractors for additional reliability, maintenance, and IEIMA projects.~~a January 2021 storm.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased ~~$34~~$205 million induring the first ~~nine~~three months of ~~2017,~~2021, compared with the year-ago ~~period. Capital expenditures increased $27 million~~period, primarily as a result of ~~activity~~a $193 million increase in cash paid for the acquisition of wind generation assets and a $58 million increase in capital expenditures, which were driven by increases at Ameren Missouri and Ameren Illinois, ~~discussed below,~~ partially offset by a ~~$72 million~~ decrease ~~in capital expenditures~~ at ~~ATXI. ATXI’s capital expenditures decreased~~ATXI primarily as a result of decreased ~~expenditures on the~~

Illinois Rivers ~~project,~~transmission line expenditures, as it was placed in service in December 2020. The increase in Ameren’s cash used in investing activities was partially offset by ~~increased expenditures related~~a $34 million decrease due to the ~~Spoon River project. Nuclear~~timing of nuclear fuel expenditures ~~increased $11~~and a $13 million ~~as a result of~~decrease due to net investment activity in the ~~activity~~nuclear decommissioning trust fund at Ameren ~~Missouri, as discussed below.~~Missouri.

Ameren Missouri’s cash used in investing activities ~~decreased $269~~increased $70 million ~~between periods,~~during the first three months of 2021, compared with the year-ago period, primarily ~~due~~as a result of a $193 million increase in cash paid for the acquisition of wind generation assets and a $63 million increase in capital expenditures, primarily related to ~~net money pool advances. In 2017,~~electric delivery infrastructure upgrades, electric distribution system reliability projects, and generator repairs to the Callaway Energy Center. The increase in Ameren ~~Missouri received $143~~Missouri’s cash used in investing activities was partially offset by a $139 million decrease in ~~returns of~~ net money pool advances, ~~compared~~a $34 million decrease due to ~~investing $165 million in money pool advances in 2016. The decrease was partially offset by increased capital expenditures~~the timing of ~~$33 million primarily related to electric distribution system reliability and energy center projects and investments in transmission communication technology, as well as an $11 million increase in~~ nuclear fuel expenditures, ~~because of the timing of purchases~~and a $13 million decrease due to net investment activity in the ~~first nine months of 2017, compared with the prior-year period.~~nuclear decommissioning trust fund.

Ameren Illinois’ cash used in investing activities increased ~~$75~~$14 million ~~between periods largely~~during the first three months of 2021, compared with the year-ago period, due to an increase in capital expenditures, ~~of $77 million~~ primarily related to ~~electric distribution~~software and ~~transmission system reliability projects, updates to natural gas main infrastructure, substation upgrades and investments in smart grid technology.~~communication network projects.

Cash Flows from Financing Activities

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

Ameren’s cash ~~used in~~provided by consolidated financing activities ~~decreased $224~~increased $374 million during the first ~~nine~~three months of ~~2017,~~2021, compared towith the year-ago period. During the first ~~nine~~three months of ~~2017,~~2021, Ameren utilized ~~net~~ proceeds ~~of $737 million~~ from the issuance of $450 million of long-term ~~indebtedness~~debt for general corporate purposes, including to repay then-outstanding short-term debt, and to fund, in part, investing activities. Ameren also utilized net proceeds from commercial paper issuances of $399 million and cash on hand to fund operating activities, including increased purchases in natural gas for resale and purchased power costs as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, and to fund, in part, investing activities. In addition, Ameren received cash proceeds of $113 million from the settlement of the remaining portion of the forward sale agreement of common stock that were used to fund a portion of Ameren Missouri’s wind generation investments. In comparison, during the first three months of 2020, Ameren utilized proceeds of $640 million from a long-term debt issuance, credit facility borrowings, and net commercial paper issuances to repay at maturity ~~$425~~long-term debt of $85 million ~~of higher cost long-term indebtedness~~ and to fund, in part, investing activities. During the first three months of 2021, Ameren paid common stock dividends of $140 million, compared with $122 million in dividend payments in the year-ago period.

Ameren Missouri’s cash provided by financing activities increased $44 million during the first three months of 2021, compared to the year-ago period. During the first three months of 2021, Ameren Missouri utilized net proceeds from commercial paper issuances of $204 million and cash on hand to fund operating activities, including increased purchases in natural gas for resale and purchased power costs as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, and to fund, in part, investing activities. Additionally, Ameren Missouri utilized a $113 million capital contribution from Ameren (parent) to fund, in part, its wind generation expenditures. In comparison, during the first ~~nine~~three months of ~~2016,~~2020, Ameren ~~used~~Missouri utilized net proceeds ~~of $456 million~~ from the issuance of $465 million in long-term ~~indebtedness and net~~debt to repay then-outstanding commercial paper issuances, ~~to repay~~including short-term debt incurred in connection with the repayment at maturity ~~$389~~of long-term debt of $85 million. In 2020, Ameren Missouri repaid net short-term debt of $104 million ~~of higher cost long-term indebtedness~~ and used cash provided by financing activities to fund, in part, investing activities.

Ameren ~~Missouri’s~~Illinois’ cash ~~used in~~provided by financing activities ~~was comparable between periods.~~increased $220 million during the first three months of 2021, compared with the year-ago period. During the first ~~nine~~three months of ~~2017,~~2021, Ameren ~~Missouri issued $399~~Illinois utilized net proceeds from commercial paper issuances of $323 million to fund operating activities, including increased purchases in natural gas for resale and purchased power costs as a result of ~~long-term indebtedness~~the significant increase in customer demand and ~~used the proceeds, along with cash on hand,~~prices for natural gas and electricity experienced in mid-February 2021 due to ~~repay at maturity $425~~extremely cold weather, and to fund, in part, investing activities. Ameren Illinois received a $40 million ~~of higher cost long-term indebtedness. In comparison, during~~capital contribution from Ameren (parent), the first ~~nine~~three months of ~~2016, Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds, along with cash on hand,~~2021, compared to repay at maturity $260 million of higher cost long-term indebtedness. In addition, during the first nine months of 2017, Ameren Missouri paid $332 million in common stock dividends compared with $285 million in dividend payments and the receipt of a ~~$38~~$100 million capital contribution in the year-ago period.

In addition, Ameren ~~Illinois’ financing activities provided cash of $126 million during the first nine months of 2017, compared with $16~~Illinois repaid $19 million of cash used in financing activities during the year-ago period. During the first nine months of 2017, Ameren Illinois used proceeds from net commercial paper issuances of $118 million to fund, in part, investing activities. In comparison, during the first nine months of 2016, Ameren Illinois used proceeds from net commercial paper issuances to repay at maturity $129 million of higher cost long-term indebtedness. Ameren Illinois did not pay common stock dividends during the nine months ended September 30, 2017, compared to dividend payments of $95 million during the same period in 2016. Additionally, money pool borrowings ~~decreased $43~~and redeemed $13 million ~~compared with~~of preferred stock in the ~~year-ago~~current year period.

See Long-term Debt and Equity in this section for additional information on maturities and issuances of long-term ~~debt.~~debt, issuances of common stock, and redemptions of preferred stock.

Credit Facility Borrowings and Liquidity

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

The following table presents Ameren’s consolidated liquidity as of March 31, 2021:



Ameren (parent)and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,200

Less: Ameren (parent) commercial paper outstanding	233
Less: Ameren Missouri commercial paper outstanding	204

Less: Ameren Missouri letters of credit	3
Missouri Credit Agreement – subtotal	760
Ameren (parent) and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,100

Less: Ameren (parent) commercial paper outstanding	129
Less: Ameren Illinois commercial paper outstanding	323

Less: Ameren Illinois letters of credit	1
Illinois Credit Agreement – subtotal	647
Subtotal	$	1,407
Add: Cash and cash equivalents	6
Net Available Liquidity	$	1,413

The Credit ~~Agreements.~~Agreements, among other things, provide $2.3 billion of credit until maturity in December 2024. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on 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, 2017~~:

Ameren and Ameren Missouri:

Missouri Credit Agreement – borrowing capacity
$ 1,000
Less: Ameren (parent) commercial paper outstanding 162
Missouri Credit Agreement – credit available 838
Ameren and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity
1,100
Less: Ameren (parent) commercial paper outstanding 115
Less: Ameren Illinois commercial paper outstanding 169
Less: Letters of credit 1
Illinois Credit Agreement – credit available
815
Total Credit Available $ 1,653
Cash and cash equivalents 9
Total Liquidity $ 1,662

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 ofAgreements. During 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 thethree months ended March 31, 2021, Ameren (parent), Ameren Missouri, and Ameren Illinois each issued commercial ~~paper programs were available at lower interest rates than the interest rates available~~paper. Borrowings under the Credit ~~Agreements. Commercial~~Agreements and commercial paper issuances ~~were thus preferred to credit facility borrowings as~~are based upon available interest rates at that time of the borrowing or issuance.

Ameren has a ~~source of third-party short-term debt.~~

~~In addition, Ameren Missouri and Ameren Illinois may borrow cash from the utility~~ money pool ~~when funds are available. The rate~~agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of ~~interest depends on the composition of internal and external funds in the utility money pool.~~funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option ~~offers~~has the lowest interest rates.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval ~~by the FERC~~ under the Federal Power Act. In ~~June 2017,~~2020, the FERC issued orders authorizing Ameren Missouri and Ameren Illinois to each issue up to $1 billion of short-term debt securities through March 2022 and September 2022, respectively. In July 2019, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities, ~~through~~which expires in July ~~2019.~~2021.

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

arrangements, or other arrangements may be made.

Long-term Debt and Equity

The following table presents ~~the~~Ameren’s issuances (net of any issuance premiums or discounts), of long-term debt and equity, as well as maturities of long-term debt and redemptions of preferred stock for the three months ended March 31, 2021 and 2020:


	Month Issued, Redeemed, or Matured	2021		2020
Issuances of Long-term Debt
Ameren:
1.75% Senior unsecured notes due 2028	March	$	450	$	—

Ameren Missouri:
2.95% First mortgage bonds due 2030	March	$	—	$	465



Total Ameren long-term debt issuances		$	450	$	465
Issuances of Common Stock
Ameren:
DRPlus and 401(k) (a)	Various	$	12	$	13
Forward sale agreement (b)	February	113		—
Total common stock issuances (c)		$	125	$	13
Total Ameren long-term debt and common stock issuances		$	575	$	478
Maturities of Long-term Debt
Ameren Missouri:
5.00% Senior secured notes due 2020	February	$	—	$	85




Total Ameren long-term debt maturities		$	—	$	85
Redemptions of Preferred Stock
Ameren Illinois:
6.625% Series	March	$	12	$	—
7.75% Series	March	1		—
Total Ameren Illinois preferred stock redemptions		$	13	$	—
Total Ameren long-term debt maturities and preferred stock redemptions		$	13	$	85

(a)Ameren issued a total of 0.1 million and 0.2 million shares of common stock under its DRPlus and 401(k) plan in the three months ended March 31, 2021 and 2020, respectively.

(b)Ameren issued 1.6 million shares of common stock to settle the remainder of the forward sale agreement.

(c)Excludes 0.5 million and 0.5 million shares of common stock valued at $33 million and $38 million issued for no cash consideration in connection with stock-based compensation for the three months ended March 31, 2021 and 2020, respectively.

See Note 4 – Long-Term Debt and Equity Financings under Part I, Item 1, of this report for additional information, including proceeds from issuances of long-term debt, ~~for Ameren Missouri, Ameren Illinois,~~the use of those proceeds and ATXI for the nine months ended September 30, 2017 and 2016. The Ameren Companies did not issue any common stock during the first nine months of 2017 or 2016. In March 2016, Ameren Missouri received cash capital contributions of $38 million from Ameren (parent).

Month Issued, Redeemed, or Matured 2017 2016
Issuances of Long-term Debt
Ameren Missouri:
2.95% Senior secured notes due 2027 June $ 399
$ —
3.65% Senior secured notes due 2045 June —
149
ATXI:
3.43% Senior notes due 2050 June $ 150
$ —
3.43% Senior notes due 2050 August $ 300
$ —
Total Ameren long-term debt issuances $ 849
$ 149
Redemptions and Maturities of Long-term Debt
Ameren Missouri:
6.40% Senior secured notes due 2017 June $ 425
$ —
5.40% Senior secured notes due 2016 February —
260
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 $ 425
$ 389

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

In June 2017, pursuant to a note purchase agreement, ATXI agreed to issue $450 million principal amount of 3.43% senior unsecured notes, due 2050, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI issued $150 million principal amount of the notes in June 2017 and the remaining $300 million principal amount of the notes in August 2017. ATXI received proceeds of $449 million from the notes, which were used by ATXI to repay existing short-term and long-term affiliate debt owed to Ameren (parent).Ameren’s forward equity sale agreement.

Indebtedness Provisions and Other Covenants

At March 31, 2021, the Ameren Companies were in compliance with the provisions and covenants contained in their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement. See Note 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) and covenants contained in our credit agreements, in ATXI’s note purchase agreement, and in certain of the Ameren Companies’ indentures and articles of incorporation.

At September 30, 2017, the Ameren Companies were in compliance with the provisions and covenants contained in their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreement.

We consider access to short-term and long-term capital markets to be a significant source of funding for capital requirements not satisfied by cash ~~generated from~~provided by our operating activities. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital ~~markets.~~markets on reasonable terms. 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 dividends payable on 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 annual earnings over the next few years. On ~~October 13, 2017,~~May 7, 2021, Ameren’s board of directors declared a quarterly common stock dividend of ~~45.75~~55 cents per share payable on ~~December 29, 2017,~~June 30, 2021, to shareholders of record on December 13, 2017, resulting in an annualized equivalent dividend rate of $1.83 per share. The previous annualized equivalent dividend rate, based on the common stock dividend declared and paid in the third quarter of 2017, was $1.76 per share.June 9, 2021.

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, 2017~~,March 31, 2021, 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~~subsidiaries to their parent, Ameren Corporation, for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2021 and ~~2016~~2020:


	Three Months
	2021		2020
Ameren	$	140	$	122


ATXI	25		—

Commitments

Nine Months
2017 2016
Ameren Missouri $ 332
$ 285
Ameren Illinois —
95
Ameren 320
309
As of March 31, 2021, there have been no material changes other than in the ordinary course of business related to cash requirements arising from contractual obligations provided in Item 7 of the Form 10-K for the year ended December 31, 2020, with the exception of Ameren parent’s debt issuance discussed in Long-Term Debt and Equity section above.

~~Contractual Obligations~~Off-balance-sheet Arrangements

~~For a listing~~At March 31, 2021, none of ~~our obligations and commitments, see Other Obligations in Note 9 – Commitments and Contingencies under Part I, Item 1, of this report.~~the Ameren Companies had any significant off-balance-sheet financing arrangements, other than variable interest entities. See Note 111 – ~~Retirement Benefits~~Summary of Significant Accounting Policies under Part I, Item 1, of this report for ~~information regarding expected minimum funding levels for our pension plan.~~further detail concerning variable interest entities.

At September 30, 2017, total obligations related to minimum purchase 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 $2,649 million, $1,806 million, and $820 million, respectively.

~~Off-Balance-Sheet Arrangements~~

At ~~September 30, 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.

Credit Ratings

~~The~~Our credit ratings ~~of the Ameren Companies and ATXI assigned by Moody’s and S&P, as applicable, can~~ affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.

The following table presents the principal credit ratings ~~of the Ameren Companies and ATXI,~~ by Moody’s and S&P, as applicable, 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

Senior unsecured debt

Baa1

~~BBB+~~Not Rated

Commercial paper

P-2

A-2

Ameren Illinois:

Issuer/corporate credit rating

BBB+

Secured debt

Senior unsecured debt

BBB+

Commercial paper

P-2

A-2

ATXI:

Issuer credit rating

Not Rated

Senior unsecured debt

Not Rated

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

Collateral Postings

Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts, and cash collateral posted by external parties were immaterial at ~~Ameren, Ameren Missouri, and Ameren Illinois at September 30, 2017.~~March 31, 2021. A sub-investment-grade issuer or senior unsecured debt rating ~~(whether~~(below “Baa3” from Moody’s or below “BBB-” from S~~&P or below “Baa3” from Moody’s)~~&P) at ~~September 30, 2017,~~March 31, 2021, 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 ~~$89~~$117 million, ~~$48~~$104 million, and ~~$41~~$13 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at ~~September 30, 2017,~~March 31, 2021, if market prices were 15% higher or lower than ~~September 30, 2017~~March 31, 2021 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 seek to improve our regulatory frameworks and cost recovery mechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworks, while also advocating for responsible energy policies. We seek to align our overall spending, both operating and capital, with economic conditions and with regulatory frameworks established by our regulators and to create and capitalize on investment opportunities for the benefit of our customers and shareholders. We focus on minimizing the gap between allowed and earned returns on equity and allocating 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 pursue 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 evaluate 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 generation portfolio.

Below are some key trends, events, and uncertainties that ~~are~~may reasonably ~~likely to~~ affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for ~~2017~~2021 and beyond.

~~Operations~~

~~Ameren continues to invest~~The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The Illinois Rivers project involves the construction of a transmission line from eastern Missouri across the state of Illinois to western Indiana. Construction activities for the Illinois Rivers project are continuingsubsequent periods will depend on ~~schedule,~~its severity and longevity, future regulatory or legislative actions with respect thereto, and the ~~last section~~resulting impact on business, economic, and capital market conditions. We continue to assess the impacts the COVID-19 pandemic is having on our businesses, including but not limited to impacts on our liquidity; demand for residential, commercial, and industrial electric and natural gas services; changes in deferred payment arrangements for customers; the timing and extent to which recovery of ~~this project~~incremental costs incurred, net of savings, and forgone customer late fee revenues at Ameren Missouri is expected to be completed by 2019. The Spoon River project, located in northwest Illinois, and the Mark Twain project, located in northeast Missouri and connecting the Illinois Rivers project to Iowa, are the other two MISO-approved projects to be constructed by ATXI. Construction activities for the Spoon River project are continuing on schedule, and the project is expected to be completed in 2018. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the Mark Twain project and its approval process and the Illinois Rivers project. The total investment in all three projects is expected to be more than $540 million from 2017 through 2019. Ameren Illinois expects to invest $2.2 billion in electric transmission assets from 2017 through 2021 to replace aging infrastructure and improve reliability.

Both Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on the preliminary rate calculations that will become effective on January 1, 2018, and the currently allowed 10.82% return on common equity, the 2018 revenue requirement that is expected to be collected in rates for Ameren Illinois’ electric transmission business is $297 million. The 2018 rates reflect a $38 million increase over the 2017 revenue requirement, primarily due to rate base growth. These rates reflect a capital structure comprised of 51.6% common equity and a projected average rate base of $1.6 billion. Based on the preliminary rate calculations that will become effective on January 1, 2018, and the currently allowed 10.82% return on equity, the 2018 revenue requirement that is expected to be collected in rates for ATXI’s electric transmission business is $197 million. The 2018 rates represents a $27 million increase over the 2017 revenue requirement, primarily due to rate base growth. These rates reflect a capital structure comprised of 56.2% common equity and a projected average rate base of $1.3 billion, reflecting additional investments in the Illinois Rivers and Spoon River projects.

The return on common equity for MISO transmission owners, including Ameren Illinois and ATXI, was the subject of two FERC complaint proceedings, the November 2013 complaint case and the February 2015 complaint case, that each challenged the allowed base return on common equity. 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 a 50 basis point incentive adder for participation in an RTO. The order required customer refunds, with interest, to be issued for that 15-month period. ~~Refunds for the November 2013 complaint case were issued in the first six months 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 for the 15-month period of February 2015 to May 2016 to~~ ~~9.70%, or a 10.20% total allowed return on equity with the inclusion of a 50 basis point incentive adder for participation~~MoPSC; changes 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 is uncertain for two reasons.~~ First, while the FERC reestablished a quorum of commissioners in August 2017 after six months without a quorum, the FERC is under no deadline to issue a final order. Second, in the second quarter of 2017, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded to the FERC an order in a separate case in which the FERC established the allowed base return on common equity methodology used in the two MISO complaint cases described above. In addition, in September 2017, MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a motion to dismiss the February 2015 complaint case with the FERC. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for information regarding the MISO transmission owners’ motion to dismiss the February 2015 complaint case. A 50 basis point reduction in the FERC-allowed base return on common equity would reduce Ameren's and Ameren Illinois' annual earnings by an estimated $7 million and $4 million, respectively, based on each company’s 2017 projected rate base. Ameren and Ameren Illinois recorded current regulatory liabilities on their respective September 30, 2017 balance sheets, representing their estimate of the expected refunds related to the February 2015 complaint case.

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

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' 2017 electric distribution service revenues will be based on its 2017 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. The 2017 revenue

requirement is expected to be higher than the 2016 revenue requirement because of an expected increase in recoverable costs, expected rate base growth of 5%, and an expected increase in the monthly average of 30-year 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 $7 million change in Ameren's and Ameren Illinois' net income, based on Ameren Illinois’ 2017 projected year-end rate base.

In April 2017, Ameren Illinois filed with the ICC its annual electric distribution service formula rate update to establish the revenue requirement used for 2018 rates. In June 2017, the ICC staff submitted its calculation of the revenue requirement, which Ameren Illinois supported in its revised July 2017 filing, and recommended a decrease to the electric distribution service revenue requirement. Pending ICC approval, this update filing will result in a ~~$17 milliondecrease in Ameren Illinois’ electric distribution service revenue requirement beginning in January 2018.~~ These rates will affect Ameren Illinois' cash receipts during 2018, but will not determine its electric distribution service operating revenues, which will instead be based on its 2018 actual recoverable costs, rate base, and return on common equity as calculated under the Illinois performance-based formula ratemaking framework. In November 2017, an administrative law judge issued a proposed order that was consistent with Ameren Illinois’ revised July 2017 filing. An ICC decision on the revenue requirement used for 2018 rates is expected by December 2017.

Beginning in 2017, the FEJA provides that Ameren 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 now recognizes revenues consistent with the timing of incurred electric distribution recoverable costs and recognizes 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 incurred quarterly year-over-year increases to earnings in 2017 in comparison to 2016 for the first and second quarters and a decrease to earnings in the third quarter. Ameren Illinois expects an estimated $28 million increase to earnings in the fourth quarter of 2017 in comparison to 2016 as a result of the change. The change in interim period revenue recognition will not impact 2017’s annual earnings.

Beginning in June 2017, the FEJA allows 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 Ameren Illinois’ 2018 through 2021 energy efficiency plan and a formula provided in the FEJA, Ameren Illinois estimates it can annually invest up to $99 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 theour 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. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this reportdisconnect customers for ~~information regarding Ameren Illinois approved energy efficiency program for 2018 through 2021.~~

~~In July 2017, Illinois enacted a law that increased the state's corporate income tax rate from~~ ~~7.75% to 9.5%~~ ~~as of July 1, 2017. The law made the increase in the state’s corporate income taxrate, which was previously scheduled to decrease to~~ ~~7.3% in 2025,~~ ~~permanent. In July 2017, Ameren recorded~~an expense of $14 million at Ameren (parent) due to the revaluation of accumulated deferred taxes and the estimated state apportionment of such taxes. Beyond this expense, Ameren does not expect this tax increase to have a material impact on its consolidated net income prospectively. The tax increase is not expected to materially impact the earnings of the Ameren Illinois Electric Distribution, the Ameren Transmission, or the Ameren Illinois Transmission segments, since these businesses operate under formula ratemaking frameworks. The tax increase is expected to unfavorably affect 2017 net income of the Ameren Illinois Natural Gas segment by less than $1 million. The Ameren Illinois Natural Gas segment will continue to be impacted by the tax increase by approximately $1 million annually until customer rates are reset in a rate review to reflect the increased taxes.

In early 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.

~~Ameren Missouri's scheduled refueling and maintenance outage at its Callaway energy center began in October 2017.~~Ameren Missouri expects to incur $32 million of maintenance expenses, which approximates the cost of the spring 2016 outage. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending onnonpayment; bad debt expense; supply chain operations; the availability of ~~its other generation sources~~our employees and ~~the market prices for power, Ameren Missouri's purchased power costs may increase~~contractors; counterparty credit; capital construction; infrastructure operations and ~~the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs~~maintenance; energy-efficiency programs; and ~~excess~~

~~power available for sale are included in the FAC, which results in limited impacts to earnings. Ameren Missouri does not have a scheduled refueling and maintenance outage in 2018.~~

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

•

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

pension valuations. For additional information regarding recent rate orders, lawsuits, ~~the Westinghouse bankruptcy filing,~~ and pending requests filed with state and federal regulatory commissions, including those discussed below, 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.

Operations

•In the first three months of 2021, our sales volumes, which have been, and continue to be, affected by the COVID-19 pandemic, among other things, were comparable to the same period in 2020, excluding the estimated effects of weather and customer energy efficiency programs. We expect a gradual improvement in sales volumes in 2021, compared to 2020. Our customers’ payment for services has been adversely affected by the COVID-19 pandemic, which led to an increase in our accounts receivable balances that are past due or that are a part of a deferred payment arrangement. Because of their regulatory frameworks, Ameren Illinois’ and ATXI’s revenues are largely decoupled from changes in sales volumes. See the Results of Operations section above for additional information on our accounts receivable balances, Ameren Illinois’ electric and natural gas bad debt riders, and changes in Ameren Missouri’s sales volumes in the first three months of 2021, compared to the same period in 2020, and sales volumes expected in 2021, compared to 2020. Additionally, see Note 2 – Rate and Regulatory Matters 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 for information on Ameren Missouri’s and Ameren Illinois’ reinstatement of customer disconnection and late fee charges for non-payment, accounting authority orders issued by the MoPSC related to Ameren Missouri's electric and natural gas services to allow Ameren Missouri to accumulate certain costs incurred, net of savings, and forgone customer late fee revenues related to the COVID-19 pandemic for consideration of recovery in the current electric and natural gas service regulatory rate reviews, and orders issued by the ICC in a service disconnection moratorium proceeding, which required Ameren Illinois to implement more flexible credit and collection practices and allowed for recovery of costs incurred related to the COVID-19 pandemic and forgone late fees.

•The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on investments in certain property, plant, and equipment placed in service, and not included in base rates. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC, with all approved PISA deferrals added to rate base prospectively and recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Ameren Missouri recognizes the cost of debt on PISA deferrals in revenue, instead of using the applicable WACC, with the difference recognized in revenues when recovery of such deferrals is reflected in customer rates. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including

limitations on electric customer rate increases. Ameren Missouri does not expect to exceed these rate increase limitations in 2021. Both the rate increase limitation and the PISA are effective through December 2023, unless Ameren Missouri requests and the MoPSC approves an extension through December 2028.

•In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency programs through December 2022 and low-income customer energy-efficiency programs through December 2024, along with a rider. Ameren Missouri intends to invest $290 million over the life of the plan, including $65 million in 2021 and $70 million in 2022. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals. If the target goals were achieved for 2020, additional revenues of $10 million would be recognized in 2021, and, if target goals are achieved for 2021 and 2022, additional revenues of $24 million would be recognized in 2022. Incremental additional revenues of $3 million, $3 million, and $1 million may be earned for 2020, 2021, and 2022, respectively, and would be recognized in the respective following year if Ameren Missouri exceeds its targeted goals. Ameren Missouri’s ability to achieve and/or exceed targeted goals could be affected by the COVID-19 pandemic. For the year ended December 31, 2020, Ameren Missouri recognized $6 million in revenues related to MEEIA performance incentives.

•In March 2021, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $299 million. 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 February 2022 and new rates effective by March 2022. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, or whether any rate change 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 rate change goes into effect.

•In March 2020, the MoPSC issued an order in Ameren Missouri’s July 2019 electric service regulatory rate review, resulting in a decrease of $32 million to Ameren Missouri’s annual revenue requirement for electric retail service. The order also approved a change in rate design, which will result in winter rates applied to May usage and summer rates applied to September usage beginning in 2021. Previously, blended rates were applied to both months’ usage. The quarterly year-over-year increases/(decreases) to 2021 earnings, compared to the same periods in 2020, from the effect of the change in rate design are estimated at approximately ($50) million and $50 million for the second and third quarter comparisons, respectively.

•Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base growth and the currently allowed 10.52% ROE, which includes a 50 basis point adder for participation in an RTO, the revenue requirements included in 2021 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $380 million and $200 million, respectively. These revenue requirements represent an increase in Ameren Illinois’ and ATXI’s revenue requirements of $67 million and $8 million, respectively, from the revenue requirements reflected in 2020 rates, primarily due to expected rate base growth. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2021, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2021 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the FERC formula ratemaking framework.

•The allowed base ROE for FERC-regulated transmission rates previously charged under the MISO tariff is the subject of an appeal filed with the United States Court of Appeals for the District of Columbia Circuit. Depending on the outcome of the appeal, the transmission rates charged during previous periods and the currently effective rates may be subject to change. Additionally, in March 2019, the FERC issued a Notice of Inquiry regarding its transmission incentives policy. In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which addressed many of the issues in the Notice of Inquiry on transmission incentives. The Notice of Proposed Rulemaking included an increased incentive in the allowed base ROE for participation in an RTO to 100 basis points from the current 50 basis points and revised the parameters for awarding incentives, while limiting the overall incentives to a cap of 250 basis points, among other things. In April 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking, which proposes to modify the Notice of Proposed Rulemaking’s incentive for participation in an RTO by limiting this incentive for utilities that join an RTO to 50 basis points and only allowing them to earn the incentive for three years, among other things. If this proposal is included in a final rule, Ameren Illinois and ATXI would no longer be eligible for the 50 basis point RTO incentive adder, prospectively. The FERC is under no deadline to issue a final rule on this matter. Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy, or any further order on base ROE. A 50 basis point change in the FERC-allowed base ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $11 million and $7 million, respectively, based on each company’s 2021 projected rate base.

•Ameren Illinois’ electric distribution service performance-based formula ratemaking framework allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to

reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the year. Unless extended by legislation, the ability to conduct annual updates to performance-based formula rates expires at the end of 2022. If not extended, Ameren Illinois would be required to establish future rates through a traditional regulatory rate review with the ICC, which would allow the use of a future test year. The decoupling provisions extend beyond the end of 2022 by law, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. Ameren Illinois is actively pursuing constructive ratemaking. In March 2021, the ICC issued an order approving Ameren Illinois’ requested tariff to reconcile its electric distribution service revenue requirement for a period of up to two years after the final customer rate update under performance-based formula ratemaking. To utilize the reconciliation, the ICC-approved tariff requires Ameren Illinois to file a traditional regulatory rate review for its electric distribution service, which may be based on a future test year, by the end of March in the year following the last year in which an annual performance-based formula rate update was permitted.

•In 2020, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $49 million decrease in Ameren Illinois’ electric distribution service rates beginning in January 2021. Illinois law provides for an annual reconciliation of the electric distribution revenue requirement as is necessary to reflect the actual costs incurred and a return at the applicable WACC on year-end rate base in a given year with the revenue requirement that was reflected in customer rates for that year. Consequently, Ameren Illinois’ 2021 electric distribution service revenues will be based on its 2021 actual recoverable costs, 2021 year-end rate base, and a return at the applicable WACC, with the ROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. As of March 31, 2021, Ameren Illinois expects its 2021 electric distribution year-end rate base to be $3.7 billion. With or without extension of the formula ratemaking framework, the 2021 revenue requirement reconciliation will be collected from, or refunded to, customers in 2023. A 50 basis point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $10 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 2021 projected year-end rate base, including electric energy-efficiency investments. Ameren Illinois’ allowed ROE for the first three months of 2021 was based on an estimated annual average of the monthly yields of the 30-year United States Treasury bonds of 2.37%.

•In April 2021, Ameren Illinois filed its annual electric distribution service performance-based formula rate update with the ICC, requesting an increase of $64 million in its rates. An ICC decision in this proceeding is expected by December 2021, with new rates effective January 2022. These rates will affect Ameren Illinois' cash receipts during 2022, but will not affect electric distribution service revenues, which will be based on 2022 actual recoverable costs, 2022 year-end rate base, and a return at the applicable WACC as calculated under the Illinois performance-based formula ratemaking framework.

•In January 2021, the ICC issued an order in Ameren Illinois’ February 2020 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $76 million. The new rates became effective in January 2021. As a result of this order, the rate base under the QIP was reset to zero. Ameren Illinois used a 2021 future test year in this proceeding. The order also approved the implementation of a change in rate design, which concentrates more revenues in the winter heating season due to an increase in volumetric rates and a decrease in fixed customer rates. As such, the change in rate design will have an impact on interim period 2021 earnings, compared to 2020, but is not expected to materially affect annual earnings comparisons. The quarterly year-over-year increases/(decreases) to 2021 earnings, compared to the same periods in 2020, from the combined effect of the rate increase and the change in rate design are estimated at $17 million, ($7) million, and $7 million for the first quarter, third quarter, and fourth quarter comparisons, respectively.

•Pursuant to Illinois law, Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the applicable WACC, with the ROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. The allowed ROE on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. Ameren Illinois plans to invest up to approximately $100 million per year in electric energy-efficiency programs through 2025. While the ICC has approved a plan consistent with this spending level through 2021, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not included in the electric distribution service performance-based formula ratemaking framework. In March 2021, Ameren Illinois filed with the ICC an energy-efficiency plan which includes annual investments in electric energy-efficiency programs up to approximately $100 million per year from 2022 through 2025. A decision by the ICC in this proceeding is expected by September 2021.

•During its return to full power after the completion of the last refueling and maintenance outage in late December 2020, the Callaway Energy Center experienced a non-nuclear operating issue related to its generator. A thorough investigation of this matter was conducted. Work continues to replace certain key components of the generator in order to return the energy center to service. Ameren Missouri expects generator repairs of approximately $65 million, which are expected to be largely capital expenditures. Due to the long lead time for the manufacture, repair, and installation of the components, the energy center is expected to return to service in July 2021. In April 2021, Ameren Missouri’s insurance claims were accepted by NEIL, which are expected to cover a significant portion of the

capital expenditures and replacement power costs. Replacement power costs of up to $4.5 million weekly are covered by insurance after March 17, 2021. Insurance recoveries related to replacement power costs will be reflected in electric operating revenues and included in net energy costs under the FAC. Insurance recoveries related to the capital expenditures will be reflected as a reduction to property, plant, and equipment. For the duration of the unplanned outage, Ameren Missouri expects an increase to its purchased power expense and a decrease to its off-system sales, with changes to both items recovered through the FAC. Ameren Missouri does not expect a significant increase to other operations and maintenance expense as a result of the unplanned outage. Pursuant to a February 2020 MoPSC order, Ameren Missouri deferred, as a regulatory asset, a total of $39 million in maintenance expenses related to its scheduled fall 2020 outage, which it began to amortize in January 2021. The regulatory asset will be amortized until the completion of the next refueling and maintenance outage, which is scheduled for the spring of 2022.

•Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek increases to electric and natural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, 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, economic impacts of the COVID-19 pandemic, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective technological advances, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by increased demand resulting from increased electrification of the economy for efficiencies and as a means to address economy-wide CO2 emission concerns. We expect that increased investments, including expected future investments for environmental compliance, system reliability improvements, and potential new generation sources, will result in rate base and revenue growth but also higher depreciation and financing costs.

Liquidity and Capital Resources

•Our customers’ payment for our services has been adversely affected by the COVID-19 pandemic, resulting in a decrease to our cash flow from operations. See the Results of Operations section above for additional information on our accounts receivable balances. Further, our liquidity and our capital expenditure plans could be adversely affected by other impacts resulting from the COVID-19 pandemic, including but not limited to potential impacts on our ability to access the capital markets on reasonable terms and when needed, Ameren Missouri’s expected wind generation additions remaining in 2021, and the timing of tax payments and the utilization of tax credits. We expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, however, disruptions to the capital markets and the ability of our suppliers and contractors to perform as required under their contracts could impact the execution of our capital investment strategy. For further discussion on the impacts to our ability to access the capital markets and Ameren Missouri’s expected wind generation additions remaining in 2021, see below.

•In February 2021, Ameren Missouri ~~files a non-binding 20-year integrated resource plan~~filed an update to its Smart Energy Plan with the MoPSC, ~~every three years.~~which includes a five-year capital investment overview with a detailed one-year plan for 2021. The plan is designed to upgrade Ameren Missouri’s ~~integrated resource~~electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan ~~filed~~are expected to total approximately $8.4 billion over the five-year period from 2021 through 2025, with expenditures largely recoverable under the PISA and the RESRAM. The planned investments in 2024 and 2025 are based on the assumption that Ameren Missouri requests and receives MoPSC approval of an extension of the PISA through December 2028.

•In connection with Ameren Missouri’s 2020 IRP, Ameren established a goal of achieving net-zero carbon emissions by 2050. Ameren is also targeting a 50% CO2 emission reduction by 2030 and an 85% reduction by 2040 from the 2005 level. The plan, which is subject to review by the MoPSC ~~in September 2017~~ ~~includes Ameren Missouri’s preferred plan~~ for ~~meeting customers’ projected long-term energy needs in a cost-effective fashion that maintains system reliability as it~~compliance with Missouri law, targets cleaner and more diverse sources of energy ~~generation.~~generation, including solar, wind, hydro, and nuclear power, and supports increased investment in new energy technologies. It also includes expanding renewable sources by adding 3,100 MWs of renewable generation by the end of 2030 and a total of 5,400 MWs of renewable generation by 2040. These ~~new~~amounts include 700 MWs related to the High Prairie and Atchison renewable energy ~~sources would also~~centers, which will support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of native load sales from renewable energy sources by 2021, subject to customer rate increase limitations. Ameren Missouri’s plan contemplates adding at least 700 megawatts of wind generation by 2020, as well as 100 megawatts of solar generation over the next 10 years, with 50 megawatts anticipated to come online by 2025. The new wind generation is expected to be locatedbeginning in ~~Missouri and neighboring states. The source, location, and cost of the new wind generation, among other items, remain subject to reaching agreements with developers.~~Based on current and projected market prices for energy, and for wind and solar generation technologies, among other factors, Ameren Missouri expects its ownership of these renewable resources would represent the lowest-cost alternative for customers.2021. The plan also includes ~~expected~~advancing the retirement dates of the Sioux and Rush Island coal-fired energy centers to 2028 and 2039, respectively, which are subject to the approval of a change in the assets’ depreciable lives by the MoPSC in Ameren Missouri’s current electric service regulatory rate review, the continued implementation of ~~continued~~ customer energy-efficiency programs, and the expectation that Ameren Missouri will seek NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date. Additionally, the plan includes retiring the Meramec and Labadie coal-fired energy ~~efficiency programs.~~centers at the end of their useful lives (by 2022 and 2042, respectively). Ameren Missouri’s plan ~~for the addition of renewable resources~~ could be ~~impacted~~affected by, among other factors: the availability of federal production tax credits related to renewable energy and its ability to use such credits; the cost of wind and solar generation technologies, as well as energy prices; Ameren Missouri’s ability to obtain interconnection agreements with MISO or other RTOs, including the cost of such interconnections; and Ameren Missouri’s ability to obtain a certificate of convenience and necessity from the MoPSC, ~~for projects located in Missouri, or~~and any other required approvals for the addition of renewable resources, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability of developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary materials and equipment, including those that are affected by the disruptions in the global supply chain caused by the COVID-19 pandemic, among other things; the availability of federal production and investment tax credits related to renewable energy and Ameren

Missouri’s ability to use such credits; the cost of wind, solar, and other renewable generation and storage technologies; changes in environmental regulations, including those related to carbon emissions; energy prices and demand; and Ameren Missouri’s ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost. The next integrated resource plan is expected to be filed in September 2023.

•In January 2021, Ameren Missouri acquired an up-to 300-MW wind generation project ~~approvals.~~located in northwestern Missouri and partially placed it in service as the Atchison Renewable Energy Center. As of the date of this filing, Ameren Missouri has placed approximately half of the project in service, representing a purchase price of approximately $250 million, including an immaterial amount of transaction costs. Ameren Missouri expects the remaining MWs of the project to be in service by the end of September 2021.


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

	~~43-1723446~~
1-2967				~~(Missouri Corporation)~~
		~~1901 Chouteau Avenue~~
		~~St. Louis, Missouri 63103~~
		~~(314) 621-3222~~

~~1-2967~~		Union Electric Company	43-0559760

	~~43-0559760~~
1-3672				~~(Missouri Corporation)~~
		~~1901 Chouteau Avenue~~
		~~St. Louis, Missouri 63103~~
		~~(314) 621-3222~~

~~1-3672~~		Ameren Illinois Company	37-0211380

	~~37-0211380~~
Title of each class			Trading Symbol(s)		~~(Illinois Corporation)~~	Name of each exchange on which registered
Common Stock, $0.01 par value per share			AEE		~~6 Executive Drive~~
		~~Collinsville, Illinois 62234~~
		~~(618) 343-8150~~		New York Stock Exchange



Registrant	Title of each class of common stock	Shares outstanding
Ameren Corporation	Common stock, $0.01 par value per share– ~~242,634,798~~	255,552,619
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



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



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


					Page
Glossary of Terms and Abbreviations					1

Forward-looking Statements					1

PART I. Financial Information

				~~Page~~
~~Glossary of Terms and Abbreviations~~ Item 1.		1

~~Forward-looking Statements~~		1

~~PART I Financial Information~~

~~Item 1.~~	Financial Statements (Unaudited)	34
			Ameren Corporation		34
			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	74

			Consolidated Balance Sheet		5
			Consolidated Statement of Cash Flows		6
			Consolidated Statement of Shareholders’ Equity		7
			Union Electric Company (d/b/a Ameren Missouri)		8
			Statement of Income (Loss)		8
			Balance Sheet		89
			Statement of Cash Flows		910
			Statement of Shareholders’ Equity		11
			Ameren Illinois Company (d/b/a Ameren Illinois)		1012
			Statement of Income ~~and Comprehensive Income~~		1012
			Balance Sheet		1113
			Statement of Cash Flows		1214
			Statement of Shareholders’ Equity		15
			Note 1. Summary of Significant Accounting Policies		1316
			Note 2. Rate and Regulatory Matters		1617
			Note 3. Short-term Debt and Liquidity		1820
			Note 4. Long-term Debt and Equity Financings		1921
			Note 5. Other Income, ~~and Expenses~~Net		2022
			Note 6. Derivative Financial Instruments		2022
			Note 7. Fair Value Measurements		2324
			Note 8. ~~Related Party~~Related-party Transactions		2826
			Note 9. Commitments and Contingencies		2927
			Note 10. Callaway Energy Center		3230
			Note 11. Retirement Benefits		3431
			Note 12. ~~Segment Information~~Income Taxes		3432
			Note 13. Supplemental Information		32
			Note 14. Segment Information		35
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 3.			Quantitative and Qualitative Disclosures About Market Risk		6263
Item 4.			Controls and Procedures		6463

PART IIII. Other Information

Item 1.			Legal Proceedings		6463
Item 1A.			Risk Factors		64
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds		6564
Item 6.			Exhibits		65

Signatures					66


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
	2017		2016		2017		2016				2021		2020
Operating Revenues:									Operating Revenues:
Electric	$	1,594	$	1,725	$	4,183	$	4,101	Electric		$	1,156	$	1,120
Natural gas	129		134		592		619		Natural gas		410		320
Total operating revenues	1,723		1,859		4,775		4,720		Total operating revenues		1,566		1,440
Operating Expenses:									Operating Expenses:
Fuel	199		205		594		574		Fuel		65		140
Purchased power	162		178		491		451		Purchased power		191		134
Natural gas purchased for resale	25		34		196		227		Natural gas purchased for resale		165		107
Other operations and maintenance	402		411		1,229		1,246		Other operations and maintenance		420		438

Depreciation and amortization	225		211		668		628		Depreciation and amortization		281		255
Taxes other than income taxes	129		129		364		358		Taxes other than income taxes		128		125
Total operating expenses	1,142		1,168		3,542		3,484		Total operating expenses		1,250		1,199
Operating Income	581		691		1,233		1,236		Operating Income		316		241
Other Income and Expenses:
Miscellaneous income	13		18		42		54
Miscellaneous expense	2		8		16		21
Total other income	11		10		26		33

Other Income, Net									Other Income, Net		46		21
Interest Charges	97		97		295		287		Interest Charges		100		93
Income Before Income Taxes	495		604		964		982		Income Before Income Taxes		262		169
Income Taxes	205		233		376		356		Income Taxes		27		21

Net Income	290		371		588		626		Net Income		235		148
Less: Net Income Attributable to Noncontrolling Interests	2		2		5		5		Less: Net Income Attributable to Noncontrolling Interests		2		2

Net Income Attributable to Ameren Common Shareholders	$	288	$	369	$	583	$	621	Net Income Attributable to Ameren Common Shareholders		$	233	$	146

Net Income									Net Income		$	235	$	148
Other Comprehensive Income, Net of Taxes									Other Comprehensive Income, Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $0 and $0, respectively									Pension and other postretirement benefit plan activity, net of income taxes of $0 and $0, respectively		1		1
Comprehensive Income									Comprehensive Income		236		149
Less: Comprehensive Income Attributable to Noncontrolling Interests									Less: Comprehensive Income Attributable to Noncontrolling Interests		2		2
Comprehensive Income Attributable to Ameren Common Shareholders									Comprehensive Income Attributable to Ameren Common Shareholders		$	234	$	147


Earnings per Common Share – Basic	$	1.19	$	1.52	$	2.40	$	2.56	Earnings per Common Share – Basic		$	0.92	$	0.59


Earnings per Common Share – Diluted	$	1.18	$	1.52	$	2.39	$	2.56	Earnings per Common Share – Diluted		$	0.91	$	0.59

Dividends per Common Share	$	0.44	$	0.425	$	1.32	$	1.275
Average Common Shares Outstanding – Basic	242.6		242.6		242.6		242.6
Average Common Shares Outstanding – Diluted	244.7		242.9		244.0		243.0
Weighted-average Common Shares Outstanding – Basic									Weighted-average Common Shares Outstanding – Basic		254.4		246.4
Weighted-average Common Shares Outstanding – Diluted									Weighted-average Common Shares Outstanding – Diluted		255.9		248.1


	September 30, 2017			December 31, 2016				March 31, 2021		December 31, 2020
ASSETS							ASSETS
Current Assets:							Current Assets:
Cash and cash equivalents	$	9		$	9		Cash and cash equivalents	$	6	$	139
Accounts receivable – trade (less allowance for doubtful accounts of $20 and $19, respectively)	507			437
Accounts receivable – trade (less allowance for doubtful accounts of $47 and $50, respectively)							Accounts receivable – trade (less allowance for doubtful accounts of $47 and $50, respectively)	464		415
Unbilled revenue	262			295			Unbilled revenue	210		269
Miscellaneous accounts receivable	85			63			Miscellaneous accounts receivable	61		65
Inventories	547			527			Inventories	467		521

Restricted cash							Restricted cash	134		17
Current regulatory assets	75			149			Current regulatory assets	367		109

Other current assets	96			113			Other current assets	114		118

Total current assets	1,581			1,593			Total current assets	1,823		1,653
Property, Plant, and Equipment, Net	20,906			20,113			Property, Plant, and Equipment, Net	27,307		26,807
Investments and Other Assets:							Investments and Other Assets:
Nuclear decommissioning trust fund	672			607			Nuclear decommissioning trust fund	1,010		982
Goodwill	411			411			Goodwill	411		411

Regulatory assets	1,509			1,437			Regulatory assets	1,249		1,100
Other assets	538			538			Other assets	989		1,077

Total investments and other assets	3,130			2,993			Total investments and other assets	3,659		3,570
TOTAL ASSETS	$	25,617		$	24,699		TOTAL ASSETS	$	32,789	$	32,030
LIABILITIES AND EQUITY							LIABILITIES AND EQUITY
Current Liabilities:							Current Liabilities:
Current maturities of long-term debt	$	777		$	681		Current maturities of long-term debt	$	8	$	8
Short-term debt	446			558			Short-term debt	889		490
Accounts and wages payable	548			805			Accounts and wages payable	581		958
Taxes accrued	159			46			Taxes accrued	128		82
Interest accrued	106			93			Interest accrued	84		114
Customer deposits	108			107

Current regulatory liabilities	119			110			Current regulatory liabilities	225		121

Other current liabilities	318			274			Other current liabilities	392		407

Total current liabilities	2,581			2,674			Total current liabilities	2,307		2,180
Long-term Debt, Net	6,922			6,595			Long-term Debt, Net	11,527		11,078
Deferred Credits and Other Liabilities:							Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net	4,721			4,264
Accumulated deferred investment tax credits	50			55
Accumulated deferred income taxes and tax credits, net							Accumulated deferred income taxes and tax credits, net	3,253		3,211

Regulatory liabilities	2,045			1,985			Regulatory liabilities	5,230		5,282
Asset retirement obligations	631			635			Asset retirement obligations	705		696
Pension and other postretirement benefits	711			769			Pension and other postretirement benefits	38		37
Other deferred credits and liabilities	469			477			Other deferred credits and liabilities	452		466

Total deferred credits and other liabilities	8,627			8,185			Total deferred credits and other liabilities	9,678		9,692
Commitments and Contingencies (Notes 2, 9, and 10)							Commitments and Contingencies (Notes 2, 9, and 10)	0		0
Ameren Corporation Shareholders’ Equity:							Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding	2			2
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 255.5 and 253.3, respectively							Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 255.5 and 253.3, respectively	3		3
Other paid-in capital, principally premium on common stock	5,534			5,556			Other paid-in capital, principally premium on common stock	6,295		6,179
Retained earnings	1,830			1,568			Retained earnings	2,850		2,757
Accumulated other comprehensive loss	(21		)	(23		)	Accumulated other comprehensive loss	0		(1)

Total Ameren Corporation shareholders’ equity	7,345			7,103			Total Ameren Corporation shareholders’ equity	9,148		8,938
Noncontrolling Interests	142			142			Noncontrolling Interests	129		142
Total equity	7,487			7,245			Total equity	9,277		9,080
TOTAL LIABILITIES AND EQUITY	$	25,617		$	24,699		TOTAL LIABILITIES AND EQUITY	$	32,789	$	32,030



	Ameren Missouri				Ameren Illinois^(a)			Ameren
Balance at December 31, 2016	$	644		^(b)	$	6		$	650		^(b)
Liabilities settled	(4		)		(1		)	(5		)
Accretion^(c)	20				(d)			20
Change in estimates^(e)	(18		)		(1		)	(19		)
Balance at September 30, 2017	$	642		^(b)	$	4		$	646		^(b)



	Performance Share Units
	Share Units		Weighted-average Fair Value per Share Unit
Nonvested at January 1, 2017	1,059,639		$	48.04
Granted^(a)	500,943		59.16
Forfeitures	(48,661	)	52.54
Vested^(b)	(27,446	)	52.88
Nonvested at September 30, 2017	1,484,475		$	51.55



Payment Date		Principal Payment
August 2022	$	49.5
August 2024		49.5
August 2027		49.5
August 2030		49.5
August 2032		49.5
August 2038		49.5
August 2043		76.5
August 2050		76.5
Total Principal Amount of Notes	$	450.0



	Aggregate Fair Value of Derivative Liabilities^(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required^(b)
2017
Ameren Missouri	$	59	$	3	$	48
Ameren Illinois	48		—		41
Ameren	$	107	$	3	$	89



		Fair Value								Weighted Average
		Assets		Liabilities			Valuation Technique(s)	Unobservable Input	Range	Weighted Average
Level 3 Derivative asset and liability – commodity contracts^(a):
2017
	Fuel oils	$	1	$	(1	)	Option model	Volatilities(%)^(b)	24 – 32	26
							Discounted cash flow	Counterparty credit risk(%)^(c)(d)	0.12 – 0.22	0.17
								Ameren Missouri credit risk(%)^(c)(d)	0.37	(e)
	Natural gas	—		(2		)	Discounted cash flow	Nodal basis ($/mmbtu)^(b)	(1.10) – (0.10)	(0.80)
								Counterparty credit risk (%)^(c)(d)	0.34 – 6	0.73
								Ameren Illinois credit risk (%)^(c)(d)	0.37	(e)
	Power^(g)	$	11	$	(193	)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)^(h)	25 – 41	28
								Estimated auction price for FTRs ($/MW)^(b)	(324) – 1,194	269
								Nodal basis ($/MWh)^(h)	(3) – 0	(2)



~~Commission~~



		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):
	Fuel oils	$	2	$	—	$	1	$	3
	Natural gas	1		1		—		2
	Power	—		—		11		11
	Total derivative assets – commodity contracts	$	3	$	1	$	12	$	16
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	445		—		—		445
	Debt securities:
	U.S. treasury and agency securities	—		119		—		119
	Corporate bonds	—		82		—		82
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	447	$	225	$	—	$	672
	Total Ameren	$	450	$	226	$	12	$	688
Ameren Missouri	Derivative assets – commodity contracts^(a):
	Fuel oils	$	2	$	—	$	1	$	3
	Power	—		—		11		11
	Total derivative assets – commodity contracts	$	2	$	—	$	12	$	14
	Nuclear decommissioning trust fund:
	Cash and cash equivalents	$	2	$	—	$	—	$	2
	Equity securities:
	U.S. large capitalization	445		—		—		445
	Debt securities:
	U.S. treasury and agency securities	—		119		—		119
	Corporate bonds	—		82		—		82
	Other	—		24		—		24
	Total nuclear decommissioning trust fund	$	447	$	225	$	—	$	672
	Total Ameren Missouri	$	449	$	225	$	12	$	686
Ameren Illinois	Derivative assets – commodity contracts^(a):
	Natural gas	$	1	$	1	$	—	$	2
Liabilities:
Ameren	Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	—		19		2		21
	Power	—		—		193		193
	Total Ameren	$	1	$	19	$	196	$	216
Ameren Missouri	Derivative liabilities – commodity contracts^(a):
	Fuel oils	$	1	$	—	$	1	$	2
	Natural gas	—		7		—		7
	Power	—		—		1		1
	Total Ameren Missouri	$	1	$	7	$	2	$	10
Ameren Illinois	Derivative liabilities – commodity contracts^(a):
	Natural gas	$	—	$	12	$	2	$	14
	Power	—		—		192		192
	Total Ameren Illinois	$	—	$	12	$	194	$	206



		Net derivative commodity contracts
		Ameren Missouri			Ameren Illinois			Ameren
For the three months ended September 30, 2017
Beginning balance at July 1, 2017	$	14		$	(192	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(2	)		(3	)		(5	)
Sales		1			—			1
Settlements		(3	)		3			—
Ending balance at September 30, 2017	$	10		$	(192	)	$	(182	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2017	$	—		$	(2	)	$	(2	)
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 nine months ended September 30, 2017
Beginning balance at January 1, 2017	$	7		$	(185	)	$	(178	)
Realized and unrealized gains (losses) included in regulatory assets/liabilities		(3	)		(14	)		(17	)
Purchases		15			—			15
Sales		1			—			1
Settlements		(10	)		7			(3	)
Ending balance at September 30, 2017	$	10		$	(192	)	$	(182	)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2017	$	—		$	(15	)	$	(15	)
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	)



	Coal			Natural Gas^(a)		Nuclear Fuel		Purchased Power^(b)(c)		Methane Gas		Other		Total
Ameren:^(d)
2017	$	162		$	65	$	19	$	59	$	1	$	33	$	339
2018	453			200		67		170		4		57		951
2019	356			148		27		63		4		39		637
2020	79			94		39		13		5		39		269
2021	27			36		45		2		5		26		141
Thereafter	—			47		58		20		64		123		312
Total	$	1,077		$	590	$	255	$	327	$	83	$	317	$	2,649
Ameren Missouri:
2017	$	162		$	14	$	19	$	—	$	1	$	20	$	216
2018	453			42		67		—		4		44		610
2019	356			34		27		—		4		25		446
2020	79			26		39		—		5		25		174
2021	27			13		45		—		5		26		116
Thereafter	—			22		58		—		64		100		244
Total	$	1,077		$	151	$	255	$	—	$	83	$	240	$	1,806
Ameren Illinois:
2017	$	—	��	$	51	$	—	$	59	$	—	$	13	$	123
2018	—			158		—		170		—		13		341
2019	—			114		—		63		—		14		191
2020	—			68		—		13		—		14		95
2021	—			23		—		2		—		—		25
Thereafter	—			25		—		20		—		—		45
Total	$	—		$	439	$	—	$	327	$	—	$	54	$	820



	Three Months^(a)				Nine Months^(a)
	2017		2016		2017		2016
Ameren	41	%	39	%	39	%	36	%
Ameren Missouri	38	%	38	%	38	%	38	%
Ameren Illinois	40	%	39	%	40	%	39	%
Ameren Illinois Electric Distribution	38	%	40	%	39	%	39	%
Ameren Illinois Natural Gas	51	%	20	%	40	%	39	%
Ameren Illinois Transmission	42	%	38	%	40	%	38	%
Ameren Transmission	44	%	38	%	41	%	39	%



	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided by (Used In) Financing Activities
	2017		2016		Variance			2017			2016			Variance			2017			2016			Variance
Ameren^(a)	$	1,643	$	1,559	$	84		$	(1,585	)	$	(1,551	)	$	(34	)	$	(58	)	$	(282	)	$	224
Ameren Missouri	819		888		(69		)	(455		)	(724		)	269			(364		)	(362		)	(2		)
Ameren Illinois	628		627		1			(754		)	(679		)	(75		)	126			(16		)	142



Ameren and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,000
Less: Ameren (parent) commercial paper outstanding	162
Missouri Credit Agreement – credit available	838
Ameren and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,100
Less: Ameren (parent) commercial paper outstanding	115
Less: Ameren Illinois commercial paper outstanding	169
Less: Letters of credit	1
Illinois Credit Agreement – credit available	815
Total Credit Available	$	1,653
Cash and cash equivalents	9
Total Liquidity	$	1,662


•	~~In connection with the integrated resource plan filing, discussed above,~~ ~~Ameren Missouri established a goal of reducing CO~~₂ ~~emissions 80% by 2050 from a 2005 base level. To meet this goal, Ameren Missouri is targeting a 35% CO~~₂ ~~emission reduction by 2030 and a 50% reduction by 2040 from the 2005 level by retiring coal-fired generation at the end of its useful life.~~



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
Ameren Missouri:
Level 1	$	1		$	—		$	—		$	—		$	1
Level 2^(a)	(3		)	(4		)	—			—			(7		)
Level 3^(b)	8			2			—			—			10
Total	$	6		$	(2	)	$	—		$	—		$	4
Ameren Illinois:
Level 1	$	—		$	1		$	—		$	—		$	1
Level 2^(a)	(7		)	(4		)	—			—			(11		)
Level 3^(b)	(13		)	(29		)	(29		)	(123		)	(194		)
Total	$	(20	)	$	(32	)	$	(29	)	$	(123	)	$	(204	)
Ameren:
Level 1	$	1		$	1		$	—		$	—		$	2
Level 2^(a)	(10		)	(8		)	—			—			(18		)
Level 3^(b)	(5		)	(27		)	(29		)	(123		)	(184		)
Total	$	(14	)	$	(34	)	$	(29	)	$	(123	)	$	(200	)


~~(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.


~~(b)~~	~~Changes in Internal Controls over Financial Reporting~~



AMEREN CORPORATION (Registrant)
~~AMEREN CORPORATION~~ ~~(Registrant)~~
/s/ Michael L. Moehn
~~/s/ Martin J. Lyons, Jr.~~
~~Martin J. Lyons, Jr.~~ Michael L. Moehn Executive Vice President and Chief Financial Officer (Principal Financial Officer)


UNION ELECTRIC COMPANY (Registrant)

/s/ ~~Martin J. Lyons, Jr.~~Michael L. Moehn
~~Martin J. Lyons, Jr.~~ Michael L. Moehn Executive Vice President and Chief Financial Officer (Principal Financial Officer)


AMEREN ILLINOIS COMPANY (Registrant)

/s/ ~~Martin J. Lyons, Jr.~~Michael L. Moehn
~~Martin J. Lyons, Jr.~~ Michael L. Moehn Executive Vice President and Chief Financial Officer (Principal Financial Officer)