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


	June 30, 2023		December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	—

Accounts receivable – trade (less allowance for doubtful accounts of $27 and $18, respectively)	281		341
Accounts receivable – affiliates	10		12
Unbilled revenue	130		262
Miscellaneous accounts receivable	29		23
Inventories	196		233


Current regulatory assets	88		87

Other current assets	36		98
Total current assets	770		1,056
Property, Plant, and Equipment, Net	13,955		13,353
Investments and Other Assets:
Goodwill	411		411
Regulatory assets	1,091		821
Pension and other postretirement benefits	335		318
Other assets	548		482
Total investments and other assets	2,385		2,032
TOTAL ASSETS	$	17,110	$	16,441
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	—	$	100
Short-term debt	117		264

Accounts and wages payable	357		451
Accounts payable – affiliates	68		93


Customer deposits	111		87


Current regulatory liabilities	82		64
Other current liabilities	212		232
Total current liabilities	947		1,291
Long-term Debt, Net	5,232		4,735
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net	1,783		1,699

Regulatory liabilities	2,344		2,313


Other deferred credits and liabilities	309		235
Total deferred credits and other liabilities	4,436		4,247
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	2,929		2,929
Preferred stock	49		49
Retained earnings	3,517		3,190

Total shareholders’ equity	6,495		6,168
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	17,110	$	16,441

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

Table of Contents

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

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,
	2023		2022
Cash Flows From Operating Activities:
Net income	$	328	$	273
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	271		251
Amortization of debt issuance costs and premium/discounts	2		6
Deferred income taxes and investment tax credits, net	70		55

Allowance for equity funds used during construction	(10)		(9)
Other	12		6
Changes in assets and liabilities:
Receivables	182		(76)
Inventories	37		(1)
Accounts and wages payable	(92)		76
Taxes accrued	(36)		62
Regulatory assets and liabilities	(105)		55
Assets, other	(42)		(43)
Liabilities, other	13		23
Pension and other postretirement benefits	(46)		(18)
Counterparty collateral, net	53		15

Net cash provided by operating activities	637		675
Cash Flows From Investing Activities:
Capital expenditures	(844)		(699)

Other	(2)		—
Net cash used in investing activities	(846)		(699)
Cash Flows From Financing Activities:

Dividends on preferred stock	(1)		(1)
Short-term debt, net	(147)		38

Maturities of long-term debt	(100)		—
Issuances of long-term debt	498		—




Debt issuance costs	(3)		—

Net cash provided by financing activities	247		37
Net change in cash, cash equivalents, and restricted cash	38		13
Cash, cash equivalents and restricted cash at beginning of year	191		133
Cash, cash equivalents, and restricted cash at end of period	$	229	$	146

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

Table of Contents

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

STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited) (In millions)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Common Stock	$	—	$	—	$	—	$	—

Other Paid-in Capital	2,929		2,914		2,929		2,914







Preferred Stock	49		49		49		49




Retained Earnings:
Beginning of period	3,388		2,846		3,190		2,677
Net income	130		104		328		273

Dividends on preferred stock	(1)		(1)		(1)		(1)

Retained earnings, end of period	3,517		2,949		3,517		2,949














Total Shareholders’ Equity	$	6,495	$	5,912	$	6,495	$	5,912

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

Table of Contents

AMEREN CORPORATION (Consolidated)

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

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

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

~~September~~June 30, ~~2017~~2023

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 is developing MISO-approved electric transmission projects, including~~business in the ~~Illinois Rivers, Spoon River,~~MISO.

Ameren’s and ~~Mark Twain projects.~~

~~Ameren’s~~Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of ~~its~~their majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren ~~Missouri and~~Missouri’s subsidiaries were created for the acquisition of renewable generation projects. Ameren Illinois ~~have~~has 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~~presentation 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~~reporting periods. Actual results could differ from those estimates. The results of operations offor 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”~~June 30, 2023, and ~~“Liabilities of discontinued operations” included on the~~ December 31, ~~2016 balance sheet have been reclassified~~2022, Ameren had unconsolidated variable interests in ~~this report~~various equity method investments, primarily to advance clean and resilient energy technologies, totaling $72 million and $68 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 of~~ ~~$52.46~~ at ~~December 31, 2016, and lattice simulations. Lattice simulations~~consolidated balance sheet. Any earnings or losses related to these investments are ~~used to estimate expected share payout based~~included in “Other Income, Net” on Ameren’s ~~total shareholder return for a~~ ~~three~~-year performance period beginning January 1, 2017, relative 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 scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of ~~1.47%, volatility 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.~~

~~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~~

Ameren Missouri and Ameren Illinois collect certain excise taxes from customers that are levied on the sale or distribution of natural gas and electricity. Excise taxes are levied on Ameren Missouri’s electric and natural gas businesses and on Ameren Illinois’ natural gas business and are recorded gross in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statement of income or theconsolidated statement of income and comprehensive income. ~~Excise taxes for electric service~~Ameren is not the primary beneficiary of 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 June 30, 2023, Ameren’s maximum exposure to loss related to these variable interests is limited to its investment of $72 million plus associated outstanding funding commitments of $16 million.

COLI

Ameren and Ameren Illinois have COLI, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of June 30, 2023, the cash surrender value of COLI at Ameren and Ameren Illinois was $255 million (December 31, 2022 – $246 million) and $122 million (December 31, 2022 – $118 million), respectively, while total borrowings against the policies were $115 million (December 31, 2022 – $110 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in ~~Illinois are levied~~“Other assets” on ~~the customer and therefore are not included in Ameren Illinois’ revenues and expenses.~~their respective balance sheets. 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~~net cash surrender value of Ameren’s COLI is ~~computed by dividing “Net Income Attributable to Ameren Common Shareholders”~~affected by the ~~weighted-average number~~investment performance of ~~common shares outstanding during the period. Earnings per diluted share is computed by dividing “Net Income Attributable to~~a separate account in which Ameren ~~Common Shareholders” by the weighted-average number~~holds a beneficial interest.

Table 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.Contents

~~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 tax~~rate, 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. In addition, in the third quarter of 2017, Ameren’s 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 to present the other components of net benefit cost in the income statement separately from the service cost component and outside of operating income. The guidance also requires that an entity only capitalize the service cost component as part of an asset, such as inventory or property, plant, and equipment, on a prospective basis. Previously, all of the net benefit cost components were eligible for capitalization.

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~~June 2023 MoPSC Electric Rate Order

In ~~March 2017,~~June 2023, the MoPSC issued an order ~~approving a unanimous stipulation and agreement~~ in Ameren Missouri’s ~~July 2016~~2022 electric service regulatory rate ~~review.~~review, approving a nonunanimous stipulation and agreement. The order resulted in ~~a $3.4 billion revenue requirement, which is a $92~~an increase of $140 million ~~increase in~~to Ameren Missouri’s annual revenue requirement for electric ~~service, compared to its prior~~retail service. The approved revenue requirement ~~established in~~is based on infrastructure investments as of December 31, 2022, and included an extension of the ~~MoPSC's April 2015 electric rate order. The new rates, base level~~depreciable lives of ~~expenses, and amortizations became effective on April 1, 2017.~~

the Sioux Energy Center’s assets from 2028 to 2030. The order ~~authorized~~did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of the FAC and ~~the regulatory tracking mechanisms~~trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy ~~standards~~standard costs that the MoPSC previously authorized in earlier electric rate ~~orders. These regulatory tracking mechanisms provide~~orders, as well as the use of an electric property tax tracker. It also includes a tracker for ~~a base level~~the utilization of ~~expense to be reflected in Ameren Missouri’s base electric rates with differences~~production and investment tax credits or proceeds from the sale of tax credits allowed under the IRA. For additional information regarding the property tax tracker and the IRA, see Note 2 – Rate and Regulatory Matters and Note 12 – Income Taxes under Part II, Item 8, in the ~~actual expenses incurred recorded as a regulatory asset or liability. Excluding cost reductions associated with reduced sales volumes,~~Form 10-K. The order increased the annualized base level of net energy costs ~~decreased~~pursuant to the FAC by ~~$54~~approximately $40 million from the base level established in the ~~MoPSC's April 2015~~MoPSC’s December 2021 electric rate order. ~~Changes in amortizations~~The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023.

Solar Generation Facilities

During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities. The following table provides information with respect to each agreement:

Boomtown

Solar Project(a)

Huck Finn

Solar Project(b)

Split Rail

Solar Project(c)

Cass County

Solar Project(c)

Vandalia

Solar Project(c)

Bowling Green

Solar Project(c)

Agreement type

Build-transfer

Development-transfer(d)

Self-build(e)

Facility size

150-MW

200-MW

300-MW

150-MW

50-MW

Status of MoPSC CCN

Approved April 2023

Approved February 2023

Filed June 2023(f)

Status of FERC approval of acquisition

Requested May 2023

Received March 2023

Expect to request by mid-2024

Not applicable

Earliest completion date(g)(h)

Fourth quarter 2024

Mid-2026

Fourth quarter 2024

Fourth quarter 2025

First quarter 2026

(a)The Boomtown Solar Project is expected to support Ameren Missouri’s transition to renewable energy generation and serve customers under the ~~other regulatory tracking mechanisms, including extending~~Renewable Solutions Program discussed below.

(b)The Huck Finn Solar Project represents approximately $0.35 billion of capital expenditures and is expected to support Ameren Missouri’s compliance with the ~~amortization period~~state of ~~certain regulatory assets, reduced expenses by $26 million from the base levels established~~Missouri’s renewable energy standard. Investments in the ~~MoPSC's April 2015 electric rate order.~~project will be eligible for recovery under the RESRAM.

~~ATXI’s Mark Twain Project~~(c)These solar projects are expected to support Ameren Missouri’s transition to renewable energy generation.

The Mark Twain project is a MISO-approved transmission line 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 (d)Ameren Missouri entered into an agreement to ~~locate nearly all of~~acquire the ~~Mark Twain~~Cass County Solar Project, which includes 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 fileddesign, land rights, and engineering, supply, and construction agreements for a ~~certificate of convenience and necessity with~~solar generation facility. Ameren Missouri will construct the facility after obtaining a CCN from the MoPSC and ~~anticipates a decision from~~acquiring the project. Acquisition of the project is expected by mid-2024.

(e)Ameren Missouri entered into engineering, supply, and construction agreements to construct these solar projects.

(f)Ameren Missouri expects decisions by the MoPSC in the first ~~half~~quarter of ~~2018. ATXI~~2024.

(g)Expected completion dates may be impacted by potential sourcing issues resulting from a United States Department of Commerce investigation of solar panel components imported from four Southeast Asian countries initiated in March 2022 and the detention of certain solar panel components sourced from China as a result of the Uyghur Forced Labor Prevention Act that became effective in June 2022.

(h)Expected completion dates are dependent on the timing of regulatory approvals, among other things.

Renewable Solutions Program

The April 2023 MoPSC order approving the CCN for the Boomtown Solar Project also approved Ameren Missouri’s Renewable Solutions Program and a tariff related to participation in the program. The program will allow certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources.

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MoPSC Staff Review of Planned Rush Island Energy Center Retirement

In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center as a result of the NSR and Clean Air Act Litigation discussed in Note 9 – Commitments and Contingencies. The MoPSC staff’s review includes potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to ~~complete~~mitigate the ~~project in December 2019; however, delays in obtaining approval from~~customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. In Ameren Missouri’s electric service regulatory rate review discussed above, the MoPSC staff recommended a lower rate base for the Rush Island Energy Center claiming imprudent actions by Ameren Missouri. While the nonunanimous stipulation and agreement approved by the June 2023 MoPSC electric rate order did not specify any rate base disallowance, it did not preclude parties to the agreement from raising issues regarding the prudence of Ameren Missouri’s actions and decisions with regard to the energy center in future proceedings. Ameren Missouri is unable to predict the results of this matter. Results of the review could ~~delay completion.~~be used in other MoPSC proceedings, which could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

MEEIA

In March 2023, Ameren Missouri filed a proposed three-year customer energy-efficiency plan with the MoPSC under the MEEIA. As a result of a nonunanimous stipulation and agreement filed with the MoPSC in August 2023 by Ameren Missouri, the MoPSC staff, and the MoOPC to extend Ameren Missouri’s MEEIA 2019 program through 2024, Ameren Missouri expects to revise the proposed three-year plan in 2024. The stipulation and agreement, which is subject to MoPSC approval, includes the establishment of a portfolio of customer energy-efficiency programs for 2024 and performance incentives that would provide Ameren Missouri an opportunity to earn revenues, including $12 million if Ameren Missouri achieves certain energy-efficiency goals in 2024. If approved, Ameren Missouri expects to invest $76 million in energy-efficiency programs in 2024. The MoPSC is under no deadline to issue an order in this proceeding.

Illinois

~~IEIMA & FEJA~~MYRP

In January 2023, Ameren ~~Illinois’~~Illinois filed an MYRP with the ICC, which was subsequently revised in July 2023, to be used in setting electric distribution service rates for 2024 through 2027. Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of the four-year period. In July 2023, the ICC staff submitted its recommendation for electric distribution service rates for 2024 through 2027 under the MYRP. The following table includes the forecasted revenue requirement, the requested and recommended ROE, the requested and recommended capital structure common equity percentage, and the forecasted average annual rate base for 2024 through 2027, as reflected in Ameren Illinois’ revised MYRP filing and the ICC staff’s filing:


Year	Forecasted Revenue Requirement (in millions)(a)	Requested/Recommended ROE(b)(c)	Requested/Recommended Capital Structure Common Equity Percentage(b)(d)	Forecasted Average Annual Rate Base (in billions)
Ameren Illinois’ July 2023 Filing:
2024	$1,291	10.5%	53.99%	$4.3
2025	$1,387	10.5%	53.97%	$4.6
2026	$1,484	10.5%	54.02%	$4.9
2027	$1,560	10.5%	54.03%	$5.2
ICC Staff’s July 2023 Filing:
2024	$1,211	8.9%	50.00%	$4.1
2025	$1,292	8.9%	50.00%	$4.4
2026	$1,371	8.9%	50.00%	$4.6
2027	$1,429	8.9%	50.00%	$4.8

(a)If an initial rate increase phase-in provision, discussed below, is approved by the ICC, it would not affect the annual revenue requirement, but would affect the timing of associated recovery from customers.

(b)ROE and capital structure common equity percentage requested in Ameren Illinois’ July 2023 filing and recommended in the ICC staff’s July 2023 filing.

(c)The ICC staff filing recommended an ROE based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points, to be updated annually for each applicable calendar year of the MYRP. An estimated ROE of 8.9% was used to calculate the forecasted revenue requirements in the ICC staff filing, which is based on the average monthly yields of the 30-year United States Treasury bonds for 2022. The ICC staff proposed that variances in the revenue requirement resulting from a change in the ROE would be excluded from the reconciliation cap discussed below.

(d)A capital structure of up to and including 50% common equity is deemed prudent and reasonable by law. A higher equity ratio requires specific ICC approval.

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Under an MYRP, the IETL permits any initial rate increase to be phased in, with at least 50% of the first annual period’s approved rate increase reflected in rates in the first annual period, with the remaining portion deferred as a regulatory asset that earns a return at the applicable WACC and is collected from customers over a period not to exceed two years beginning within one year after the second annual period’s rates are effective. Ameren Illinois’ revised MYRP filing utilizes this phase-in provision and proposes to defer 50% of the requested 2024 rate increase of $179 million as a regulatory asset to be collected from customers in 2026. Ameren Illinois recognizes revenues that have been authorized for rate recovery when amounts are expected to be collected from customers within two years from the end of an applicable year. The ICC staff’s filing does not utilize a phase-in provision. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024. Ameren Illinois cannot predict the level of any electric distribution service rate change the ICC may approve, or whether any rate change that may eventually be approved will be sufficient for Ameren Illinois to recover its costs to the extent those costs are subject to and exceed the reconciliation cap discussed below and earn a reasonable return on its investments when the rate change goes into effect.

The MYRP also allows Ameren Illinois to reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs would be excluded from the reconciliation ~~to its actual recoverable~~cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and ~~allowed return on~~amortization of certain assets. The reconciliation cap also excludes costs recovered through riders outside of base rates, such as riders for electric energy-efficiency investments, power procurement and transmission services, renewable energy credit compliance, zero emission credits, certain environmental costs, and bad debt write-offs, among others. Ameren Illinois’ existing riders will remain effective and electric distribution service revenues will continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year would incorporate Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the common equity ~~under~~ratio in such capital structure may not exceed that approved by the ICC in the MYRP. Excluding the phase-in of the initial rate increase discussed above, and subject to the reconciliation cap, if a ~~formula ratemaking process effective through 2022. This formula ratemaking framework qualifies as~~given year’s revenue amount collected from customers varies from the approved revenue requirement, an ~~alternative revenue program under GAAP. Each year, Ameren Illinois records~~adjustment would be made to electric operating revenues with an offset to a regulatory asset or ~~a regulatory~~ liability ~~and a corresponding increase or decrease~~ to ~~operating revenues for any differences between the~~reflect that year’s actual revenue requirement, ~~reflected in customer rates for that year and its estimate~~independent of actual sales volumes. The regulatory balance would then be collected from, or refunded to, customers within two years from the end of the ~~probable increase or decrease in~~applicable annual period.

Under the ~~revenue requirement expected to ultimately be~~MYRP, the ROE approved by the ICC will be subject to annual adjustments based on ~~that year's actual recoverable costs incurred~~performance metrics. In 2022, the ICC issued an order approving total ROE incentives and ~~investment return. As~~penalties of ~~September 30, 2017, Ameren Illinois had recorded regulatory assets~~24 basis points, allocated among seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of ~~$24 million~~outages, a reduction in peak loads, an increased percentage of spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to ~~reflect its 2016 revenue requirement reconciliation adjustment, which was included in~~customer requests for interconnection of distributed energy resources. These performance metrics will apply annually from 2024 through 2027 under 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 requirementMYRP, and the ~~revenue requirement reflected in customer rates, including interest.~~impact of any incentives and penalties will be excluded from the reconciliation cap described above.

2022 Electric Distribution Revenue Requirement Reconciliation Adjustment Request

In April ~~2017,~~2023, Ameren Illinois filed ~~with the ICC~~for a reconciliation adjustment to its ~~annual~~2022 electric distribution service ~~formula rate update to establish the~~ revenue requirement ~~used for 2018 rates.~~with the ICC. In July 2023, Ameren Illinois filed a revised reconciliation adjustment, requesting recovery of $125 million. The reconciliation adjustment reflects Ameren Illinois’ actual 2022 recoverable costs, year-end rate base, and capital structure, which was composed of 53.99% common equity. In June ~~2017,~~2023, the ICC staff submitted its calculation of the ~~revenue requirement,~~reconciliation adjustment, recommending recovery of $109 million, which is based on a capital structure composed of 50% common equity. An ICC decision in this proceeding is required by December 2023, and any approved adjustment would be collected from customers in 2024.

Electric Customer Energy-Efficiency Investments

In May 2023, Ameren Illinois ~~supported~~filed its annual electric energy-efficiency formula rate update to increase its rates by $27 million with the ICC. An ICC decision in this proceeding is required by December 2023, with new rates effective January 2024.

2023 Natural Gas Delivery Service Regulatory Rate Review

In January 2023, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service. In July 2023, Ameren Illinois filed a revised request seeking to increase its annual revenues by $148 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the QIP and other riders. The request is based on a 10.3% allowed ROE, a capital structure composed of 53.99% common equity, and a rate base of $2.9 billion. In an attempt to reduce regulatory lag, Ameren Illinois used a 2024 future test year in this proceeding. In July ~~2017 filing, and~~2023, the ICC staff 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. This update reflects an increase to annual revenues for natural gas delivery service of $128 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the ~~annual formula rate~~QIP and other riders. The recommendation is based on ~~2016 actual costs~~a 9.89% ROE, a capital structure composed of 50% common equity, and ~~expected net plant additions for 2017, as well as~~a rate base of $2.9 billion. Other intervenors recommended an increase to ~~include~~annual revenues ranging from

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$98 million to $106 million, which were based on varying rate base amounts, a 9.5% ROE, and a capital structure composed of 52% common equity. A decision by the ~~2016 revenue requirement reconciliation adjustment. The increases~~ICC in this proceeding is required by late November 2023, with new rates expected to be effective in early December 2023. Ameren Illinois cannot predict the ~~update filing are more than offset by a decrease for~~level of any delivery service rate change the ~~conclusion of the 2015 revenue requirement reconciliation adjustment, which~~ICC may approve, nor whether any rate change that may eventually be approved will be ~~fully collected from~~sufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on investments when the rate changes go into effect.

RTO Cost-Benefit Study

~~customers in 2017, consistent with~~In July 2022, an Illinois law prohibiting the ICC’s December 2016 annual update filing order. In November 2017, an administrative law judge issued a proposed order that was consistent with Ameren Illinois’ revised July 2017 filing. An ICC decision regarding the revenue requirementstate’s oversight of certain electric utilities’ choice of RTO membership ceased to be ~~used for customer rates~~effective. Given the change in ~~2018 is expected by December 2017.~~

~~The FEJA revised certain portions of~~law and the IEIMA, including extending the IEIMA formula ratemaking process through 2022 and clarifying that a common equity ratio of up to, and including, 50% is prudent. Beginning in 2017, the FEJA provides that Ameren Illinois will recover, within the following two years, its electric distribution revenue requirement for a given year, independent of actual sales volumes. Prior to the FEJA, Ameren Illinois’ interim period revenue recognition was volume-based, as revenues were affected by the timing of sales volumes due to seasonal rates and changes in volumeshigh prices resulting from among other things, weather and energy efficiency. This previous revenue recognition method resulted in more revenues during the third quarter and less revenues during the other quarters of each year. Beginning in 2017, in connection with the decoupling provisions of the FEJA, Ameren Illinois changed its method used to recognize interim period revenue. Ameren Illinois now recognizes revenue consistent with 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 its revenue requirement and the revenue requirement reflected in customer rates 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.

~~In June 2017, pursuant to the FEJA, Ameren Illinois filed with the ICC an energy efficiency plan for 2018 through 2021. In September 2017,~~MISO’s April 2022 capacity auction, the ICC issued an order ~~approving Ameren Illinois' implementation of FEJA electric energy efficiency savings targets and investments.~~requiring Ameren Illinois ~~plans~~ to ~~invest up to $99 million in electric energy efficiency programs per year from 2018 through 2021 that will earn~~perform a ~~return. The electric energy efficiency program investments and the return on those investments will be collected from customers through a rider and will not be included~~cost-benefit study of continued participation in the ~~IEIMA formula ratemaking process.~~

~~ATXI’s~~MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois ~~Rivers Project~~

Infiled its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a period of five to 10 years, beginning June 2024. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. Comments on the study are due by late August ~~2017, the Illinois Circuit Court for Edgar County dismissed several of ATXI’s condemnation cases~~2023. The ICC is under no obligation to issue an order related to ~~one segment in~~ the Illinois Rivers project, which has an estimated segment cost of approximately $85 million, of which $32 million was invested as of September 30, 2017. These cases had been filed in order to obtain necessary easements and rights of way to complete the segment. The court found that required notice was not given to the relevant landowners during the underlying ICC proceeding. ATXI intends to appeal this decision. ATXI plans to complete the project in 2019; however, delays associated 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. cost-benefit study.

Federal

FERC Complaint Cases

InSince 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%~~has been subject to ~~9.15%.~~customer complaint cases and has been changed by various FERC orders. In ~~September 2016,~~May 2020, the FERC issued ~~a final~~an order, ~~in the November 2013 complaint case,~~ which ~~lowered~~set the allowed base ~~return on common equity~~ROE to 10.02%, and required refunds, with interest, for the ~~15-month period of~~periods 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. In the first six months of 2017,and from late September 2016 forward. 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.paid these refunds, including interest, by March 31, 2022. 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 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,July 2020, Ameren Missouri, Ameren Illinois, and ATXI, as well as various customers, petitioned 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. Ameren is unable to predict the impactfor review of the ~~outcome~~May 2020 order, challenging certain aspects of the ~~United States Court of Appeals for the District of Columbia Circuit’s remand on the MISO FERC complaint cases at this time.~~

~~In September 2017, MISO transmission owners, including~~new ROE methodology established. The petition filed by Ameren Missouri, Ameren Illinois, and ATXI ~~filed~~challenged the refunds required for the period from September 2016 to May 2020. In August 2022, the court issued a ~~motion~~ruling that granted the customers’ petition for review, vacated the FERC’s previous MISO ROE-determining orders, and remanded the proceedings to ~~dismiss the February 2015 complaint case with~~ the FERC. The ~~MISO transmission owners maintain that the February 2015 complaint was predicated~~court elected not to rule on the ~~now superseded 12.38%~~issues raised by Ameren Missouri, Ameren Illinois, and ATXI. The currently allowed base ~~return on common equity being an unjust and unreasonable return and~~ROE of 10.02% will remain effective for customer billings, but 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 provensubject to ~~be unjust and unreasonable based on information provided, including~~refund if 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 unreasonableROE is ~~insufficient. That same approach was rejected~~changed by the ~~United States Court of Appeals for the District of Columbia Circuit, as discussed above.~~FERC in a future order. The FERC is under no deadline to issue an order ~~on this motion.~~

~~As of September 30, 2017, Ameren and Ameren Illinois had recorded current regulatory liabilities of $41 million and $24 million, respectively,~~related to reflect the expected refunds, including interest, associated with the reduced allowed returns on common equity in the initial decision in the February 2015 complaint case. Ameren Missouri does not expect that a reductionthese proceedings. A 50-basis-point change in the FERC-allowed ~~base return~~ROE would affect Ameren’s and Ameren Illinois’ annual revenue by an estimated $19 million and $13 million, respectively, based on ~~common equity would be material to its results of operations, financial position, or liquidity.~~each company’s 2023 projected rate base.

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 June 30, 2023, 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~~.$1.3 billion. The Ameren Companies were in compliance with the covenants in their Credit Agreements as of ~~September~~June 30, ~~2017.~~2023. As of ~~September~~June 30, ~~2017,~~2023, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were ~~51%~~60%, ~~47%~~51%, and ~~46%~~45% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

~~Commercial Paper~~

The following table presents commercial paper outstanding, net of issuance discounts, as of ~~September~~June 30, ~~2017,~~2023, and December 31, ~~2016:~~2022. There were no borrowings outstanding under the Credit Agreements as of June 30, 2023, or December 31, 2022.


	June 30, 2023		December 31, 2022
Ameren (parent)	$	839	$	477
Ameren Missouri	373		329
Ameren Illinois	117		264
Ameren consolidated	$	1,329	$	1,070

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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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016:~~2022:


	Ameren (parent)			Ameren Missouri			Ameren Illinois			Ameren Consolidated
2023
Average daily amount outstanding	$	595		$	343		$	230		$	1,168

Weighted-average interest rate	5.14		%	5.04		%	5.10		%	5.10		%
Peak amount outstanding during period(a)	$	841		$	592		$	450		$	1,381
Peak interest rate	5.55		%	5.55		%	5.60		%	5.60		%
2022
Average daily amount outstanding	$	374		$	271		$	57		$	702

Weighted-average interest rate	0.87		%	0.65		%	0.47		%	0.75		%
Peak amount outstanding during period(a)	$	595		$	539		$	142		$	1,101
Peak interest rate	2.05		%	2.05		%	2.05		%	2.05		%

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.

(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.

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~~six months ended ~~September~~June 30, ~~2017,~~2023, was ~~1.24%~~5.28% and ~~1.18%~~5.04%, respectively ~~(2016~~(2022 – ~~0.53%~~0.98% and ~~0.54%~~0.69%, respectively). 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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~.2022.

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

For the three and six months ended June 30, 2023, Ameren issued a total of 0.1 million and 0.2 million shares of common stock, respectively, under its DRPlus and 401(k) plan, and received proceeds of $4 million and $16 million, respectively. As of June 30, 2023, Ameren had a receivable of $7 million related to its DRPlus and 401(k) plan. In addition, in the first quarter of 2023, Ameren issued 0.5 million shares of common stock valued at $37 million upon the settlement of stock-based compensation awards.

There were no shares issued under the ATM program for the three and six months ended June 30, 2023. As of June 30, 2023, Ameren had approximately $910 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of June 30, 2023, discussed below.

The forward sale agreements outstanding as of June 30, 2023, can be settled at Ameren’s discretion on or prior to dates ranging from January 10, 2024 to February 28, 2025. On a settlement date or dates, if Ameren elects to physically settle a forward sale agreement, Ameren will issue shares of common stock to the counterparties at the then-applicable forward sale price. The initial forward sale price for the agreements ranged from $81.83 to $94.63, with an average initial forward sale price of $91.23. Each initial forward sale price is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the forward sale agreements by specified amounts related to expected dividends on shares of the common stock during the term of the forward sale agreements. If the overnight bank funding rate is less than the spread on any day, the interest rate factor will result in a reduction of the forward sale price. The forward sale agreements will be physically settled unless Ameren elects to settle in cash or to net share settle. At June 30, 2023, Ameren could have settled the forward sale agreements with physical delivery of 4.3 million shares of common stock to the respective counterparties in exchange for cash of $389 million. Alternatively, the forward sale agreements could have also been settled at June 30, 2023, with the counterparties delivering approximately $41 million of cash or approximately 0.5 million shares of common stock to Ameren. In connection with the forward sale agreements outstanding at June 30, 2023, the various counterparties, or their affiliates, borrowed from third parties and sold 4.3 million shares of common stock. The gross sales price of these shares totaled $392 million. In connection with sales in the three months ended June 30, 2023, the counterparties were deemed to have received commissions of less than $1 million. Ameren has not received any proceeds from such sales of borrowed shares. The forward sale agreements have been classified as equity transactions.

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Ameren Missouri

In ~~June 2017,~~January 2023, Ameren Missouri ~~issued $400~~and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of ~~2.95% senior secured notes,~~the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri. Ownership of the energy center was transferred to Ameren Missouri in January 2023, at which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture.

In March 2023, Ameren Missouri issued $500 million of 5.45% first mortgage bonds due March 2053, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2023. Ameren Missouri received net proceeds of $495 million, which were used for capital expenditures and to repay short-term debt.

Ameren Illinois

In May 2023, Ameren Illinois issued $500 million of 4.95% first mortgage bonds due June ~~2027,~~2033, with interest payable semiannually on June 151 and December 151 of each year, beginning in December ~~2017.~~1, 2023. Ameren ~~Missouri~~Illinois received net proceeds of ~~$396~~$495 million, which were used ~~in conjunction with other available funds,~~ to repay ~~at maturity in June 2017 $425~~$100 million principal amount of its ~~6.40% senior secured notes.~~

~~ATXI~~

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 notes0.375% first mortgage bonds that matured in June ~~2017~~2023 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).~~

ATXI may prepay at any time not less than 5% of 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.debt.

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~~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~~June 30, ~~2017,~~2023, 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.~~agreements.

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

At ~~September~~June 30, ~~2017,~~2023, none of the Ameren Companies had any material off-balance-sheet financing arrangements, other than ~~operating leases~~Ameren’s investment in variable interest entities and the multiple forward sale agreements under the ATM program relating to common stock. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.

~~entered into in the ordinary course~~

Table of ~~business, letters of credit, and Ameren parent guarantee arrangements on behalf of its subsidiaries.~~Contents

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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~:2022:


	Three Months				Six Months
	2023		2022		2023		2022
Ameren:

Allowance for equity funds used during construction	$	14	$	11	$	23	$	19
Interest income on industrial development revenue bonds	—		6		1		12


Non-service cost components of net periodic benefit income(a)	63		47		127		93
Miscellaneous income	11		5		20		9
Earnings related to equity method investments	—		1		2		4
Donations	(2)		(2)		(4)		(4)
Miscellaneous expense	(4)		(6)		(9)		(11)
Total Other Income, Net	$	82	$	62	$	160	$	122
Ameren Missouri:

Allowance for equity funds used during construction	$	8	$	6	$	12	$	10
Interest income on industrial development revenue bonds	—		6		1		12

Non-service cost components of net periodic benefit income(a)	14		14		28		28
Miscellaneous income	3		1		7		3
Donations	(1)		(1)		(2)		(2)
Miscellaneous expense	(2)		(2)		(5)		(4)
Total Other Income, Net	$	22	$	24	$	41	$	47
Ameren Illinois:

Allowance for equity funds used during construction	$	6	$	5	$	10	$	9


Non-service cost components of net periodic benefit income	31		21		62		42
Miscellaneous income	7		3		12		5
Donations	(1)		(1)		(2)		(2)
Miscellaneous expense	(2)		(3)		(4)		(5)
Total Other Income, Net	$	41	$	25	$	78	$	49

(a)For the three and six months ended June 30, 2023 the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $17 million and $34 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. The deferral was $5 million and $11 million, respectively, for the three and six months ended June 30, 2022. See Note 11 – Retirement Benefits 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, 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.

Table of Contents

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~~June 30, ~~2017,~~2023, and December 31, ~~2016,~~2022, 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 June 30, 2023, and December 31, 2022. As of June 30, 2023, these contracts extended through October 2026, October 2029, May 2032 and March 2024 for fuel oils, natural gas, power and uranium, respectively.


	Quantity (in millions)
	June 30, 2023			December 31, 2022
Commodity	Ameren Missouri	Ameren Illinois	Ameren	Ameren Missouri	Ameren Illinois	Ameren
Fuel oils (in gallons)	18	—	18	18	—	18
Natural gas (in mmbtu)	57	218	275	48	157	205
Power (in MWhs)	1	5	6	1	6	7
Uranium (pounds in thousands)	186	—	186	514	—	514

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~~June 30, ~~2017,~~2023, and December 31, ~~2016:~~

2022:

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.


		June 30, 2023						December 31, 2022
	Balance Sheet Location	Ameren Missouri		Ameren Illinois		Ameren			Ameren Missouri		Ameren Illinois		Ameren







Fuel oils	Other current assets	$	5	$	—	$	5		$	13	$	—	$	13
	Other assets	1		—		1			3		—		3


Natural gas	Other current assets	2		8		10			7		23		30
	Other assets	5		5		10			9		11		20


Power	Other current assets	15		—		15			14		2		16
	Other assets	—		—		—			—		4		4


Uranium	Other current assets	2		—		2			2		—		2
	Other assets	—		—		—			1		—		1
	Total assets	$	30	$	13	$	43		$	49	$	40	$	89


Fuel oils	Other current liabilities	$	1	$	—	$	1		$	—	$	—	$	—
	Other deferred credits and liabilities	1		—		1			—		—		—


Natural gas	Other current liabilities	8		27		35			7		20		27
	Other deferred credits and liabilities	8		19		27			2		9		11


Power	Other current liabilities	13		10		23			59		2		61
	Other deferred credits and liabilities	—		58		58			—		37		37




	Total liabilities	$	31	$	114	$	145		$	68	$	68	$	136

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

~~The Ameren Companies elect to present~~

Table of Contents

The following table provides the ~~fair value~~recognized gross derivative balances and the net amounts of ~~derivative assets and derivative liabilities~~those derivatives subject to an enforceable master netting arrangement or similar agreement as of June 30, 2023, and December 31, 2022:


			Gross Amounts Not Offset in the Balance Sheet
Commodity Contracts Eligible to be Offset	Gross Amounts Recognized in the Balance Sheet		Derivative Instruments		Cash Collateral Received/Posted(a)		Net Amount
June 30, 2023
Assets:
Ameren Missouri	$	30	$	9	$	—	$	21
Ameren Illinois	13		9		—		4
Ameren	$	43	$	18	$	—	$	25
Liabilities:
Ameren Missouri	$	31	$	9	$	12	$	10
Ameren Illinois	114		9		—		105
Ameren	$	145	$	18	$	12	$	115
December 31, 2022
Assets:
Ameren Missouri	$	49	$	9	$	—	$	40
Ameren Illinois	40		20		—		20
Ameren	$	89	$	29	$	—	$	60
Liabilities:
Ameren Missouri	$	68	$	9	$	56	$	3
Ameren Illinois	68		20		—		48
Ameren	$	136	$	29	$	56	$	51

(a)Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. ~~However, if the~~Cash collateral posted reduces gross ~~amounts recognized~~liability balances and is included in “Current collateral assets” and “Other assets” on the balance sheet ~~were netted with derivative instruments~~for Ameren and ~~cash collateral received or posted, the net amounts would not be materially different from the gross amounts at September 30, 2017,~~Ameren Missouri and ~~December 31, 2016.~~“Other current assets” and “Other assets” for Ameren Illinois.

~~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~~June 30, ~~2017,~~2023, if counterparty groups were to fail completely to perform on contracts, the Ameren Companies’ maximum exposure related to derivative assets, predominantly from financial institutions, 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 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. The following table presents, as of ~~September~~June 30, ~~2017~~,2023, 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~~require:



	Aggregate Fair Value of Derivative Liabilities(a)		Cash Collateral Posted		Potential Aggregate Amount of Additional Collateral Required(b)
Ameren Missouri	$	19	$	—	$	10
Ameren Illinois	46		—		37
Ameren	$	65	$	—	$	47

(a)Before consideration of master netting arrangements or similar agreements.

(b)As collateral ~~required is the net liability position allowed under the~~requirements with certain counterparties are based on master netting arrangements or similar agreements, ~~assuming (1)~~ the ~~credit risk-related contingent features underlying these arrangements were triggered on~~ ~~September 30, 2017, and (2) those counterparties with rights~~aggregate amount of additional collateral required to ~~do so requested collateral.~~be posted is determined after consideration of the effects of such arrangements.

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~~levels and valuation techniques.

Table of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

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

Contents

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~~six months ended ~~September~~June 30, ~~2017~~2023 or ~~2016.~~2022. At ~~September~~June 30, ~~2017,~~2023, and December 31, ~~2016,~~2022, 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~~June 30, ~~2017~~:

2023, and December 31, 2022:

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.~~


		June 30, 2023									December 31, 2022
		Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets:
Ameren Missouri
	Derivative assets – commodity contracts:
	Fuel oils	$	6	$	—	$	—	$	6		$	16	$	—	$	—	$	16
	Natural gas	—		7		—		7			1		15		—		16
	Power	—		—		15		15			—		—		14		14
	Uranium	—		—		2		2			—		—		3		3
	Total derivative assets – commodity contracts	$	6	$	7	$	17	$	30		$	17	$	15	$	17	$	49
	Nuclear decommissioning trust fund:

	Equity securities:
	U.S. large capitalization	$	727	$	—	$	—	$	727		$	618	$	—	$	—	$	618
	Debt securities:
	U.S. Treasury and agency securities	—		147		—		147			—		137		—		137
	Corporate bonds	—		126		—		126			—		122		—		122


	Other	—		69		—		69			—		70		—		70
	Total nuclear decommissioning trust fund	$	727	$	342	$	—	$	1,069	(a)	$	618	$	329	$	—	$	947	(a)
	Total Ameren Missouri	$	733	$	349	$	17	$	1,099		$	635	$	344	$	17	$	996
Ameren Illinois
	Derivative assets – commodity contracts:
	Natural gas	$	—	$	9	$	4	$	13		$	1	$	28	$	5	$	34
	Power	—		—		—		—			—		—		6		6
	Total Ameren Illinois	$	—	$	9	$	4	$	13		$	1	$	28	$	11	$	40
Ameren
	Derivative assets – commodity contracts(b)	$	6	$	16	$	21	$	43		$	18	$	43	$	28	$	89
	Nuclear decommissioning trust fund(c)	727		342		—		1,069		(a)	618		329		—		947		(a)
	Total Ameren	$	733	$	358	$	21	$	1,112		$	636	$	372	$	28	$	1,036
Liabilities:
Ameren Missouri
	Derivative liabilities – commodity contracts:
	Fuel oils	$	2	$	—	$	—	$	2		$	—	$	—	$	—	$	—
	Natural gas	—		13		3		16			—		6		3		9
	Power	12		—		1		13			57		—		2		59

	Total Ameren Missouri	$	14	$	13	$	4	$	31		$	57	$	6	$	5	$	68
Ameren Illinois
	Derivative liabilities – commodity contracts:
	Natural gas	$	1	$	38	$	7	$	46		$	—	$	19	$	10	$	29
	Power	—		—		68		68			—		—		39		39
	Total Ameren Illinois	$	1	$	38	$	75	$	114		$	—	$	19	$	49	$	68
Ameren
	Derivative liabilities – commodity contracts(b)	$	15	$	51	$	79	$	145		$	57	$	25	$	54	$	136

(a)Balance excludes $6 million and $11 million of cash and cash equivalents, receivables, payables, and accrued income, net, for June 30, 2023, and December 31, 2022, 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.

Table of Contents

Level 3 fuel oils, natural gas, and uranium 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 and six months ended June 30, 2023 and 2022:


	2023						2022
	Ameren Missouri		Ameren Illinois		Ameren			Ameren Missouri		Ameren Illinois		Ameren
For the three months ended June 30:
Beginning balance at April 1	$	5	$	(52)	$	(47)		$	(53)	$	(74)	$	(127)
Realized and unrealized gains/(losses) included in regulatory assets/liabilities	14		(20)		(6)			(5)		32		27


Settlements	(5)		4		(1)			22		(2)		20


Ending balance at June 30	$	14	$	(68)	$	(54)		$	(36)	$	(44)	$	(80)
Change in unrealized gains/(losses) related to assets/liabilities held at June 30	$	14	$	(20)	$	(6)		$	2	$	30	$	32
For the six months ended June 30:
Beginning balance at January 1	$	12	$	(33)	$	(21)		$	(15)	$	(117)	$	(132)
Realized and unrealized gains/(losses) included in regulatory assets/liabilities	8		(41)		(33)			(45)		74		29


Settlements	(6)		6		—			24		(1)		23


Ending balance at June 30	$	14	$	(68)	$	(54)		$	(36)	$	(44)	$	(80)
Change in unrealized gains/(losses) related to assets/liabilities held at June 30	$	14	$	(35)	$	(21)		$	(36)	$	72	$	36

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 June 30, 2023, and December 31, 2022:


			Fair Value						Weighted Average(b)
	Commodity		Assets		Liabilities	Valuation Technique(s)	Unobservable Input(a)	Range
2023	Power(c)	$	15	$	(69)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)	32 – 67	43

							Nodal basis ($/MWh)	(9) – (1)	(5)


2022	Power(d)	$	20	$	(41)	Discounted cash flow	Average forward peak and off-peak pricing – forwards/swaps ($/MWh)	38 – 89	51

							Nodal basis ($/MWh)	(10) – (1)	(4)


							Trend rate (%)	0 – 1	0

(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 use visible forward prices adjusted for nodal-to-hub basis differentials.

(d)Valuations through 2031 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2031 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.

Table of Contents

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 June 30, 2023, and ~~uranium~~December 31, 2022:


	Carrying Amount			Fair Value
				Level 1		Level 2		Level 3			Total
	June 30, 2023
Ameren:
Cash, cash equivalents, and restricted cash	$	246		$	246	$	—	$	—		$	246

Short-term debt	1,329			—		1,329		—			1,329
Long-term debt (including current portion)	14,678		(a)	—		12,745		453		(b)	13,198
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	8		$	8	$	—	$	—		$	8


Short-term debt	373			—		373		—			373

Long-term debt (including current portion)	6,341		(a)	—		5,688		—			5,688
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	229		$	229	$	—	$	—		$	229

Short-term debt	117			—		117		—			117

Long-term debt (including current portion)	5,232		(a)	—		4,735		—			4,735
	December 31, 2022
Ameren:
Cash, cash equivalents, and restricted cash	$	216		$	216	$	—	$	—		$	216
Investment in industrial development revenue bonds(c)	240			—		240		—			240
Short-term debt	1,070			—		1,070		—			1,070
Long-term debt (including current portion)(c)	14,025		(a)	—		11,989		464		(b)	12,453
Ameren Missouri:
Cash, cash equivalents, and restricted cash	$	13		$	13	$	—	$	—		$	13

Investment in industrial development revenue bonds(c)	240			—		240		—			240
Short-term debt	329			—		329		—			329
Long-term debt (including current portion)(c)	6,086		(a)	—		5,365		—			5,365
Ameren Illinois:
Cash, cash equivalents, and restricted cash	$	191		$	191	$	—	$	—		$	191
Short-term debt	264			—		264		—			264

Long-term debt (including current portion)	4,835		(a)	—		4,320		—			4,320

(a)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~~$105 million, $45 million, and ~~liabilities classified~~$47 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as ~~Level 3 in~~of June 30, 2023. Included unamortized debt issuance costs, which were excluded from the fair value ~~hierarchy:~~measurement, of $99 million, $41 million, and $44 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2022.

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~~(b)The Level 3 ~~represent either (1) existing assets~~fair value amount consists of ATXI’s senior unsecured notes.

(c)Ameren and ~~liabilities~~Ameren Missouri had an investment in industrial development revenue bonds, classified as held-to-maturity, that were ~~previously categorized as a higher level, but were recategorized to Level 3 because the inputs~~equal to the ~~model became unobservable during~~finance obligation for the ~~period or (2) existing assets and liabilities that were previously classified as Level 3, but were recategorized to a higher level because~~Audrain CT energy center. As of December 31, 2022, 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 of the ~~short-term nature of these instruments. They are considered to be Level 1~~investment in industrial development revenue bonds and the finance obligation approximated 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.value.

~~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.

Support Services Agreements

Ameren Missouri and Ameren Illinois had long-term receivables included in “Other assets” from Ameren Services of $33 million and $35 million, respectively, as of June 30, 2023, and $41 million and $43 million, respectively, as of December 31, 2022, related to Ameren Services’ allocated portion of Ameren’s pension and postretirement benefit plans.

Tax Allocation Agreement

See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K ~~and~~for a discussion of the ~~money pool arrangements discussed in Note 3 – Short-term Debt and Liquidity of this report.~~

~~Electric Power Supply Agreement~~

~~In April 2017, Ameren Illinois conducted a procurement event, administered by~~tax allocation agreement. The following table presents the ~~IPA,~~affiliate balances related to ~~purchase energy products. Ameren Missouri was among the winning suppliers in this event. As a result, in April 2017,~~income taxes for Ameren Missouri and Ameren Illinois ~~entered into an energy product agreement by which Ameren Missouri agreed to sell,~~as of June 30, 2023, and ~~Ameren Illinois agreed to purchase, 85,600 megawatthours at an average price~~December 31, 2022:

Table of ~~$34 per megawatthour during~~Contents


	June 30, 2023				December 31, 2022
	Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Income taxes payable to parent(a)	$	—	$	28	$	—	$	50
Income taxes receivable from parent(b)	38		—		39		—

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

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

Effects of ~~March 2019 through May 2020.~~Related-party Transactions on the Statement of Income

The following table presents the impact on Ameren Missouri and Ameren Illinois of ~~related party~~related-party transactions for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~:2022:


				Three Months				Six Months
Agreement	Income Statement Line Item			Ameren Missouri		Ameren Illinois		Ameren Missouri		Ameren Illinois
Ameren Missouri power supply	Operating Revenues	2023	$	(b)	$	(a)	$	(b)	$	(a)
agreements with Ameren Illinois		2022		1		(a)		5		(a)
Ameren Missouri and Ameren Illinois	Operating Revenues	2023	$	8	$	(b)	$	18	$	(b)
rent and facility services		2022		6		(b)		12		(b)
Ameren Missouri and Ameren Illinois miscellaneous	Operating Revenues	2023	$	(b)	$	(b)	$	(b)	$	(b)
support services		2022		(b)		(b)		(b)		1
Total Operating Revenues		2023	$	8	$	(b)	$	18	$	(b)
		2022		7		(b)		17		1
Ameren Illinois power supply	Purchased Power	2023	$	(a)	$	(b)	$	(a)	$	(b)
agreements with Ameren Missouri		2022		(a)		1		(a)		5
Ameren Missouri and Ameren Illinois	Purchased Power	2023	$	1	$	(b)	$	1	$	(b)
transmission services from ATXI		2022		(b)		(b)		(b)		(b)
Total Purchased Power		2023	$	1	$	(b)	$	1	$	(b)
		2022		(b)		1		(b)		5
Ameren Missouri and Ameren Illinois	Other Operations and Maintenance	2023	$	(b)	$	(b)	$	(b)	$	2
rent and facility services		2022		(b)		(b)		(b)		1
Ameren Services support services	Other Operations and Maintenance	2023	$	35	$	33	$	70	$	68
agreement		2022		33		32		71		67
Total Other Operations and		2023	$	35	$	33	$	70	$	70
Maintenance		2022		33		32		71		68
Money pool borrowings (advances)	(Interest Charges)/Other Income, Net	2023	$	(b)	$	(b)	$	(b)	$	(b)
		2022		(b)		(b)		(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~~Environmental Matters

~~In April~~Our electric generation, transmission, 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 powerdistribution and natural gas ~~for distribution. The table below presents our estimated minimum fuel, purchased power,~~distribution and ~~other commitments for fuel at September 30, 2017. Ameren’s~~storage operations must comply with a variety of statutes and ~~Ameren Illinois’ purchased power commitments include~~regulations relating to the ~~Ameren Illinois agreements entered into as part~~protection of the ~~IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design~~environment and ~~construction,~~human health 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 environmental laws and regulations enforced~~safety including permitting programs implemented by federal, state, and local authorities. The development and operation of electric generation, transmission, and distribution facilities and natural gas storage, transmission, and distribution facilities can trigger compliance obligations with respect to diverseSuch environmental laws address air emissions; discharges to water bodies; the storage, handling and ~~regulations. These laws and regulations address emissions, discharges into water, water usage, impacts to air, land, and water, and chemical~~disposal of hazardous 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 energy-

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related 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 requirements of environmental laws.

~~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 from~~under the Clean Air Act 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_Xx, mercury, toxic metals and acid ~~gases.~~gases, and CO2 emissions. Regulations implementing the Clean Water Act govern both intake and discharges ~~from power plants are regulated under~~of water, as well as 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, capital expenditures associated with these modifications 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 the closure of 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 compliance with 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.

Additionally, Ameren ~~Missouri's current plan for compliance with existing air emission regulations includes burning ultra-low-sulfur coal~~Missouri’s wind generation facilities may be subject to operating restrictions to limit the impact on protected species. From April through October, since 2021, Ameren Missouri’s High Prairie Renewable Energy Center curtailed nighttime operations to limit impacts on protected species. Seasonal nighttime curtailment began again in April 2023 as the critical biological season resumed, but the extent and ~~installing new~~duration of the curtailment is unknown at this time as assessment of mitigation technologies is ongoing. Ameren Missouri does not anticipate these operating curtailments to have a material impact on its results of operations, financial position, or ~~optimizing existing pollution control equipment.~~ liquidity.

Ameren and Ameren Missouri estimate that they will need to make capital expenditures of ~~$425~~$90 million to ~~$525~~$120 million ~~in the aggregate~~ from ~~2017~~2023 through ~~2021~~2027 in order to comply with existing environmental regulations. Additional capital expenditures for environmental controls beyond ~~2021~~2027 could be required. This estimate of capital expenditures includes ~~expenditures~~surface impoundment closure and corrective action measures required ~~for~~by the CCR ~~regulations, Clean Water Act rules applicable~~Rule and potential modifications to cooling water intake structures at existing power plants ~~and effluent limitation guidelines applicable to steam electric generating units,~~under Clean Water Act rules, all of which are discussed below. ~~The EPA has proposed~~In addition to ~~repeal~~planned retirements of coal-fired energy centers as set forth in the 2022 Change to the 2020 IRP filed with the MoPSC in June 2022 and as noted in the NSR and Clean ~~Power Plan, which would have regulated CO~~₂Air Act litigation discussed below and Illinois emissions ~~from power plants. The above capital expenditure amounts exclude estimated impacts from~~standards discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of the ~~Clean Power Plan.~~Form 10-K, 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 by state regulators and the EPA, ~~will substantively revise~~revisions to regulatory obligations, ~~the precise~~and varying 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~~periodically amends and revises its regulations and ~~rulemaking activities, including the effluent limitation~~proposes amendments to regulations and guidelines, ~~and the CCR 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 the 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 phase~~In April 2022, the EPA proposed plans for additional NOx emission reductions from power plants in Missouri, Illinois, and other states through revisions to the CSAPR. In January 2023, the EPA issued its final disapproval of Missouri’s proposed state implementation plan for addressing the transport of ozone under the Good Neighbor Plan of the Clean Air Act. The disapproval of the state plan allows the EPA to implement revisions to the CSAPR ~~emission reduction requirements became effective in 2015. The second phase of emission reduction~~through a federal implementation plan. In March 2023, the EPA announced federal implementation plan requirements, which were revised by the EPA in 2016, became effective in 2017; additional emission reduction requirements may apply in subsequent years. To achieve compliance with the CSAPR, Ameren Missouri burns ultra-low-sulfur coal, operates two scrubbers at its Sioux energy center, and optimizes other existing pollution control equipment. Ameren Missouri did not make additional capital investments to comply with the 2017 CSAPR requirements. However, Ameren Missouri expects to incur additional costs to lower its emissions at one or more of its energy centers to comply with the CSAPR in future years. These higher costs are expected to be recovered from customers through the FAC or higher base rates.

CO₂ ~~Emissions Standards~~

~~In 2015, the EPA issued the 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 the Clean Power Plan and will seek public comment as~~subsequently published to the ~~scope~~Federal Register in June 2023, reducing the amount of ~~future regulations~~

NOx allowances available for state budgets and imposing NOx emission limits on electric generating units for Missouri, Illinois, and other states under the Good Neighbor Plan of the Clean Air Act. In April 2023, the Missouri Attorney General and Ameren Missouri separately filed lawsuits in the United States Court of Appeals for the Eighth Circuit challenging the EPA’s disapproval of the Missouri state plan and sought a stay of the EPA’s disapproval of the Missouri state plan. The United States Court of Appeals for the ~~District~~Eighth Circuit in May 2023 granted those stay motions thereby preventing the EPA from imposing the federal implementation plan until the court of ~~Columbia Circuit~~appeals issues a ruling, which is expected in 2024. Ameren Missouri has ~~stayed~~complied with the current CSAPR requirements by minimizing emissions through the use of low-sulfur coal, operation of two scrubbers at its Sioux Energy Center, and optimization of other existing NOx air pollution control equipment. Restrictions on the use of state budget NOx allowances for compliance with NOx emission limits could result in additional controls being required on Ameren Missouri’s generating units and/or the reduction of operations. Any additional costs for compliance are expected to be recovered from customers, subject to MoPSC prudence review, through the FAC or higher base rates.

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CO2 Emissions Standards

In June 2022, the United States Supreme Court issued its decision in West Virginia v. EPA, clarifying that there are limits on how the EPA may regulate greenhouse gases absent further ~~action pending~~direction from the United States Congress. The court concluded that the EPA’s ~~administrative review.~~

Weproposed rules were designed to shift generation from fossil-fuel-fired power plants to renewable energy facilities, which was improper absent specific congressional authorization. In May 2023, the EPA issued a proposed rule that would set CO2 emission standards for new and existing fossil-fuel-fired power plants based on the adoption of carbon capture technology, natural gas co-firing, and co-firing hydrogen fuel to reduce emissions. If the proposed rule were adopted, the affected fossil-fuel-fired power plants would be required to comply with the rule through a phased-in approach or retire. Capacity restrictions for coal-fired units could apply as early as 2030. Larger natural gas-fired power plants would be required to co-fire with hydrogen by 2032, with additional requirements by 2038. The EPA expects to issue a final rule in 2024. Legal challenges to the final rule, if adopted, are expected. Ameren Missouri cannot predict the ~~outcome~~results of any such challenges. Ameren Missouri is currently reviewing the ~~EPA’s future rulemaking,~~proposed rule and cannot predict the ~~outcome~~impact of ~~legal challenges relating to either~~any such regulations on the ~~repeal of the Clean Power Plan or such future rulemakings, nor the resulting impact on our~~ results of operations, financial position, and liquidity of Ameren or ~~liquidity.~~Ameren Missouri.

NSR and Clean Air Act Litigation

In January 2011, the United States 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 Rush Island coal-fired energy center~~performed in 2007 and 2010 ~~Ameren Missouri~~at the coal-fired Rush Island Energy Center 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 that the projects violated provisions of the Clean Air Act and Missouri law. The case will now proceed to the second phase to determine the actions required to remedy the violations found in the liability phase of the litigation. The EPA previously withdrew all claims for penalties and fines. No date has been set by the district court for a trial on the remedy phase of the litigation. At the conclusion of both phases of the litigation,against Ameren Missouri ~~intends~~and, in September 2019, entered a remedy order that required Ameren Missouri to install a flue gas desulfurization system at the Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. Following an appeal ~~the liability ruling to~~from Ameren Missouri in August 2021, the United States Court of Appeals for the Eighth ~~Circuit.~~Circuit affirmed the liability ruling and the district court’s remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In November 2021, the court of appeals issued an order denying requests for re-consideration sought by both Ameren Missouri and the United States Department of Justice.

Based on its assessment of available legal, operational, and regulatory alternatives, Ameren Missouri filed a motion in December 2021, with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The March 30, 2024 compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. In 2022, in response to an Ameren Missouri request for a final, binding reliability assessment, the MISO designated the Rush Island Energy Center as a system support resource and concluded that certain mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation for the Rush Island Energy Center through August 2024, and in July 2023, an agreement between Ameren Missouri and the MISO was filed with the FERC for approval that details the manner of continued operation for the Rush Island Energy Center that results in operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. The FERC is under no deadline to issue an order. The transmission upgrade projects have been approved by the MISO, and construction activities necessary to complete the upgrades are underway. Ameren Missouri expects to complete the last of the upgrades by mid-2025. In August 2023, Ameren Missouri requested the district court to extend the March 30, 2024 compliance date to October 15, 2024, at which point Ameren Missouri proposes to retire the Rush Island Energy Center. In addition, in October 2022, the FERC established hearing and settlement procedures in response to an August 2022 request from Ameren Missouri for recovery of non-energy costs under the related MISO tariff. In May 2023, a settlement agreement between Ameren Missouri and certain intervenors in the non-energy costs proceeding at the FERC, which provides for recovery of substantially all of Ameren Missouri’s requested non-energy costs through August 2023, was filed with the FERC for approval. The FERC is under no deadline to issue an order. Revenues and costs under the MISO tariff are included in the FAC. The district court has the authority to determine the retirement date and operating parameters for the Rush Island Energy Center and is not bound by the MISO determination of the Rush Island Energy Center as a system support resource or the FERC’s approval. The district court is under no deadline to issue a ruling modifying the remedy order. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review the planned accelerated retirement of the Rush Island Energy Center. See Note 2 – Rate and Regulatory Matters for additional information.

In connection with the planned accelerated retirement of the Rush Island Energy Center, Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to Missouri’s securitization statute. As of June 30, 2023, the Rush Island Energy Center had a net plant balance of approximately $550 million included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net” and a rate base of approximately $0.5 billion. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information regarding plant to be abandoned, net.

Ameren Missouri is unable to predict the ultimate resolution of this ~~matter~~matter; however, such resolution 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~~

Table of this matter could result in increased capital expenditures for the installation of pollution control equipment, as well as increased operations and maintenance expenses. We are unable to predict the ultimate resolution of this matter or the costs that might be incurred.Contents

Clean Water Act

~~In 2014,~~The EPA’s regulations implementing Section 316(b) of the ~~EPA issued its final rule applicable~~Clean Water Act require 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~~power plant’s water discharge ~~permit, which will occur between 2018~~permit. Permits for Ameren Missouri’s coal-fired and ~~2023.~~nuclear energy centers have been issued or are in the process of renewal.

~~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~~prohibit effluent discharges of certain waste streams, and ~~imposes~~impose more stringent limitations on certain water discharges from power ~~plants. In September 2017, the EPA published a rule that postponed the compliance dates~~plants 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~~2025. To comply with these 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~~wastewater treatment facilities at ~~Ameren Missouri’s~~its coal-fired energy ~~centers, and if such investments are not recovered on a timely basis in electric rates charged to Ameren Missouri’s customers.~~centers.

~~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 has resulted in the closure of surface impoundments at Ameren Missouri’s energy centers. ~~These regulations affect CCR disposal and handling costs at~~ Ameren ~~Missouri's energy centers. They require closure of impoundments if performance criteria relating~~Missouri plans to ~~groundwater impacts and location restrictions are not achieved. In September 2017,~~substantially complete the ~~EPA granted petitions filed on behalf of coal-fired electricity generators in which the EPA agreed to reconsider provisions~~closures of the remaining surface impoundments at its Sioux Energy Center and retired Meramec Energy Center as required by the CCR ~~rules.~~Rule by the end of 2024. Ameren Missouri’s CCR management compliance plan includes installation of groundwater monitoring equipment and groundwater treatment facilities. Ameren and Ameren ~~Missouri’s~~Missouri have AROs of $45 million recorded on their respective balance sheets as of June 30, 2023, associated with CCR storage facilities reflect the regulations issued in 2015. Ameren plans to close these CCR storage facilities between 2018 and 2024. Ameren Missouri's capital expenditure plan includes the cost of constructing landfills as part of its environmental compliance plan.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~~June 30, ~~2017,~~2023, 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 by

at the remaining sites in 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 ~~review~~prudence reviews by the ICC. As of ~~September~~June 30, ~~2017,~~2023, Ameren Illinois estimated the remaining obligation related to these former MGP sites at ~~$184~~$61 million to ~~$255~~$112 million. Ameren and Ameren Illinois recorded a liability of ~~$184~~$61 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate. About half of the remaining liability recorded relates to remediation activities that are expected to be completed after 2023.

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, including additional or more stringent cleanup standards, or will affect our results of operations, financial position, or liquidity.

~~Ameren Missouri Municipal Taxes~~

~~The cities~~

Table 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.Contents

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 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 scheduled refueling and maintenance outage. A change of fuel suppliers or a change in the type of fuel assembly design that is currently licensed for use at the Callaway energy center could take an estimated three years of analysis and NRC licensing efforts to implement.Missouri’s AROs.

Insurance

The following table presents insurance coverage at Ameren Missouri’s Callaway ~~energy center~~Energy Center at ~~September~~June 30, ~~2017.~~2023:


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, 2023	$	450		$	—
Pool participation	(a)	13,210		(a)	138		(b)
		$	13,660	(c)	$	138
Property damage:
NEIL and EMANI	April 1, 2023	$	3,200	(d)	$	28	(e)
Accidental outage:
NEIL	April 1, 2023	$	490	(f)	$	9	(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 changes in the number of licensed power reactors.

(d)NEIL provides $2.7 billion in property ~~coverage~~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 ~~nuclear liability coverage renewal dates~~accumulated funds from NEIL.

(f)Accidental outage insurance provides for lost sales 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 ~~April 1 and January 1, respectively, of each year. Both coverages were renewed in 2017.~~

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

Public liability and nuclear worker liability:
American Nuclear Insurers $ 450
   $ —

Pool participation 12,986
^(a)
127
^(b)
$ 13,436
^(c)
$ 127

Property damage:
NEIL and EMANI $ 3,200
^(d)
$ 29
^(e)
Replacement power:
NEIL $ 490
^(f)
$ 7
^(e)


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


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


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


~~(d)~~	NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage 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.

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~~insurance 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.

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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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~:2022:


	Pension Benefits								Postretirement Benefits
	Three Months				Six Months				Three Months				Six Months
	2023		2022		2023		2022		2023		2022		2023		2022
Service cost(a)	$	23	$	31	$	46	$	64	$	3	$	5	$	6	$	10
Non-service cost components:
Interest cost	56		41		111		81		12		9		23		17
Expected return on plan assets(b)	(84)		(80)		(167)		(160)		(23)		(22)		(46)		(43)
Amortization of(b):

Prior service benefit	—		—		—		—		(1)		(1)		(2)		(2)
Actuarial loss (gain)	(28)		6		(57)		12		(12)		(5)		(23)		(9)
Total non-service cost components(c)	$	(56)	$	(33)	$	(113)	$	(67)	$	(24)	$	(19)	$	(48)	$	(37)

Net periodic benefit income(d)	$	(33)	$	(2)	$	(67)	$	(3)	$	(21)	$	(14)	$	(42)	$	(27)

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)Prior service benefit is amortized on a straight-line basis over the average future service of active participants benefiting under a plan amendment. Net actuarial gains or losses related to the net benefit obligation subject to amortization are amortized on a straight-line basis over 10 years. The difference between the actual and expected return on plan assets is amortized over 4 years.

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

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

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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~:2022:


	Pension Benefits								Postretirement Benefits
	Three Months				Six Months				Three Months				Six Months
	2023		2022		2023		2022		2023		2022		2023		2022
Ameren Missouri(a)	$	(17)	$	(1)	$	(35)	$	(2)	$	(7)	$	(4)	$	(15)	$	(7)
Ameren Illinois	(13)		—		(27)		1		(14)		(10)		(27)		(20)
Other	(3)		(1)		(5)		(2)		—		—		—		—
Ameren(a)	$	(33)	$	(2)	$	(67)	$	(3)	$	(21)	$	(14)	$	(42)	$	(27)

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

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.~~

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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 and six months ended June 30, 2023 and 2022:


	Ameren				Ameren Missouri				Ameren Illinois
	2023		2022		2023		2022		2023		2022
Three Months
Federal statutory corporate income tax rate	21	%	21	%	21	%	21	%	21	%	21	%
Increases (decreases) from:
Amortization of deferred investment tax credit	—		—		—		(1)		—		—
Amortization of excess deferred taxes(a)	(7)		(8)		(15)		(15)		(2)		(2)
Depreciation differences	—		—		—		—		(1)		(1)
Other	—		1		—		—		—		—
Renewable and other tax credits(b)	(5)		(4)		(10)		(10)		—		—
State tax	5		5		3		3		7		7


Effective income tax rate	14	%	15	%	(1)	%	(2)	%	25	%	25	%
Six Months
Federal statutory corporate income tax rate	21	%	21	%	21	%	21	%	21	%	21	%
Increases (decreases) from:
Amortization of deferred investment tax credit	—		—		—		(1)		—		—
Amortization of excess deferred taxes(a)	(8)		(8)		(15)		(16)		(2)		(2)
Depreciation differences	—		—		—		—		(1)		—
Renewable and other tax credits(b)	(4)		(5)		(10)		(10)		—		—
State tax	5		5		3		3		7		7

Other permanent items	(1)		—		—		—		—		—
Effective income tax rate	13	%	13	%	(1)	%	(3)	%	25	%	26	%

(a)Reflects the amortization of amounts resulting from the revaluation of deferred income taxes subject to regulatory ratemaking, which are being refunded to customers. Deferred income taxes are revalued when federal or state income tax rates change, and the offset to the revaluation of deferred income taxes subject to regulatory ratemaking is recorded to a regulatory asset or liability.

(b)The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM.

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 at June 30, 2023, and December 31, 2022:


	June 30, 2023						December 31, 2022
	Ameren		Ameren Missouri		Ameren Illinois		Ameren		Ameren Missouri		Ameren Illinois
“Cash and cash equivalents”	$	7	$	—	$	—	$	10	$	—	$	—

Restricted cash included in “Other current assets”	13		5		6		13		5		6
Restricted cash included in “Other assets”	223		—		223		185		—		185
Restricted cash included in “Nuclear decommissioning trust fund”	3		3		—		8		8		—
Total cash, cash equivalents, and restricted cash	$	246	$	8	$	229	$	216	$	13	$	191

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. 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.

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 June 30, 2023, and December 31, 2022, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $37 million and $31 million, respectively.

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The following table provides a reconciliation of the beginning and ending amount of the allowance for doubtful accounts for the three and six months ended June 30, 2023 and 2022:


	Three Months				Six Months
	2023		2022		2023		2022
Ameren:
Beginning of period	$	34	$	28	$	31	$	29
Bad debt expense	13		6		23		9
Charged to other accounts(a)	1		1		1		2
Net write-offs	(9)		(5)		(16)		(10)
End of period	$	39	$	30	$	39	$	30
Ameren Missouri:
Beginning of period	$	12	$	11	$	13	$	13
Bad debt expense	2		2		4		3
Net write-offs	(2)		(1)		(5)		(4)
End of period	$	12	$	12	$	12	$	12
Ameren Illinois:(b)
Beginning of period	$	22	$	17	$	18	$	16
Bad debt expense	11		4		19		6
Charged to other accounts(a)	1		1		1		2
Net write-offs	(7)		(4)		(11)		(6)
End of period	$	27	$	18	$	27	$	18

(a)Amounts associated with the allowance for doubtful accounts related to receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.

(b)Ameren Illinois has riders 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. The table above does not include the impact related to the riders.

As of June 30, 2023, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 26%, 15%, and 35%, or $133 million, $28 million, and $106 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ customer trade receivables before allowance for doubtful accounts, respectively. In comparison, as of June 30, 2022, these percentages were 19%, 14%, and 24%, or $107 million, $29 million, and $78 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.

Supplemental Cash Flow Information

The following table provides noncash financing and investing activity excluded from the statements of cash flows for the six months ended June 30, 2023 and 2022:


	June 30, 2023						June 30, 2022
	Ameren		Ameren Missouri				Ameren Illinois	Ameren		Ameren Missouri		Ameren Illinois
Investing:
Accrued capital expenditures	$	325	$	132	$	173		$	408	$	204	$	193

Net realized and unrealized gain/(loss) – nuclear decommissioning trust fund	105		105		—			(211)		(211)		—
Return of investment in industrial development revenue bonds(a)	240		240		—			—		—		—
Financing:
Issuance of common stock for stock-based compensation	$	37	$	—	$	—		$	31	$	—	$	—
Issuance of common stock under the DRPlus	7		—		—			8		—		—
Termination of a financing obligation(a)	240		240		—			—		—		—

(a)In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri.

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Asset Retirement Obligations

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the six months ended June 30, 2023:


	Ameren Missouri			Ameren Illinois			Ameren
Balance at December 31, 2022	$	782	(a)	$	4	(b)	$	786	(a)

Liabilities settled	(4)			—			(4)
Accretion	16		(c)	—			16		(c)

Balance at June 30, 2023	$	794	(a)	$	4	(b)	$	798	(a)

(a)Balance included $23 million in “Other current liabilities” on the balance sheet as of both June 30, 2023, and December 31, 2022.

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

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

Stock-based Compensation

In the first quarter of 2023, Ameren granted 265,422 performance share units with a grant date fair value of $24 million and 116,701 restricted share units with a grant date fair value of $10 million. Awards vest approximately 3 years 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 (227,494 performance share units) or clean energy transition targets (37,928 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 six months ended June 30, 2023 and 2022, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $6 million and $5 million, respectively.

Deferred Compensation

At June 30, 2023, and December 31, 2022, the present value of benefits to be paid for deferred compensation obligations was $85 million and $87 million, respectively, which was primarily reflected in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet.

Operating Revenues

As of June 30, 2023 and 2022, 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 and six months ended June 30, 2023 and 2022:


	Three Months				Six Months
	2023		2022		2023		2022
Ameren Missouri	$	39	$	39	$	73	$	73
Ameren Illinois	26		28		63		73
Ameren	$	65	$	67	$	136	$	146

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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 and six months ended June 30, 2023 and 2022:


	Three Months		Six Months
	2023	2022	2023	2022


Weighted-average Common Shares Outstanding – Basic	262.6	258.2	262.4	258.0
Assumed settlement of performance share units and restricted stock units	0.6	1.0	0.8	1.1
Dilutive effect of forward sale agreements	—	0.2	—	0.1
Weighted-average Common Shares Outstanding – Diluted(a)	263.2	259.4	263.2	259.2

(a)There was an immaterial number of anti-dilutive performance share units excluded from the earnings per diluted share calculations for the three and six months ended June 30, 2023 and 2022. The outstanding forward sale agreements as of June 30, 2023, were anti-dilutive for the three and six months ended June 30, 2023, and excluded from the earnings per diluted share calculation as calculated using the treasury stock method.

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 attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~.2022. 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 2023:
External revenues	$	933	$	540	$	152	$	135		$	—	$	—	$	1,760
Intersegment revenues	8		—		—		26			—		(34)		—
Net income (loss) attributable to Ameren common shareholders	102		66		11		72		(a)	(14)		—		237
Capital expenditures	433		180		90		197			2		(11)		891
Three Months 2022:
External revenues	$	912	$	504	$	184	$	126		$	—	$	—	$	1,726
Intersegment revenues	7		—		—		24			—		(31)		—
Net income (loss) attributable to Ameren common shareholders	100		51		6		63		(a)	(13)		—		207
Capital expenditures	392		143		69		160			1		(1)		764
Six Months 2023:
External revenues	$	1,846	$	1,164	$	543	$	269		$	—	$	—	$	3,822
Intersegment revenues	18		—		—		55			—		(73)		—
Net income attributable to Ameren common shareholders	130		127		98		143		(a)	3		—		501
Capital expenditures	914		350		141		410			5		2		1,822
Six Months 2022:
External revenues	$	1,720	$	968	$	665	$	252		$	—	$	—	$	3,605
Intersegment revenues	17		1		—		44			—		(62)		—
Net income attributable to Ameren common shareholders	150		100		86		121		(a)	2		—		459
Capital expenditures	806		281		118		332			3		(2)		1,538

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

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

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~~(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).~~

Ameren Illinois


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations		Ameren Illinois
Three Months 2023:
External revenues	$	540	$	152	$	87	$	—	$	779
Intersegment revenues	—		—		26		(26)		—
Net income available to common shareholder	66		11		52		—		129
Capital expenditures	180		90		167		—		437
Three Months 2022:
External revenues	$	504	$	184	$	81	$	—	$	769
Intersegment revenues	—		—		24		(24)		—
Net income available to common shareholder	51		6		46		—		103
Capital expenditures	143		69		145		—		357
Six Months 2023:
External revenues	$	1,164	$	543	$	173	$	—	$	1,880
Intersegment revenues	—		—		54		(54)		—
Net income available to common shareholder	127		98		102		—		327
Capital expenditures	350		141		353		—		844
Six Months 2022:
External revenues	$	969	$	665	$	159	$	—	$	1,793
Intersegment revenues	—		—		44		(44)		—
Net income available to common shareholder	100		86		86		—		272
Capital expenditures	281		118		300		—		699

The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 2023 and 2022. 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, off-system sales, and capacity revenues.

Ameren


	Ameren Missouri		Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas		Ameren Transmission		Intersegment Eliminations		Ameren
Three Months 2023:
Residential	$	360	$	337		$	—	$	—	$	—	$	697
Commercial	311		193			—		—		—		504
Industrial	75		48			—		—		—		123
Other	172		(38)		(a)	—		161		(34)		261
Total electric revenues	$	918	$	540		$	—	$	161	$	(34)	$	1,585
Residential	$	13	$	—		$	98	$	—	$	—	$	111
Commercial	6		—			25		—		—		31
Industrial	1		—			2		—		—		3
Other	3		—			27		—		—		30
Total natural gas revenues	$	23	$	—		$	152	$	—	$	—	$	175
Total revenues(b)	$	941	$	540		$	152	$	161	$	(34)	$	1,760

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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.~~


	Ameren Missouri		Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas		Ameren Transmission		Intersegment Eliminations		Ameren
Three Months 2022:
Residential	$	371	$	284		$	—	$	—	$	—	$	655
Commercial	298		180			—		—		—		478
Industrial	73		53			—		—		—		126
Other	148		(13)		(a)	—		150		(31)		254
Total electric revenues	$	890	$	504		$	—	$	150	$	(31)	$	1,513
Residential	$	16	$	—		$	117	$	—	$	—	$	133
Commercial	8		—			30		—		—		38
Industrial	1		—			11		—		—		12
Other	4		—			26		—		—		30
Total natural gas revenues	$	29	$	—		$	184	$	—	$	—	$	213
Total revenues(b)	$	919	$	504		$	184	$	150	$	(31)	$	1,726
Six Months 2023:
Residential	$	684	$	719		$	—	$	—	$	—	$	1,403
Commercial	558		393			—		—		—		951
Industrial	136		96			—		—		—		232
Other	381		(44)		(a)	—		324		(72)		589
Total electric revenues	$	1,759	$	1,164		$	—	$	324	$	(72)	$	3,175
Residential	$	65	$	—		$	394	$	—	$	—	$	459
Commercial	29		—			102		—		—		131
Industrial	3		—			9		—		—		12
Other	8		—			38		—		(1)		45
Total natural gas revenues	$	105	$	—		$	543	$	—	$	(1)	$	647
Total revenues(b)	$	1,864	$	1,164		$	543	$	324	$	(73)	$	3,822
Six Months 2022:
Residential	$	703	$	547		$	—	$	—	$	—	$	1,250
Commercial	538		338			—		—		—		876
Industrial	130		98			—		—		—		228
Other	257		(14)		(a)	—		296		(62)		477
Total electric revenues	$	1,628	$	969		$	—	$	296	$	(62)	$	2,831
Residential	$	67	$	—		$	486	$	—	$	—	$	553
Commercial	30		—			127		—		—		157
Industrial	3		—			28		—		—		31
Other	9		—			24		—		—		33
Total natural gas revenues	$	109	$	—		$	665	$	—	$	—	$	774
Total revenues(b)	$	1,737	$	969		$	665	$	296	$	(62)	$	3,605

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(a)Includes over-recoveries of various riders.

(b)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the three and six months ended June 30, 2023 and 2022:


	Ameren Missouri			Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Ameren
Three Months 2023:
Revenues from alternative revenue programs	$	—		$	60	$	9	$	5	$	74
Other revenues not from contracts with customers	(2)		(a)	2		1		—		1		(a)
Three Months 2022:
Revenues from alternative revenue programs	$	—		$	41	$	3	$	(4)	$	40
Other revenues not from contracts with customers	(36)		(a)	1		1		—		(34)		(a)
Six Months 2023:
Revenues from alternative revenue programs	$	(2)		$	124	$	37	$	13	$	172
Other revenues not from contracts with customers	(8)		(a)	4		2		—		(2)		(a)
Six Months 2022:
Revenues from alternative revenue programs	$	(6)		$	96	$	(2)	$	(3)	$	85
Other revenues not from contracts with customers	(36)		(a)	3		2		—		(31)		(a)

(a)Includes net realized losses on derivative power contracts.

Ameren Illinois


	Ameren Illinois Electric Distribution			Ameren Illinois Natural Gas		Ameren Illinois Transmission		Intersegment Eliminations		Ameren Illinois
Three Months 2023:
Residential	$	337		$	98	$	—	$	—	$	435
Commercial	193			25		—		—		218
Industrial	48			2		—		—		50
Other	(38)		(a)	27		113		(26)		76
Total revenues(b)	$	540		$	152	$	113	$	(26)	$	779
Three Months 2022:
Residential	$	284		$	117	$	—	$	—	$	401
Commercial	180			30		—		—		210
Industrial	53			11		—		—		64
Other	(13)		(a)	26		105		(24)		94
Total revenues(b)	$	504		$	184	$	105	$	(24)	$	769
Six Months 2023:
Residential	$	719		$	394	$	—	$	—	$	1,113
Commercial	393			102		—		—		495
Industrial	96			9		—		—		105
Other	(44)		(a)	38		227		(54)		167
Total revenues(b)	$	1,164		$	543	$	227	$	(54)	$	1,880
Six Months 2022:
Residential	$	547		$	486	$	—	$	—	$	1,033
Commercial	338			127		—		—		465
Industrial	98			28		—		—		126
Other	(14)		(a)	24		203		(44)		169
Total revenues(b)	$	969		$	665	$	203	$	(44)	$	1,793

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(a)Includes over-recoveries of various riders.

(b)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 and six months ended June 30, 2023 and 2022:


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Ameren Illinois
Three Months 2023:
Revenues from alternative revenue programs	$	60	$	9	$	3	$	72
Other revenues not from contracts with customers	2		1		—		3

Three Months 2022:
Revenues from alternative revenue programs	$	41	$	3	$	(3)	$	41
Other revenues not from contracts with customers	1		1		—		2

Six Months 2023:
Revenues from alternative revenue programs	$	124	$	37	$	10	$	171
Other revenues not from contracts with customers	4		2		—		6

Six Months 2022:
Revenues from alternative revenue programs	$	96	$	(2)	$	(2)	$	92
Other revenues not from contracts with customers	3		2		—		5

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

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

~~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.

Ameren’s and ~~Mark Twain projects.~~

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~~ in the three months ended ~~September~~June 30, ~~2017,~~2023, was $237 million, or $0.90 per diluted share, compared with ~~$369~~$207 million, or $0.80 per diluted share, in the year-ago period. Net income attributable to Ameren common shareholders ~~was $583 million~~ in ~~nine~~the six months ended ~~September~~June 30, ~~2017,~~2023, was $501 million, or $1.90 per diluted share, compared with ~~$621~~$459 million, or $1.77 per diluted share, in the year-ago period. Net income ~~was unfavorably affected in~~for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, compared to the year-ago periods,~~2023, was favorably affected by ~~milder temperatures in 2017 and decreased~~increased rate base investments across all segments, a higher recognized ROE at Ameren Illinois Electric Distribution ~~earnings~~ due to a ~~change~~higher estimated annual average of the monthly yields of the 30-year United States Treasury bonds, and decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase 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~~cash surrender value of ~~the FEJA. Earnings were also unfavorably affected in~~COLI. Net income for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, 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 towith the year-ago periods, was ~~favorably~~unfavorably affected by ~~an increase in base rates and lower base level of tracked expense~~decreased electric retail sales at Ameren Missouri, ~~pursuant to~~primarily resulting from milder spring and early summer temperatures in the ~~MoPSC’s March 2017 electric rate order~~three month period ended June 30, 2023, as well as

Table of Contents

warmer winter temperatures in the six month period ended June 30, 2023, compared with the same periods in 2022; and increased ~~investments in infrastructure~~financing costs from the issuance of long-term debt at ~~the~~ Ameren ~~Illinois Electric Distribution~~Missouri and ~~Ameren Transmission segments reflecting Ameren’s strategy to allocate incremental capital to those businesses.~~higher interest rates on increased levels of short-term borrowings.

Ameren’s strategic plan includes investing in ~~and operating its utilities in, a manner consistent with existing~~rate-regulated energy infrastructure, enhancing regulatory ~~frameworks, enhancing those~~ frameworks and advocating for responsible ~~energy~~policies, and ~~economic policies, as well as creating and capitalizing~~optimizing operating performance to capitalize on opportunities ~~for investment for~~to benefit our customers, our shareholders, and the ~~benefit of its customers and shareholders.~~environment. Ameren remains focused on disciplined cost management and strategic capital allocation. ~~In the first nine months of 2017,~~ Ameren ~~continued to allocate significant amounts of capital to those businesses that are supported by constructive regulatory frameworks, investing $1~~invested $1.8 billion ~~of capital expenditures~~ in its ~~FERC~~ rate-regulated ~~electric transmission and Illinois electric and natural gas distribution businesses.~~businesses in the six months ended June 30, 2023.

In ~~March 2017,~~June 2023, the MoPSC issued an order ~~approving a unanimous stipulation and agreement~~that resulted in an increase of $140 million to Ameren Missouri’s ~~July 2016 regulatory~~annual revenue requirement for electric retail service. The approved revenue requirement is based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to 2030. The order did not explicitly specify an ROE, capital structure, or rate ~~review.~~base. The order provides for the continued use of the FAC and trackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker. It also includes a tracker for the utilization of production and investment tax credits or proceeds from the sale of tax credits allowed under the IRA. The order ~~resulted in a $92 million increase in Ameren Missouri’s revenue requirement, a $54 million decrease in~~increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and ~~a $26 million reduction in~~liability amortization amounts, and the base level of ~~certain tracked~~ expenses ~~compared~~for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to ~~the amounts in the MoPSC’s April 2015 rate order.~~non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates ~~and base level of expenses~~ became effective on ~~April 1, 2017.~~ July 9, 2023.

In ~~September 2017,~~June 2023, Ameren Missouri filed ~~its non-binding 20-year integrated resource plan~~for CCNs with the MoPSC ~~which 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 targets cleaner and more diverse sources of energy generation. These new renewable energy sources would also 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 offour solar generation ~~over~~facilities and expects decisions in the ~~next 10 years, with 50 megawatts anticipated to come online by 2025.~~first quarter of 2024. These facilities include the Split Rail Solar Project (300-MW facility, build-transfer agreement), the Cass County Solar Project (150-MW facility, development-transfer agreement), the Vandalia Solar Project (50-MW facility, self-build), and the Bowling Green Solar Project (50-MW facility, self-build). The ~~new wind generation~~Cass County Solar Project is expected to be located in central Illinois and the other three projects are expected to be located in central Missouri. Each project is expected to support Ameren Missouri’s transition to renewable generation. In February and April 2023, the MoPSC issued orders approving requested CCNs for the Huck Finn and Boomtown solar projects, respectively.

In March 2023, Ameren Missouri filed a proposed three-year customer energy-efficiency plan with the MoPSC under the MEEIA. As a result of a nonunanimous stipulation and ~~neighboring states. The source, location,~~agreement filed with the MoPSC in August 2023 by Ameren Missouri, the MoPSC staff, and ~~cost of~~ the ~~new wind generation, among other items, remain subject~~MoOPC to ~~reaching agreements with developers.Based on current and projected market prices for energy, and for wind and solar generation technologies, among other factors,~~extend Ameren Missouri’s MEEIA 2019 program through 2024, Ameren Missouri expects to revise the proposed three-year plan in 2024. The stipulation and agreement, which is subject to MoPSC approval, includes the establishment of a portfolio of customer energy-efficiency programs for 2024 and performance incentives that would provide Ameren Missouri an opportunity to earn revenues, including $12 million if Ameren Missouri achieves certain energy-efficiency goals in 2024. If approved, Ameren Missouri expects to invest $76 million in energy-efficiency programs in 2024. The MoPSC is under no deadline to issue an order in this proceeding.

In February 2023, Ameren Missouri filed an update to its ~~ownership of these renewable resources would represent~~Smart Energy Plan with the ~~lowest-cost alternative~~MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for ~~customers.~~2023. The plan ~~also includes expected implementation of continued customer energy efficiency programs.~~is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan ~~for~~are expected to total approximately $9.9 billion over the ~~addition of renewable resources could be impacted by, among other factors:~~five-year period from 2023 through 2027, with expenditures largely recoverable under the ~~availability of federal production tax credits related to renewable energy~~PISA and the RESRAM. Ameren Missouri’s Smart Energy Plan excludes investments in its ~~ability to use such credits; the cost of wind and solar generation technologies,~~natural gas distribution business, as well as ~~energy prices;~~removal costs, net of salvage.

In July 2023, Ameren ~~Missouri’s ability~~Illinois filed a revised MYRP with the ICC to ~~obtain interconnection agreements with MISO or other RTOs, including~~be used in setting electric distribution service rates for 2024 through 2027. Under the ~~cost~~MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of ~~such interconnections;~~the four-year period. The following table includes the forecasted revenue requirement, the requested ROE, the requested capital structure common equity percentage, and ~~Ameren Missouri’s ability to obtain a certificate of convenience and necessity from~~ the ~~MoPSC~~forecasted average annual rate base for ~~projects located in Missouri, or any other required project approvals. The wind generation identified~~2024 through 2027, as reflected in Ameren ~~Missouri’s plan could represent incremental investments~~Illinois’ revised MYRP filing:


Year	Forecasted Revenue Requirement (in millions)(a)	Requested ROE	Requested Capital Structure Common Equity Percentage(b)	Forecasted Average Annual Rate Base (in billions)
2024	$1,291	10.5%	53.99%	$4.3
2025	$1,387	10.5%	53.97%	$4.6
2026	$1,484	10.5%	54.02%	$4.9
2027	$1,560	10.5%	54.03%	$5.2

(a)If an initial rate increase phase-in provision, discussed below, is approved by the ICC, it would not affect the annual revenue requirement, but would affect the timing of ~~approximately $1 billion. In connection~~associated recovery from customers.

(b)A capital structure of up to and including 50% common equity is deemed prudent and reasonable by law. A higher equity ratio requires specific ICC approval.

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Under an MYRP, the IETL permits any initial rate increase to be phased in, with at least 50% of the ~~integrated resource plan filing, 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.~~

~~Ameren Illinois invested approximately $535 million~~first annual period’s approved rate increase reflected in ~~electric distribution and natural gas infrastructure projects~~rates in the first ~~nine months~~annual period, with the remaining portion deferred as a regulatory asset that earns a return at the applicable WACC and is collected from customers over a period not to exceed two years beginning within one year after the second annual period’s rates are effective. Ameren Illinois’ revised MYRP filing utilizes this phase-in provision and proposes to defer 50% of ~~2017.~~ the requested 2024 rate increase of $179 million as a regulatory asset to be collected from customers in 2026. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024.

In ~~April 2017,~~July 2023, Ameren Illinois filed ~~with the ICC~~a revised reconciliation adjustment to 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 million decrease in Ameren Illinois’2022 electric distribution service revenue requirement ~~beginning in January 2018. This update reflects an increase to~~with the ~~annual formula rate based on 2016 actual costs and expected net plant additions for 2017, as well as an increase to include the 2016 revenue requirement reconciliation adjustment.~~ICC, requesting recovery of $125 million. The ~~increases in the update filing are more than offset by a decrease for the conclusion of the 2015 revenue requirement~~ reconciliation adjustment reflects Ameren Illinois’ actual 2022 recoverable costs, year-end rate base, and capital structure, which ~~will~~was composed of 54% common equity. An ICC decision in this proceeding is required by December 2023, and any approved adjustment would be ~~fully~~ collected from customers in ~~2017.~~2024.

In July 2023, Ameren Illinois filed a revised request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $148 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the QIP and other riders. The request is based on a 10.3% allowed ROE, a capital structure composed of 53.99% common equity, and a rate base of $2.9 billion. In an attempt to reduce regulatory lag, Ameren Illinois used a 2024 future test year in this proceeding.A decision by the ICC in this proceeding is required by late November 2023, with new rates expected to be effective in early December 2023.

In May 2023, Ameren Illinois filed its annual electric energy-efficiency formula rate update to increase its rates by $27 million with the ICC. An ICC decision in this proceeding is required by December 2023, with new rates effective January 2024.

For further information on the ~~revenue requirement to be used for 2018 rates is expected by December 2017.~~

~~In the first nine months~~matters discussed above, see Note 2 – Rate and Regulatory Matters under Part I, Item I, 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 2017this report, 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).Outlook section below.

RESULTS OF OPERATIONS

Our results of operations and financial position are affected by many factors. Economic conditions, ~~energy efficiency~~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 and by weather conditions, such as storms, as well as by ~~nuclear refueling and other~~ energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing, ~~and~~ our pension and postretirement benefits ~~costs.~~costs, the cash surrender value of COLI, and the asset value of Ameren Missouri’s nuclear decommissioning trust fund. 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 are observing inflationary pressures on the prices of certain commodities, labor, services, materials, and supplies, as well as increasing interest rates. Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for fuel, purchased power, and natural gas supply. Additionally, for certain non-commodity cost changes, the use of trackers, riders, formula ratemaking, and future test years, as applicable, mitigates our exposure.

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.

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Earnings Summary

The following table presents a summary of ~~Ameren's~~Ameren’s earnings for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016:~~2022:


	Three Months				Nine Months					Three Months				Six Months
	2017		2016		2017		2016			2023		2022		2023		2022
Net income attributable to Ameren common shareholders	$	288	$	369	$	583	$	621	Net income attributable to Ameren common shareholders	$	237	$	207	$	501	$	459
Earnings per common share – diluted	1.18		1.52		2.39		2.56		Earnings per common share – diluted	0.90		0.80		1.90		1.77

Net income attributable to Ameren common shareholders ~~decreased $81~~increased $30 million, or 3410 cents per diluted share, in the three months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago ~~period. The decrease was principally~~period, primarily due to net income ~~decreases~~increases of ~~$62~~$15 million, $9 million, $5 million, and $7$2 million at Ameren Illinois Electric Distribution, Ameren Transmission, Ameren Illinois Natural Gas 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).~~respectively.

Net income attributable to Ameren common shareholders ~~decreased $38~~increased $42 million, or 1713 cents per diluted share, in the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago period. The ~~decrease~~increase was due to net income ~~decreases~~increases of ~~$28~~$27 million, $22 million, and $4$12 million at Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively. Additionally, activity not reported as part of 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 wasrespectively, partially offset by ~~an increase in~~a $20 million net income ~~of $12 million and $8 million~~decrease at Ameren ~~Missouri and Ameren Transmission, respectively.~~Missouri.

Earnings per diluted share were ~~unfavorably~~favorably affected in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared to the year-ago periods (except where a specific period is referenced), by:

•decreased ~~demand~~other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase in the cash surrender value of COLI, primarily at Ameren Missouri and Ameren Illinois Natural Gas (9 cents and 12 cents per share, respectively);

•increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE due to a higher estimated annual average of the monthly yields of the 30-year United States Treasury bonds at Ameren Illinois Electric Distribution, which increased revenues at these segments (5 cents and 12 cents per share, respectively);

•increased base rate revenues at Ameren Missouri for the inclusion of previously deferred interest charges pursuant to the December 2021 MoPSC electric rate order effective February 28, 2022, partially offset in the six months ended June 30, 2023, by increased interest charges resulting from lower deferrals related to infrastructure investments associated with the PISA and RESRAM (2 cents and 4 cents per share, respectively);

•decreased taxes other than income taxes, primarily at Ameren Missouri, largely resulting from employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act in the six months ended June 30, 2023 (1 cent and 3 cents per share, respectively);

•increased other income, net, largely due to increased non-service cost components of net periodic benefit income not subject to formula rates or trackers (2 cents per share for the six months ended June 30, 2023);

•decreased income tax expense not subject to formula rates or riders, resulting, in part, from the effect of favorable market returns on COLI, compared with unfavorable returns in the year-ago periods (2 cents per share for both periods);

•recovery of previously incurred expenses at Ameren Illinois Electric Distribution (2 cents per share for both periods);

•increased base rate revenues at Ameren Missouri effective February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, partially offset by the amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a higher base level of expenses, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (1 cent per share for the six months ended June 30, 2023); and

•increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP (1 cent per share for the six months ended June 30, 2023).

Earnings per diluted share were unfavorably affected in the three and six months ended June 30, 2023, compared to the year-ago periods, by:

•decreased electric retail sales at Ameren Missouri, primarily resulting from milder ~~winter~~spring and early summer temperatures in ~~2017~~the three months ended June 30, 2023, as well as warmer winter temperatures in the six months ended June 30, 2023, compared with the same periods in 2022 (estimated at 86 cents ~~per share~~ and 16 cents per share, respectively);

~~a change in the method used~~•increased financing costs, primarily at Ameren (parent) and Ameren Missouri, due to ~~recognize~~higher interest rates on increased levels of short-term borrowings and higher long-term debt balances at Ameren ~~Illinois Electric Distribution’s interim period revenue in connection with the decoupling provisions~~Missouri (3 cents and 7 cents per share, respectively); and

•increased weighted-average basic common shares outstanding resulting from issuances of ~~the FEJA~~common shares as ~~discussed~~detailed in Note 24 – ~~Rate~~Long-term Debt and ~~Regulatory Matters~~Equity Financings 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 15 – ~~Summary of Significant Accounting Policies~~Long-term Debt and Equity Financings under Part I,II, Item ~~1, of this report (6 cents per share for both periods);~~

~~the absence in 2017~~8, 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 belowForm 10-K (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, compared to the year-ago periods (except where a specific period is referenced), by:~~

an increase in base rates and lower base level of expenses at Ameren Missouri pursuant to the MoPSC’s March 2017 electric rate order as discussed in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report (15 cents per share and 26 cents per share, respectively);

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

increased 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, primarily due to additional rate base investment as well as a higher recognized return on equity (2 cents per share and 43 cents per share, respectively).

Table of Contents

The cents per share ~~information~~variances above are presented is based on the ~~average diluted~~weighted-average basic common shares outstanding in the three and ~~nine~~six months ended ~~September~~June 30, ~~2016. Amounts~~2022, and do not reflect the impact of dilution on earnings per share, unless otherwise noted. The amounts above other than variances related to income taxes have been presented net of income taxes using Ameren’s ~~2016~~2023 blended federal and state statutory tax rate of ~~39%~~26%. For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas ~~Margins,~~Margins; Other Operations and Maintenance ~~Expenses,~~Expenses; Depreciation and Amortization Expenses; Taxes Other Than Income ~~Taxes,~~Taxes; Other Income, ~~and Expenses,~~Net; Interest ~~Charges,~~Charges; and Income Taxes, see the major headings below.

Table of Contents

Below is Ameren’s table of income statement components by segment for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016:~~2022:


	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Other / Intersegment Eliminations		Ameren
Three Months 2023:
Electric revenues	$	918	$	540	$	—	$	161	$	(34)	$	1,585
Fuel	(152)		—		—		—		—		(152)
Purchased power	(137)		(218)		—		—		27		(328)
Electric margins	629		322		—		161		(7)		1,105
Natural gas revenues	23		—		152		—		—		175
Natural gas purchased for resale	(9)		—		(33)		—		—		(42)
Natural gas margins	14		—		119		—		—		133
Other operations and maintenance expenses	(237)		(133)		(58)		(13)		(9)		(450)
Depreciation and amortization expenses	(186)		(87)		(27)		(34)		(1)		(335)
Taxes other than income taxes	(88)		(18)		(13)		(2)		(3)		(124)
Operating income (loss)	132		84		21		112		(20)		329
Other income, net	22		26		8		8		18		82
Interest charges	(52)		(22)		(13)		(23)		(24)		(134)
Income (taxes) benefit	1		(21)		(5)		(25)		12		(38)
Net income (loss)	103		67		11		72		(14)		239
Noncontrolling interests – preferred stock dividends	(1)		(1)		—		—		—		(2)
Net income (loss) attributable to Ameren common shareholders	$	102	$	66	$	11	$	72	$	(14)	$	237
Three Months 2022:
Electric revenues	$	890	$	504	$	—	$	150	$	(31)	$	1,513
Fuel	(83)		—		—		—		—		(83)
Purchased power	(161)		(182)		—		—		25		(318)
Electric margins	646		322		—		150		(6)		1,112
Natural gas revenues	29		—		184		—		—		213
Natural gas purchased for resale	(12)		—		(68)		—		—		(80)
Natural gas margins	17		—		116		—		—		133
Other operations and maintenance expenses	(260)		(148)		(63)		(16)		(4)		(491)
Depreciation and amortization expenses	(178)		(82)		(25)		(30)		(1)		(316)
Taxes other than income taxes	(90)		(19)		(16)		(2)		(2)		(129)
Operating income (loss)	135		73		12		102		(13)		309
Other income, net	24		15		6		4		13		62
Interest charges	(60)		(18)		(11)		(20)		(17)		(126)
Income (taxes) benefit	2		(18)		(1)		(23)		4		(36)
Net income (loss)	101		52		6		63		(13)		209
Noncontrolling interests – preferred stock dividends	(1)		(1)		—		—		—		(2)
Net income (loss) attributable to Ameren common shareholders	$	100	$	51	$	6	$	63	$	(13)	$	207

Table of Contents

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


	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission		Other / Intersegment Eliminations		Ameren
Six Months 2023:
Electric revenues	$	1,759	$	1,164	$	—	$	324	$	(72)	$	3,175
Fuel	(265)		—		—		—		—		(265)
Purchased power	(345)		(533)		—		—		55		(823)
Electric margins	1,149		631		—		324		(17)		2,087
Natural gas revenues	105		—		543		—		(1)		647
Natural gas purchased for resale	(56)		—		(194)		—		—		(250)
Natural gas margins	49		—		349		—		(1)		397
Other operations and maintenance expenses	(476)		(262)		(117)		(29)		(14)		(898)
Depreciation and amortization expenses	(362)		(171)		(53)		(67)		(2)		(655)
Taxes other than income taxes	(168)		(36)		(36)		(4)		(7)		(251)
Operating income (loss)	192		162		143		224		(41)		680
Other income, net	41		50		16		14		39		160
Interest charges	(103)		(43)		(26)		(45)		(44)		(261)
Income (taxes) benefit	2		(41)		(35)		(50)		49		(75)
Net income	132		128		98		143		3		504
Noncontrolling interests – preferred stock dividends	(2)		(1)		—		—		—		(3)
Net income attributable to Ameren common shareholders	$	130	$	127	$	98	$	143	$	3	$	501
Six Months 2022:
Electric revenues	$	1,628	$	969	$	—	$	296	$	(62)	$	2,831
Fuel	(259)		—		—		—		—		(259)
Purchased power	(211)		(333)		—		—		49		(495)
Electric margins	1,158		636		—		296		(13)		2,077
Natural gas revenues	109		—		665		—		—		774
Natural gas purchased for resale	(58)		—		(315)		—		—		(373)
Natural gas margins	51		—		350		—		—		401
Other operations and maintenance expenses	(492)		(295)		(126)		(32)		(7)		(952)
Depreciation and amortization expenses	(342)		(163)		(48)		(60)		(2)		(615)
Taxes other than income taxes	(175)		(39)		(47)		(4)		(6)		(271)
Operating income (loss)	200		139		129		200		(28)		640
Other income, net	47		31		10		7		27		122
Interest charges	(99)		(36)		(22)		(42)		(31)		(230)
Income (taxes) benefit	4		(33)		(31)		(44)		34		(70)
Net income	152		101		86		121		2		462
Noncontrolling interests – preferred stock dividends	(2)		(1)		—		—		—		(3)
Net income attributable to Ameren common shareholders	$	150	$	100	$	86	$	121	$	2	$	459

Table of Contents

Below is Ameren ~~Illinois'~~Illinois’ table of income statement components by segment for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016:~~2022:


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Other / Intersegment Eliminations		Ameren Illinois
Three Months 2023:
Electric revenues	$	540	$	—	$	113	$	(26)	627
Purchased power	(218)		—		—		26		(192)
Electric margins	322		—		113		—		435
Natural gas revenues	—		152		—		—		152
Natural gas purchased for resale	—		(33)		—		—		(33)
Natural gas margins	—		119		—		—		119
Other operations and maintenance expenses	(133)		(58)		(10)		—		(201)
Depreciation and amortization expenses	(87)		(27)		(24)		—		(138)
Taxes other than income taxes	(18)		(13)		(1)		—		(32)
Operating income (loss)	84		21		78		—		183
Other income, net	26		8		7		—		41
Interest charges	(22)		(13)		(15)		—		(50)
Income taxes	(21)		(5)		(18)		—		(44)
Net income	67		11		52		—		130
Preferred stock dividends	(1)		—		—		—		(1)
Net income attributable to common shareholder	$	66	$	11	$	52	$	—	$	129
Three Months 2022:
Electric revenues	504		$	—	$	105	$	(24)	585
Purchased power	(182)		—		—		24		(158)
Electric margins	322		—		105		—		427
Natural gas revenues	—		184		—		—		184
Natural gas purchased for resale	—		(68)		—		—		(68)
Natural gas margins	—		116		—		—		116
Other operations and maintenance expenses	(148)		(63)		(14)		—		(225)
Depreciation and amortization expenses	(82)		(25)		(21)		—		(128)
Taxes other than income taxes	(19)		(16)		—		—		(35)
Operating income (loss)	73		12		70		—		155
Other income, net	15		6		4		—		25
Interest charges	(18)		(11)		(12)		—		(41)
Income taxes	(18)		(1)		(16)		—		(35)
Net income	52		6		46		—		104
Preferred stock dividends	(1)		—		—		—		(1)
Net income attributable to common shareholder	$	51	$	6	$	46	$	—	$	103

Table of Contents

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


	Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Illinois Transmission		Other / Intersegment Eliminations		Ameren Illinois
Six Months 2023:
Electric revenues	$	1,164	$	—	$	227	$	(54)	$	1,337
Purchased power	(533)		—		—		54		(479)
Electric margins	631		—		227		—		858
Natural gas revenues	—		543		—		—		543
Natural gas purchased for resale	—		(194)		—		—		(194)
Natural gas margins	—		349		—		—		349
Other operations and maintenance expenses	(262)		(117)		(24)		—		(403)
Depreciation and amortization expenses	(171)		(53)		(47)		—		(271)
Taxes other than income taxes	(36)		(36)		(2)		—		(74)
Operating income (loss)	162		143		154		—		459
Other income, net	50		16		12		—		78
Interest charges	(43)		(26)		(28)		—		(97)
Income taxes	(41)		(35)		(36)		—		(112)
Net income	128		98		102		—		328
Preferred stock dividends	(1)		—		—		—		(1)
Net income attributable to common shareholder	$	127	$	98	$	102	$	—	$	327
Six Months 2022:
Electric revenues	$	969	$	—	$	203	$	(44)	$	1,128
Purchased power	(333)		—		—		44		(289)
Electric margins	636		—		203		—		839
Natural gas revenues	—		665		—		—		665
Natural gas purchased for resale	—		(315)		—		—		(315)
Natural gas margins	—		350		—		—		350
Other operations and maintenance expenses	(295)		(126)		(27)		—		(448)
Depreciation and amortization expenses	(163)		(48)		(41)		—		(252)
Taxes other than income taxes	(39)		(47)		(2)		—		(88)
Operating income (loss)	139		129		133		—		401
Other income, net	31		10		8		—		49
Interest charges	(36)		(22)		(25)		—		(83)
Income taxes	(33)		(31)		(30)		—		(94)
Net income	101		86		86		—		273
Preferred stock dividends	(1)		—		—		—		(1)
Net income attributable to common shareholder	$	100	$	86	$	86	$	—	$	272

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

Table of Contents

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

Electric Margins

~~(a)~~

~~Includes a decrease in transmission margins of $1 million and an increase of $10 million for the three- and nine-month periods, respectively, at Ameren Illinois.~~

Increase (Decrease) by Segment

~~(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

Overall Ameren Decrease of ~~weather on~~$7 Million (QTD YoY)

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

Increase of $10 Million (YTD YoY)
~~(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. Total by Segment(a)


~~(d)~~	~~Electric and natural gas revenue changes are offset by corresponding changes~~

(a)Includes other/intersegment eliminations of $(7) million, $(6) million, $(17) million, and $(13) million in ~~Fuel, Purchased power, and Natural gas purchased for resale, resulting in no change to electric and natural gas margins.~~


~~(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.

~~Ameren~~

~~Ameren's electric margins decreased $109 million, or 8%, for~~ the three months ended ~~September~~June 30, ~~2017,~~2023 and 2022, and six months ended June 30, 2023, and 2022, respectively.

Ameren Missouri

Ameren Illinois Electric Distribution

Ameren Transmission

Other/Intersegment Eliminations

Natural Gas Margins

Increase (Decrease) by Segment

Overall Ameren Change of $- Million (QTD YoY)

Overall Ameren Decrease of $4 Million (YTD YoY)

Total by Segment(a)

(a)Includes other/intersegment eliminations of $(1) million in the six months ended June 30, 2023.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Table of Contents

The following tables present the favorable (unfavorable) variations by Ameren segment for electric and natural gas margins for the three and six months ended June 30, 2023, compared with the year-ago ~~period,~~periods:


Electric and Natural Gas Margins
Three Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission(a)		Other /Intersegment Eliminations		Ameren
Electric revenue change:
Base rates (estimate)(b)	$	—	$	2	$	—	$	11	$	—	$	13
Effect of weather (estimate)(c)	(23)		—		—		—		—		(23)
Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)	(6)		—		—		—		—		(6)

Off-system sales, capacity, and FAC revenues, net	28		—		—		—		—		28
Ameren Illinois energy-efficiency program investment revenues	—		5		—		—		—		5
Other	(1)		(1)		—		—		(1)		(3)
Cost recovery mechanisms – offset in fuel and purchased power(d)	28		36		—		—		(2)		62
Other cost recovery mechanisms(e)	2		(6)		—		—		—		(4)
Total electric revenue change	$	28	$	36	$	—	$	11	$	(3)	$	72
Fuel and purchased power change:
Energy costs (excluding the estimated effect of weather)	$	(22)	$	—	$	—	$	—	$	—	$	(22)
Effect of weather (estimate)(c)	3		—		—		—		—		3

Other	2		—		—		—		—		2
Cost recovery mechanisms – offset in electric revenue(d)	(28)		(36)		—		—		2		(62)
Total fuel and purchased power change	$	(45)	$	(36)	$	—	$	—	$	2	$	(79)
Net change in electric margins	$	(17)	$	—	$	—	$	11	$	(1)	$	(7)
Natural gas revenue change:
Effect of weather (estimate)(c)	$	(1)	$	—	$	—	$	—	$	—	$	(1)
Sales volumes (excluding the estimated effect of weather)	(2)		—		—		—		—		(2)
QIP	—		—		3		—		—		3

Cost recovery mechanisms – offset in natural gas purchased for resale(d)	(2)		—		(35)		—		—		(37)
Other cost recovery mechanisms(e)	(1)		—		—		—		—		(1)
Total natural gas revenue change	$	(6)	$	—	$	(32)	$	—	$	—	$	(38)
Natural gas purchased for resale change:
Effect of weather (estimate)(c)	$	1	$	—	$	—	$	—	$	—	$	1
Cost recovery mechanisms – offset in natural gas revenue(d)	2		—		35		—		—		37
Total natural gas purchased for resale change	$	3	$	—	$	35	$	—	$	—	$	38
Net change in natural gas margins	$	(3)	$	—	$	3	$	—	$	—	$	—

Table of Contents


Electric and Natural Gas Margins
Six Months	Ameren Missouri		Ameren Illinois Electric Distribution		Ameren Illinois Natural Gas		Ameren Transmission(a)		Other /Intersegment Eliminations		Ameren
Electric revenue change:
Base rates (estimate)(b)	$	38	$	(2)	$	—	$	28	$	—	$	64
Effect of weather (estimate)(c)	(56)		—		—		—		—		(56)
Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)	(13)		—		—		—		—		(13)

Off-system sales, capacity, and FAC revenues, net	118		—		—		—		—		118
Ameren Illinois energy-efficiency program investment revenues	—		9		—		—		—		9
Other	1		2		—		—		(4)		(1)
Cost recovery mechanisms – offset in fuel and purchased power(d)	40		200		—		—		(6)		234
Other cost recovery mechanisms(e)	3		(14)		—		—		—		(11)
Total electric revenue change	$	131	$	195	$	—	$	28	$	(10)	$	344
Fuel and purchased power change:
Energy costs (excluding the estimated effect of weather)	$	(112)	$	—	$	—	$	—	$	—	$	(112)
Effect of weather (estimate)(c)	10		—		—		—		—		10
Effect of higher net energy costs included in base rates	(1)		—		—		—		—		(1)
Other	3		—		—		—		—		3
Cost recovery mechanisms – offset in electric revenue(d)	(40)		(200)		—		—		6		(234)
Total fuel and purchased power change	$	(140)	$	(200)	$	—	$	—	$	6	$	(334)
Net change in electric margins	$	(9)	$	(5)	$	—	$	28	$	(4)	$	10
Natural gas revenue change:
Effect of weather (estimate)(c)	$	(10)	$	—	$	—	$	—	$	—	$	(10)
Sales volumes (excluding the estimated effect of weather)	(2)		—		—		—		—		(2)
QIP	—		—		6		—		—		6
Other	2		—		—		—		(1)		1
Cost recovery mechanisms – offset in natural gas purchased for resale(d)	7		—		(121)		—		—		(114)
Other cost recovery mechanisms(e)	(1)		—		(7)		—		—		(8)
Total natural gas revenue change	$	(4)	$	—	$	(122)	$	—	$	(1)	$	(127)
Natural gas purchased for resale change:
Effect of weather (estimate)(c)	$	9	$	—	$	—	$	—	$	—	$	9
Cost recovery mechanisms – offset in natural gas revenue(d)	(7)		—		121		—		—		114
Total natural gas purchased for resale change	$	2	$	—	$	121	$	—	$	—	$	123
Net change in natural gas margins	$	(2)	$	—	$	(1)	$	—	$	(1)	$	(4)

(a)Includes an increase in transmission margins of $8 million and $24 million at Ameren Illinois for the three and six months ended June 30, 2023, compared with the year-ago periods.

(b)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 for the recovery of lost electric margins resulting from the MEEIA customer energy-efficiency programs and a decrease in base rates for RESRAM. These changes in Ameren Missouri base rates are included in the “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” and “Cost recovery mechanisms - offset in fuel and purchased power” line items, respectively.

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

(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 ~~decreased margins at~~income, resulting in no change to electric and natural gas margins. Activity in Other/Intersegment Eliminations represents the elimination of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI, as well as Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution. Ameren’s electric margins increased $22 million, or 1%, for the nine months ended September 30, 2017, 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 natural gas margins increased $4 million, or 4%, and $4 million, or 1%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because of increased margins at Ameren Illinois Natural Gas, partially offset by decreased margins at Ameren Missouri.

~~Ameren Transmission~~

Ameren Transmission's margins increased $11 million, or 10%, and $43 million, or 15%, for the three and nine months ended September 30, 2017, respectively, compared with the year-ago periods. Margins were favorably affected by increased capital investment, as evidenced by a 22% 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 28 – ~~Rate~~Related-party Transactions and ~~Regulatory Matters~~Note 14 – Segment Information under Part 1,I, Item 1, of this report for additional information ~~regarding~~on intersegment eliminations.

(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 ~~allowed return~~“Operating Expenses” section and "Income Taxes" in the statement of income. These items have no overall impact on ~~common equity for FERC-regulated transmission rate base.~~earnings.

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Ameren ~~Missouri~~

~~Ameren Missouri's~~Ameren’s electric margins decreased $5$7 million, or 1%, for the three months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago ~~period.~~period, due to decreased margins at Ameren ~~Missouri’s~~Missouri, partially offset by increased margins at Ameren Transmission, as discussed below. Ameren’s electric margins increased ~~$23~~$10 million, or less than 1%, for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago ~~period.~~period, due to increased margins at Ameren ~~Missouri’s~~Transmission, partially offset by decreased margins at Ameren Missouri and Ameren Illinois Electric Distribution, as discussed below. Ameren’s natural gas margins were comparable for the three months ended ~~September~~June 30, ~~2017,~~2023, and decreased $4 million, or 1%, for the six months ended June 30, 2023, compared with the year-ago period, due to decreased margins at Ameren Missouri Natural Gas and Ameren Illinois Natural Gas, as discussed below.

Ameren Transmission

Ameren Transmission’s margins increased $11 million, or 7%, and $28 million, or 9%, for the three and six months ended June 30, 2023, respectively, compared with the year-ago ~~period.~~ periods. Base rate revenues were favorably affected primarily by higher recoverable expenses (+$5 million and +$16 million, respectively) and increased capital investment (+$6 million and +$13 million, respectively), as evidenced by an 11% increase in rate base used to calculate the revenue requirement.

Ameren Missouri

Ameren Missouri’s ~~natural gas~~electric margins decreased $3$17 million, or 5%3%, and $9 million, or 1%, for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017,~~2023, respectively, compared with the year-ago ~~period.~~periods. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $28 million and $40 million for the three and six months ended June 30, 2023, respectively, due to increased revenue related to the amortization of costs previously deferred under the FAC that were reflected in customer rates, which also increased fuel expense. The changes to “Cost recovery mechanisms - offset in fuel and purchased power” are fully offset by “Cost recovery mechanisms - offset in electric revenue,” in the table above, and result in no impact to margins. Ameren Missouri’s 5% exposure to net energy cost variances under the FAC is reflected within “Off-system sales, capacity, and FAC revenues, net” and “Energy costs (excluding the estimated effect of weather)”, as discussed below.

The following items had ~~a favorable~~an unfavorable effect on Ameren ~~Missouri's~~Missouri’s electric margins for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago periods (except where a specific period is referenced):

•Summer temperatures were milder as cooling degree days decreased 15% for the three months ended June 30, 2023, and winter temperatures were warmer as heating degree days decreased 19% for the six months ended June 30, 2023. The aggregate effect of weather decreased margins an estimated $20 million and $46 million for the three and six months ended June 30, 2023, respectively. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (-$23 million and -$56 million, respectively) and the “Effect of weather (estimate)” on fuel and purchased power (+$3 million and +$10 million, respectively) in the table above.

•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues decreased an estimated $6 million and $13 million for the three and six months ended June 30, 2023, respectively. These decreases were primarily due to a decrease in retail sales volumes and a decrease in the average retail price per kilowatthour related to changes in customer usage patterns.

The following items had a favorable effect on Ameren Missouri’s electric margins for the three and six months ended June 30, 2023, compared with the year-ago periods:

•Higher electric base rates, ~~effective April 1, 2017, as a result of~~excluding the ~~March 2017~~change in base rates for the MEEIA customer energy-efficiency programs and the RESRAM, resulting from the December 2021 MoPSC electric rate order effective February 28, 2022, partially offset by higher net energy costs included in base rates, increased margins by an estimated ~~$49~~$37 million ~~and $85 million, respectively.~~for the six months ended June 30, 2023. The change in electric base rates is the sum of the change in ~~base~~“Base rates (estimate)” (+$~~29 million and +$53 million, respectively)~~38 million) and the ~~effect~~“Effect of ~~lower~~higher net energy costs included in base ~~rates (+~~rates” (-$~~20 million and +$32 million, respectively)~~1 million) in the ~~Electric and Natural Gas Margins~~ table above.

~~Excluding~~•Ameren Missouri’s 5% exposure to net energy cost variances under 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~~FAC 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~~$6 million for the three and ~~nine~~six months ended ~~September~~June 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, partially offset by growth. The throughput disincentive 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 in net energy costs of $3 million for nine months ended September 30, 2017, compared with the year-ago period.2023. The change in net energy costs is the sum of “Off-system sales, capacity and FAC revenues, net” (+$28 million and +$118 million, respectively) and “Energy costs (excluding the ~~change~~estimated effect of weather)” (-$22 million and -$112 million, respectively) in the table above. In the three and six months ended June 30, 2023, these revenues and costs increased primarily due to higher capacity prices, partially offset by the effect of decreased generation volumes and lower market prices for power. Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. For the three and six months ended June 30, 2023, capacity revenues increased $54 million and $209 million, respectively, and capacity costs increased $52 million and $201 million, respectively. Capacity revenues and costs increased due to an increase in the price set by the annual MISO auction in April 2022, which became effective June 2022. These increases in capacity revenues and costs were partially offset by lower capacity prices set by the annual MISO auction in April 2023, which became effective June 2023, as well as the

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effect of lower market prices for power, which resulted in a decrease in off-system sales ~~(+$94~~and related fuel costs. See Outlook for additional information related to the April 2022 and April 2023 MISO auctions.

•Other cost recovery mechanisms increased margins $3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017)~~2023, primarily due to an increase in recoverable MEEIA program costs.

•Other decreases in fuel and ~~the change in energy costs (excluding the effect of weather and the New Madrid Smelter) (-$91~~purchased power expenses, which increased margins $3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017)~~2023, were largely due to a decrease in transmission network upgrade charges.

Ameren Missouri’s natural gas margins decreased $3 million, or 18%, for the three months ended June 30, 2023, and were comparable for the six months ended June 30, 2023. Margins decreased for the three months ended June 30, 2023, due primarily to lower sales volume from residential customers. Purchased gas costs increased $7 million for the six months ended June 30, 2023, due to amortization of natural gas costs previously deferred under the PGA, driven by a significant increase in cost and customer demand as result of the extremely cold weather in mid-February 2021. The increased purchased natural gas costs are fully offset by an increase in natural gas revenues under the PGA, resulting in no impact to margin. The increase in purchased natural 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” in the ~~Electric and Natural Gas Margins~~ table above.

Ameren Illinois

Ameren ~~Illinois'~~Illinois’ electric margins ~~decreased by $113~~increased $8 million, or ~~25%~~2%, and ~~$30~~$19 million, or 3%2%, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, respectively, compared with the year-ago periods, driven by ~~a decrease in~~increased margins at Ameren Illinois Transmission, partially offset by decreased margins at Ameren Illinois Electric Distribution ~~($112 million and $40 million, respectively).~~for the six months ended June 30, 2023. Ameren Illinois Natural Gas’ margins increased ~~by $5~~$3 million, or ~~6%, and $7 million, or 2%~~3%, for the three ~~and nine~~ months ended ~~September~~June 30, ~~2017, respectively, compared with~~2023, and were comparable for 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.~~six months ended June 30, 2023.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins ~~decreased $112 million, or 30%, and $40 million or 5%,~~were comparable for the three ~~and nine~~ months ended ~~September~~June 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~~2023, 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.

The absence of the impact of warmer-than-normal summer temperatures experienced in the third quarter of 2016 and the decoupling of revenues in 2017, which decreased margins by $7 million for both periods. The change in margins due to weather is the sum of the effect of weather (estimate) on revenues (-$9 million and -$7 million, respectively) and the effect of weather (estimate) on fuel and purchased power (+$2 million and flat, respectively) in the Electric and Natural Gas Margins table above.

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 margins decreased $1~~ $5 million, or 1%, for the ~~three~~six months ended ~~September~~June 30, ~~2017, compared to the year-ago period. Ameren Illinois Transmission’s margins increased $10 million, or 5%~~2023, ~~for the nine months ended September 30, 2017,~~ compared with the year-ago ~~period. Margins were unfavorably affected~~periods. Purchased power costs increased $36 million and $200 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~ 2023, respectively, primarily due to increased energy prices (+$1 million and +$96 million, respectively) largely reflecting the results of IPA procurement events, and increased capacity prices (+$19 million and +$63 million, respectively). In the three and six months ended June 30, 2023, capacity revenues and costs increased due to an increase in the price set by the annual MISO auction in April 2022, which became effective June 2022. These increases in capacity revenues and costs were partially offset by lower capacity prices set by the annual MISO auction in April 2023, which became effective June 2023. See Outlook for additional information related to the April 2022 and April 2023 MISO auctions. In addition to increased energy and capacity prices, higher volumes increased purchased power costs (+$13 million and +$31 million, respectively), primarily due to residential and small commercial customer switching from alternative retail electric suppliers to Ameren Illinois’ supplied power. 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” in the table above.

Other cost recovery mechanisms decreased margins by $6 million and $14 million for the three and six months ended June 30, 2023, respectively, compared with the year-ago periods, primarily due to a lower amount of bad debt costs included in customer rates pursuant to the associated rider. The decreased margins were partially offset by an increase in revenues of $5 million and $9 million, respectively, due to the ~~absence~~recovery of ~~a temporarily higher allowed~~and return on ~~common equity~~increased energy-efficiency program investments under performance-based formula ratemaking. The impact from base rates was comparable (+$2 million and -$2 million, respectively) due to lower recoverable non-purchased power expenses (-$3 million and -$16 million, respectively), offset by a higher recognized ROE (+$2 million and +$8 million, respectively), as evidenced by an increase of ~~12.38% for nearly four months~~74 basis points in ~~2016 as a result~~the estimated annual average of the ~~expiration~~monthly yields of the ~~refund period in the February 2015 complaint case. Margins were favorably affected by~~30-year United States Treasury bonds, and increased capital investment (+$3 million and +$6 million, respectively), as evidenced by a ~~15%~~7% increase in rate base used to calculate the revenue ~~requirement at September~~requirement.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins increased $3 million, or 3%, for the three months ended June 30, ~~2017, compared to September~~2023, and were comparable for the six months ended June 30, ~~2016, as well as higher recoverable~~2023. Purchased gas costs decreased $35 million and $121 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, respectively, primarily due to lower amortization of natural gas costs that were previously deferred under the PGA and lower natural gas prices in 2023. Those deferred natural gas costs related to the mid-February 2021 weather event were fully recovered from customers by the end of 2022. The decreased purchased natural gas costs are fully offset by a decrease in natural gas revenues under the PGA, resulting in no impact to margin. The decrease in purchased natural 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” in the table above. Revenues increased $3 million and $6 million due to additional investment in natural gas infrastructure under the QIP for the three and six months ended June 30, 2023, respectively. Other cost recovery mechanisms decreased

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revenues $7 million for the six months ended June 30, 2023, primarily due to decreased revenues for excise taxes.

Ameren Illinois Transmission

Ameren Illinois Transmission’s margins increased $8 million, or 8%, and $24 million, or 12%, for the three and six months ended June 30, 2023, respectively, compared with the year-ago ~~periods, under forward-looking formula ratemaking.~~

periods. Base rate revenues were favorably affected primarily by increased capital investment (+$6 million and +$13 million, respectively), as evidenced by a 17% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$3 million and +$12 million, respectively).

Other Operations and Maintenance Expenses

Increase (Decrease) by Segment

Overall Ameren Decrease of $41 Million (QTD YoY)

Overall Ameren Decrease of $54 Million (YTD YoY)

Total by Segment(a)

(a)Includes $13 million and $16 million at Ameren Transmission in the three months ended June 30, 2023 and 2022, respectively. Includes other/intersegment eliminations of $9 million and $4 million in the three months ended June 30, 2023 and 2022, respectively. Also includes other/intersegment eliminations of $14 million and $7 million in the six months ended June 30, 2023and 2022, 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 $41 million and ~~$17~~$54 million ~~lower~~ in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, respectively, as compared with the year-ago ~~periods,~~periods. In addition to changes by segments discussed below, other operations and maintenance expenses increased $5 million and $7 million in the three and six months ended June 30, 2023, respectively, for activity not reported as ~~discussed below.~~part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of an increase in the elimination of the non-service cost component of net periodic benefit income at Ameren Services. The non-service cost component of net periodic benefit cost or income at Ameren Services is allocated to the segments and primarily included in the segments’ other operations and maintenance expenses.

Ameren Transmission

Other operations and maintenance expenses ~~were comparable~~decreased $3 million in both the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago periods, primarily because of increases in the cash surrender value of COLI due to favorable market returns in 2023, compared with unfavorable market returns in the year-ago periods.

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Ameren Missouri

Other operations and maintenance expenses ~~were $4~~decreased $23 million ~~higher~~ and ~~$15~~$16 million ~~lower~~ in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, respectively, as compared with the year-ago periods. The following items decreased other operations and maintenance expenses ~~for~~in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago periods (except where a specific period is referenced):

~~Refueling~~•The cash surrender value of COLI increased $10 million and ~~maintenance outage costs at~~$19 million, respectively. In the ~~Callaway energy center were lower by $27 million~~three and six months ended June 30, 2023, the effect of changes in the ~~nine-month period, as the current year refueling and maintenance outage began~~cash surrender value of COLI resulted in ~~October 2017, while the 2016 refueling and maintenance outage was completed in the second quarter.~~

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

~~Solar rebate amortization costs decreased by $3 million and $6 million, respectively, primarily as a result of the March 2017 MoPSC electric rate order.~~

~~Estimated litigation costs decreased by $3~~$2 million and $5 million, ~~respectively.~~respectively, compared with losses of $8 million and $14 million, respectively, in the year-ago periods.

•The ~~following items increased~~recognition of regulatory assets for previously expensed costs approved for recovery pursuant to the June 2023 MoPSC rate order decreased other operations and maintenance expenses $15 million in both periods.

•Renewable development costs decreased $6 million and $9 million, respectively, as the MoPSC order approving CCNs for the Boomtown and Huck Finn solar projects in the first half of 2023 led to increased capitalization of renewable development costs pursuant to anticipated recovery from customers.

•Energy center operating and maintenance costs decreased $2 million and $5 million, respectively, related to the retirement of the Meramec Energy Center.

The above decreases in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago ~~periods:~~periods, were partially offset by the below items (except where a specific period is referenced):

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~~•Labor and benefit costs increased $5 million and $11 million, respectively, primarily because of increased medical and retirement benefits, including the effect of a higher base level of pension service costs reflected in ~~both periods~~electric service rates effective February 28, 2022, pursuant to the December 2021 MoPSC rate order for ~~crews assisting other utilities with power restoration,~~the six months ended June 30, 2023. Pursuant to the pension tracker, differences between actual costs incurred and base level expenses included in customer rates are deferred as a regulatory asset or liability for recovery from, or refund to, customers over a period of time as determined in a subsequent regulatory rate review.

•Callaway Energy Center costs increased $2 million and $5 million, respectively, primarily ~~caused by hurricane damage. These~~because of the amortization of increased costs ~~are being recovered from~~related to the ~~other utilities, with no overall effect on net income.~~

~~Energy center maintenance costs, excluding~~spring 2022 refueling and maintenance outage, which costs ~~at the Callaway energy center,~~began amortizing in June 2022.

•MEEIA customer energy-efficiency program spend increased ~~by $5~~$4 million in ~~both periods,~~the six months ended June 30, 2023, as approved by the MoPSC.

•Costs for injuries and damages increased $4 million in the six months ended June 30, 2023, primarily because of ~~higher coal handling charges.~~an increase in claims, compared with the year-ago period.

•Technology-related expenditures increased $3 million in the six months ended June 30, 2023, resulting from increased software maintenance expenses.

Ameren Illinois

Other operations and maintenance expenses ~~were $15~~decreased $24 million ~~lower~~and $45 million in the three and six months ended ~~September~~June 30, ~~2017,~~2023, respectively, compared with the year-ago ~~period,~~periods, 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~~decreased $4 million and ~~maintenance expenses were comparable~~$3 million at Ameren Illinois Transmission in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, respectively, compared with the year-ago periods, ~~at Ameren Illinois Transmission.~~primarily because of increases in the cash surrender value of COLI due to favorable market returns in 2023, compared with unfavorable market returns in the year-ago periods.

Ameren Illinois Electric Distribution

Other operations and maintenance expenses decreased ~~$14~~$15 million and $8$33 million in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, respectively, compared with the year-ago periods. The following items decreased other operations and maintenance expenses in the three and six months ended June 30, 2023, compared with the year-ago periods (except where a specific period is referenced):

•Bad debt costs decreased $10 million and $23 million, respectively, because of a lower amount of costs included in customer rates pursuant to the associated rider.

•The cash surrender value of COLI increased $5 million and $9 million, respectively, primarily because of favorable market returns in 2023, compared with unfavorable market returns in the year-ago periods.

•Costs for injuries and damages decreased $4 million in both periods, primarily because of ~~decreased customer energy efficiency~~a decrease in claims compared with the year-ago periods.

The above decreases in the three and ~~environmental remediation costs, which are included in cost recovery mechanisms resulting in decreased electric revenues,~~six months ended June 30, 2023, compared with ~~no overall effect on net income. These decreases~~the year-ago periods, were partially offset by ~~an increase~~increases of $2 million and $4 million, respectively, in ~~storm-related repair costs, as well as increased wages and staffing additions.~~the amortization of regulatory assets associated with customer energy-efficiency program investments under formula ratemaking.

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Ameren Illinois Natural Gas

Other operations and maintenance expenses ~~were comparable~~decreased $5 million and $9 million in the three and six months ended June 30, 2023, compared with the year-ago periods, primarily because the cash surrender value of COLI increased $3 million and $5 million, respectively. In the three and six months ended June 30, 2023, the effect of changes in the cash surrender value of COLI resulted in gains of $1 million in both periods, compared with losses of $2 million and $4 million, respectively, in the year-ago periods. Other operations and maintenance expenses also decreased $2 million and $4 million, respectively, because of decreased distribution system expenditures, primarily because of the timing of expenditures.

Depreciation and Amortization Expenses

Increase by Segment

Overall Ameren Increase of $19 Million (QTD YoY)

Overall Ameren Increase of $40 Million (YTD YoY)

Total by Segment(a)

(a)Includes other/intersegment eliminations of $1 million and $1 million in the three months ended ~~September~~June 30, ~~2017,~~2023 and 2022, respectively. Also includes other/intersegment eliminations of $2 million and $2 million in the six months ended June 30, 2023and 2022, respectively..

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Depreciation and amortization expenses increased $19 million, $8 million, and $10 million in the three months ended June 30, 2023, and $40 million, $20 million, and $19 million in the six months ended June 30, 2023, compared with the year-ago ~~period.~~periods, 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 for the three and six months ended June 30, 2023, compared with the year-ago periods, were affected by the following (except where a specific period is referenced), which include the effect of the additional investments at Ameren Missouri:

•Depreciation and amortization rate changes effective February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which increased depreciation and amortization expenses by $11 million, in the six months ended June 30, 2023.

•Increased depreciation and amortization expenses of $11 million for amounts previously deferred under the PISA and RESRAM and subsequently reflected in base rates effective February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, largely due to investments in wind generation, in the six months ended June 30, 2023.

•Depreciation and amortization expenses at Ameren and Ameren Missouri reflected a deferral to a regulatory asset of depreciation and amortization expenses pursuant to PISA and RESRAM. The amount of depreciation and amortization expenses included in base rates for PISA and RESRAM deferrals was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021. The effect of deferrals and increased depreciation and amortization expenses, primarily because of electric system capital additions, increased depreciation

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$3 million and $11 million, respectively.

•The lower net under-recovery of RESRAM eligible expenses increased depreciation and amortization expenses by $2 million in the three months ended June 30, 2023, while the higher net under-recovery of RESRAM eligible expenses decreased depreciation and amortization expenses by $11 million in the six months ended June 30, 2023.

•The impact of the retirement of the Meramec Energy Center in December 2022 resulted in a $3 million increase to depreciation and amortization expenses in the three months ended June 30, 2023, and a $3 million decrease in the six months ended June 30, 2023, primarily due to the deferral in 2022 of the energy center’s depreciation and amortization expenses and resulting amortization of that deferral pursuant to the December 2021 MoPSC electric rate order, which established a five-year recovery period for certain Meramec Energy Center costs beginning February 28, 2022.

Taxes Other ~~operations~~Than Income Taxes

Increase (Decrease) by Segment

Overall Ameren Decrease of $5 Million (QTD YoY)

Overall Ameren Decrease of $20 Million (YTD YoY)

Total by Segment(a)

(a)Includes $2 million, $2 million, $4 million, and ~~maintenance expenses increased~~$4 million at Ameren Transmission in the three months ended June 30, 2023 and 2022, and in the six months ended June 30, 2023 and 2022, respectively. Also includes other/intersegment eliminations of $3 million, $2 million, $7 million, and $6 million in the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2023 and 2022, and in the six months ended June 30, 2023 and 2022, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Taxes other than income taxes decreased $5 million in the three months ended June 30, 2023, compared with the year-ago period, primarily because of increased bad debt, customer energy efficiency, and environmental remediation costs, which are included 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~~decreased sales at Ameren Illinois inNatural Gas and deferral of taxes under the ~~three and nine months ended September 30, 2017, respectively, compared with the year-ago periods, primarily because of additional~~Ameren Missouri electric property ~~plant, and equipment across their respective segments.~~

~~Taxes Other Than Income Taxes~~

tax tracker. Taxes other than income taxes ~~were comparable at each of the Ameren Companies and their respective segments~~decreased $20 million in the ~~three~~six months ended ~~September~~June 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,~~2023, compared with the year-ago period, primarily because of ~~higher property~~a $9 million decrease in excise taxes at Ameren Illinois Natural Gas, primarily resulting from decreased sales. Taxes other than income also decreased $5 million and $2 million at Ameren Missouri and ~~at each~~ Ameren Illinois ~~segment.~~Electric Distribution, respectively, because of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act.

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Other Income, Net

Increase (Decrease) by Segment

Overall Ameren Increase of $20 Million (QTD YoY)

Overall Ameren Increase of $38 Million (YTD YoY)

Total by Segment(a)

(a)Includes $8 million and ~~Expenses~~

$4 million at Ameren

~~Other income, net of expenses, was comparable~~ Transmission in the three months ended ~~September~~June 30, ~~2017, with the year-ago period.~~ 2023 and 2022, respectively.

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

Other income, net, ~~of expenses, decreased $7~~increased $20 million in the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago period, primarily because of increases in the non-service cost component of net periodic benefit income of $7 million, $6 million, and $3 million for activity not reported as part of a segment, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. In the three months ended June 30, 2023, other income, net, also increased $4 million because of higher interest income on under-recovered balances associated with regulatory recovery mechanisms at Ameren Illinois Electric Distribution and $2 million because of higher allowance for equity funds used during construction at Ameren Transmission. Other income, net, increased $38 million in the six months ended June 30, 2023, compared with the year-ago period, primarily because of increases in the non-service cost component of net periodic benefit income of $15 million, $13 million, and $6 million for activity not reported as part of a segment, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. In the six months ended June 30, 2023, other income, net, also increased $7 million because of higher interest income on under-recovered balances associated with regulatory recovery mechanisms at Ameren Illinois Electric Distribution and $4 million because of higher allowance for equity funds used during construction at Ameren Transmission. The increases in other income, net, in the three and six months ended June 30, 2023, were partially offset by $6 million and $11 million decreases, respectively, in interest income on industrial development revenue bonds at Ameren Missouri, as these bonds were settled in December 2022 and January 2023. The increases in other income, net, associated with these bonds are offset by decreases in interest charges on a related financing obligation agreement, as discussed below.

See Note 5 – Other Income, ~~and Expenses~~Net, under Part I, Item 1, of this report for additional information. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for more information on the non-service cost components of net periodic benefit income.

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Interest Charges

Increase (Decrease) by Segment

Overall Ameren Increase of $8 Million (QTD YoY)

Overall Ameren Increase of $31 Million (YTD YoY)

Total by Segment

Ameren Missouri

Ameren Illinois Natural Gas

Other/Intersegment Eliminations

Ameren Illinois Electric Distribution

Ameren Transmission

See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report and the Long-term Debt and Equity section below for additional information on short-term borrowings and long-term debt, respectively, discussed below. See Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information on the termination of the financing obligation agreement discussed below.

Ameren ~~Transmission~~

~~Other income, net of expenses, was comparable~~Interest charges increased $8 million and $31 million in the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago periods. In addition to changes by segments discussed below, interest charges increased $8 million and $14 million, respectively, at Ameren (parent) because of higher interest rates on increased levels of short-term borrowings.

Ameren Missouri

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

~~Ameren Illinois~~

~~Other income, net of expenses, was comparable~~Interest charges decreased $8 million in the three months ended ~~September~~June 30, ~~2017, with the year-ago period, for Ameren Illinois~~2023, and ~~each of its segments. Other income, net of expenses, decreased $5~~increased $4 million in the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago ~~period, primarily because of lower~~periods. The following items increased interest ~~income associated with the IEIMA revenue requirement reconciliation at Ameren Illinois Electric Distribution. Other income, net of expenses, was comparable~~charges in the ~~nine~~three and six months ended ~~September~~June 30, ~~2017,~~2023, compared with the year-ago periods (except where a specific period ~~for the remaining Ameren Illinois segments.~~is referenced):

~~Interest Charges~~

~~Ameren~~

•Interest charges ~~were comparable~~increased $3 million and $8 million, respectively, because of higher interest rates on increased levels of short-term borrowings.

•Issuances of long-term debt in April 2022 and March 2023 collectively increased interest charges by $7 million and $13 million, respectively.

•Interest charges reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM. The amount of interest charges included in base rates for PISA and RESRAM deferrals was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021. Lower deferrals, due to the inclusion in base rates of interest associated with certain property, plant, and equipment previously deferred under the PISA and RESRAM, increased interest charges by $2 million in the six months ended June 30, 2023.

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The following items decreased interest charges in the three and six months ended June 30, 2023 (except where a specific period is referenced):

•Increased PISA and RESRAM deferrals reduced interest charges by $7 million in the three months ended ~~September~~June 30, ~~2017, with the year-ago period.~~ 2023.

•Interest charges ~~increased $8~~decreased $6 million and $11 million, respectively, primarily due to the termination of a financing obligation agreement related to the CT energy center in ~~the nine months ended September 30, 2017, compared with the year-ago period, as discussed below.~~Audrain County.

~~Ameren Transmission~~

•Interest charges ~~were comparable in the three months ended September 30, 2017, with the year-ago period. Interest charges increased $6~~decreased $4 million ~~in the nine months ended September 30, 2017, compared with the year-ago period, primarily~~and $9 million, respectively, because of an increase in ~~average outstanding debt at Ameren Illinois~~the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to increased eligible construction work in process balances and ~~ATXI.~~

~~Ameren Missouri~~

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

Ameren Illinois

Interest charges ~~were comparable~~increased $9 million and $14 million in the three and six months ended ~~September~~June 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,~~2023, compared with the year-ago ~~period,~~periods, primarily ~~because~~due to the issuances of ~~an increase~~long-term debt in ~~average outstanding~~2022. Issuances of long-term debt at Ameren ~~Illinois.~~

Illinois in August and November 2022 collectively increased interest charges by $4 million and $8 million, respectively, at Ameren Illinois Electric Distribution, by $3 million and $6 million, respectively, at Ameren Illinois Transmission, and by $2 million and $4 million, respectively, at Ameren Illinois Natural Gas.

Income Taxes

The following table presents effective income tax rates for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016:~~2022:


	Three Months(a)				Six Months(a)
	2023		2022		2023		2022
Ameren	14	%	15	%	13	%	13	%
Ameren Missouri	(1)	%	(2)	%	(1)	%	(3)	%
Ameren Illinois	25	%	25	%	25	%	26	%
Ameren Illinois Electric Distribution	25	%	26	%	25	%	25	%
Ameren Illinois Natural Gas	27	%	25	%	26	%	27	%
Ameren Illinois Transmission	26	%	25	%	26	%	26	%
Ameren Transmission	26	%	26	%	26	%	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)Estimate of the annual effective income tax rate adjusted to reflect the tax effect of items discrete to the three and six months ended June 30, 2023 and 2022.


~~(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.~~

See Note 12 – Income Taxes under Part I, Item 1, of this report for a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the Ameren Companies.

The effective income tax rate was higher in the three and nine months ended September 30, 2017, compared with the year-ago periods, because of an increase in the Illinois statutory income tax rate, which became effective on July 1, 2017. Additionally, the effective income tax rate was higher in the nine-month period because of a decrease in the recognition of income tax benefits associated with share-based compensation.

~~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~~June 30, ~~2017,~~2023, 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~~higher depreciation differences on property-related ~~items, partially offset by the increase in the Illinois statutory income tax rate.~~items.

~~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). As of June 30, 2023, there have been no material changes other than in the ordinary course of business related to cash requirements arising from these long-term commitments provided in Item 7 of the Form 10-K.

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 target requirements, environmental compliance, and other improvements. ~~We intend to fund those~~For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of the Form 10-K and Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report. As part of its funding plan for capital expenditures, ~~primarily~~Ameren is using newly issued shares of common stock to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2027. Ameren expects these equity issuances to total about $100 million annually. In addition, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. There were no shares issued under the ATM program for the three and six months ended June 30, 2023. As of June 30, 2023, Ameren has entered into multiple forward sale agreements under the ATM program with ~~cash provided~~various counterparties relating to 4.3 million shares of common stock. Ameren expects to settle approximately $300 million

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of the forward sale agreements with physical delivery of 3.2 million shares of common stock by ~~operating activities~~December 31, 2023. Also, Ameren plans to issue approximately $500 million of equity each year from 2024 to 2027, in addition to issuances under the DRPlus and ~~short-term~~employee benefit plans. As of June 30, 2023, Ameren had approximately $910 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of June 30, 2023. Ameren expects its equity to total capitalization to be about 45% by December 31, 2027, with the long-term intent to support solid investment-grade credit ratings. See Long-term Debt and ~~long-term debt issuances so that we maintain an equity ratio around 50%, assuming constructive regulatory environments.~~Equity below and Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information on the ATM program, including the forward sale agreements under the ATM program.

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~~June 30, ~~2017~~,2023, for ~~the~~ Ameren, ~~Companies. The working capital deficit as of September 30, 2017, was primarily the result of current maturities of long-term debt~~Ameren Missouri, and ~~our decision to finance our businesses with lower-cost commercial paper issuances.~~Ameren Illinois. With the credit capacity available under the Credit Agreements, and cash and cash equivalents, Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, had net available liquidity of $1.3 billion at June 30, 2023. Additionally, as of June 30, 2023, Ameren could have settled the ~~Ameren Companies had access~~forward sale agreements with physical delivery of 4.3 million shares of common stock to ~~$1.7 billion~~the respective counterparties in exchange for cash of ~~liquidity atSeptember 30, 2017.~~$389 million. See Credit Facility Borrowings and Liquidity and Long-term Debt and Equity below for additional information.

The following table presents net cash provided by (used in) operating, investing, and financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~:2022:


	Net Cash Provided By Operating Activities								Net Cash Used In Investing Activities						Net Cash Provided By Financing Activities
	2023			2022			Variance		2023		2022		Variance		2023		2022		Variance
Ameren	$	1,111	(a)	$	872	(a)	$	239	$	(1,889)	$	(1,552)	$	(337)	$	808	$	686	$	122

Ameren Missouri	443			181			262		(980)		(818)		(162)		532		636		(104)
Ameren Illinois	637		(a)	675		(a)	(38)		(846)		(699)		(147)		247		37		210

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)Both Ameren and Ameren Illinois’ cash provided by operating activities included cash outflows of $56 million and $37 million for the FEJA electric energy-efficiency rider and $5 million and $3 million for the customer generation rebate program for the six months ended June 30, 2023 and 2022, respectively.


~~(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 regulatory rate ~~proceeding.~~review, subject to prudence reviews. 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.

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, Ameren Missouri and Ameren Illinois had under-recovered costs for the month of February 2021 under their PGA clauses and, for Ameren Missouri, under the FAC (Ameren Missouri – PGA $53 million, FAC $50 million; Ameren Illinois – PGA $221 million). Ameren Missouri’s PGA under-recovery is being collected from customers over 36 months beginning November 2021, pursuant to an October 2021 MoPSC order, and the FAC under-recovery was collected over eight months beginning October 2021. Ameren Illinois collected the PGA under-recovery over 18 months beginning April 2021.

Ameren

Ameren’s cash ~~from~~provided by operating activities increased ~~$84~~$239 million in the first ~~nine~~six months of ~~2017,~~2023, compared with the year-ago period. The following items contributed to the increase:

•A ~~$160~~$237 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.

•A $158 million increase resulting from increased customer collections, primarily from base rate increases effective February 28, 2022, pursuant to Ameren Missouri’s December 2021 electric rate order, electric transmission rate base growth, and an increase attributable to other regulatory mechanisms, partially offset by a decrease under Ameren Illinois’ PGA resulting from the recovery in 2022 of costs for the mid-February 2021 weather event discussed above.

•A $45 million decrease in the cost of natural gas ~~margins, as discussed~~held in ~~Results~~storage, primarily at Ameren Illinois, because of ~~Operations, excluding certain noncash items, as well as the change in customer receivable balances.~~lower commodity prices.

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•A ~~$26~~$40 million decrease in payments for ~~scheduled~~ nuclear refueling and maintenance outages at Ameren Missouri’s Callaway ~~energy center, as~~Energy Center, primarily due to the ~~current year~~spring 2022 outage. Ameren Missouri’s next refueling and maintenance outage ~~began in October 2017, while~~at its Callaway Energy Center is scheduled for 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~~fall 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.~~

2023.

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

~~The absence~~•A $58 million decrease due to the timing of ~~a $42~~payments for accounts payable and prepaid expenses.

•A $54 million ~~insurance receipt~~increase in coal inventory levels at Ameren Missouri, ~~related~~primarily due to ~~the Taum Sauk breach received~~fewer transportation delays and less coal burned 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~~2023 as a result of decreased generation volumes driven by lower market power prices and decreased retail load because of both milder summer temperatures and warmer winter ~~temperatures compared with the prior year.~~temperatures.

~~Ameren Missouri~~

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

An increase in income tax payments of $115 million to Ameren (parent) pursuant to the tax allocation agreement, primarily related to higher taxable income in 2017, due to significantly lower property-related deductions.

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

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

•A ~~$62 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 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.~~

~~Ameren Illinois~~

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

~~An $84 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 $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 deductions 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 under the PGA.~~

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

~~A $13~~$40 million increase in interest payments, primarily due to an increase in the average outstanding ~~debt.~~debt and an increase in interest rates.

•A $23 million increase in purchases of materials and supplies inventories to support operations as levels were increased to mitigate against potential supply disruptions.

•A $12 million decrease resulting from income tax payments of $5 million in 2023, compared with income tax refunds of $7 million in 2022, primarily due to increased income tax extension payments, which are based on the preceding year’s taxable income and estimated payments.

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

Ameren Missouri

Ameren Missouri’s cash provided by operating activities increased $262 million in the first six months of 2023, compared with the year-ago period. The following items contributed to the increase:

•A $199 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.

•A $142 million increase resulting from increased customer collections, primarily from base rate increases effective February 28, 2022, pursuant to the December 2021 electric rate order and an increase attributable to other regulatory mechanisms.

•A $40 million decrease in payments for nuclear refueling and maintenance outages at the Callaway Energy Center, primarily due to the spring 2022 outage. The next refueling and maintenance outage at the Callaway Energy Center is scheduled for the fall of 2023.

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

•A $54 million increase in coal inventory levels, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes driven by lower market power prices and decreased retail load because of both milder summer temperatures and warmer winter temperatures.

•A $16 million increase in purchases of materials and supplies inventories to support operations as levels were increased to mitigate against potential supply disruptions.

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

•A $7 million decrease due to the timing of payments for accounts payable and prepaid expenses.

Ameren Illinois

Ameren Illinois’ cash provided by operating activities decreased $38 million in the first six months of 2023, compared with the year-ago period. The following items contributed to the decrease:

•A $95 million decrease resulting from income tax payments to Ameren (parent) of $64 million in 2023, compared with income tax refunds from Ameren (parent) of $31 million in 2022, pursuant to the tax allocation agreement, primarily due to increased income tax extension payments, which are based on the preceding year’s taxable income and estimated payments.

•A $33 million decrease due to the timing of payments for accounts payable and prepaid expenses.

•A $17 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates.

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

•A $42 million decrease in the cost of natural gas held in storage ~~caused~~because of lower commodity prices.

•A $38 million decrease in net collateral posted with counterparties, primarily ~~by reduced withdrawals as a result~~due to changes in the market prices of ~~milder winter temperatures compared with the prior year.~~power and natural gas.

~~A $5~~•An $16 million increase resulting from increased customer collections, primarily from electric transmission rate base growth and an increase attributable to other regulatory mechanisms, partially offset by a decrease under the PGA resulting from the recovery in ~~payments to contractors~~2022 of

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costs for ~~additional reliability, maintenance, and IEIMA projects.~~the mid-February 2021 weather event discussed above.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased ~~$34~~$337 million induring the first ~~nine~~six months of ~~2017,~~2023, compared with the year-ago period, primarily as a result of a $284 million increase in capital expenditures, largely resulting from increased expenditures for electric transmission upgrades at Ameren Missouri, Ameren Illinois, and ATXI and electric distribution infrastructure upgrades at Ameren Missouri and Ameren Illinois. ATXI’s capital expenditures increased $25 million during the first six months of 2023, compared with the year-ago period. ~~Capital expenditures increased $27 million as a result of activity at~~In addition, in 2022, Ameren Missouri ~~and Ameren Illinois, discussed below, partially offset by a $72~~received $17 million ~~decrease~~ in ~~capital expenditures at ATXI. ATXI’s capital expenditures decreased as a result of decreased expenditures on~~insurance proceeds for the

Illinois Rivers project, partially offset by increased expenditures related to the Spoon River project. Nuclear fuel expenditures increased $11 million as a result of the activity at Ameren Missouri, as discussed below. Callaway Energy Center’s generator.

Ameren Missouri’s cash used in investing activities ~~decreased $269~~increased $162 million ~~between periods,~~during the first six months of 2023, compared with the year-ago period, primarily ~~due to net money pool advances.~~as a result of a $108 million increase in capital expenditures, largely resulting from increased expenditures for electric transmission and distribution infrastructure upgrades. In ~~2017,~~addition, in 2022, Ameren Missouri received ~~$143~~$17 million in returns of net money pool advances, compared to investing $165 million in money pool advances in 2016. The decrease was partially offset by increased capital expenditures 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 ofinsurance proceeds for the ~~timing of purchases in the first nine months of 2017, compared with the prior-year period.~~Callaway Energy Center’s generator.

Ameren Illinois’ cash used in investing activities increased ~~$75~~$147 million ~~between periods largely due to an~~during the first six months of 2023, compared with the year-ago period, as a result of a $145 million increase in capital expenditures, ~~of $77 million primarily related to~~largely resulting from increased expenditures for electric transmission and distribution ~~and transmission system reliability projects, updates to natural gas main~~ infrastructure ~~substation upgrades and investments in smart grid technology.~~upgrades.

Cash Flows from Financing Activities

Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the 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 $122 million during the first ~~nine~~six months of ~~2017,~~2023, compared towith the year-ago period. During the first ~~nine~~six months of ~~2017,~~2023, Ameren utilized ~~net~~ proceeds ~~of $737 million~~ from the issuance of long-term ~~indebtedness and net commercial paper issuances~~debt of $997 million for capital expenditures, to repay ~~at maturity $425 million of higher cost long-term indebtedness~~then-outstanding short-term debt, and to fund, in part, investing activities. In comparison, during the first nine months of 2016, Ameren used net proceeds of $456 million from the issuance of long-term indebtedness and net commercial paper issuances to repay ~~at maturity $389 million of higher cost long-term indebtedness and to fund, in part, investing activities.~~

~~Ameren Missouri’s cash used in financing activities was comparable between periods. During the first nine months of 2017, Ameren Missouri issued $399~~$100 million of long-term indebtedness and used the proceeds, along with cash on hand, to repay at maturity $425 million of higher cost long-term indebtedness. In comparison, during the first nine months of 2016, Ameren Missouri issued $149 million of long-term indebtedness and used the proceeds, along with cash on hand, to repay at maturity $260 million of higher cost long-term indebtedness.debt maturities. In addition, during the first ~~nine~~six months of ~~2017,~~2023, Ameren ~~Missouri paid $332 million in common stock dividends compared with $285 million in dividend payments and the receipt of a $38 million capital contribution in the year-ago period.~~

Ameren Illinois’ financing activities provided cash of $126 million during the first nine months of 2017, compared with $16 million of cash used in financing activities during the year-ago period. During the first nine months of 2017, Ameren Illinois usedutilized proceeds from net commercial paper issuances of ~~$118~~$260 million along with cash provided by operating activities to fund, in part, ~~investing activities.~~capital expenditures. In comparison, during the first ~~nine~~six months of ~~2016,~~2022, Ameren ~~Illinois used~~utilized proceeds of $524 million of long-term debt to repay then-outstanding short-term debt and for capital expenditures. In addition, during the first six months of 2022, Ameren utilized proceeds from net commercial paper issuances of $475 million and cash provided by operating activities to ~~repay at maturity $129 million~~fund, in part, capital expenditures. During the first six months of ~~higher cost long-term indebtedness.~~2023, Ameren ~~Illinois did not pay~~paid common stock dividends ~~during~~of $330 million, compared with $305 million in the ~~nine months ended September 30, 2017, compared to~~year-ago period, as a result of an increase in both the dividend ~~payments~~rate and the number of ~~$95~~common shares outstanding.

Ameren Missouri’s cash provided by financing activities decreased $104 million during the ~~same period in 2016. Additionally, money pool borrowings decreased $43 million,~~first six months of 2023, compared with the year-ago period. During the first six months of 2023, Ameren Missouri utilized proceeds from the issuance of long-term debt of $499 million for capital expenditures and to repay then-outstanding short-term debt. During the first six months of 2023, Ameren Missouri utilized proceeds from net commercial paper issuances of $44 million and cash provided by operating activities to fund, in part, capital expenditures. In comparison, during the first six months of 2022, Ameren Missouri utilized proceeds from the issuance of $524 million to repay then-outstanding short-term debt and for capital expenditures. In addition, during the first six months of 2022, Ameren Missouri utilized proceeds from net commercial paper issuances of $120 million and cash provided by operating activities to fund, in part, capital expenditures.

Ameren Illinois’ cash provided by financing activities increased $210 million during the first six months of 2023, compared with the year-ago period. During the first six months of 2023, Ameren Illinois utilized proceeds from the issuance of long-term debt of $498 million to repay then-outstanding short-term debt and $100 million of long-term debt maturities. In addition, during the first six months of 2023, Ameren Illinois repaid net commercial paper borrowings totaling $147 million. In comparison, during the first six months of 2022, Ameren Illinois utilized proceeds from net commercial paper issuances of $38 million and cash provided by operating activities to fund, in part, capital expenditures.

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 noncash settlement of a financing obligation.

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Credit Facility Borrowings and Liquidity

The following table presents Ameren’s consolidated liquidity ~~needs~~as of June 30, 2023:


	Available at June 30, 2023
Ameren (parent)and Ameren Missouri:
Missouri Credit Agreement – borrowing capacity	$	1,400

Less: Ameren (parent) commercial paper outstanding	494
Less: Ameren Missouri commercial paper outstanding	373

Less: Ameren Missouri letters of credit	1
Missouri Credit Agreement – subtotal	532
Ameren (parent) and Ameren Illinois:
Illinois Credit Agreement – borrowing capacity	1,200

Less: Ameren (parent) commercial paper outstanding	345
Less: Ameren Illinois commercial paper outstanding	117


Illinois Credit Agreement – subtotal	738
Subtotal	$	1,270
Add: Cash and cash equivalents	7
Net Available Liquidity(a)	$	1,277

(a)Does not include Ameren’s forward equity sale agreements. See Note 4 – Long-term Debt and ~~Ameren Illinois are typically supported through the use~~Equity Financings under Part I, Item 1, of ~~available cash, commercial paper issuances, short-term intercompany borrowings, or drawings under the~~this report for additional information.

The Credit ~~Agreements.~~Agreements, among other things, provide $2.6 billion of credit until maturity in December 2027. 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~~Agreements. During the six months ended June 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 of the Credit Agreements are available to Ameren to support issuances under Ameren’s commercial paper program, subject to borrowing sublimits. The Missouri Credit Agreement is available to support issuances under Ameren Missouri’s commercial paper program. The Illinois Credit Agreement is available to support issuances under Ameren Illinois’ commercial paper program. Issuances under the2023, 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 the 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.

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, and relevant 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,~~January 2023, the FERC issued ~~an order~~orders authorizing Ameren Missouri, Ameren Illinois, and ATXI to issue up to $1 billion, $1 billion, and $300 million, respectively, of short-term debt securities through ~~July 2019.~~January 2025.

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.

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Long-term Debt and Equity

The following table presents ~~the~~ issuances (net of any issuance premiums or discounts)~~, maturities,~~ of long-term debt and ~~redemptions~~equity, as well as maturities of long-term debt for the six months ended June 30, 2023 and 2022:


	Month Issued, Redeemed, or Matured	2023			2022
Issuances of Long-term Debt



Ameren Missouri:
5.45% First mortgage bonds due 2053	March	499			—
3.90% First mortgage bonds due 2052(a)	April	—			524
Ameren Illinois:
4.95% First mortgage bonds due 2033	May	498			—




Total Ameren long-term debt issuances		$	997		$	524
Issuances of Common Stock
Ameren:
DRPlus and 401(k)(b)(c)	Various	$	16		$	17


Total Ameren common stock issuances(d)		$	16		$	17

Maturities of Long-term Debt
Ameren Missouri:
Audrain County agreement (Audrain County CT) due 2023	January	$	240	(e)	$	—


Ameren Illinois:
0.375% First mortgage bonds due 2023	June	100
Total Ameren long-term debt maturities		$	340		$	—

(a)Ameren Missouri intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligible criteria.

(b)Ameren ~~Illinois,~~issued a total of 0.2 million and ~~ATXI~~0.3 million shares of common stock under its DRPlus and 401(k) plan for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016. The Ameren Companies did not issue any~~2022, respectively.

(c)Excludes a $7 million and $8 million receivable at June 30, 2023 and 2022, respectively.

(d)Excludes 0.5 million and 0.4 million shares of common stock ~~during~~valued at $37 million and $31 million issued for no cash consideration in connection with stock-based compensation for the ~~first nine~~six months ~~of 2017 or 2016.~~ ended June 30, 2023 and 2022, respectively.

(e)In ~~March 2016,~~January 2023, 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~~Audrain County mutually agreed to ~~issue $450 million principal amount~~terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of ~~3.43% senior unsecured notes, due 2050, through a private placement offering exempt from registration under~~ the ~~Securities Act of 1933,~~agreement as ~~amended. ATXI issued $150~~the $240 million principal amount of the ~~notes in June 2017~~financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri.

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, including Ameren Missouri’s March 2023 issuance of first mortgage bonds, the use of those proceeds, Ameren’s forward equity sale agreements, 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).ATM program.

Indebtedness Provisions and Other Covenants

At June 30, 2023, 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 agreements. 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)~~provisions, and covenants contained in our credit agreements, in ATXI’s note purchase ~~agreement,~~agreements, 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 and credit 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 and credit markets, could negatively affect our ability to maintain and expand our businesses. After assessing ~~its~~their respective 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.~~and credit markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital and credit markets or make access to the capital and credit markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital and credit 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

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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, Ameren’s board of directors declared a quarterly common stock dividend of 45.75 cents per share payable on December 29, 2017, 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.

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~~June 30, ~~2017~~,2023, 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~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~:

2022:

Nine Months
2017 2016
Ameren Missouri $ 332
$ 285
Ameren Illinois —
95
Ameren 320
309


	Six Months
	2023		2022
Ameren	$	330	$	305


ATXI	75		—

~~Contractual Obligations~~

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

At September 30, 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 were immaterial and cash collateral posted by external parties were ~~immaterial at~~$46 million for Ameren ~~Ameren Missouri,~~ and Ameren Illinois at ~~September~~June 30, ~~2017.~~2023. 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~~June 30, ~~2017,~~2023, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade and contractual obligations amounting to ~~$89~~$587 million, ~~$48~~$526 million, and ~~$41~~$61 million, respectively.

Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at ~~September~~June 30, ~~2017,~~2023, if market prices were 15% higher or lower than ~~September~~June 30, ~~2017~~2023 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, orand Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade and contractual obligations.

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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~~2023 and beyond.

~~Operations~~

Ameren continues to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The Illinois Rivers project involves the construction of a transmission line from eastern Missouri across the For additional information regarding recent rate orders, lawsuits, and pending requests filed with state ~~of Illinois to western Indiana. Construction activities for the Illinois Rivers project are continuing on schedule,~~ and the last section of this project is expected to be completed by 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. Seefederal regulatory commissions, including those discussed below, 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.

Operations

•We are observing inflationary pressures on the prices of certain commodities, labor, services, materials, and supplies, as well as increasing interest rates. Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for ~~information regarding~~fuel, purchased power, and natural gas supply. Additionally, for certain non-commodity cost changes, the ~~Mark Twain project~~use of trackers, riders, formula ratemaking, and future test years, as applicable, mitigates our exposure. The inflationary pressures and increasing interest rates could impact our ability to control costs and/or make substantial investments in our businesses, including our ability to recover costs and investments, and to earn our allowed ROEs within frameworks established by our regulators, while maintaining rates that are affordable to our customers. In addition, these inflationary pressures and increasing interest rates could adversely affect our customers’ usage of, or payment for, our services.

•The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense for investments in qualifying property, plant, and equipment placed in service and not included in base rates. Investments not eligible for recovery under the PISA include amounts related to new nuclear and natural gas generating units and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC until added to rate base prospectively. Ameren Missouri recognizes an offset to interest charges for its cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its ~~approval process~~cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are 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 to comply with Missouri’s renewable energy standard. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the ~~Illinois Rivers project.~~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. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. The ~~total investment~~rate increase approved by the June 2023 MoPSC electric rate order did not exceed the rate increase limitation applicable through 2023. Missouri Senate Bill 745 became effective on August 28, 2022. The law extended Ameren Missouri’s PISA election through December 2028 and allows for an additional extension through December 2033 if requested by Ameren Missouri and approved by the MoPSC, among other things. The law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates due to the inclusion of incremental PISA deferrals in ~~all three projects is expected~~the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024, and will be based on the revenue requirement established in the immediately preceding rate order.

•In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to ~~be more than $540~~Ameren Missouri’s annual revenue requirement for electric retail service. The order increased the annualized base level of net energy costs pursuant to the FAC by approximately $40 million from ~~2017~~the base level established in the MoPSC’s December 2021 electric rate order. The order also changed annualized depreciation, regulatory asset and liability amortization amounts, and the base level of expenses for trackers. On an annualized basis, these changes reflect approximate increases in “Depreciation and amortization” of $90 million and “Other income, net”, of $100 million, related to non-service pension and postretirement benefit income, on Ameren’s and Ameren Missouri’s consolidated statements of income. The new rates became effective on July 9, 2023. As a result of this order, Ameren Missouri expects a year-over-year increase to 2023 earnings, compared to 2022, of approximately $44 million ($11 million in the second quarter, $23 million in the third quarter, and $10 million in the fourth quarter).

•In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency and demand response programs through ~~2019.~~December 2023. Ameren ~~Illinois~~Missouri intends to invest approximately $350 million over the life of the plan, including $75 million in 2023. 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 spending goals are achieved for 2023, the performance incentive would result in revenues of $12 million in 2023.

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•In August 2023, Ameren Missouri, the MoPSC staff, and the MoOPC filed a nonunanimous stipulation and agreement with the MoPSC to extend Ameren Missouri’s MEEIA 2019 program through 2024. The stipulation and agreement, which is subject to MoPSC approval, includes the establishment of a portfolio of customer energy-efficiency programs for 2024 and performance incentives that would provide Ameren Missouri an opportunity to earn revenues, including $12 million if Ameren Missouri achieves certain energy-efficiency goals in 2024. If approved, Ameren Missouri expects to invest ~~$2.2 billion~~$76 million in ~~electric transmission assets from 2017 through 2021~~energy-efficiency programs in 2024. The MoPSC is under no deadline to ~~replace aging infrastructure and improve reliability.~~issue an order in this proceeding.

~~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~~expected rate ~~calculations that will become effective on January 1, 2018,~~base 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~~10.52% ROE, which includes 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~~50-basis-point incentive adder for participation in an RTO, the revenue requirements included in 2023 rates for Ameren Illinois’ and ~~require customer refunds, with interest,~~ATXI’s electric transmission businesses are $476 million and $194 million, respectively. These revenue requirements represent an increase in Ameren Illinois’ revenue requirement of $54 million and a decrease in ATXI’s revenue requirement of $1 million from the revenue requirements reflected in 2022 rates, primarily due to higher expected rate base at Ameren Illinois and a lower expected rate base at ATXI. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2023, but will not determine their respective electric transmission service operating revenues, which will instead be based on 2023 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 ~~that 15-month period.~~ ~~The timing~~FERC-regulated transmission rates previously charged under the MISO tariff is the subject of pending proceedings. Depending on the outcome of the ~~issuance of~~proceedings, the ~~final order in~~transmission rates charged during previous periods and the ~~February 2015 complaint case is uncertain for two reasons.~~ ~~First, while~~currently effective rates may be subject to change and refund. In March 2020, the FERC ~~reestablished~~issued a ~~quorum~~Notice of ~~commissioners~~Proposed Rulemaking on its transmission incentives policy, which increased the incentive ROE for participation in ~~August 2017 after six months without~~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 ~~quorum,~~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 ~~order. Second, in~~rule on this matter. Ameren is unable to predict the ~~second quarter~~ultimate impact of ~~2017, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded~~any changes to the ~~FERC an~~FERC’s incentives policy, or any further order ~~in a separate case in which the FERC established the allowed~~on 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.ROE. A ~~50 basis point reduction~~50-basis-point change in the FERC-allowed ~~base return on common equity~~ROE would ~~reduce Ameren's~~affect Ameren’s and Ameren ~~Illinois'~~Illinois’ annual ~~earnings~~net income by an estimated $7$14 million and $4$10 million, respectively, based on each company’s ~~2017~~2023 projected rate base.

•Ameren ~~and~~Illinois’ electric distribution service performance-based formula ratemaking framework under the IEIMA allows Ameren Illinois ~~recorded current~~to reconcile electric distribution service rates to its actual revenue requirement on an annual basis to reflect actual recoverable costs incurred and a return at the applicable WACC on year-end rate base through 2023. 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 ~~liabilities on their respective September 30, 2017~~asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance ~~sheets, representing their estimate~~is then collected from, or refunded to, customers within two years from the end of the ~~expected refunds~~year. Pursuant to December 2022 and March 2021 ICC orders, Ameren Illinois used the current IEIMA formula framework to establish annual customer rates effective through 2023, and will reconcile the related revenue requirement for customer rates established for 2023. As such, Ameren Illinois’ 2023 revenues will reflect actual recoverable costs, year-end rate base, and a return at the applicable WACC, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points. By law, the decoupling provisions extend beyond the end of existing performance-based formula ratemaking, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. In April 2023, Ameren Illinois filed for a reconciliation adjustment to its 2022 electric distribution service revenue requirement with the ICC. In July 2023, Ameren Illinois filed a revised reconciliation adjustment, requesting recovery of $125 million. An ICC decision in this proceeding is required by December 2023, and any approved adjustment would be collected from customers in 2024.

•Pursuant to the ~~February 2015 complaint case.~~IETL, which was enacted in September 2021, Ameren Illinois may file an MYRP with the ICC to establish base rates for electric distribution service to be charged to customers for each calendar year of a four-year period. The base rates for a particular calendar year are based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ forecasted average annual rate base using a forecasted capital structure, with a common equity ratio of up to 50% being deemed prudent and reasonable by law and a higher equity ratio requiring specific ICC approval. The ROE determined by the ICC for each calendar year of the four-year period is subject to annual adjustments based on certain performance incentives and penalties. An MYRP allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis, subject to a reconciliation cap and adjustments to the ROE. If a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment would be 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 would then be collected from, or refunded to, customers within two years from the end of the applicable annual period. Ameren Illinois’ existing riders will remain effective under the MYRP discussed below, and will continue to remain effective beyond 2027 whether it elects to file an MYRP or a traditional regulatory rate review. Additionally, electric distribution service revenues continue to be decoupled from sales volumes under either election.

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•In ~~March 2017,~~January 2023, Ameren Illinois filed an MYRP with the ~~MoPSC~~ICC. In July 2023, Ameren Illinois filed a revised MYRP requesting approval of forecasted revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,291 million, $1,387 million, $1,484 million, and $1,560 million, respectively. Pursuant to a provision under the IETL that permits initial rate increases under an MYRP to be phased in, Ameren Illinois’ filing proposes to defer 50% of the requested 2024 rate increase of $179 million as a regulatory asset to be collected from customers in 2026. That regulatory asset would earn a return at the applicable WACC. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024. Ameren Illinois cannot predict the level of any electric distribution service rate change the ICC may approve, or whether any rate change that may eventually be approved will be sufficient for Ameren Illinois to recover its costs to the extent those costs are subject to and exceed the MYRP reconciliation cap and earn a reasonable return on its investments when the rate change goes into effect. If the rates approved by the ICC are materially different from its forecasted spend, Ameren Illinois may adjust its overall spending, both operating and capital.

•In December 2022, the ICC issued an order ~~approving a unanimous stipulation and agreement~~ in Ameren ~~Missouri’s July 2016 regulatory rate review.~~ ~~The order resulted in~~Illinois’ annual update filing that approved a ~~$3.4 billion revenue requirement, which is a $92~~$61 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~~Illinois’ electric distribution ~~revenue requirement necessary to reflect the actual costs incurred and investment return~~service rates beginning in ~~a given year with the revenue requirement that was reflected in customer rates for that year. Consequently,~~January 2023. Ameren ~~Illinois' 2017~~Illinois’ 2023 electric distribution service revenues will be based on its ~~2017~~2023 actual recoverable costs, 2023 year-end rate base, and a return at the applicable WACC, with the ROE component based 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~~annual average of ~~an expected increase in recoverable costs, expected rate base growth of 5%, and an expected increase in~~ the monthly ~~average~~yields of the 30-year United States Treasury ~~bonds.~~bonds plus 580 basis points. As of June 30, 2023, Ameren Illinois expects its 2023 electric distribution year-end rate base to be $4.2 billion. The ~~2017~~2023 revenue requirement reconciliation ~~is expected to result in a regulatory asset that~~adjustment will be collected from, or refunded to, customers in ~~2019.~~2025. A ~~50 basis point~~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 $7$12 million change in ~~Ameren's~~Ameren’s and Ameren ~~Illinois'~~Illinois’ annual net income, based on Ameren Illinois’ ~~2017~~2023 projected year-end rate ~~base.~~base, including electric energy-efficiency investments. Ameren Illinois’ recognized ROE for the first half of 2023 was based on an annual average of the monthly yields of the 30-year United States Treasury bonds of 3.84%.

•In ~~April 2017,~~January 2023, Ameren Illinois filed a request with the ICC seeking approval to increase its annual ~~electric distribution service formula rate update~~revenues for natural gas delivery service. In July 2023, Ameren Illinois filed a revised request seeking to ~~establish~~increase its annual revenues by $148 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the ~~revenue requirement~~QIP and other riders. In an attempt to reduce regulatory lag, Ameren Illinois used ~~for 2018 rates. In June 2017,~~a 2024 future test year in this proceeding. A decision by the ICC ~~staff submitted its calculation of the revenue requirement, which~~in this proceeding is required by late November 2023, with new rates expected to be effective in early December 2023. Ameren Illinois ~~supported in~~cannot predict the level of any delivery service rate change the ICC may approve, nor whether any rate change that may eventually be approved will be sufficient to enable Ameren Illinois to recover its ~~revised July 2017 filing,~~costs and ~~recommended~~to earn a ~~decrease~~reasonable return on investments when the rate changes go into effect. Without legislative action, the QIP will expire after December 2023.

•Pursuant to ~~the electric distribution service revenue requirement. Pending ICC approval, this update filing will result in a~~ ~~$17 milliondecrease in~~Illinois law, 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~~energy-efficiency investments ~~will be~~are deferred as a regulatory asset and ~~will~~ earn a return at the ~~company’s weighted average cost of capital,~~applicable WACC, with the ~~equity return~~ROE component based on the annual average of the monthly ~~average yield~~yields of the 30-year United States Treasury bonds plus 580 basis points. The ~~equity portion of Ameren Illinois’ return~~allowed ROE on electric ~~energy efficiency~~energy-efficiency investments can ~~also~~ be increased or decreased by up to 200 basis points, ~~based~~depending on the achievement of annual energy savings goals. ~~Based on Ameren Illinois’ 2018 through 2021 energy efficiency~~While the ICC has approved a plan ~~and a formula provided in the FEJA,~~for Ameren Illinois ~~estimates it can annually~~to invest ~~up to $99~~approximately $120 million ~~from 2018 through 2021, up to $107 million annually from 2022~~per year in electric energy-efficiency programs through 2025, ~~and up to $114 million annually from 2026 through 2030. The~~the ICC has the ability to ~~lower~~reduce the amount of electric ~~energy efficiency saving~~energy-efficiency savings goals in future program years if there are insufficient ~~cost effective measures~~cost-effective programs available, ~~or if achieving~~which could reduce the ~~savings goals would require investment levels that exceed the formula amounts shown above.~~investments in electric energy-efficiency programs. The electric ~~energy efficiency~~energy-efficiency program investments and the return on those investments ~~will be recovered~~are collected from customers through a rider and ~~will~~are not berecovered through the electric distribution service performance-based formula ratemaking framework.

•In May 2023, the MISO released the results of its April 2023 capacity auction, which included capacity price decreases in the ~~IEIMA formula rate process. See Note 2 – Rate~~central region of the MISO footprint, where Ameren Missouri’s and ~~Regulatory Matters under Part I, Item 1,~~Ameren Illinois’ service territories are located. Capacity prices decreased from $237 per MW-day for June 2022 through May 2023 pursuant to the April 2022 capacity auction to seasonal prices ranging from $2 to $15 per MW-day for June 2023 through May 2024. Based on estimated power prices and customer demand as of ~~this report for information regarding~~June 30, 2023, the capacity prices set by the April 2023 MISO auction, and the amounts of energy and capacity hedged through IPA procurement events, Ameren Illinois ~~approved~~estimates a decrease to purchased power costs for calendar year 2023, compared to 2022, of approximately $100 million. The actual decrease to purchased power costs will vary due to differences between estimated and realized power prices as well as customer demand satisfied by Ameren Illinois, which will be affected by changes in customers’ elections to use Ameren Illinois or an alternative retail electric supplier for their energy ~~efficiency program for 2018 through 2021.~~

~~In July 2017, Illinois enacted~~needs. Because of the power procurement riders, the difference between actual purchased power costs and costs billed to customers in a ~~law that increased the state's corporate~~given period is deferred as a regulatory asset or liability. These pass-through costs do not affect Ameren Illinois’ net income, ~~tax rate from~~ ~~7.75% to 9.5%~~ as ~~of July 1, 2017. The law made the increase~~any change in ~~the state’s corporate income taxrate, which was previously scheduled to decrease to~~ ~~7.3%~~costs are offset by a corresponding change in ~~2025,~~ ~~permanent. In July 2017, Ameren recordedan expense of $14 million at Ameren (parent)~~revenues. Also, largely due to the ~~revaluation~~capacity price set by the April 2023 MISO auction, Ameren Missouri estimates decreases to capacity revenues and purchased power costs for the calendar year 2023, compared to 2022, of ~~accumulated deferred taxes~~approximately $100 million. Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. Capacity revenues and purchased power costs are a part of the net energy costs recoverable under the FAC, with 95% of the variance between net energy costs and the ~~estimated state apportionment~~amount set in base rates recovered or refunded through the FAC.

Table 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.Contents

~~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~~Missouri’s next refueling and maintenance outage at its Callaway ~~energy center began in October 2017.Ameren Missouri expects to incur $32 million~~Energy Center is scheduled for the fall of ~~maintenance expenses, which approximates the cost of the spring 2016 outage.~~2023. During a scheduled ~~outage,~~refueling, which occurs every 18 months, maintenance expenses ~~increase relative~~are deferred as a regulatory asset and amortized until the completion of the next refueling and maintenance outage. Ameren Missouri expects to ~~non-outage years. Additionally,~~incur approximately $40 million in maintenance expenses related to the fall 2023 outage. During an outage, depending on the availability of its other generation sources and the market prices for power, Ameren ~~Missouri's~~Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess

power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri ~~does not have a scheduled refueling and~~may incur increased non-nuclear energy center maintenance ~~outage~~costs in ~~2018.~~non-outage years.

~~Ameren and~~•In December 2021, Ameren Missouri ~~expect~~filed a motion with the United States District Court for the Eastern District of Missouri to modify a September 2019 remedy order issued by the district court to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. The March 30, 2024 compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. In 2022, in response to an ~~approximately $15 million decrease in annual interest charges~~Ameren Missouri request for a final, binding reliability assessment, the MISO designated the Rush Island Energy Center as a ~~result~~system support resource and concluded that certain mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation for the Rush Island Energy Center through August 2024, and in July 2023, an agreement between Ameren Missouri and the MISO was filed with the FERC for approval that details the manner of continued operation for the ~~repayment of $425 million of Ameren Missouri’s 6.40% senior secured notes at maturity~~Rush Island Energy Center that results in operating during peak demand times and ~~issuance of $400 million 2.95% senior secured notes in 2017. In 2018,~~emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. The FERC is under no deadline to issue an order. The transmission upgrade projects have been approved by the MISO, and construction activities necessary to complete the upgrades are underway. Ameren Missouri expects to ~~refinance maturing long-term debt with lower-cost long-term debt,~~complete the last of the upgrades by mid-2025. In August 2023, Ameren Missouri requested the district court to extend the March 30, 2024 compliance date to October 15, 2024, at which ~~would further reduce Ameren’s~~point Ameren Missouri proposes to retire the Rush Island Energy Center. In addition, in October 2022, the FERC established hearing and settlement procedures in response to an August 2022 request from Ameren Missouri for recovery of non-energy costs under the related MISO tariff. In May 2023, a settlement agreement between Ameren Missouri and certain intervenors in the non-energy costs proceeding at the FERC, which provides for recovery of substantially all of 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.

requested non-energy costs through August 2023, was filed with the FERC for approval. The FERC is under no deadline to issue an order. Revenues and costs under the MISO tariff are included in the FAC. The district court has the authority to determine the retirement date and operating parameters for the Rush Island Energy Center and is not bound by the MISO determination of the Rush Island Energy Center as a system support resource or the FERC’s approval. The district court is under no deadline to issue a ruling modifying the remedy order. For additional information ~~regarding recent rate orders, lawsuits,~~on the ~~Westinghouse bankruptcy filing,~~NSR and ~~pending requests filed with state and federal regulatory commissions,~~Clean Air Act litigation, see Note 29 – ~~Rate~~Commitments and ~~Regulatory Matters and Note 10 – Callaway Energy Center~~Contingencies under Part I, Item 1, of this ~~report and Note 2 – Rate and Regulatory Matters under Part II, Item 8,~~report. In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the ~~Form 10-K.~~Rush Island Energy Center, including potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. In Ameren Missouri’s last electric service regulatory rate review, the MoPSC staff recommended a lower rate base for the Rush Island Energy Center claiming imprudent actions by Ameren Missouri. While the nonunanimous stipulation and agreement approved in that regulatory rate review by the June 2023 MoPSC electric rate order did not specify any rate base disallowance, it did not preclude parties to the agreement from raising issues regarding the prudence of Ameren Missouri’s actions and decisions with regard to the energy center in future proceedings. As part of the assessment of any potential future abandonment loss, consideration will be given to rate and securitization orders issued by the MoPSC to Ameren Missouri and to orders issued to other Missouri utilities with similar facts.

•Pursuant to Illinois state law, Ameren Missouri’s natural gas-fired energy centers in Illinois are subject to limits on emissions, including CO2 and NOx, equal to their unit-specific average annual emissions from 2018 through 2020, for any rolling twelve-month period through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by 2029. The reductions could also limit the operations of Ameren Missouri’s other four natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to certain conditions, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service.

•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, increasing inflation, higher cost of debt, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective advancements in innovative energy technologies, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by

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increased demand resulting from increased electrification of the economy 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 new generation sources, will result in rate base and revenue growth but also higher depreciation and financing costs.

Liquidity and Capital Resources

•Ameren Missouri’s preferred resource plan is included in its 2022 Change to the 2020 IRP. In connection with this plan, Ameren is targeting net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels. Ameren’s goals include both direct emissions from operations (scope 1), as well as electricity usage at Ameren buildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. Achieving these goals will be dependent on a variety of factors, including cost-effective advancements in innovative clean energy technologies and constructive federal and state energy and economic policies. The 2022 Change to the 2020 IRP includes, among other things, the following:

•the continued implementation of customer energy-efficiency programs;

•expanding renewable sources by adding 2,800 MWs of renewable generation by 2030, 400 MWs of battery storage by 2035, and a total of 4,700 MWs of renewable generation and 800 MWs of battery storage by 2040. These amounts include the solar generation projects discussed below;

•adding 1,200 MWs of natural gas-fired combined cycle generation by 2031, with plans to switch to hydrogen fuel and/or blend hydrogen fuel with natural gas and install carbon capture technology if these technologies become commercially available at a reasonable cost;

•adding 1,200 MWs of additional clean dispatchable generation by 2043;

•the expectation that Ameren Missouri ~~files~~will seek and receive NRC approval for an extension of the operating license for the Callaway Energy Center beyond its current 2044 expiration date;

•extending the retirement date of the coal-fired Sioux Energy Center from 2028 to 2030 to ensure reliability during the transition to clean energy generation;

•accelerating the retirement date of the Rush Island coal-fired energy center to 2025;

•retiring the Meramec coal-fired energy center at the end of its useful life, which was completed in December 2022;

•retiring the generating units at the Labadie coal-fired energy center at the end of their useful lives (two generating units by 2036 and the other two by 2042);

•accelerating the retirement date of the Venice natural gas-fired energy center to 2029; and

•retiring Ameren Missouri’s other natural gas-fired energy centers in Illinois by 2040.

Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources or natural gas-fired combined cycle generation, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability to enter into agreements for renewable or natural gas-fired combined cycle generation and acquire or construct that generation at a ~~non-binding 20-year~~reasonable cost; the ability of suppliers, contractors, and developers to meet contractual commitments and timely complete projects, which is dependent upon the availability of necessary labor, materials, and equipment, geopolitical conflict, or government actions, among other things; changes in the scope and timing of projects; the ability to qualify for, and use or transfer, federal production or investment tax credits; the cost of wind, solar, and other renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to maintain system reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; energy prices and demand; Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion, the inability to earn an adequate return on invested capital; and the ability to raise capital on reasonable terms. The next integrated resource plan will be filed in September 2023.

•Missouri law allows Missouri electric utility companies to petition the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance the cost of retiring electric generation facilities before the end of their useful lives. In connection with the planned accelerated retirement of the Rush Island Energy Center due to the NSR and Clean Air Act Litigation discussed above, Ameren Missouri expects to seek approval from the MoPSC ~~every three years.~~as early as the fourth quarter of 2023, to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds.

•During 2022 and 2023, Ameren Missouri, and certain subsidiaries of Ameren Missouri, entered into agreements to acquire and/or construct various solar generation facilities, with various regulatory approvals pending. All of the solar generation facilities are aligned with the 2022 Change to the 2020 IRP discussed above, and capital expenditures related to these facilities are included in Ameren’s and Ameren Missouri’s ~~integrated resource plan filed with the MoPSC in September 2017~~ ~~includes~~ expected capital investments discussed below.

•Ameren Missouri’s ~~preferred plan for meeting customers’ projected long-term energy needs in a cost-effective fashion that maintains system reliability as it~~2022 Change to the 2020 IRP targets cleaner and more diverse sources of energy generation, including solar

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generation. ~~These new renewable energy sources would also support Ameren Missouri’s compliance with~~While rights to acquire and/or construct the ~~state~~solar facilities discussed above were secured through agreements, supply chain disruptions, including solar panel shortages and increasing material costs as a result 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,government tariffs and other factors, could affect the costs, as well as ~~100 megawatts~~the timing, of these projects and other solar generation projects. The supply of solar ~~generation over~~panel components to the ~~next 10 years,~~United States was significantly disrupted as a result of an investigation initiated by the United States Department of Commerce in late March 2022, which could result in significant tariffs on solar panel components imported from four Southeast Asian countries. The investigation is in response to a petition, which alleged that Chinese solar manufacturers shifted solar panel component manufacturing to these countries to avoid tariffs imposed on imports from China. In December 2022, the United States Department of Commerce issued a preliminary determination, finding that all exporters and producers of solar panel components from the four Southeast Asian countries, with ~~50 megawatts anticipated~~a few exceptions, have been circumventing tariffs imposed on imports from China. As a result of the preliminary determination, importers and exporters may avoid the imposition of increased tariffs by certifying to ~~come online~~the United States Department of Commerce that the entry of solar panel components into the United States are not subject to the investigation or that they fall within the scope of the 24-month waiver of tariffs discussed below. Failure to submit the applicable certifications, or denial of the submitted certifications by ~~2025.~~the United States Department of Commerce, could result in increased tariffs on solar panel components that are subject to the investigation and entered the United States on or after April 1, 2022. The ~~new wind generation~~United States Department of Commerce is expected to ~~be located in Missouri~~issue a final determination by mid-August 2023. Additionally, certain solar panel components from China have been subject to detention by the United States Customs and ~~neighboring states. The source, location, and cost~~Border Protection Agency as a result of the ~~new wind~~Uyghur Forced Labor Prevention Act that became effective in June 2022. Also, in June 2022, President Biden authorized the United States Department of Energy to use the Defense Production Act to rapidly expand American manufacturing of five critical clean energy technologies, including solar panel components. President Biden also took executive action to temporarily lift certain tariffs on solar panel components imported from the four Southeast Asian countries under investigation by the United States Department of Commerce for 24 months in order to allow the United States access to a sufficient supply of solar panel components to meet electricity generation ~~among~~needs while domestic manufacturing scales up. Any future tariffs or other ~~items, remain subject to reaching agreements with developers.Based on current~~outcomes resulting from the investigation by the United States Department of Commerce or actions by the United States Customs and ~~projected market prices for energy,~~Border Protection Agency could affect the cost 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. 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 credits related to renewable energy~~solar panel components and ~~its ability to use such credits;~~ the ~~cost~~timing and amount of ~~wind and~~Ameren Missouri’s estimated capital expenditures associated with 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 any other required project approvals.investments.


•	~~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.~~

•Through ~~2021,~~2027, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest ~~in total~~ up to ~~$11.2~~$20.5 billion (Ameren Missouri – up to ~~$4.2~~$10.8 billion; Ameren Illinois – up to ~~$6.4~~$9.5 billion; ATXI – up to ~~$0.6~~$0.2 billion) of capital expenditures during the period from ~~2017~~2023 through ~~2021.~~2027. These planned investments are based on the assumption of continued constructive regulatory frameworks. Ameren’s and Ameren Missouri’s estimates ~~do not reflect the potential additional~~include $2.5 billion of renewable generation investments ~~identified~~through 2027 consistent with investments outlined in Ameren Missouri’s ~~integrated resource plan~~2022 Change to the 2020 IRP. Ameren’s estimate also includes $0.8 billion of capital expenditures through 2027 related to projects assigned to Ameren pursuant to the first tranche of projects under the MISO’s long-range transmission planning roadmap discussed ~~above, which could represent incremental investments~~below.

•As a result of major storms experienced throughout our service territories in late June and July 2023, Ameren Missouri and Ameren Illinois expect capital expenditures related to restoration costs of approximately $1$65 million to $80 million and $60 million to $75 million, respectively.

•In 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate. Construction on the Ameren projects is expected to begin in 2025, with completion dates expected near the end of this decade. The MISO initiated requests for proposals for additional first tranche competitive bid projects in December 2022, June 2023, and July 2023, with proposals due in May 2023, November 2023, and October 2023, respectively. These competitive-bid projects are estimated by the MISO to cost approximately $0.7 billion and are expected to be awarded between late-2023 and mid-2024. In November 2022, the MISO released plans for a second tranche of projects and began the process of identifying a list of projects for consideration under this tranche. Ameren expects the second tranche of projects to be approved in the first half of 2024. In July 2022, a group of industrial customers filed a complaint with the FERC, challenging provisions of a MISO tariff that exclude regional transmission projects from the MISO’s competitive bid process based on state laws related to the right of first refusal, which provide an incumbent utility the right to build, maintain, and own transmission lines located within its service territory. The complaint seeks to require MISO to revise its tariff to prohibit the application of state laws related to the right of first refusal in the MISO’s long-range transmission planning and require projects to be bid on a competitive basis, to the maximum extent possible. It also is asking for refunds related to any costs under the tariff that would not comply with the sought-after revisions. The FERC is under no deadline to issue an order in this proceeding.

•In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from MISO’s April 2022 capacity auction, the ICC issued an order requiring

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Ameren Illinois to perform a cost-benefit study of continued participation in the MISO compared to participation in PJM Interconnection LLC, another RTO. In July 2023, Ameren Illinois filed its cost-benefit study with the ICC. The cost-benefit study examined the impacts of participation in each RTO, including reliability, resiliency, affordability, and environmental impacts, among other things, for a period of five to 10 years, beginning June 2024. The study concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. The ICC is under no obligation to issue an order related to the cost-benefit study.

•Environmental regulations, including those related to CO2 emissions, or other actions taken by the EPA or state regulators, or requirements that may result from the NSR and Clean Air Act Litigation, could result in significant increases in capital expenditures and operating costs. Regulations can be reviewed and repealed, and replacement or alternative regulations can be proposed or adopted by the current federal administration, including the EPA. See Note 9 – Commitments and Contingencies under Part I, Item 1, of this report, for additional information on environmental matters, including the NSR and Clean Air Act litigation. The ultimate implementation of any of these new regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal and natural gas-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances, as well as regulatory ~~approval. Ameren and Ameren Missouri will evaluate alternatives for funding these potential additional investments.~~

•

~~Environmental regulations, including those related to CO~~₂emissions, or other actions taken by the EPA could result in significant increases in capital expenditures and operating costs. Certain of these regulations are being challenged through litigation or are being reviewed by the EPA, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing environmental regulations could result in significant capital expenditures, increased operating costs, the closure or alteration of some of Ameren Missouri's coal-fired energy centers, or require further capital investment. Ameren Missouri's capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances as well as regulatory

lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. ~~Ameren's~~Ameren’s and Ameren ~~Missouri's~~Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.

•The Ameren Companies have multiyear credit agreements that cumulatively provide ~~$2.1~~$2.6 billion of credit through December ~~2021,~~2027, subject to a 364-day repayment term ~~in the case of~~for Ameren Missouri and Ameren ~~Illinois.~~Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $3.2 billion. See Note 43 – Short-term Debt and Liquidity under Part I, Item 1, of this report and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for additional information regarding the Credit Agreements. BySee Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, in the ~~end~~Form 10-K for long-term debt maturities from 2023 to 2027 and beyond at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI and see Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of ~~2018, $378 million and $707 million~~this report for principal payments made on long-term debt during 2023 through the date of ~~senior secured notes are scheduled to mature at~~this report. Ameren, Ameren Missouri, and Ameren Illinois respectively. Ameren Missouri and Ameren Illinois expect to refinance these senior secured notes, as well as a portion of any outstanding short-term debt at the time, with long-term debt. Ameren, Ameren Missouri, and Ameren Illinoiseach believe that their liquidity is adequate given their respective expected operating cash flows, capital expenditures, and ~~related~~ financing ~~plans.~~plans, and expect to continue to have access to the capital and credit markets on reasonable terms when needed. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.

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

As of September 30, 2017, Ameren had $450 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $4 million and Ameren Illinois – $115 million) and $116 million in federal and state income tax credit carryforwards (Ameren Missouri – $31 million and Ameren Illinois – $2 million). In addition, Ameren has $7 million of expected state income tax refunds and state overpayments. Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities for Ameren Missouri and Ameren Illinois until 2021. These tax benefits, primarily at the Ameren (parent) level, when realized, would be available to support funding Ameren Transmission investments. Based on existing tax laws, Ameren does not expect to make material federal income tax payments until 2021 and Ameren and Ameren Missouri do not expect to make material state income tax payments until 2021. Due to differences between federal and state tax laws, Ameren and Ameren Illinois expect to begin making material state income tax payments in 2018.

Since the 2016 presidential and congressional elections, there have been various legislative proposals to reform the federal income tax code. Tax law changes that would affect our businesses include those changes associated with the statutory federal corporate income tax rate, interest deductibility, tax deductions for capital investments, the availability of federal production tax credits and our ability to use them, and state and local tax deductibility. Changes to the normalization of income taxes for ratemaking and return of excess deferred tax liabilities to customers could also affect our businesses. Depending on the magnitude and mix of any implemented changes, federal income tax reform could materially affect our results of operations, financial position, and liquidity.

•Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2027. Ameren expects these equity issuances to total about $100 million annually. In addition, Ameren has an ATM program under which Ameren may offer and sell from time to time common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. As of June 30, 2023, Ameren had multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 4.3 million shares of common stock. Ameren expects to ~~use debt~~settle approximately $300 million of the forward sale agreements with physical delivery of 3.2 million shares of common stock by December 31, 2023. Also, Ameren plans to ~~fund such cash shortfalls. If cash flows change materially~~issue approximately $500 million of equity each year from ~~those expected, such~~2024 to 2027, in addition to issuances under the DRPlus and employee benefit plans. As of June 30, 2023, Ameren had approximately $910 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of June 30, 2023. Ameren expects its equity to total capitalization to be about 45% by December 31, 2027, with the long-term intent to support solid investment-grade credit ratings. Ameren Missouri and Ameren Illinois expect to fund cash flow needs ~~associated~~through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent).

•The IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates clean energy tax credits for projects placed in service after 2024. The clean energy tax credits will apply to renewable energy production and investments, along with certain nuclear energy production, and will be phased out beginning in 2033, at the earliest. The phase-out is triggered when greenhouse gas emissions from the electric generation industry are reduced by at least 75% from the annual 2022 emission rate or at the beginning of 2033, whichever is later. The law allows for transferability to an unrelated party for cash of up to 100% of certain tax credits generated after 2022. In addition, the new law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after

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December 31, 2022. Once a corporation exceeds this three-year average annual adjusted financial statement income threshold, it will be subject to the minimum tax for all future tax years. Additional regulations, interpretations, amendments, or technical corrections to or in connection with the ~~potential investments identified~~IRA are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren as discussed below.

•As of June 30, 2023, Ameren had $198 million in tax benefits from federal and state income tax credit carryforwards and $48 million in tax benefits from federal and state net operating loss carryforwards, which will be utilized in future periods. Future expected income tax payments are based on expected taxable income, available income tax credit and net operating loss carryforwards, and current tax law. Expected taxable income is affected by expected capital expenditures, when property, plant, and equipment is placed in-service or retired, and the timing of regulatory reviews, among other things. Ameren expects federal income tax payments at the required minimum levels from 2023 to 2027 resulting from the anticipated use of existing production tax credits generated by Ameren Missouri’s ~~integrated resource plan,~~High Prairie Renewable and Atchison Renewable energy centers, existing income tax credit and net operating loss carryforwards, and outstanding refunds. Based on its preliminary calculations, Ameren ~~will reevaluate its funding plan.~~does not expect to be subject to the 15% minimum tax on adjusted financial statement income imposed by the IRA in 2023 and 2024. Ameren expects annual federal income tax payments, including payments related to the 15% minimum tax pursuant to the IRA, to be immaterial through 2027.

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

REGULATORY MATTERS

See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the

forward-looking statements. We handle market risk in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.

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

~~With the exception of the following, there~~There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, ~~equity~~commodity price risk, ~~commodity~~investment price risk, and commodity supplier risk included in the Form 10-K. In the first quarter of 2017, Ameren Missouri’s supplier of nuclear fuel assemblies, Westinghouse, filed a voluntary petition for a court-supervised restructuring process under Chapter 11 of the United States Bankruptcy Code. At this time, Ameren and Ameren Missouri believe the restructuring proceeding will not affect Westinghouse’s performance under the terms of its existing contracts with Ameren Missouri, and therefore do not expect any material impact to Ameren Missouri’s operations10-K, except as a result of this restructuring proceeding. Ameren Missouri received all necessary fuel assemblies for the fall 2017 refueling and maintenance outage. See Note 10 – Callaway Energy Center under Part I, Item 1, of this report for additional information.discussed below. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risk.

~~Fair Value~~Ameren Missouri received a planned delivery of ~~Contracts~~

~~We use derivatives principally to manage the risk of changes in market prices for natural gas, power, and~~enriched uranium ~~as well as the risk of changes in rail transportation surcharges through fuel oil hedges. The following table presents the favorable (unfavorable) changes~~from a Russian supplier in the ~~fair value~~spring of ~~all derivative~~2023. The planned delivery concluded the nuclear fuel supply agreement with this Russian supplier with no future deliveries planned with any Russian suppliers. Ameren Missouri has sufficient inventory and supply contracts ~~marked-to-market during the three and nine months ended September 30, 2017. We use various methods to determine the fair value of our contracts. In accordance~~ with authoritative accounting guidance for fair value hierarchy levels, the sources we used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methodsnon-Russian suppliers that are not corroborated by market data (Level 3). See Note 7 – Fair Value Measurements under Part I, Item 1, of this report for additional information regarding the methods used to determine the fair value of these contracts.

Three Months Nine Months

Ameren
Missouri

Ameren
Illinois
Ameren Ameren
Missouri Ameren
Illinois Ameren
Fair value of contracts at beginning of period, net $ 2
$ (205 ) $ (203 ) $ (4 ) $ (180 ) $ (184 )
Contracts realized or otherwise settled during the period (1 ) 6
5
(3 ) 2
(1 )
Fair value of new contracts entered into during the period 1
—
1
10
(2 ) 8
Other changes in fair value 2
(5 ) (3 ) 1
(24 ) (23 )
Fair value of contracts outstanding at end of period, net $ 4
$ (204 ) $ (200 ) $ 4
$ (204 ) $ (200 )

~~The following table presents maturities of derivative contracts as of~~ ~~September 30, 2017, based on the hierarchy levels used to determine the fair value~~adequately meet all of the ~~contracts:~~nuclear fuel needs of the Callaway Energy Center through the 2026 refueling reload.

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.

ITEM 4. CONTROLS AND PROCEDURES.


~~(a)~~	~~Evaluation of Disclosure Controls and Procedures~~

(a)Evaluation of Disclosure Controls and Procedures

As of ~~September~~June 30, ~~2017~~,2023, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and the principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of ~~September~~June 30, ~~2017~~,2023, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive officer and its principal financial officer, to allow timely decisions regarding required disclosure.


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

(b)Changes in Internal Controls over Financial Reporting

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

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except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. ~~Material~~We believe that we have established appropriate reserves for potential losses. For additional information on material legal and administrative proceedings, ~~which are discussed in~~ see Note 2 – Rate and Regulatory Matters, Note 9 – Commitments and Contingencies, and Note 10 – Callaway Energy Center, under Part I, Item 1, of this ~~report include the following:~~report. Pursuant to Item 103(c)(3)(iii) of Regulation S-K, our policy is to disclose environmental proceedings to which a governmental entity is a party if we reasonably believe such proceedings will result in monetary sanctions of $1 million or more.

~~ATXI’s request for certificate of convenience and necessity from the MoPSC for the Mark Twain project;~~

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

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

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

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

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

ITEM 1A. RISK FACTORS.

~~A detailed discussion of our~~There have been no material changes to the risk factors ~~is included~~disclosed in Part I, Item 1A, Risk Factors in the Form 10-K. ~~The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in the Form 10-K.~~

~~Our operations are subject to acts of terrorism, cyber-attacks, and other intentionally disruptive acts.~~

Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and information systems may be affected by terrorist activities and other intentionally disruptive acts, including cyber-attacks, which could disrupt our ability to produce or distribute our energy products. Within our industry, there have been attacks on energy infrastructure such as power plants, substations, and related assets in the past, and there may be more attacks in the future. Any such incident could limit our ability to generate, purchase, or transmit power or natural gas and could have significant regional economic consequences. Any such disruption could result in a significant decrease in revenues, a significant increase in costs including those for repair, or adversely impact economic activity in our service territory which could adversely affect our results of operations, financial position, and liquidity.

There has been an increase in the number and sophistication of cyber-attacks across all industries around the world. A security breach at our physical assets or in our information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, including nuclear generation, and/or subject us to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer, employee, financial, and operating system information. Many of our suppliers, vendors, contractors, and information technology providers have access to our systems that support our operations and maintain customer and employee data. A breach of these third-party systems could adversely affect our business as if it was a breach of our own system. If a significant breach occurred, our reputation could be adversely affected, customer confidence could be diminished, or we could be subject to legal claims, any of which could result in a significant decrease in revenues or significant costs for remedying the impacts of such a breach. Our generation, transmission, and distribution systems are part of an interconnected system. Therefore, a disruption caused by a cyber-incident at another

utility, electric generator, RTO, or commodity supplier could also adversely affect our businesses. In addition, new regulations could require changes in our security measures and result in increased costs. The occurrence of any of these events could adversely affect our results of operations, financial position, and liquidity.

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

Ameren Corporation, Ameren Missouri, and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from ~~July~~April 1, ~~2017~~2023, to ~~September~~June 30, ~~2017~~.2023.

ITEM 5. OTHER INFORMATION.

Insider Adoption or Termination of Trading Arrangements

During the fiscal quarter ended June 30, 2023, none of our directors or officers informed us of the adoption or termination of a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Regulation S-K, Item 408.

Table of Contents

ITEM 6. EXHIBITS.

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

Exhibit
Designation

Registrant(s)

Nature of Exhibit

Previously Filed as Exhibit to:

~~Exhibit~~

~~Designation~~

~~Registrant(s)~~

~~Nature of Exhibit~~

~~Previously Filed as Exhibit to:~~

Instruments Defining Rights of Security Holders, Including Indentures

4.1

Ameren
Ameren Illinois

~~Ameren~~

~~Ameren Illinois~~

Supplemental Indenture , dated as of ~~October 25, 2017,~~May 1, 2023, to the Ameren Illinois Mortgage for 4 .9 5% First Mortgage Bonds due 20 3 3

May 31, 2023 Form 8-K, Exhibit 4.2, File No. 1-3672

Material Contracts

10.1

Ameren Ameren Missouri

First Amendment, dated as of April 19, 2023, to Amended and Restated Credit Agreement, dated as of December 6, 2022, by and among Ameren, Ameren Missouri and JPMorgan Chase Bank, N.A., as agent and the lenders party thereto

10.2

Ameren Ameren Illinois

First Amendment, dated as of April 19, 2023, to Amended and Restated Credit Agreement, dated as of December 6, 2022, by and among Ameren, Ameren Illinois ~~Mortgage~~and JPMorgan Chase Bank, N.A., as agent and the lenders party thereto

~~Statement re: Computation of Ratios~~

~~12.1~~

~~Ameren~~

~~Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges~~

~~12.2~~

~~Ameren~~

~~Missouri~~

~~Ameren Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements~~

~~12.3~~

~~Ameren~~

~~Illinois~~

~~Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements~~

Rule 13a-14(a) / 15d-14(a) Certifications

31.1

Ameren

Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren

31.2

Ameren

Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren

31.3

Ameren Missouri

~~Ameren~~

~~Missouri~~

Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri

31.4

Ameren Missouri

~~Ameren~~

~~Missouri~~

Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri

31.5

Ameren Illinois

~~Ameren~~

~~Illinois~~

Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois

31.6

Ameren Illinois

~~Ameren~~

~~Illinois~~

Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois

Section 1350 Certifications

32.1

Ameren

Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren

32.2

Ameren Missouri

~~Ameren~~

~~Missouri~~

Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri

32.3

Ameren Illinois

~~Ameren~~

~~Illinois~~

Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois

Interactive Data Files

101.INS

Ameren

Companies

Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH

Ameren

Companies

Inline XBRL Taxonomy Extension Schema Document

101.CAL

Ameren

Companies

Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB

Ameren

Companies

Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE

Ameren

Companies

Inline XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF

Ameren

Companies

Inline XBRL Taxonomy Extension Definition Document

104

Ameren Companies

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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

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

SIGNATURES

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



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

Date: ~~November~~August 3, ~~2017~~

2023


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~~	262,749,535
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~~June 30, ~~2017~~2023



¨☐			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
			Consolidated Statement of Income		8
			Consolidated Balance Sheet		89
			Consolidated Statement of Cash Flows		910
			Consolidated 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		2023
			Note 6. Derivative Financial Instruments		2023
			Note 7. Fair Value Measurements		2325
			Note 8. ~~Related Party~~Related-party Transactions		28
			Note 9. Commitments and Contingencies		29
			Note 10. Callaway Energy Center		3233
			Note 11. Retirement Benefits		34
			Note 12. ~~Segment Information~~Income Taxes		3435
			Note 13. Supplemental Information		35
			Note 14. Segment Information		38
Item 2.			Management’s Discussion and Analysis of Financial Condition and Results of Operations		3742
Item 3.			Quantitative and Qualitative Disclosures About Market Risk		6276
Item 4.			Controls and Procedures		6476

PART IIII. Other Information

Item 1.			Legal Proceedings		6476
Item 1A.			Risk Factors		6477
Item 2.			Unregistered Sales of Equity Securities and Use of Proceeds		6577
Item 6.5.			~~Exhibits~~Other Information		6577
Item 6.			Exhibits		78

Signatures					6679


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016			2023		2022		2023		2022
Operating Revenues:									Operating Revenues:
Electric	$	1,594	$	1,725	$	4,183	$	4,101	Electric	$	1,585	$	1,513	$	3,175	$	2,831
Natural gas	129		134		592		619		Natural gas	175		213		647		774
Total operating revenues	1,723		1,859		4,775		4,720		Total operating revenues	1,760		1,726		3,822		3,605
Operating Expenses:									Operating Expenses:
Fuel	199		205		594		574		Fuel	152		83		265		259
Purchased power	162		178		491		451		Purchased power	328		318		823		495
Natural gas purchased for resale	25		34		196		227		Natural gas purchased for resale	42		80		250		373
Other operations and maintenance	402		411		1,229		1,246		Other operations and maintenance	450		491		898		952

Depreciation and amortization	225		211		668		628		Depreciation and amortization	335		316		655		615
Taxes other than income taxes	129		129		364		358		Taxes other than income taxes	124		129		251		271
Total operating expenses	1,142		1,168		3,542		3,484		Total operating expenses	1,431		1,417		3,142		2,965
Operating Income	581		691		1,233		1,236		Operating Income	329		309		680		640
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	82		62		160		122
Interest Charges	97		97		295		287		Interest Charges	134		126		261		230
Income Before Income Taxes	495		604		964		982		Income Before Income Taxes	277		245		579		532
Income Taxes	205		233		376		356		Income Taxes	38		36		75		70

Net Income	290		371		588		626		Net Income	239		209		504		462
Less: Net Income Attributable to Noncontrolling Interests	2		2		5		5		Less: Net Income Attributable to Noncontrolling Interests	2		2		3		3

Net Income Attributable to Ameren Common Shareholders	$	288	$	369	$	583	$	621	Net Income Attributable to Ameren Common Shareholders	$	237	$	207	$	501	$	459

Net Income									Net Income	$	239	$	209	$	504	$	462
Other Comprehensive Income (Loss), Net of Taxes									Other Comprehensive Income (Loss), Net of Taxes
Pension and other postretirement benefit plan activity, net of income taxes of $—, $—, $—, and $—, respectively									Pension and other postretirement benefit plan activity, net of income taxes of $—, $—, $—, and $—, respectively	(1)		—		(2)		1
Comprehensive Income									Comprehensive Income	238		209		502		463
Less: Comprehensive Income Attributable to Noncontrolling Interests									Less: Comprehensive Income Attributable to Noncontrolling Interests	2		2		3		3
Comprehensive Income Attributable to Ameren Common Shareholders									Comprehensive Income Attributable to Ameren Common Shareholders	$	236	$	207	$	499	$	460


Earnings per Common Share – Basic	$	1.19	$	1.52	$	2.40	$	2.56	Earnings per Common Share – Basic	$	0.90	$	0.80	$	1.91	$	1.78


Earnings per Common Share – Diluted	$	1.18	$	1.52	$	2.39	$	2.56	Earnings per Common Share – Diluted	$	0.90	$	0.80	$	1.90	$	1.77

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	262.6		258.2		262.4		258.0
Weighted-average Common Shares Outstanding – Diluted									Weighted-average Common Shares Outstanding – Diluted	263.2		259.4		263.2		259.2


	September 30, 2017			December 31, 2016				June 30, 2023		December 31, 2022
ASSETS							ASSETS
Current Assets:							Current Assets:
Cash and cash equivalents	$	9		$	9		Cash and cash equivalents	$	7	$	10
Accounts receivable – trade (less allowance for doubtful accounts of $20 and $19, respectively)	507			437
Accounts receivable – trade (less allowance for doubtful accounts of $39 and $31, respectively)							Accounts receivable – trade (less allowance for doubtful accounts of $39 and $31, respectively)	482		600
Unbilled revenue	262			295			Unbilled revenue	378		446
Miscellaneous accounts receivable	85			63			Miscellaneous accounts receivable	63		54
Inventories	547			527			Inventories	711		667

Current regulatory assets	75			149			Current regulatory assets	239		354

Investment in industrial development revenue bonds							Investment in industrial development revenue bonds	—		240
Current collateral assets							Current collateral assets	20		142
Other current assets	96			113			Other current assets	119		155

Total current assets	1,581			1,593			Total current assets	2,019		2,668
Property, Plant, and Equipment, Net	20,906			20,113			Property, Plant, and Equipment, Net	32,351		31,262
Investments and Other Assets:							Investments and Other Assets:
Nuclear decommissioning trust fund	672			607			Nuclear decommissioning trust fund	1,075		958
Goodwill	411			411			Goodwill	411		411

Regulatory assets	1,509			1,437			Regulatory assets	1,790		1,426
Pension and other postretirement benefits							Pension and other postretirement benefits	442		411
Other assets	538			538			Other assets	859		768

Total investments and other assets	3,130			2,993			Total investments and other assets	4,577		3,974
TOTAL ASSETS	$	25,617		$	24,699		TOTAL ASSETS	$	38,947	$	37,904
LIABILITIES AND EQUITY							LIABILITIES AND EQUITY
Current Liabilities:							Current Liabilities:
Current maturities of long-term debt	$	777		$	681		Current maturities of long-term debt	$	350	$	340
Short-term debt	446			558			Short-term debt	1,329		1,070
Accounts and wages payable	548			805			Accounts and wages payable	719		1,159
Taxes accrued	159			46
Interest accrued	106			93
Customer deposits	108			107
Current regulatory liabilities	119			110

Other current liabilities	318			274			Other current liabilities	845		797

Total current liabilities	2,581			2,674			Total current liabilities	3,243		3,366
Long-term Debt, Net	6,922			6,595			Long-term Debt, Net	14,328		13,685
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	3,913		3,804

Regulatory liabilities	2,045			1,985			Regulatory liabilities	5,445		5,309
Asset retirement obligations	631			635			Asset retirement obligations	775		763
Pension and other postretirement benefits	711			769

Other deferred credits and liabilities	469			477			Other deferred credits and liabilities	417		340

Total deferred credits and other liabilities	8,627			8,185			Total deferred credits and other liabilities	10,550		10,216
Commitments and Contingencies (Notes 2, 9, and 10)							Commitments and Contingencies (Notes 2, 9, and 10)
Ameren Corporation Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – 242.6 shares outstanding	2			2
Shareholders’ Equity:							Shareholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 262.7 and 262.0, respectively							Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 262.7 and 262.0, 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	6,880		6,860
Retained earnings	1,830			1,568			Retained earnings	3,817		3,646
Accumulated other comprehensive loss	(21		)	(23		)	Accumulated other comprehensive loss	(3)		(1)
Total Ameren Corporation shareholders’ equity	7,345			7,103

Total shareholders’ equity							Total shareholders’ equity	10,697		10,508
Noncontrolling Interests	142			142			Noncontrolling Interests	129		129
Total equity	7,487			7,245			Total equity	10,826		10,637
TOTAL LIABILITIES AND EQUITY	$	25,617		$	24,699		TOTAL LIABILITIES AND EQUITY	$	38,947	$	37,904



	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



		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)



		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



~~Commission~~



		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



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	)