What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-02-18 compared with 2024-02-29 · 606 added, 667 removed, 681 unchanged (65% of the section changed)

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All intercompany transactions have been eliminated.

Ameren Missouri’s subsidiaries were created for the ownership of renewable generation projects.

Ameren Illinois has no subsidiaries.

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We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per diluted share.

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Our core strategy is driven by the following three pillars, which allow us to capitalize on opportunities to benefit our customers, communities, shareholders, and the environment:

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By prudently investing in our businesses, we believe that we deliver superior value to both customers and shareholders.

We seek to partner with our stakeholders, including our customers, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers and shareholders.

We seek to partner with our stakeholders, including our customers, communities, regulators, federal and state legislators, and RTOs, to enhance our regulatory frameworks and advocate for responsible energy and economic policies for the benefit of our customers, communities, and shareholders.

We believe enhancing our regulatory frameworks is important to drive investment in our business segments, earn competitive returns on those investments, and realize timely recovery of our costs with the benefits accruing to both customers and shareholders.

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Regulatory Frameworks (c)

Improved Reliability (f)

Electric Customer Rates (f)

Segment Regulatory Framework

Transmission Formula ratemaking

Transmission Formula ratemaking with initial rates based on a future test year

Allowed ROE of 10.48%

Ameren Illinois

Distribution Future test year ratemaking under an MYRP (d)

Distribution Future test year ratemaking under an MYRP (d) and RBA

Allowed ROE of 8.72% (e)

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(d) In January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order in its MYRP proceeding.

(d) Ameren Illinois filed appeals of the December 2023 and June 2024 orders, and intends to file an appeal of the December 2024 ICC order, in its MYRP proceeding.

For more information on the MYRP proceeding, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(e) Ameren Illinois’ formula ratemaking framework related to energy-efficiency investments uses an allowed ROE of the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points, subject to performance standards discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.

(f) As measured by Ameren Missouri’s and Ameren Illinois’ System Average Interruption Frequency Index.

(f) Average residential electric prices.

Edison Electric Institute, ‘Typical Bills and Average Rates Report’ for the 12 months ended June 30, 2024.

Key announcements, updates, and regulatory outcomes

In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service.

The approved revenue requirement was 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 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 compliance 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 such tax credits allowed under the IRA.

The order 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 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.

Table of Conten t s

In June 2023, Ameren Missouri filed for CCNs with the MoPSC for four solar generation facilities, including 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).

In February 2024, Ameren Missouri, the MoPSC staff, and the MoOPC filed a nonunanimous stipulation and agreement requesting the MoPSC approve Ameren Missouri’s requests for CCNs for the Split Rail, Vandalia, and Bowling Green solar projects.

The stipulation and agreement also requests MoPSC approval of the CCN request for the Cass County Solar Project conditioned upon the facility supporting the Renewable Solutions Program and full subscription of the portion of the program supported by this facility, subject to certain other terms and conditions.

The remaining intervenors did not object to the agreement.

Ameren Missouri expects a decision by the MoPSC in March 2024.

Each project is expected to support Ameren Missouri’s transition to renewable generation and, in addition, the Cass County Solar Project is expected to support Ameren Missouri’s Renewable Solutions Program.

In February and April 2023, the MoPSC issued orders approving requested CCNs for the Huck Finn and Boomtown solar projects, respectively.

In August 2023, the MoPSC issued an order approving a nonunanimous stipulation and agreement to extend Ameren Missouri’s MEEIA 2019 program for an additional year through 2024.

For 2024, the order approved the establishment of a portfolio of customer energy-efficiency programs and performance incentives that will provide Ameren Missouri an opportunity to earn revenues, including $12 million of performance incentive revenues if Ameren Missouri achieves certain program spending goals.

In 2024, Ameren Missouri expects to invest $76 million in energy-efficiency programs.

In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA for 2025 through 2027.

The proposed plan includes a portfolio of customer energy-efficiency programs, along with 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.

If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027.

In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals.

If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan.

Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals.

Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.

In November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility.

Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance.

In February 2024, the MoPSC staff filed a response to Ameren Missouri’s petition that stated Ameren Missouri’s decision to accelerate the retirement of the Rush Island Energy Center was prudent and largely supported Ameren Missouri’s securitization request.

However, the MoPSC staff claimed Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, were imprudent and recommended that the impact of those actions on customers be considered in future rate reviews.

If Ameren Missouri is not allowed to recover Rush Island Energy Center costs through securitization or if future rate reviews result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act Litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.

In September 2023, the United States District Court for the Eastern District of Missouri granted Ameren Missouri’s request to modify a September 2019 remedy order issued by the district court in order to allow the retirement of the Rush Island Energy Center in advance of its previously expected retirement date of 2039, in lieu of installing a flue gas desulfurization system.

Ameren Missouri retired the Rush Island Energy Center on October 15, 2024.

In December 2024, the United States District Court for the Eastern District of Missouri issued an order resolving all outstanding claims in this case.

The order requires Ameren Missouri to fund a program to provide electric buses and charging stations to schools in the metro St.

Louis area and a program to provide air purifiers to eligible Ameren Missouri electric residential customers.

These programs are estimated to cost approximately $64 million.

As of December 31, 2024, Ameren and Ameren Missouri recorded liabilities of $64 million and charges of $59 million in 2024 related to the cost of these programs.

In June 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service.

In February 2025, Ameren Missouri filed an updated electric rate increase request seeking approval to increase its annual revenues for electric service by $446 million .

The electric rate increase request is based on a 10.25% ROE, a capital structure composed of 52% common equity, a rate base of $13.9 billion, and a test year ended March 31, 2024, with certain pro-forma adjustments through the true-up date of December 31, 2024.

In February 2025, the MoPSC staff recommended an increase to Ameren Missouri's annual electric service revenues of $384 million based on a 9.74% ROE, a capital structure composed of 52% common equity, and a rate base of $13.9 billion.

The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by May 2025 and new rates effective by June 2025.

In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF to finance $476 million of costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs.

Ameren Missouri will collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance.

The securitized tariff bonds were issued in December 2024.

The financing order also included a determination that the decision to retire the Rush Island Energy Center was reasonable and prudent.

The MoPSC did not make a determination regarding the prudency of Ameren Missouri's prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation discussed in Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, however, claims regarding such actions could be considered in future regulatory proceedings.

If future regulatory proceedings result in revenue reductions based on Ameren Missouri’s prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation, it could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.

In 2024, the MoPSC issued orders approving requested CCNs for the Split Rail, Vandalia, Bowling Green, and Cass County solar projects .

Ameren Missouri acquired the Cass County, Boomtown, and Huck Finn solar projects in June 2024, September 2024, and October 2024, respectively, and placed the assets of the projects, totaling $1 billion, in service in December 2024.

In October 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement filed by Ameren Missouri, the MoPSC staff, and other intervenors requesting a CCN for the Castle Bluff Natural Gas Project.

The order also includes the use of a post-construction cost deferral related to the project, which allows Ameren Missouri to defer and recover depreciation expense, financing costs, and applicable income taxes incurred from the date the project is placed in service to the date when project costs are reflected in updated base rates as a result of a regulatory rate review.

The period of deferral would be limited to the earlier of the time the project costs are reflected in base rates or six months.

In September 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for natural gas delivery service by $40 million.

The natural gas rate increase request is based on a 10.25% ROE, a capital structure composed of 52% common equity, a rate base of $531 million, and a test year ended March 31, 2024, with certain pro-forma adjustments expected through the true-up date of December 31, 2024.

The MoPSC proceeding relating to the proposed natural gas delivery service rate changes will take place over a period of up to 11 months, with a decision by the MoPSC expected by August 2025 and new rates effective by September 2025.

In November 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement for Ameren Missouri’s MEEIA 2025 plan, which includes a portfolio of customer energy-efficiency and demand response programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from customers its actual MEEIA program costs, related lost electric revenues, and performance incentives.

Ameren Missouri intends to invest $51 million annually in 2025 and 2026 and $22 million in 2027 for customer energy-efficiency and demand response programs.

In addition, the order approved performance incentives applicable to each plan year to earn revenues by achieving certain spending and demand response goals.

If 100% of the goals are achieved in 2025, 2026, and 2027, Ameren Missouri would earn performance incentive revenues of $5 million, $5 million, and $2 million, respectively.

In February 2025, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2025.

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Investments under the plan are expected to total approximately $16.2 billion over the five-year period from 2025 through 2029, with expenditures largely recoverable under the PISA.

Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding.

Rate changes consistent with the order became effective in January 2024.

The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months .

Ameren Illinois expects to file a revised Grid Plan with the ICC in March 2024, and also expects to file a request to update the associated MYRP revenue requirements for 2024 through 2027 in the first half of 2024.

The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027, using the 2022 year-end rate base approved by the ICC in its 2022 electric distribution service revenue requirement reconciliation adjustment order discussed below.

This rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement.

In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order.

The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA.

In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include

Table of Conten t s

a base level of investments to maintain grid reliability in each year of the MYRP, among other things.

In January 2024, the ICC partially denied Ameren Illinois’ rehearing request by denying Ameren Illinois’ request regarding the allowed ROE, and granting Ameren Illinois’ request to consider whether it is appropriate to use the 2022 year-end rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP.

Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP.

In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements and annual rate base amounts to reflect a base level of investments to maintain grid reliability for 2024 through 2027.

An ICC decision in this rehearing is expected by late June 2024.

Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order and the partial denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District.

The court is under no deadline to address the appeal.

Ameren Illinois cannot predict the ultimate outcome of the revised Grid Plan filing, its request to update the associated MYRP revenue requirements for 2024 through 2027, the rehearing proceeding, or the appeal to the Illinois Appellate Court for the Fifth Judicial District.

The following table presents the approved revenue requirements, ROE, capital structure common equity percentage, and annual rate base in the ICC’s December 2023 order, as well as the proposed revenue requirements and annual rate base amounts in Ameren Illinois’ February 2024 rehearing request filing:

Year Revenue Requirement (in millions) ROE Capital Structure Common Equity Percentage Annual Rate Base (in billions)

ICC’s December 2023 MYRP Order:

2024 $1,162 8.72% 50% $3.9

2025 $1,210 8.72% 50% $3.9

2026 $1,242 8.72% 50% $3.9

2027 $1,255 8.72% 50% $3.9

Ameren Illinois’ February 2024 Rehearing Request Filing:

2024 $1,214 (a) 50% $4.2

2025 $1,300 (a) 50% $4.5

2026 $1,371 (a) 50% $4.7

2027 $1,420 (a) 50% $4.9

(a) The ROE is under appeal as discussed above.

The approved revenue requirements in the ICC’s December 2023 order represent a cumulative increase of $142 million compared to a cumulative increase of $444 million requested by Ameren Illinois in its revised September 2023 MYRP filing.

The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase.

In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing.

This order approved a reconciliation adjustment of $110 million , which reflected Ameren Illinois’ actual 2022 recoverable costs, year-end rate base of $3.9 billion , and a capital structure composed of 50% common equity.

The approved reconciliation adjustment will be collected from customers in 2024.

In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base.

The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.

Ameren Missouri’s Smart Energy Plan includes approximately $1 billion in capital expenditures that may be necessary to comply with regulations issued by the EPA in 2024 relating to CO 2 emissions and MATS, if such regulations are not revised or overturned.

See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, for additional information on the EPA regulations.

The Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million based on a 9.44% allowed ROE, a capital structure composed of 50% common equity, and a rate base of approximately $2.85 billion.

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In December 2023, Ameren Illinois filed a request for rehearing of the ICC's November 2023 order.

The filing requested the ICC revise the order to include an allowed ROE of at least 9.89%, a capital structure composed of 52% common equity, and a reversal of the approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things.

In January 2024, the ICC denied Ameren Illinois’ rehearing request.

Subsequently, in January 2024, Ameren Illinois filed an appeal of the November 2023 ICC order and the January 2024 ICC denial of Ameren Illinois’ request for rehearing to the Illinois Appellate Court for the Fifth Judicial District.

The court is under no deadline to address the appeal.

Ameren Illinois cannot predict the ultimate outcome of this appeal.

transmission capital investments included in the order, among other things.

In January 2024, the ICC denied Ameren Illinois’ rehearing request, and Ameren Illinois filed an appeal with the Illinois Appellate Court for the Fifth Judicial District.

In January 2025, the appellate court ruled on the appeal filed by Ameren Illinois.

In that ruling, the court reversed a reduction of planned transmission capital investments of $48 million, but affirmed the ICC-approved 9.44% ROE and the remaining reduction of planned distribution capital investments.

Ameren Illinois took prudent steps to align its operations with the ICC order, while continuing to ensure safe and adequate service is maintained.

In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding approving base rates for electric distribution services for 2024 through 2027 and rejecting Ameren Illinois' Grid Plan, which was addressed as part of the MYRP proceeding.

Rate changes consistent with the December 2023 order became effective in January 2024 and remained effective through late June 2024, when new rates became effective pursuant to the June 2024 ICC rehearing order discussed below.

The December 2023 order adopted an alternative methodology to establish a rate base and revenue requirements for the years 2024 through 2027 using Ameren Illinois’ previously approved 2022 year-end rate base.

In January 2024, the ICC partially denied a rehearing requested by Ameren Illinois to revise the allowed ROE in the December 2023 order and granted Ameren Illinois’ rehearing request to reconsider the rate base for each year of the MYRP and to include a base level of investments to maintain grid reliability in each year of the MYRP.

In June 2024, the ICC issued an order on Ameren Illinois’ rehearing request approving revenue requirements for electric distribution services for 2024 through 2027.

New rates became effective in late June 2024 and remained effective through late December 2024, when new rates became effective pursuant to the December 2024 ICC order discussed below.

In July 2024, Ameren Illinois filed a request for rehearing of the ICC’s June 2024 rehearing order to include an asset associated with other postretirement benefits in the rate base.

Subsequently, in August 2024, the ICC denied the rehearing request.

Also, in January 2024, Ameren Illinois filed an appeal of the December 2023 ICC order, including the 8.72% ROE, and subsequently updated the appeal filing in September 2024 to include the June 2024 rehearing order regarding the inclusion of an asset associated with other postretirement benefits in the rate base to the Illinois Appellate Court for the Fifth Judicial District.

The court is under no deadline to address the appeal and Ameren Illinois cannot predict the ultimate outcome of the appeal.

In March 2024, pursuant to the December 2023 ICC order discussed above, Ameren Illinois filed a revised Grid Plan and a revised MYRP to update the requested revenue requirements for 2024 through 2027.

In December 2024, the ICC issued an order in connection with Ameren Illinois’ revised Grid Plan and revised MYRP, approving revenue requirements for electric distribution services for 2024, 2025, 2026, and 2027 of $1,206 million, $1,287 million, $1,367 million, and $1,422 million, respectively.

Rate changes consistent with the December 2024 order became effective in December 2024.

In January 2025, Ameren Illinois filed a request for rehearing of the ICC’s December 2024 order to revise the allowed ROE and to include an asset associated with other postretirement benefits in the rate base, among other things.

Subsequently, in February 2025, the ICC denied the rehearing request.

Ameren Illinois intends to file an appeal of the ICC’s December 2024 order and update the appeal filed in September 2024 to the Illinois Appellate Court for the Fifth Judicial District as discussed above.

In 20 24, Ameren Illinois took prudent steps to align its operations with the December 2023 and June 2024 ICC orders, while continuing to ensure safe and adequate service was maintained.

In November 2024, the ICC issued an order in Ameren Illinois’ annual update filing that approved electric customer energy-efficiency rates of $126 million beginning in January 2025, which represents an increase of $26 million from 2024 rates.

The order was based on a projected 2024 year-end rate base of $394 million.

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This order was based on a projected 2025 year-end rate base of $434 million.

In December 2024, the ICC issued an order approving Ameren Illinois’ 2023 electric distribution service revenue requirement reconciliation adjustment filing.

This order approved a reconciliation adjustment of $158 million, which reflected Ameren Illinois’ actual 2023 recoverable costs, year-end rate base of $4.2 billion, and capital structure composed of 50% common equity.

The approved reconciliation adjustment will be collected from customers in 2025.

In January 2025, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $140 million.

The request is based on a 10.7% ROE, a capital structure composed of 52% common equity, and a rate base of $3.3

Ameren Illinois used a 2026 future test year in this proceeding.

A decision by the ICC in this proceeding is required by early December 2025, with new rates expected to be effective in December 2025.

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.

In 2022, the MISO approved the first tranche of projects under 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.

Related to these projects, Ameren expects to begin substation upgrades in 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade.

In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects.

In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion.

The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024.

In February 2024, Ameren Illinois and ATXI filed a request for a CCN with the ICC related to the portion of the MISO long-range transmission projects discussed above that are expected to be constructed within the ICC’s jurisdiction.

A decision by the ICC is expected by February 2025.

Related to these projects, Ameren began substation upgrades in May 2024 in advance of transmission line construction, which is expected to begin in 2026, with forecasted completion dates near the end of this decade.

In addition, the MISO awarded three competitive bid projects to ATXI that represent a total estimated investment of approximately $220 million for ATXI.

In February 2024, Ameren Illinois and ATXI filed a request for a CCN, among other things, with the ICC related to the portion of the MISO long-range transmission projects they will construct within the ICC’s jurisdiction.

A decision by the ICC is expected by mid-2025.

In 2024, ATXI filed requests for CCNs, among other things, with the MoPSC related to the MISO long-range transmission projects that it expects to construct within the MoPSC’s jurisdiction.

Decisions by the MoPSC are expected in 2025.

Also in December 2024, the MISO approved a first set of second tranche projects.

A portion of these projects were assigned to Ameren and are estimated to cost approximately $1.3 billion, based on the MISO’s cost estimate.

The first set of second tranche projects also includes competitive bid projects that are estimated to cost $6.5 billion, which includes projects located in Illinois that are estimated to cost $1.8 billion, based on the MISO’s cost estimate.

The competitive bid process is expected to take place through 2026.

The MISO is assessing future long-range transmission scenarios in the first quarter of 2025 and development of a second set of second tranche projects will follow this assessment.

In October 2024, the FERC issued an order, which decreased the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff from 10.02% to 9.98% and required refunds, with interest, for the periods from November 2013 to February 2015 and from late September 2016 forward.

In November 2024, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed a request for rehearing with the FERC, arguing, among other things, the FERC should not have ordered refunds back to September 2016 or imposed interest on those refunds.

Also in November 2024, another intervenor filed a request for rehearing with the FERC, requesting the FERC correct aspects of the ROE methodology used in the October 2024 order and reconsider its decision in a February 2015 complaint case to deny refunds for the period from February 2015 to May 2016.

In December 2024, the FERC issued a notice indicating a future order related to the rehearing requests will be issued but did not specify a timeline.

In January 2025, the MISO transmission owners, including Ameren Missouri, Ameren Illinois, and ATXI, filed an appeal of the October 2024 order to the United States Court of Appeals for the District of Columbia Circuit.

As a result of the October 2024 order, Ameren and Ameren Illinois recognized reductions to electric revenues of $10 million and $7 million, respectively, and recognized interest expense of $2 million and $1 million, respectively, on their statements of income in 2024.

In February 2024, Ameren’s board of directors increased the quarterly common stock dividend to 67 cents per share, resulting in an annualized equivalent dividend rate of $2.68 per share.

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Net income attributable to Ameren common shareholders was $1,182 million, or $4.42 per diluted share, for 2024, and $1,152 million, or $4.38 per diluted share, for 2023.

Net income was favorably affected in 2023, compared with 2022, by increased infrastructure investments across all business segments and a higher recognized ROE at Ameren Illinois Electric Distribution as well as increased base rate revenues at Ameren Missouri pursuant to the June 2023 MoPSC electric rate order.

Earnings were also favorably affected by decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, including an increase in the cash surrender value of COLI, at Ameren Missouri and Ameren Illinois Natural Gas.

Net income was unfavorably affected in 2023, compared with 2022, by decreased retail sales at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to milder winter and summer temperatures.

In addition, lower retail sales volumes, excluding the estimated effects of weather, decreased net income at Ameren Missouri in 2023, compared with 2022.

Earnings in 2023, compared to 2022, were also unfavorably affected by increased financing costs at Ameren (parent), Ameren Missouri, and Ameren Illinois Natural Gas, primarily due to higher interest rates on increased levels of short-term borrowings at Ameren (parent), and higher long-term debt balances and higher interest rates on short-term borrowings and long-term debt, partially offset by higher levels of allowance for funds used during construction, at Ameren Missouri and Ameren Illinois Natural Gas.

Net income was favorably affected in 2024, compared with 2023, by increased infrastructure investments at Ameren Transmission and Ameren Missouri.

Net income was also favorably affected in 2024, compared with 2023, by increased base rate revenues pursuant to the MoPSC's June 2023 electric rate order as well as higher base rate revenues pursuant to the ICC's November 2023 natural gas rate order, which increased earnings at Ameren Illinois Natural Gas.

Additionally, earnings in 2024, compared with 2023, were favorably affected by decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, largely because of lower energy center maintenance costs, lower storm costs, disciplined cost management including lower labor costs from decreased headcount and decreased use of contractors, and lower amortization of refueling costs for the Callaway Energy Center, partially offset by the absence of the regulatory deferrals associated with the June 2023 MoPSC rate order.

Net income in 2024, compared with 2023, was also favorably affected by increased retail electric sales volumes at Ameren Missouri, primarily due to higher sales excluding customer energy-efficiency programs.

Net income was unfavorably affected in 2024, compared with 2023, by two charges related to matters that originated over a decade ago.

The first of these charges was recorded by Ameren Missouri related to an order from the United States District Court for the Eastern District of Missouri, which resolved all outstanding claims in the NSR and Clean Air Ac t litigation related to the Rush Island Energy Center.

The second charge was recognized by Ameren Illinois and ATXI for the decrease in the allowed base ROE under the MISO tariff resulting from the October 2024 FERC order, which included customer refunds for certain historical periods.

Net income in 2024, compared with 2023, was also unfavorably affected by increased financing costs due to higher long-term debt balances and interest rates at Ameren Missouri and Ameren (parent), a lower recognized ROE under the MYRP, and an increase in the weighted-average basic common shares outstanding, which reduced earnings per diluted share.

At December 31, 2024, Ameren, on a consolidated basis, had available liquidity in the form of cash on hand and amounts available under the Credit Agreements of $1.4 billion.

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For information regarding long-term debt issuances and maturities, common stock issuances, and outstanding forward sale agreements entered into under the ATM program through the date of this report, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.

Table of Conten t s

Ameren remains focused on strategic capital allocation.

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Ameren Illinois Natural Gas

Ameren Illinois Electric Distribution Ameren Transmission

Ameren Illinois Electric Distribution Ameren Transmission (b)

For 2025 through 2029, Ameren’s cumulative capital expenditures are projected to range from $25.2 billion to $27.4 billion.

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$ 16.0 – $ 17.5

Ameren Illinois Electric Distribution (b)

Ameren Illinois Natural Gas (b)

Ameren Transmission 3.9 – 4.3

Ameren Illinois Electric Distribution 3.1 – 3.3

Ameren Illinois Natural Gas 1.7 – 1.8

Ameren Transmission (b)

Ameren (a)(b)

$ 25.2 – $ 27.4

(a) Amounts include $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments, which inc ludes $0.9 billion related to coal-fired generation, through 2028, consistent with Ameren Missouri’s 2023 IRP.

(b) Amounts include investments necessary to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained.

Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.

(a) Amounts include investments under Ameren Missouri’s Smart Energy Plan.

(b) Amounts include the MISO long-range transmission projects assigned to Ameren, as well as the first tranche competitive projects awarded to ATXI discussed above .

RESULTS OF OPERATIONS

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See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory frameworks.

Table of Conten t s

We are observing inflationary pressures on the prices of labor, services, materials, and supplies, as well as high 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 and enriched uranium for fuel in its electric operations and purchases natural gas for its customers.

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The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, inflation, and many other factors.

We have natural gas cost recovery mechanisms for our Illinois and Missouri natural gas distribution businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution business, and a FAC for Ameren Missouri’s electric business.

We have natural gas

cost recovery mechanisms for our Illinois and Missouri natural gas distribution businesses, a purchased power cost recovery mechanism for Ameren Illinois’ electric distribution business, and a FAC for Ameren Missouri’s electric business.

We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business.

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Earnings per common share – diluted

Net income attributable to Ameren common shareholders in 2023 increased $78 million, or $0.24 per diluted share, from 2022.

The increase was due to net income increases of $56 million, $33 million, and $11 million at Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively.

The increases in net income were partially offset by a net income decrease of $17 million at Ameren Missouri and an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent), of $5 million.

Net income attributable to Ameren common shareholders in 2024 increased $30 million, and $0.04 per diluted share, from 2023.

The increase was due to net income increases of $27 million, $15 million, and $14 million at Ameren Transmission, Ameren Illinois Natural Gas, and Ameren Missouri, respectively.

The increases in net income were partially offset by a net income decrease of $24 million at Ameren Illinois Electric Distribution and an increase in the net loss for activity not reported as part of a segment, primarily at Ameren (parent), of $2 million.

Earnings per share in 2024, compared with 2023, were favorably affected by:

• increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE due to a higher 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 (25 cents per share);

• increased base rate revenues at Ameren Missouri effective July 9, 2023, pursuant to the June 2023 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 lower base level of expenses included in trackers, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (12 cents per share);

• decreased 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 (11 cents per share);

• decreased income tax expense not subject to formula rates or riders due, in part, to decreased income tax expense recognized at Ameren (parent) because of changes in the state income taxes apportioned to Missouri and Illinois, reflecting changes in revenues, as well as the effect of favorable market returns on COLI, compared with unfavorable returns in the year-ago period (6 cents per share);

• increased base rate revenues at Ameren Missouri for the inclusion of previously deferred PISA and RESRAM interest charges pursuant to the December 2021 and June 2023 MoPSC electric rate orders effective February 28, 2022, and July 9, 2023, respectively, partially offset by increased interest charges resulting from lower deferrals related to infrastructure investments associated with the PISA and RESRAM (6 cents per share);

• 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 2023 (3 cents per share);

• increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP (3 cents per share);

• increased other income, net, largely due to increased non-service cost components of net periodic benefit income not subject to formula rates or trackers (3 cents per share);

• recovery of previously incurred expenses at Ameren Illinois Electric Distribution (2 cents per share).

• increased allowance for equity funds used during construction and increased base rate revenues for the inclusion of previously deferred PISA and RESRAM interest charges pursuant to the June 2023 MoPSC electric rate order effective July 9, 2023, and decreased interest charges resulting from higher deferrals related to infrastructure investments associated with the PISA and RESRAM, at Ameren Missouri (17 cents per share);

• increased rate base investments at Ameren Transmission, which increased earnings in this segment (16 cents per share);

• increased base rate revenues at Ameren Missouri effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, partially offset by the net effect of amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a lower base level of expenses included in trackers, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (9 cents per share);

• increased retail electric sales volumes at Ameren Missouri, primarily due to higher sales excluding customer energy-efficiency programs (estimated at 8 cents per share);

• increased other income, net, primarily due to lower donations and a gain on the extinguishment of debt, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for more information, partially offset by decreased non-service cost components of net periodic benefit income not subject to formula rates or trackers largely due to lower investment returns (6 cents per share);

• increased base rate revenues at Ameren Illinois Natural Gas effective November 28, 2023, pursuant to the November 2023 ICC natural gas rate order, partially offset by increased depreciation and amortization expenses included in base rates (4 cents per share);

• decreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, excluding a charge related to the NSR and Clean Air Act litigation discussed below largely because of lower energy center maintenance costs, lower storm costs, disciplined cost management including lower labor costs from decreased headcount and decreased use of contractors, and lower amortization of refueling costs for the Callaway Energy Center, partially offset by the absence of regulatory deferrals associated with the June 2023 MoPSC rate order (2 cents per share).

Earnings per share in 2024, compared with 2023, were unfavorably affected by:

• decreased retail sales at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to milder winter and summer temperatures as well as lower sales volumes, excluding the estimated effects of weather, in 2023 (estimated at 25 cents per share);

Table of Conten t s

• increased financing costs at Ameren (parent), Ameren Missouri, and Ameren Illinois Natural Gas, primarily due to higher interest rates on increased levels of short-term borrowings at Ameren (parent), and higher long-term debt balances and higher interest rates on short-term borrowings and long-term debt, partially offset by higher levels of allowance for funds used during construction, at Ameren Missouri and Ameren Illinois Natural Gas (13 cents per share);

• increased weighted-average basic common shares outstanding resulting from issuances of common shares as detailed in Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report (7 cents per share);

• increased depreciation and amortization expenses not recoverable under riders or trackers at Ameren Missouri and Ameren Illinois Natural Gas, primarily due to additional property, plant, and equipment investments (4 cents per share);

• lower MEEIA 2019 performance incentives recognized at Ameren Missouri (3 cents per share).

The cents per share variances above are presented on the weighted-average basic shares outstanding in 2022 and do not reflect the impact of dilution on earnings per share, unless otherwise noted.

• a charge recorded by Ameren Missouri, included in other operation and maintenance expenses, related to an order from the United States District Court for the Eastern District of Missouri, which resolved all outstanding claims in the NSR and Clean Air Ac t litigation related to the Rush Island Energy Center, see Note 14 - Commitments and Contingencies under Part II, Item 8, of this report for more information (17 cents per share);

• increased financing costs primarily at Ameren Missouri and Ameren (parent), largely due to higher long-term debt balances and interest rates, partially offset by lower levels of short-term borrowings (17 cents per share);

• lower revenue at Ameren Illinois Electric Distribution due to a lower recognized ROE under the MYRP (9 cents per share);

• increased weighted-average basic common shares outstanding resulting from issuances of common shares (7 cents per share);

• the result of the October 2024 FERC order reducing the allowed base ROE for FERC regulated transmission rate base under the MISO tariff, which decreased Ameren Transmission earnings (4 cents per share);

• increased taxes other than income taxes at Ameren Missouri, largely resulting from the absence in 2024 of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act (2 cents per share).

The cents per share variances above are presented based on the weighted-average basic shares outstanding in 2023 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 2024 blended federal and state statutory tax rate of 26%.

For additional details regarding the Ameren Companies’ results of operations, including explanations of Electric and Natural Gas Margins, Other Operations and Maintenance Expenses, Depreciation and Amortization Expenses, Taxes Other Than Income Taxes, Other Income, Net, Interest Charges, and Income Taxes, see the major headings below.

Table of Conten t s

For additional details regarding the Ameren Companies’ results of operations, including explanations of Operating Revenues for both Electric Revenues and Natural Gas Revenues;

Fuel and Purchased Power Expenses;

Other Operations and Maintenance Expenses;

Depreciation and Amortization Expenses;

Taxes Other Than Income Taxes;

Other Income, Net;

Interest Charges;

and Income Taxes, see the major headings below.

Below is Ameren’s table of income statement components by segment for the years ended December 31, 2024 and 2023:

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Electric revenues $ 3,847 $ 2,089 $ — $ 781 $ (177) $ 6,540

Fuel (514) — — — — (514)

Purchased power (483) (933) — — 118 (1,298)

Electric margins 2,697 1,285 — 677 (32) 4,627

Natural gas revenues 146 — 938 — (1) 1,083

Fuel and purchased power (1,071) (740) — — 130 (1,681)

Natural gas purchased for resale (60) — (260) — — (320)

Natural gas margins 86 — 621 — (1) 706

Other operations and maintenance expenses (1,050) (619) (230) (70) — (1,969)

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Electric revenues $ 3,694 $ 2,218 $ — $ 677 $ (150) $ 6,439

Fuel (473) — — — — (473)

Purchased power (677) (984) — — 114 (1,547)

Electric margins 2,699 1,272 — 615 (25) 4,561

Natural gas revenues 165 — 897 — (1) 1,061

Fuel and purchased power (997) (933) — — 118 (1,812)

Natural gas purchased for resale (79) — (276) — — (355)

Natural gas margins 93 — 627 — (1) 719

Other operations and maintenance expenses (1,003) (532) (237) (60) (34) (1,866)

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Net income (loss) attributable to Ameren common shareholders $ 545 $ 258 $ 134 $ 296 $ (81) $ 1,152

Table of Conten t s

Below is Ameren Illinois’ table of income statement components by segment for the years ended December 31, 2024 and 2023:

4 unchanged sentences

Electric revenues $ 2,089 $ — $ 564 $ (119) $ 2,534

Purchased power (933) — — 113 (820)

Electric margins 1,285 — 480 — 1,765

Natural gas revenues — 938 — — 938

Purchased power (740) — — 119 (621)

Natural gas purchased for resale — (260) — — (260)

Natural gas margins — 621 — — 621

Other operations and maintenance expenses (619) (230) (57) — (906)

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Electric revenues $ 2,218 $ — $ 480 $ (113) $ 2,585

Purchased power (984) — — 104 (880)

Electric margins 1,272 — 424 — 1,696

Natural gas revenues — 897 — — 897

Purchased power (933) — — 113 (820)

Natural gas purchased for resale — (276) — — (276)

Natural gas margins — 627 — — 627

Other operations and maintenance expenses (532) (237) (49) — (818)

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Net income attributable to common shareholder $ 258 $ 134 $ 215 $ — $ 607

Electric margins are defined as electric revenues less fuel and purchased power costs.

Natural gas margins are defined as natural gas revenues less natural gas purchased for resale.

We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural gas operations between periods.

We have included the analysis below as a complement to the financial information we provide in accordance with GAAP.

However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Table of Conten t s

Electric Margins

Total by Segment (a)

Increase (Decrease) by Segment

Overall Ameren Increase of $66 Million

(a) Includes other/intersegment eliminations of $(32) million and $(25) million in 2023 and 2022, respectively.

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

Natural Gas Margins

Total by Segment (a)

Decrease by Segment

Overall Ameren Decrease of $13 Million

(a) Includes other/intersegment eliminations of $(1) million and $(1) million in 2023 and 2022, respectively.

Ameren Missouri Ameren Illinois Natural Gas Other/Intersegment Eliminations

Table of Conten t s

The following table presents the favorable (unfavorable) variations by segment for electric and natural gas margins in 2023, compared with 2022:

Electric and Natural Gas Margins

2023 versus 2022 Ameren

Missouri Ameren Illinois

Operating Revenues

The following table presents the increases (decreases) by Ameren segment for electric and natural gas revenues in 2024, compared with 2023:

2024 versus 2023 Ameren Missouri Ameren Illinois

Electric Distribution Ameren Illinois

Natural Gas Ameren

Transmission (a)

Eliminations Ameren

Natural Gas Ameren Transmission (a)

Other /Intersegment Eliminations Ameren

Electric revenue change:

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Effect of weather (estimate) (c)

(71) — — — — (71)

Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) (27) — — — — (27)

Retail sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) 27 — — — — 27

Customer charges 2 — — — — 2

Rush Island Energy Center base rate revenue deferral (13) — — — — (13)

MEEIA 2019 performance incentives 1 — — — — 1

Off-system sales, capacity, and FAC revenues, net (226) — — — — (226)

Transmission service charges (9) — — — — (9)

Ameren Illinois customer energy-efficiency program investment revenues — 18 — — — 18

Off-system sales, capacity, transmission, and FAC revenues, net 96 — — — — 96

Recovery of power restoration efforts provided to other utilities 1 3 — — — 4

Ameren Illinois energy-efficiency program investment revenues — 21 — — — 21

Electric deferred income tax adjustment (d)

— (23) — — — (23)

Other 6 4 — 15 (15) 10

Cost recovery mechanisms – offset in fuel and purchased power (d)

Cost recovery mechanisms – offset in fuel and purchased power (e)

(54) (193) — — (12) (259)

Other cost recovery mechanisms (e)

Other cost recovery mechanisms (f)

22 45 — — — 67

Total electric revenue change $ 153 $ (129) $ — $ 104 $ (27) $ 101

Fuel and purchased power change:

Energy costs (excluding the estimated effect of weather) $ 238 $ — $ — $ — $ — $ 238

Effect of weather (estimate) (c)

14 — — — — 14

Effect of higher net energy costs included in base rates (21) — — — — (21)

Transmission service charges 4 — — — — 4

Cost recovery mechanisms – offset in electric revenue (d)

(82) 51 — — 4 (27)

Total fuel and purchased power change $ 153 $ 51 $ — $ — $ 4 $ 208

Net change in electric margins $ (2) $ 13 $ — $ 62 $ (7) $ 66

Natural gas revenue change:

Base rates (estimate) $ — $ — $ 47 $ — $ — $ 47

Sales volume (excluding the estimated effects of weather) 2 — — — — 2

Effect of weather (estimate) (c)

(17) — — — — (17)

Sales volume (excluding the estimated effect of weather) — — (4) — — (4)

QIP rider — — 14 — — 14

Other — — 3 — — 3

Cost recovery mechanisms – offset in natural gas purchased for resale (d)

Cost recovery mechanisms – offset in natural gas purchased for resale (e)

(20) — (16) — — (36)

Other cost recovery mechanisms (e)

Other cost recovery mechanisms (f)

(2) — 7 — — 5

Total natural gas revenue change $ (19) $ — $ 41 $ — $ — $ 22

Natural gas purchased for resale change:

Effect of weather (estimate) (c)

$ 13 $ — $ — $ — $ — $ 13

Cost recovery mechanisms – offset in natural gas revenue (d)

12 — 277 — — 289

Total natural gas purchased for resale change $ 25 $ — $ 277 $ — $ — $ 302

Net change in natural gas margins $ (7) $ — $ (6) $ — $ — $ (13)

(a) Includes an increase in transmission electric margins of $56 million in 2023, compared with 2022, at Ameren Illinois.

(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.

(a) Includes an increase in transmission revenues of $84 million in 2024, compared with 2023, at Ameren Illinois.

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

For Ameren Missouri, base rates exclude an increase for the recovery of lost electric revenue, less the associated fuel and purchased power expenses, 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 “Retail 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 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.

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

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.

this variation is based on temperature readings from National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.

(d) The electric deferred income tax adjustment relates to certain excess deferred income taxes that will be amortized through 2025.

Offsetting expense increases or decreases are reflected within "Income Taxes" on the statement of income.

This item has no overall impact on earnings.

(e) Electric and natural gas revenue changes are offset by corresponding changes in “Fuel and purchased power” and “Natural gas purchased for resale” on the statement of income.

Activity in Other/Intersegment Eliminations of $12 million represents the changes in eliminations of related-party transactions between Ameren Missouri, Ameren Illinois, and ATXI (-$6 million), as well as changes in Ameren Transmission revenue from transmission services provided to Ameren Illinois Electric Distribution

(-$6 million).

See Note 13 – Related-party Transactions and Note 16 – Segment Information under Part II, Item 8, of this report for additional information 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 “Operating Expenses” section of the statement of income.

These items have no overall impact on earnings.

Table of Conten t s

Ameren’s electric margins increased $66 million, or 1%, in 2023, compared with 2022, because of increased margins at Ameren Transmission and Ameren Illinois Electric Distribution, as discussed below.

Ameren’s natural gas margins decreased $13 million, or 2%, between years because of decreased margins at Ameren Missouri and Ameren Illinois Natural Gas, as discussed below.

(f) Offsetting expense increases or decreases are reflected in “Other operations and maintenance,” “Depreciation and amortization,” or in “Taxes other than income taxes,” within “Operating Expenses” on the statement of income.

These items have no overall impact on earnings.

Electric Revenues

Ameren’s electric revenues increased $101 million, or 2%, in 2024, compared with 2023 , due to increased revenues at Ameren Missouri and Ameren Transmission, partially offset by decreased revenues at Ameren Illinois Electric Distribution, as discussed below.

Ameren Transmission

Ameren Transmission’s margins increased $62 million, or 10%, in 2023, compared with 2022.

Base rate revenues were favorably affected by higher recoverable expenses (+$38 million) and increased capital investment (+$24 million), as evidenced by a 10% increase in rate base used to calculate the revenue requirement.

Amer en Transmission’s electric revenues increased $104 million, or 15%, in 2024, compared with 2023.

Revenues were favorably affected by higher recoverable expenses (+$55 million), increased capital investment (+$44 million), as evidenced by a 15% increase in rate base used to calculate the revenue requirement, and increased facility rental revenues (+$15 million) related to ATXI’s transmission operations control center, which was placed in service in December 2023.

ATXI provides affiliates with access to this facility.

Rental revenues associated with this facility are affiliate transactions and eliminated in consolidation for Ameren’s consolidated financial statements.

See Note 13 – Related-party Transactions under Part II, Item 8, of this report for additional information.

Revenues were unfavorably affected by a decrease in the allowed base ROE under the MISO tariff resulting from the October 2024 FERC order, which included customer refunds for certain historical periods (-$10 million).

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the FERC complaint cases.

Ameren Missouri

Ameren Missouri’s electric margins were comparable between years.

Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $82 million in 2023, compared with 2022, due to increased revenue related to the amortization of costs previously deferred under the FAC that were reflected in customer rates.

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)”.

The following items had an unfavorable effect on Ameren Missouri’s electric margins in 2023, compared with 2022:

• Winter temperatures were warmer as heating degree days decreased 22% while spring and summer temperatures were milder as cooling degree days decreased 3%.

The aggregate effect of weather decreased margins by an estimated $57 million.

The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (-$71 million) and the “Effect of weather (estimate)” on fuel and purchased power (+$14 million) in the table above.

• Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues decreased an estimated $27 million resulting from a decrease in retail sales volumes, due, in part, to customer outages resulting from major storms experienced throughout the service territory in July and August 2023, partially offset by an increase in customer demand charge revenues and an increase in the average retail price per kilowatthour related to changes in customer usage patterns.

• MEEIA 2019 performance incentives decreased revenues $10 million as performance incentives for program years 2021 and 2022 were recognized in 2022, whereas the performance incentive for program year 2023 was recognized in 2023.

• Revenues associated with other cost recovery mechanisms decreased $10 million, primarily due to a decrease in RESRAM revenues, partially offset by an increase in excise taxes and recoverable MEEIA program costs.

• Transmission service charge revenues decreased $9 million , primarily due to lower revenues related to reactive power.

The following items had a favorable effect on Ameren Missouri’s electric margins in 2023, compared with 2022:

• Higher electric base rates, excluding the change in base rates for the MEEIA customer energy-efficiency programs and the RESRAM, resulting from the June 2023 MoPSC electric rate order effective July 9, 2023, partially offset by higher net energy costs included in base rates, increased margins an estimated $57 million.

A similar effect resulting from the December 2021 MoPSC electric rate order effective February 28, 2022, increased margins an estimated $37 million.

The change in electric base rates is the sum of the change in “Base rates (estimate)” (+$115 million) and the “Effect of higher net energy costs included in base rates” (-$21 million) in the table above.

• Ameren Missouri’s electric margins increased $12 million due to its 5% exposure to net energy cost variances under the FAC.

The change in net energy costs is the sum of “Off-system sales, capacity and FAC revenues, net” (-$226 million) and “Energy costs (excluding the estimated effect of weather)” (+$238 million) in the table above.

Revenues decreased primarily due to lower off-system sales volumes (-$108 million) related to reduced generation at the Rush Island Energy Center, lower capacity prices (-$101 million) set by the annual MISO auction in April 2023, and lower market prices for energy (-$11 million).

Energy costs decreased primarily due to lower fuel costs (+$130 million), lower purchased power costs (+$98 million), and lower capacity costs (+$95 million), partially offset by decreased deferral of expenses under the FAC (-$90 million).

• Transmission service charge expenses decreased $4 million, primarily due to a decrease in charges related to transmission network upgrades.

Table of Conten t s

Ameren Missouri’s natural gas margins decreased $7 million, or 8%, in 2023, compared with 2022.

Purchased gas costs decreased $12 million in 2023, compared with 2022, due to lower commodity prices and decreased amortization of deferred natural gas costs related to the extremely cold weather in mid-February 2021 .

The decreased purchased 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 gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above.

Margins decreased $4 million due to warmer winter temperatures as heating degree days decreased 22%.

The change in margins due to weather is the sum of the “Effect of weather (estimate)” on natural gas revenues (-$17 million) and the “Effect of weather (estimate)” on natural gas purchased for resale (+$13 million) in the table above.

Ameren Missouri’s electric revenues increased $153 million , or 4% , in 2024, compared with 2023.

The following items had a favorable effect on Ameren Missouri’s electric revenues in 2024, compared with 2023:

• “Off-system sales, capacity, transmission, and FAC revenues, net” increased $96 million, primarily due to higher summer and fall capacity prices which were set by annual MISO auctions.

• Higher electric base rates, resulting from the June 2023 MoPSC electric rate order effective July 9, 2023, increased revenues an estimated $62 million .

• Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues increased an estimated $27 million , due to an increase in residential customer counts, retail sales volumes from large commercial and industrial customers, the absence of customer outages resulting from major storms experienced throughout the service territory in July and August 2023, and an additional day in 2024 as a result of the leap year.

The increase is partially offset by lower realized prices due to changes in customer usage patterns and economic development discounts.

• Revenues associated with other cost recovery mechanisms increased $22 million , primarily due to an increase in RESRAM revenues and an increase in excise taxes due to increased retail sales revenue.

• Other revenues increased $6 million due to pole rents (+$2 million), other rentals (+$2 million), and other miscellaneous revenues

(+$2 million).

• The aggregate effect of weather increased revenues an estimated $3 million as cooling degree days increased 7% and heating degree days decreased 4%.

The following ite ms had an unfavorable effect on Ameren Missouri’s electric revenues in 2024, compared with 2023:

• Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” decreased $54 million, due to decreased revenue related to the amortization of costs previously deferred under the FAC that were reflected in customer rates.

The changes to “Cost recovery mechanisms - offset in fuel and purchased power” are fully offset by changes to “Cost recovery mechanisms - offset in electric revenue” in fuel and purchased power.

• In accordance with the June 2024 MoPSC financing order, revenues decreased $13 million due to the deferral of base rate revenues to a regulatory liability related to the Rush Island Energy Center since its October 15, 2024 retirement date.

The regulatory liability will be refunded to customers in a future rate proceeding.

Ameren Illinois

Ameren Illinois’ electric margins increased $69 million, or 4%, in 2023, compared with 2022, driven by increased margins at Ameren Illinois Transmission and Ameren Illinois Electric Distribution.

Ameren Illinois Natural Gas’ margins decreased $6 million, or 1%, between years.

Ameren Illinois’ electric revenues decreased $51 million, or 2%, in 2024, compared with 2023, driven by decreased revenues at Ameren Illinois Electric Distribution, partially offset by increased revenues at Ameren Illinois Transmission.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s margins increased $13 million, or 1%, in 2023, compared with 2022.

Purchased power costs decreased $51 million in 2023, compared with 2022, primarily due to decreased energy prices (-$54 million), which largely reflect the results of IPA procurement events, and lower volumes due to decreased sales (-$39 million), partially offset by increased revenues related to the amortization of costs previously deferred under riders (+$28 million) and higher costs due to higher capacity prices (+$9 million).

The decreased purchased power costs are fully offset by a decrease in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin.

The decrease in purchased power cost is reflected in “Cost recovery mechanisms – offset in electric revenue” and the associated recoveries from customers is reflected in “Cost recovery mechanisms – offset in fuel and purchased power” in the table above.

The following items had a favorable effect on Ameren Illinois Electric Distribution’s margins in 2023, compared with 2022:

• The impact from base rates (+$30 million) increased due to a higher recognized ROE (+$21 million), as evidenced by an increase of 98 basis points in the annual average of the monthly yields of the 30-year United States Treasury bonds, and increased capital investment (+$15 million), as evidenced by a 9% increase in year-end rate base, partially offset by lower recoverable non-purchased power expenses (-$4 million), and the results from 2021 and 2022 revenue requirement reconciliation adjustment true-ups recognized in the subsequent year (-$2 million).

• Revenues associated with customer energy-efficiency program investments increased $18 million due to the recovery of program expenses (+$12 million), increased investment (+$2 million), higher recognized ROE under formula ratemaking (+$2 million), and the results from the 2022 revenue requirement reconciliation adjustment true-up recognized in 2023 (+$2 million).

Revenues associated with other cost recovery mechanisms decreased $33 million in 2023, compared with 2022, primarily due to a lower amount of bad debt costs included in customer rates pursuant to the associated rider.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ margins decreased $6 million, or 1%, in 2023, compared with 2022.

Purchased gas costs decreased $277 million in 2023, compared with 2022, primarily due to lower amortization of natural gas costs that were previously deferred under the PGA and lower natural gas prices in 2023.

Deferred natural gas costs related to the extremely cold weather in mid-February 2021 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.

Table of Conten t s

The following items had an unfavorable effect on Ameren Illinois Natural Gas’ margins in 2023, compared with 2022:

• Revenues associated with other cost recovery mechanisms decreased $18 million, primarily due to decreased revenues for excise taxes.

• Revenues decreased $4 million primarily due to lower sales volumes related to large commercial, industrial, and transportation customers, and lower capacity revenues.

Revenues from sales to large commercial, industrial, and transportation customers are excluded from the VBA.

See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the VBA.

• Other miscellaneous revenues decreased $4 million primarily related to the refund of over-recovered costs associated with the COVID-19 pandemic, beginning in April 2023.

The following items had a favorable effect on Ameren Illinois Natural Gas’ margins in 2023, compared with 2022:

• Revenues increased $14 million due to additional investment in natural gas infrastructure under the QIP.

• Revenues increased $6 million due to higher natural gas base rates as a result of the natural gas rate order effective November 28, 2023.

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the QIP and 2023 Natural Gas Delivery Service Rate Order.

Ameren Illinois Electric Distribution’s revenues decreased $129 million, or 6%, in 2024, compared with 2023.

The following items had an unfavorable effect on Ameren Illinois Electric Distribution’s revenues in 2024, compared with 2023:

• Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” decreased $193 million, due to decreased purchased power expenses recovered from customers.

The decreases in electric revenues are fully offset by decreases in purchased power expenses under cost recovery mechanisms for purchased power, as discussed below.

• Pursuant to an ICC order, revenues decreased $23 million, due to an increase in the amortization rate for certain excess deferred income taxes.

The following items had a favorable effect on Ameren Illinois Electric Distribution’s revenues in 2024, compared with 2023:

• Other cost recovery mechanisms increased revenues by $45 million, primarily due to a higher amount of bad debt and purchased receivables from alternative retail electric suppliers included in customer rates pursuant to their associated riders, partially offset by lower environmental remediation revenues.

• Revenues associated with customer energy-efficiency program investments increased $21 million, due to the recovery of program expenses (+$15 million), an increase in the ROE (+$4 million) primarily due to maximum achievement of the annual 2023 energy savings goals, and increased investment of $2 million.

• Base rates increased revenues by $14 million, primarily due to higher recoverable non-purchased power expenses (+$38 million), partially offset by a lower recognized ROE (-$24 million).

The MYRP utilizes a fixed ROE approved by the ICC of 8.72%, with adjustments for any performance incentives and penalties, while the IEIMA formula-based ROE was based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points (9.84% as of December 31, 2023).

• The recovery of labor and benefit costs for crews assisting other utilities with power restoration efforts, primarily caused by hurricane damage, increased revenues by $3 million.

Ameren Illinois Transmission

Ameren Illinois Transmission’s electric margins increased $56 million, or 13%, in 2023, compared with 2022.

Base rate revenues were favorably affected by increased capital investment (+$25 million), as evidenced by a 15% increase in rate base used to calculate the revenue requirement, and higher recoverable expenses (+$31 million).

Ameren Illinois Transmission’s revenues increased $84 million , or 18% , in 2024, compared with 2023.

Base rate revenues were favorably affected by higher recoverable expen ses (+$58 million) and increased capital investment (+$33 million), as e videnced by a 17% increase in rate base used to calculate the revenue requirement .

Base rate revenues were unfavorably affected by a decrease in the allowed base ROE under the MISO tariff resulting from the October 2024 FERC order, which included customer refunds for certain historical periods (-$7 million).

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information regarding the FERC ROE complaint cases.

Natural Gas Revenues

Ameren’s natural gas revenues increased $22 million , or 2% , in 2024, compared with 2023, due to increased revenues at Ameren Illinois Natural Gas, partially offset by decreased revenues at Ameren Missouri, as discussed below.

Ameren Missouri

Ameren Missouri’s natural gas revenues decreased $19 million, or 12%, in 2024, compared with 2023.

Revenues associated with “Cost recovery mechanisms – offset in natural gas purchased for resale” decreased $20 million in 2024, compared with 2023, due to lower commodity prices and the absence of amortization of natural gas costs deferred under the PGA related to the extremely cold weather in mid-February 2021.

Changes in natural gas revenues under the PGA are fully offset by corresponding changes in natural gas purchased for resale expenses.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ revenues increased $41 million, or 5%, in 2024, compared with 2023.

Revenues increased an estimated $47 million due to higher natural gas base rates as a result of the November 2023 natural gas rate order, and revenues associated with other cost recovery mechanisms increased $7 million primarily due to increased revenues for excise taxes.

“Cost recovery mechanisms – offset in natural gas purchased for resale” decreased revenues $16 million, due to lower collection of natural gas costs previously deferred under the PGA.

Changes in natural gas revenues under the PGA are fully offset by the decrease in natural gas purchased for resale expenses.

Fuel and Purchased Power

The following table presents the increases (decreases) by Ameren segment for fuel and purchased power in 2024, compared with 2023:

2024 versus 2023 Ameren Missouri Ameren Illinois

Electric Distribution Ameren Illinois

Natural Gas Ameren Transmission Other /Intersegment Eliminations Ameren

Fuel and purchased power change:

Energy costs (excluding the estimated effect of weather) $ 95 $ — $ — $ — $ — $ 95

Effect of higher net energy costs included in base rates 22 — — — — 22

Retail sales volumes 6 — — — — 6

Transmission service charges 8 — — — — 8

Other (3) — — — — (3)

Cost recovery mechanisms – offset in electric revenue (a)

(54) (193) — — (12) (259)

Total fuel and purchased power change $ 74 $ (193) $ — $ — $ (12) $ (131)

(a) “Cost recovery mechanisms — offset in electric revenue” changes are offset by corresponding changes in “Cost recovery mechanisms — offset in fuel and purchased power” in electric revenues.

See Note 13 – Related-party Transactions and Note 16 – Segment Information under Part II, Item 8, of this report for additional information on intersegment eliminations.

These items have no overall impact on earnings.

Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for fuel and purchased power.

Ameren’s electric fuel and purchased power expenses decreased $131 million, or 7%, in 2024, compared with 2023, primarily due to decreased fuel and purchased power expenses at Ameren Illinois Electric Distribution, partially offset by increased fuel and purchased power expenses at Ameren Missouri, as discussed below.

Ameren Missouri

Ameren Missouri’s fuel and purchased power expenses increased $74 million, or 7%, in 2024, compared with 2023.

The following items increased Ameren Missouri’s fuel and purchased power expense in 2024, compared with 2023:

• Energy costs increased $95 million in 2024, compared with 2023, primarily due to higher summer and fall capacity prices, which were set by annual MISO auctions.

Ameren Missouri’s 5% exposure to net energy cost variances under the FAC is the difference between “Off-system sales, capacity, transmission, and FAC revenues, net” and “Energy costs (excluding the estimated effect of weather)”.

These results had an immaterial impact on earnings in 2024, compared with 2023.

• The effect of higher net energy costs included in base rates increased Ameren Missouri’s fuel and purchased power expenses $22 million in 2024, compared with 2023, as a result of the June 2023 MoPSC electric rate order.

• Transmission service charges increased $8 million due to higher transmission rates related to increased revenue requirements of other transmission operators.

• Increases in retail sales volumes increased Ameren Missouri’s fuel and purchased power expenses $6 million.

“Cost recovery mechanisms — offset in electric revenue” decreased $54 million in 2024, compared with 2023, due to decreased amortization of costs previously deferred under the FAC.

The changes to “Cost recovery mechanisms - offset in electric revenue” are fully offset by “Cost recovery mechanisms - offset in fuel and purchased power” in electric revenues.

Ameren Illinois Electric Distribution

Ameren Illinois Electric Distribution’s purchased power expenses decreased $193 million, or 21%, in 2024, compared with 2023, primarily due to decreased energy prices (-$94 million), which largely reflect the results of IPA procurement events, decreased capacity prices (-$77 million), which were set by annual MISO auctions, and lower volumes (-$43 million) primarily due to residential and small commercial customers switching from Ameren Illinois’ supplied power to alternative retail electric suppliers and customer adoption of solar technology through initiatives required under Illinois law.

These decreases in purchased power expenses were partially offset by increased expenses associated with the amortization of renewable energy credit costs (+$20 million).

The changes to “Cost recovery mechanisms - offset in electric revenue” are fully offset by changes to “Cost recovery mechanisms - offset in fuel and purchased power” in electric revenues.

Natural Gas Purchased for Resale

The following table presents the increases (decreases) by Ameren segment for natural gas purchased for resale in 2024, compared with 2023:

2024 versus 2023 Ameren Missouri Ameren Illinois

Electric Distribution Ameren Illinois

Natural Gas Ameren Transmission Other /Intersegment Eliminations Ameren

Natural gas purchased for resale change:

Effect of weather (estimate) (a)

$ 1 $ — $ — $ — $ — $ 1

Cost recovery mechanisms – offset in natural gas revenue (b)

(20) — (16) — — (36)

Total natural gas purchased for resale change $ (19) $ — $ (16) $ — $ — $ (35)

(a) Represents the estimated variation resulting primarily from changes in heating degree-days on 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.

(b) Natural gas purchased for resale changes are offset by corresponding changes in “Natural gas revenues” on the statement of income.

These items have no overall impact on earnings.

Ameren Missouri and Ameren Illinois are allowed to pass on to customers prudently incurred costs for natural gas purchased for resale.

Ameren’s natural gas purchased for resale expenses decreased $35 million, or 10%, in 2024, compared with 2023, due to decreased natural gas purchased for resale expenses at Ameren Missouri and Ameren Illinois Natural Gas, as discussed below.

Ameren Missouri

Ameren Missouri’s natural gas purchased for resale expenses decreased $19 million, or 24%, in 2024, compared with 2023.

Expenses associated with “Cost recovery mechanisms – offset in natural gas revenue” decreased $20 million in 2024, compared with 2023, due to lower commodity prices and the absence of amortization of natural gas costs deferred under the PGA related to the extremely cold weather in mid-February 2 021.

Changes in natural gas purchased for resale expenses are fully offset by corresponding changes in natural gas revenues under the PGA.

Ameren Illinois Natural Gas

Ameren Illinois Natural Gas’ natural gas purchased for resale expenses decreased $16 million, or 6%, in 2024, compared with 2023, primarily due to lower amortization of natural gas costs that were previously deferred under the PGA and lower natural gas prices.

Changes in natural gas purchased for resale expenses are fully offset by changes in natural gas revenues under the PGA.

Other Operations and Maintenance Expenses

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Increase (Decrease) by Segment

Overall Ameren Decrease of $71 Million

Overall Ameren Increase of $103 Million

(a) Includes $70 million and $60 million at Ameren Transmission in 2024 and 2023, respectively, and other/intersegment eliminations of $0 million and $34 million in 2024 and 2023, respectively.

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Ameren Illinois Electric Distribution Ameren Transmission

Other operations and maintenance expenses at Ameren decreased $71 million in 2023, compared with 2022.

In addition to changes by segment as discussed below, other operations and maintenance expenses increased $18 million in 2023 for activity not reported as part of a

Table of Conten t s

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.

Other operations and maintenance expenses increased $103 million in 2024, compared with 2023 because of the changes discussed below.

In addition to changes by segment as discussed below, other operations and maintenance expenses decreased $34 million in 2024 for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of a $14 million increase in the elimination of intercompany rent related to ATXI’s operations control center discussed below;

a $10 million increase in the elimination of the non-service cost component of net periodic benefit income at Ameren Services;

and a $8 million gain on the sale of land.

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.

Other operations and maintenance expenses were comparable at Ameren Transmission between periods.

Ameren Transmission

Other operations and maintenance expenses increased $10 million in 2024, compared with 2023, primarily because of increased costs related to ATXI’s operations control center, which was placed in service in December 2023.

ATXI provides affiliates with access to this facility.

The rent expense associated with this facility is an affiliate transaction and eliminated in consolidation for purposes of Ameren’s consolidated financial statements.

See Note 13 - Related-party Transactions under Part II, Item 8, of this report for additional information.

Ameren Missouri

The $25 million decrease in Ameren Missouri’s other operations and maintenance expenses in 2023, compared with 2022, was primarily due to the following items:

• The cash surrender value of COLI increased $21 million.

The effect of changes in the cash surrender value of COLI resulted in gains of $7 million in 2023, compared with losses of $14 million in 2022.

• The 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 $14 million.

• Renewable development costs decreased $9 million, 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 $3 million, primarily because of the retirement of the Meramec Energy Center in December 2022, partially offset by increased costs related to maintenance outages at other energy centers.

The following items partially offset the above decreases in other operations and maintenance expenses between years:

• Transmission and distribution storm-related costs increased $7 million because of the major storms experienced throughout the service territory in July and August 2023.

• Transmission and distribution expenditures, excluding storm costs, increased $7 million, primarily because of increased inspection and vegetation management expenditures.

• MEEIA customer energy-efficiency program spend increased $3 million, as approved by the MoPSC.

Other operations and maintenance expenses increased $47 million in 2024, compared with 2023, primarily due to the following items:

• A $59 million charge related to an order from the United States District Court for the Eastern District of Missouri, which resolved all outstanding claims in the NSR and Clean Air Act litigation related to the Rush Island Energy Center, see Note 14 - Commitments and Contingencies under Part II, Item 8 , of this report for more information.

• The absence in 2024 of the recognition of regulatory assets for previously expensed costs approved for recovery pursuant to the June 2023 MoPSC rate order increased expenses $15 million.

• Individually insignificant increases of $7 million in various other operations and maintenance expenses, including other labor, cloud computing costs, and a decrease in the cash surrender value of COLI.

• The absence of previously deferred expenses increased expense by $7 million.

• Legal and administrative expenses increased by $6 million, primarily related to environmental matters.

• Costs for injuries and damages increased $4 million, primarily due to an increase in claims.

• Renewable development costs increased $3 million, primarily due to the absence in 2024 of the MoPSC order approving CCNs for the Boomtown and Huck Finn energy centers in the first half of 2023 that led to increased capitalization of renewable development costs pursuant to anticipated recovery from customers.

The following items partially offset the above increases in other operations and maintenance expenses between years:

• Pension and benefit costs decreased $20 million because of a lower base level of expenses, subject to a tracker, included in customer rates pursuant to the June 2023 MoPSC electric rate order.

See Note 10 - Retirement Benefits under Part II, Item 8, of this report for more information.

• Energy center maintenance decreased $17 million, primarily because of lower amortization of Callaway Energy Center refueling and maintenance costs resulting from cost saving initiatives in the fall 2023 outage, compared to the spring 2022 outage, and lower headcount.

• Transmission and distribution storm-related costs decreased $10 million because of the major storms experienced throughout the service territory in July and August 2023.

• Transmission and distribution expenditures, excluding major storm-related costs, decreased $8 million, primarily due to reduced levels of vegetation management expenditures and lower inspection costs from decreased use of contractors, and lower headcount.

Ameren Illinois

Other operations and maintenance expenses decreased $64 million at Ameren Illinois in 2023, compared with 2022, as discussed below.

Other operations and maintenance expenses were comparable at Ameren Illinois Transmission between 2023 and 2022.

Other operations and maintenance expenses increased $88 million at Ameren Illinois in 2024, compared with 2023, as discussed below.

Ameren Illinois Electric Distribution

The $48 million decrease in Ameren Illinois Electric Distribution’s other operations and maintenance expenses in 2023, compared with 2022, was primarily due to the following items:

• Bad debt costs decreased $43 million primarily because of a lower amount of costs recovered from customers pursuant to the associated rider.

• The cash surrender value of COLI increased $10 million in 2023, primarily because of favorable market returns, compared with unfavorable market returns in 2022.

• Pension and benefit costs decreased $8 million, primarily related to decreased pension service costs due to changes in actuarial assumptions.

The following items partially offset the above decreases in other operations and maintenance expenses between years:

• Amortization of regulatory assets associated with customer energy-efficiency investments under formula ratemaking increased $9 million.

• Amortization of previously deferred storm-related costs and costs related to major storm activity in 2023, increased $6 million.

Other operations and maintenance increased $87 million in 2024, compared with 2023, was primarily due to the following items:

• Bad debt costs increased $52 million, primarily because of a higher base level of expenses included in customer rates pursuant to the associated rider.

• Amortization of previous deferrals associated with bad debt costs on purchased receivables increased $15 million, primarily because of a higher base level of expenses included in customer rates pursuant to the associated rider.

• Increased costs associated with customer energy-efficiency investments under formula ratemaking of $13 million, primarily due to amortization of regulatory assets.

• Benefit costs increased $6 million, primarily due to an increase in medical benefit claims related to active plan participants.

• Increased labor expense of $5 million, primarily caused by reduced capital expenditures due to steps taken to align operations with the MYRP orders, resulting in more maintenance activities.

• Absence of major storm-related cost deferrals in 2024 increased expense by $4 million.

• Vegetation management costs increased by $4 million due to increased activity.

• Labor expense increased by $3 million due to assistance provided to other utilities to aid in storm recovery efforts, primarily caused by hurricane damage.

The following items partially offset the above increases in other operations and maintenance expenses between years:

• Reduction in environmental remediation rider costs of $14 million.

• Technology-related expenditures decreased $3 million resulting from lower levels of software licenses and rentals.

Ameren Illinois Natural Gas

Other operations and maintenance costs decreased $16 million in 2023, compared with 2022, in part, because of a $5 million increase in the cash surrender value of COLI.

In 2023, the effect of changes in the cash surrender value of COLI resulted in a gain of $2 million, compared with a loss of $3 million in 2022.

Other operations and maintenance expenses also decreased $5 million in 2023 because of a decline in required environmental remediation work.

Additionally, other operations and maintenance expenses decreased $4 million, primarily related to labor overhead costs.

Table of Conten t s

Depreciation and Amortization

Other operations and maintenance costs decreased $7 million in 2024, compared with 2023, primarily due to a decrease of $6 million in contractor service costs and a $4 million decrease in labor expense due to steps taken to align operations with the November 2023 ICC natural gas rate order.

These decreases were partially offset by an increase of $2 million in cloud computing costs.

Ameren Illinois Transmission

Other operations and maintenance expenses increased $8 million in 2024, compared with 2023, primarily because of increased costs related to ATXI’s operations control center, which was placed in service in December 2023.

ATXI provides affiliates with access to this facility.

The rent expense associated with this facility is an affiliate transaction and eliminated in consolidation for purposes of Ameren’s consolidated financial statements.

See Note 13 - Related-party Transactions under Part II, Item 8, of this report for additional information.

Depreciation and Amortization Expenses

Total by Segment (a)

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Ameren Illinois Electric Distribution Ameren Transmission

The $98 million, $51 million, and $42 million increases in depreciation and amortization expenses in 2023, compared with 2022, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, were primarily due to additional property, plant, and equipment across their respective segments.

In addition, Ameren’s and Ameren Missouri’s depreciation and amortization expenses were affected by the following, which include the effect of the additional investments in property, plant, and equipment:

• Increased depreciation and amortization of $51 million, due to the inclusion in base rates of amounts previously deferred under the PISA and RESRAM effective February 28, 2022, and July 9, 2023, pursuant to the December 2021 and June 2023 MoPSC electric rate orders, respectively.

• Depreciation and amortization rate changes pursuant to the electric rate orders noted above, which increased depreciation and amortization expenses by $17 million.

• Increased depreciation and amortization of $6 million, primarily because of electric system capital additions not eligible for deferral under PISA and RESRAM.

• The higher deferral, net of amortization of prior-period deferrals, pursuant to a tracker related to certain excess deferred income taxes, which decreased depreciation and amortization by $17 million.

• Depreciation and amortization expenses 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;

and when new customer rates became effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, which incorporated deferrals through December 31, 2022.

The effect of higher deferrals, net of amortization of prior-period deferrals, decreased depreciation and amortization expenses by $5 million.

• The higher net under-recovery of RESRAM eligible expenses decreased depreciation and amortization expenses by $3 million.

Table of Conten t s

Depreciation and amortization expenses increased $203 million, $134 million, and $63 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment investments across their respective segments.

In addition, Ameren’s and Ameren Missouri’s depreciation and amortization expenses were affected by the following items, which include the effect of the additional investments at Ameren Missouri:

• The deferral to a regulatory liability related to production tax credits allowed under the IRA associated with the Callaway Energy Center that increased expenses by $90 million.

• Increased depreciation and amortization of $40 million due to the inclusion in base rates of amounts previously deferred under the PISA and RESRAM effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order.

• Increased amortization of prior deferrals and the lower net under-recovery of RESRAM eligible expenses increased depreciation and amortization expenses by $33 million.

• Depreciation and amortization rate changes pursuant to the electric rate order noted above, which increased depreciation and amortization expenses by $4 million.

• Depreciation and amortization expenses reflected a deferral to a regulatory asset of depreciation associated with investments in eligible property, plant, and equipment not yet included in base rates, pursuant to PISA and RESRAM.

Base rates were updated to include the eligible property, plant, and equipment in-service through December 31, 2022, when new customer rates became effective on July 9, 2023, pursuant to the June 2023 MoPSC electric rate order.

The effect of rebasing PISA and RESRAM, partially offset by increased amortization of prior PISA deferrals, decreased depreciation and amortization by $30 million.

• The higher net deferral pursuant to a tracker related to certain excess deferred income taxes, which decreased depreciation and amortization expenses by $5 million.

Taxes Other Than Income Taxes

Total by Segment (a)

Increase (Decrease) by Segment

Overall Ameren Decrease of $17 Million

Increase by Segment

Overall Ameren Increase of $25 Million

(a) Includes $9 million and $8 million at Ameren Transmission in 2024 and 2023, respectively, and other/intersegment eliminations of $13 million and $12 million in 2024 and 2023, respectively.

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Ameren Illinois Electric Distribution Ameren Transmission

Taxes other than income taxes decreased $17 million in 2023, compared with 2022, largely because of a $14 million decrease in excise taxes at Ameren Illinois Natural Gas, primarily resulting from decreased sales revenues.

Taxes other than income taxes also decreased $6 million and $2 million in 2023, at Ameren Missouri and Ameren Illinois, respectively, because of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act.

The decreases in taxes other than income taxes at Ameren Missouri were partially offset by a $4 million increase in excise taxes, primarily related to increased retail electric rates pursuant to the June 2023 MoPSC electric rate order.

See Excise Taxes in Note 15 – Supplemental Information under Part II, Item 8, of this report for additional information.

Table of Conten t s

Taxes other than income taxes increased $25 million in 2024, compared with 2023, primarily because of an increase of $7 million and $2 million at Ameren Missouri and Ameren Illinois Electric Distribution, respectively, due to the absence in 2024 of employee retention tax credits received under the Coronavirus Aid, Relief, and Economic Security Act;

a $9 million increase at Ameren Illinois Natural Gas due to an increase in excise taxes, primarily resulting from higher invested capital taxes;

and a $3 million increase in gross receipts taxes at Ameren Missouri, primarily due to increased retail electric sales.

Other Income, Net

Total by Segment Increase by Segment

Total by Segment Increase (Decrease) by Segment

Overall Ameren Increase of $69 Million

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See Note 6 – Other Income, Net under Part II, Item 8, of this report for additional information.

See Note 10 – Retirement Benefits under Part II, Item 8, of this report for more information on the non-service cost components of net periodic benefit income.

See Note 5 – Long-term Debt and Equity Financings and Note 10 – Retirement Benefits under Part II, Item 8, for additional information on the debt extinguishment and the non-service cost components of net periodic benefit income.

Other income, net, increased $69 million in 2024, compared with 2023.

In addition to changes discussed below, other income, net, increased $26 million, primarily because of a $30 million increase in the non-service cost component of net periodic benefit income for activity not reported as part of a segment, partially offset by a $3 million increase in charitable contributions.

In addition to changes discussed below, other income, net, increased $14 million for activity not reported as part of a segment, primarily due to lower charitable contributions of $18 million at Ameren (parent) and a gain of $16 million for Ameren (parent)’s repurchase of senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois.

These increases were partially offset by a decrease of $13 million due to the non-service cost component of net periodic benefit income for activity not reported as part of a segment and $7 million in intersegment eliminations.

Ameren Transmission

Other income, net, increased $11 million in 2023, compared with 2022, largely because of a $5 million increase in the allowance for equity funds used during construction, primarily resulting from a higher average monthly equity-to-debt ratio at ATXI, and higher average construction work in progress balances.

Other income, net, also increased $3 million because of an increase in the non-service cost component of net periodic benefit income.

Other income, net, decreased $2 million in 2024, compared with 2023 due to a decrease of $5 million in lower allowance for equity funds used during construction, primarily related to lower average construction work in progress balances and a decrease of $2 million in the non-service cost component of net periodic benefit income.

These decreases were partially offset by the increase of $4 million in other interest income on regulatory balances.

Ameren Missouri

Other income, net, increased $31 million in 2023, compared with 2022, primarily because of a $42 million increase in the non-service cost component of net periodic benefit income pursuant to the June 2023 MoPSC electric rate order, which reflected the effect of such increase in electric service rates effective July 9, 2023.

Other income, net, also increased $6 million because of higher allowance for equity funds used during construction, resulting from higher average construction work in progress balances.

Additionally, other income, net increased $6 million because of higher interest income on under-recovered asset balances associated with regulatory recovery mechanisms.

These increases in other income, net, were partially offset by a decrease of $23 million in interest income on industrial development revenue bonds, as these bonds were settled in December 2022 and January 2023.

See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements related to the investments in industrial development revenue bonds.

Table of Conten t s

Other income, net, increased $66 million in 2024, compared with 2023, primarily because of an increase of $42 million in the non-service cost component of net periodic benefit income because of changes in the base level of pension and postretirement costs pursuant to the June 2023 MoPSC electric rate order.

Other income, net, also increased $28 million because of a higher allowance for equity funds used during construction resulting from higher average construction work in progress balances.

These increases were offset by a decrease of $2 million in other interest income on regulatory balances.

Ameren Illinois

Other income, net, increased $60 million in 2023, compared with 2022, primarily because of increases in the non-service cost component of net periodic benefit income of $26 million, $11 million, and $3 million at Ameren Illinois Electric Distribution, Ameren Illinois Natural Gas, and Ameren Illinois Transmission, respectively.

Other income, net, also increased $13 million at Ameren Illinois Electric Distribution because of higher interest income on under-recovered balances associated with regulatory recovery mechanisms.

Other income, net, decreased $9 million in 2024, compared with 2023.

Other income, net, decreased primarily because of a decrease of $12 million and $6 million in the non-service cost component of net periodic benefit income at Ameren Illinois Electric Distribution and Ameren Illinois Natural Gas, respectively.

Other income, net decreased $2 million in the allowance of equity funds used during construction, largely at Ameren Illinois Electric Distribution.

These decreases were partially offset by the increase in other interest income on regulatory balances of $11 million, largely at Ameren Illinois Electric Distribution.

Interest Charges

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Ameren Illinois Electric Distribution Ameren Transmission

Interest charges increased $80 million in 2023, compared with 2022, primarily because of the following items:

See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, 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 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreement discussed below.

Interest charges increased $97 million in 2024, compared with 2023.

In addition to changes by segments discussed below, interest charges increased $28 million for activity not reported as part of a segment, primarily because of a $23 million increase related to higher interest rates on increased levels of short-term borrowings at Ameren (parent).

Interest charges for activity not reported as part of a segment also increased $5 million because of issuances of long-term debt at Ameren (parent) in November and December 2023.

In addition to changes by segments discussed below, interest charges increased $42 million for activity not reported as part of a segment, primarily at Ameren (parent), because of issuances of long-term debt in November and December of 2023, which collectively increased interest charges by $64 million.

The net proceeds from these issuances were used to repay short-term borrowings, which decreased short-term interest expense by $23 million, compared with 2023.

Ameren Transmission

Interest charges increased $12 million in 2023, compared with 2022, primarily because of issuances of long-term debt in August and November 2022 and May 2023, which collectively increased interest charges by $17 million.

The increases in 2023 were partially offset by a $8 million reduction to interest charges because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to increased average construction work in progress balances and a higher applicable borrowing rate.

Interest charges increased $21 million in 2024, compared with 2023, primarily due to issuances of long-term debt in May 2023, June 2024 and August 2024, which collectively increased interest charges by $9 million.

Additionally, an increase on long-term debt and a higher interest rate on an increased level of short-term borrowings increased interest charges by $8 million and $2 million, respectively.

Ameren Missouri

Interest charges increased $14 million in 2023, compared with 2022.

The following items increased interest charges between years:

Table of Conten t s

• Issuances of long-term debt in April 2022 and March 2023 collectively increased interest charges by $27 million.

• Interest charges increased $11 million because of higher interest rates on increased levels of short-term borrowings.

• Interest charges reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM.

The amount of PISA and RESRAM deferrals included in base rates 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, and when new customer rates became effective July 9, 2023, pursuant to the June 2023 MoPSC electric rate order, which incorporated deferrals through December 31, 2022.

Lower deferrals in 2023, 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 $9 million.

The following items partially offset the above increases in interest charges between years:

• Interest charges decreased $23 million, primarily due to the termination of a financing obligation agreement related to the CT energy center in Audrain County.

The decreases in interest charges associated with this agreement are offset by decreases in interest income on related industrial development revenue bonds, as discussed above.

• Interest charges decreased $14 million because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to higher average construction work in progress balances and a higher applicable borrowing rate.

Interest charges increased $17 million in 2024, compared with 2023, primarily due to issuances of long-term debt in March 2023, January 2024, April 2024, and October 2024, which collectively increased interest charges by $48 million.

The following items partially offset the above increase in interest charges between years:

• Increase in the borrowed funds capitalized as part of the allowance for funds used during construction of $12 million, primarily due to higher average construction work in progress balances.

• Interest charges decreased by $9 million due to the maturity of $350 million senior secured notes bearing a 3.5% interest rate in April 2024 that were repaid with cash on hand.

• Interest charges reflected a deferral to a regulatory asset of interest associated with investments in eligible property, plant, and equipment not yet included in base rates, pursuant to PISA and RESRAM.

This update to base rates resulted in a higher deferral of interest in 2024 pursuant to PISA and RESRAM that decreased interest charges by $5 million.

• Lower levels of short-term borrowings decreased interest charges by $4 million.

Ameren Illinois

Interest charges increased $36 million in 2023, compared with 2022, primarily because of the issuances of long-term debt in 2022 and 2023.

Issuances of long-term debt at Ameren Illinois in August and November 2022 and May 2023 collectively increased interest charges by $19 million at Ameren Illinois Electric Distribution, by $15 million at Ameren Illinois Transmission, and $12 million at Ameren Illinois Natural Gas.

The increases in 2023 were partially offset by a $4 million reduction to interest charges at Ameren Illinois Transmission because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to higher average construction work in progress balances and a higher applicable borrowing rate.

Interest charges increased $37 million in 2024, compared with 2023, primarily due to the following:

Ameren Illinois Transmission

Interest charges increased by $20 million, primarily due to issuances of long-term debt in May 2023 and June 2024, which increased interest charges by $10 million.

Additionally, an increase of interest on long-term debt, a higher interest rate on an increased level of short-term borrowings, and interest charges resulting from the October 2024 FERC ROE order increased interest charges by $4 million, $2 million, and $2 million, respectively.

Ameren Illinois Electric Distribution

Interest charges increased by $9 million, primarily due to issuances of long-term debt in May 2023 and June 2024, which increased interest charges by $11 million.

Ameren Illinois Natural Gas

Interest charges increased by $8 million, primarily due to issuances of long-term debt in May 2023 and June 2024.

The following table presents effective income tax rates for the years ended December 31, 2024 and 2023:

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See Note 12 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates for Ameren, Ameren Missouri, and Ameren Illinois.

The effective tax rate was lower at Ameren Illinois Electric Distribution in 2024, compared with 2023, primarily due to an increase in excess deferred tax amortization pursuant to an ICC order, which was offset by a corresponding decrease in revenues.

LIQUIDITY AND CAPITAL RESOURCES

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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).

In addition, to support a portion of its fuel requirements for generation, Ameren Missouri has entered into various long-term commitments to meet these requirements.

In addition, to support a portion of its fuel requirements for generation, Ameren Missouri has entered into various long-term commitments to

meet these requirements.

Ameren Missouri and Ameren Illinois also have entered into various long-term commitments for purchased power and natural gas for distribution.

Ameren’s, Ameren Missouri’s, and Ameren Illinois’ estimated minimum purchase obligations associated with these commitments totaled $2.1 billion, $1.0 billion, and, $1.1 billion, respectively, which include $0.8 billion, $0.3 billion, and, $0.5 billion, respectively, in 2025.

Further, for additional information about Ameren’s and Ameren Missouri’s obligations associated wtih operating leases, see Note 15 – Supplemental Information.

We expect to make significant capital expenditures over the next five years, as discussed in the Capital Expenditures sections below, 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.

For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see

Table of Conten t s

Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report.

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 this report.

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 2029.

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As of December 31, 2024, Ameren had multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 2.5 million shares of common stock.

Ameren expects to settle approximately $230 million of the forward sale agreements with physical delivery of 2.9 million shares of common stock by December 31, 2024.

Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue approximately $300 million of equity in 2024 and approximately $600 million of equity each year from 2025 to 2028.

Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue approximately $600 million of equity each year from 2025 to 2029.

As of December 31, 2024, Ameren had approximately $550 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of December 31, 2024.

Ameren expects its equity to total capitalization to support solid investment-grade credit ratings.

The Ameren Companies expect their equity to total capitalization and cash flow metrics to support solid investment-grade credit ratings.

See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the ATM program, including the forward sale agreements under the ATM program relating to common stock.

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See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about our regulatory frameworks.

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’s cash provided by operating activities increased $199 million in 2024, compared with 2023.

The following items contributed to the increase:

• A $372 million increase in customer collections, primarily from base rate increases effective February 28, 2022, and July 9, 2023, pursuant to Ameren Missouri’s December 2021 and June 2023 MoPSC electric rate orders, respectively, electric transmission rate base growth, and an increase attributable to non-PGA regulatory mechanisms, partially offset by a decrease under Ameren Illinois’ PGA resulting from the 2022 recovery of costs for the mid-February 2021 weather event discussed above.

• A $211 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.

• A $66 million decrease in the cost of natural gas held in storage, primarily at Ameren Illinois, because of lower commodity prices.

• A $201 million increase resulting from increased customer collections primarily from base rate increases effective July 9, 2023, at Ameren Missouri pursuant to the June 2023 electric rate order, base rate increases effective November 28, 2023, at Ameren Illinois pursuant to the November 2023 natural gas rate order and electric transmission rate base growth, and increased customer collections under cost recovery mechanisms at Ameren Illinois, partially offset by lower customer collections under cost recovery mechanisms at Ameren Missouri.

• A $68 million increase in income tax refunds, net, due to the transfer of production and investment tax credits to unrelated parties and higher income tax refunds primarily due to lower taxable income compared to 2023, mainly driven by the adoption of IRS-issued guidance for the 2024 tax year that provided a safe harbor method of accounting for the capitalization or deduction of certain

expenditures to maintain, repair, replace, or improve natural gas distribution property.

• A $37 million increase due to higher purchases of materials and supplies inventories in 2023 to support operations as levels were increased to mitigate against potential supply disruptions.

• A $33 million increase due to the absence of nuclear refueling and maintenance outage payments in 2024 related to the Callaway Energy Center.

The last scheduled refueling and maintenance outage was in the fall of 2023.

• A $24 million increase due to higher major storm restoration costs in 2023, primarily at Ameren Illinois, due to storms in the summer of 2023.

• A $22 million increase due to insurance proceeds received in 2024 related to workers’ compensation payments made in the 2023 at Ameren Illinois.

• A $20 million increase due to higher coal purchases in 2023 to bring coal inventories back to targeted levels after transportation delays experienced in 2022.

• A $20 million decrease in payments related to charitable donations.

• A $16 million increase due to workers’ compensation payments made in 2023 at Ameren Illinois.

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

Table of Conten t s

• A $148 million increase in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.

• A $65 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates.

This $70 million increase in interest payments includes a $24 million decrease in interest payments from financing obligations at Ameren Missouri that were settled in December 2022 and January 2023.

See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements.

• A $65 million increase in coal inventory levels at Ameren Missouri, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes, which were affected by reduced generation at the Rush Island Energy Center, lower market prices for capacity and energy, and decreased retail load because of warmer winter and milder spring and summer temperatures.

• A $35 million increase in labor costs and payments to contractors primarily due to major storm restoration costs, primarily at Ameren Illinois, due to major storms in late June, July, and August 2023.

• A $25 million decrease due to the timing of payments for accounts payable and prepaid expenses.

• A $25 million decrease due to the timing of payments received from the DOE for the annual reimbursement of spent nuclear fuel storage and related costs.

• A $24 million decrease in interest collections on industrial revenue bonds at Ameren Missouri, as these bonds were settled in December 2022 and January 2023.

• A $23 million increase in workers’ compensation payments at Ameren Illinois.

• An $11 million increase in property tax payments at Ameren Missouri, primarily due to higher assessed property tax values.

• A $32 million increase in the cost of natural gas held in storage, primarily at Ameren Illinois, due to changes in the market price of natural gas.

Ameren Missouri

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The following items contributed to the increase:

• A $239 million increase in customer collections, primarily from base rate increases effective February 28, 2022, and July 9, 2023, pursuant to the December 2021 and June 2023 MoPSC electric rate orders, respectively, and an increase attributable to regulatory mechanisms.

• A $131 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.

• A $5 million decrease in interest payments, primarily due to a $24 million decrease in interest payments from financing obligations that were settled in December 2022 and January 2023.

See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on the termination of the financing obligation agreements, partially offset by an increase in interest payments due to an increase in the average outstanding debt and an increase in interest rates.

• A $117 million increase in income tax refunds, net, due to the transfer of production and investment tax credits to unrelated parties, as well as an income tax refund from Ameren (parent), pursuant to the tax allocation agreement, primarily due to lower taxable income compared to 2023.

• A $49 million increase resulting from increased customer collections primarily from base rate increases effective July 9, 2023, pursuant to the June 2023 electric rate order, partially offset by lower customer collections under cost recovery mechanisms.

• A $40 million increase due to higher purchases of materials and supplies inventories in 2023 to support operations as levels were increased to mitigate against potential supply disruptions.

• A $33 million increase due to the absence of nuclear refueling and maintenance outage payments in 2024 related to the Callaway Energy Center.

The last scheduled refueling and maintenance outage was in the fall of 2023.

• A $31 million increase due to the timing of payments for accounts payable and prepaid expenses.

• A $20 million increase due to higher coal purchases in 2023 to bring coal inventories back to targeted levels after transportation delays experienced in 2022.

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

• A $65 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, which were affected by reduced generation at the Rush Island Energy Center, lower market prices for capacity and energy, and decreased retail load because of warmer winter and milder spring and summer temperatures.

• A $25 million decrease due to the timing of payments received from the DOE for the annual reimbursement of spent nuclear fuel storage and related costs.

• A $24 million decrease in interest collections on industrial revenue bonds, as these bonds were settled in December 2022 and January 2023.

• A $16 million decrease due to the timing of payments for accounts payable and prepaid expenses.

• An $11 million increase in property tax payments, primarily due to higher assessed property tax values.

• A $7 million increase in major storm restoration costs, primarily due to major storms in July and August 2023.

• A $99 million increase in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.

• A $19 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates.

Ameren Illinois

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The following items contributed to the increase:

• A $145 million increase in customer collections, primarily from electric transmission rate base growth and an increase attributable to non-PGA regulatory recovery mechanisms, partially offset by a decrease under the PGA resulting from the recovery in 2022 of costs for the mid-February 2021 weather event discussed above.

• An $83 million decrease in net collateral posted with counterparties, primarily due to changes in the market prices of power and natural gas.

• A $63 million decrease in the cost of natural gas held in storage because of lower commodity prices.

Table of Conten t s

• A $148 million increase due to an income tax refund from Ameren (parent), pursuant to the tax allocation agreement, primarily due to lower taxable income compared to 2023, mainly driven by the adoption of IRS issued guidance for the 2024 tax year that provided a safe harbor method of accounting for the capitalization or deduction of certain expenditures to maintain, repair, replace, or improve natural gas distribution property.

• A $139 million increase resulting from increased customer collections primarily from base rate increases effective November 28, 2023, pursuant to the November 2023 natural gas rate order and electric transmission rate base growth, and by increased customer collections under cost recovery mechanisms.

• A $34 million increase due to the timing of payments for accounts payable and prepaid expenses.

• A $22 million increase due to insurance proceeds received in 2024 related to workers’ compensation payments made in 2023.

• A $20 million increase due to workers’ compensation payments made in 2023.

• A $19 million increase due to higher major storm restoration costs in 2023 due to storms in the summer of 2023.

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

• A $79 million decrease resulting from income tax payments to Ameren (parent) pursuant to the tax allocation agreement, primarily due to higher taxable income in 2023.

• A $64 million decrease due to the timing of payments for accounts payable and prepaid expenses.

• A $43 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates.

• A $28 million increase in labor costs and payments to contractors primarily due to major storm restoration costs due to major storms in late June, July, and August 2023.

• A $23 million increase in workers’ compensation payments.

• A $43 million increase in net collateral posted with counterparties, primarily due to changes in the market prices of power and natural gas.

• A $29 million increase in the cost of natural gas held in storage due to changes in the market price of natural gas.

• An $18 million increase in interest payments, primarily due to an increase in the average outstanding debt and an increase in interest rates.

Cash Flows from Investing Activities

Ameren’s cash used in investing activities increased $428 million during 2023, compared with 2022, primarily as a result of a $246 million increase in capital expenditures, largely resulting from increased storm-related expenditures at Ameren Missouri and Ameren Illinois and electric transmission upgrades at ATXI.

ATXI’s capital expenditures increased $56 million.

Also, cash used in investing activities increased at Ameren Missouri, due to increased nuclear fuel expenditures of $145 million and the absence of receipt of $21 million in insurance proceeds in 2022 for the Callaway Energy Center’s generator.

Ameren Missouri’s cash used in investing activities increased $257 million during 2023, compared with 2022, primarily due to increased nuclear fuel expenditures for future refuels of $174 million in 2023 compared to $29 million in 2022.

Also, cash used in investing activities increased $70 million as a result of increased capital expenditures, largely resulting from an increase in storm-related expenditures of $58 million.

In addition, cash used in investing activities increased due to the absence of receipt of $21 million in insurance proceeds in 2022 for the Callaway Energy Center’s generator.

Ameren Illinois’ cash used in investing activities increased $131 million during 2023, compared with 2022, due to an increase in capital expenditures, largely resulting from increased storm-related expenditures of $103 million.

Ameren’s cash used in investing activities increased $658 million during 2024, compared with 2023, primarily as a result of a $722 million increase in capital expenditures, largely resulting from the acquisitions and completion of the Cass County, Boomtown, and Huck Finn energy centers at Ameren Missouri.

Ameren’s increase in capital expenditures was partially offset by decreased expenditures for electric transmission infrastructure upgrades, reduced expenditures for electric distribution infrastructure upgrades and natural gas infrastructure upgrades due to steps taken by Ameren Illinois to align its 2024 operations with the ICC’s MYRP orders and November 2023 natural gas rate order, and due to decreased storm-related expenditures of $92 million at Ameren Illinois.

Ameren’s cash used in investing activities was also partially offset by an $83 million decrease due to the timing of nuclear fuel expenditures.

Ameren Missouri’s cash used in investing activities increased $938 million during 2024, compared with 2023, primarily as a result of a $952 million increase in capital expenditures, largely resulting from the acquisitions and completion of the Cass County, Boomtown, and Huck Finn energy centers.

Ameren Missouri’s cash used in investing activities also increased as a result of a $43 million increase in net money pool advances, and was partially offset by an $83 million decrease due to the timing of nuclear fuel expenditures.

Ameren Illinois’ cash used in investing activities decreased $267 million during 2024, compared with 2023, due to a decrease in capital expenditures, largely resulting from decreased expenditures for electric transmission infrastructure upgrades.

Ameren Illinois’ capital expenditures also decreased as a result of reduced expenditures for electric distribution infrastructure upgrades and natural gas infrastructure upgrades due to steps taken by Ameren Illinois to align its 2024 operations with the ICC’s MYRP orders and November 2023 natural gas rate order, and due to decreased storm-related expenditures of $92 million.

Capital Expenditures

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(a) Includes Other capital expenditures of $6 million and $(18) million for the years ended December 31, 2024 and 2023, respectively, which includes amounts for the elimination of intercompany transfers.

Table of Conten t s

Ameren’s 2024 capital expenditures consisted of expenditures made by its subsidiaries, including $134 million by ATXI and other electric transmission subsidiaries.

Ameren Illinois Natural Gas capital expenditures for 2023 included $165 million related to natural gas projects eligible for QIP recovery.

Ameren’s 2023 capital expenditures consisted of expenditures made by its subsidiaries, including $124 million by ATXI and other electric transmission subsidiaries.

Ameren Illinois Natural Gas capital expenditures for 2022 included $183 million related to natural gas projects eligible for QIP recovery.

In both years, other capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology.

In both years, capital expenditures were made principally to maintain, upgrade, and improve the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois by investing in substation upgrades, energy center projects, and smart-grid technology.

Additionally, the Ameren Companies invested in various software projects.

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Ameren $ 4,195 $ 20,970 – $ 23,180 $ 25,165 – $ 27,375

Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, including $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments through 2028, consistent with Ameren Missouri’s 2023 IRP, as well as expenditures for compliance with environmental regulations.

Capital expenditures related to coal-fired generation of approximately $0.9 billion are included in Ameren Missouri’s estimated capital expenditures through 2028.

Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, including investments to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained.

Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.

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.

In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects.

In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion.

The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024.

Ameren Missouri’s estimated capital expenditures include transmission, distribution, grid modernization, and generation-related investments, primarily renewable and natural gas generation, as well as expenditures for compliance with environmental regulations .

Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments.

In February 2025, Ameren Missouri filed an update to its Smart Energy Plan with the MoPSC, which includes a five-year capital investment overview with a detailed one-year plan for 2025.

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Investments under the plan are expected to total approximately $16.2 billion over the five-year period from 2025 through 2029, with expenditures largely recoverable under the PISA.

Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

Ameren Missouri continually reviews its generation portfolio and expected power needs.

See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, for additional information on the EPA regulations.

The Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.

Ameren Missouri continually reviews its generation portfolio and expected power needs, including estimates of future load growth.

As a result, Ameren Missouri could modify its plan for generation capacity, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other changes.

Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments within and outside our service territories.

The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, future rate orders, and our ability and willingness to pursue transmission investments, as well as our ability to obtain necessary regulatory approvals, among other factors.

The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, significant changes in environmental regulations, future rate orders, and our ability and willingness to pursue transmission investments, as well as our ability to obtain necessary regulatory approvals, among other factors.

Any changes in future generation, transmission, or distribution needs could result in significant changes in capital expenditures or losses, which could be material.

Compliance with environmental regulations could also have significant impacts on the level of capital expenditures.

In 2022, the MISO approved the first tranche of projects under 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.

In addition, the MISO awarded three competitive bid projects to ATXI that represent a total estimated investment of approximately $220 million for ATXI.

Also in December 2024, the MISO approved a first set of second tranche projects.

A portion of these projects were assigned to Ameren and are estimated to cost approximately $1.3 billion, based on the MISO’s cost estimate.

The competitive bid process is expected to take place through 2026.

The MISO is assessing future long-range transmission scenarios in the first quarter of 2025 and development of a second set of second tranche projects will follow this assessment.

Environmental Capital Expenditures

Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO 2 , NO x , and mercury emissions from its coal-fired energy centers, compliance with the CCR Rule, and potential modifications to cooling water

Table of Conten t s

intake structures at existing power plants under Clean Water Act rules.

Ameren Missouri will continue to incur costs to comply with federal and state regulations, including those requiring the reduction of SO 2 , NO x , CO 2 , and mercury emissions from its coal-fired energy centers, compliance with the CCR Rule, and potential modifications to cooling water intake structures at existing power plants under Clean Water Act rules.

See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing and proposed environmental laws that affect, or may affect, our facilities and capital expenditures to comply with such laws.

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Ameren’s cash provided by financing activities increased $459 million during 2024, compared with 2023.

During 2023, Ameren utilized net proceeds of $2.3 billion of long-term debt for general corporate purposes, for capital expenditures, to repay then-outstanding short-term debt, and to repay $100 million of maturities of long-term debt.

Ameren also repaid net commercial paper borrowings totaling $533 million.

I n addition, Ameren utilized aggregate cash proceeds of $346 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and cash provided by operating activities to fund, in part, capital expenditures.

In comparison, in 2022, Ameren utilized proceeds from the issuance of $1.5 billion of long-term debt to repay then-outstanding short-term debt, for capital expenditures, and to repay $505 million of maturities of long-term debt.

Ameren also received aggregate cash proceeds of $333 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and $522 million from net commercial paper issuances.

These proceeds were used to fund, in part, capital expenditures.

During 2024, Ameren utilized net proceeds of $2.5 billion from the issuance of long-term debt for capital expenditures, to repay then-outstanding short-term debt, to repay $49 million of maturities of long-term debt at ATXI, and to finance energy transition costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs .

In addition, Ameren utilized proceeds from net commercial paper issuances of $607 million, aggregate cash proceeds of $273 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and cash provided by operating activities to repay $800 million of long-term debt maturities at Ameren (parent) and Ameren Missouri, and to fund, in part, capital expenditures.

In comparison, in 2023, Ameren utilized net proceeds of $2.3 billion from the issuance of long-term debt for general corporate purposes, for capital expenditures, to repay then-outstanding short-term debt, and to repay $100 million of maturities of long-term debt.

Ameren also repaid net commercial borrowings totaling $533 million.

In addition, Ameren utilized aggregate cash proceeds of $346 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan, and cash provided by operating activities to fund, in part, capital expenditures.

During 2024, Ameren paid common stock dividends of $714 million, compared with $662 million in dividend payments in 2023.

Ameren Missouri’s cash provided by financing activities increased $766 million during 2024, compared with 2023.

During 2023, Ameren Missouri utilized net proceeds of $499 million from the issuance of long-term debt for capital expenditures and to repay then-outstanding short-term debt.

During 2024, Ameren Missouri utilized net proceeds of $1.8 billion from the issuance of long-term debt for capital expenditures, to repay then-outstanding short-term debt, and to finance energy transition costs related to the accelerated retirement of the Rush Island Energy Center, which included the remaining unrecovered net plant balance associated with the facility, among other costs .

In addition, Ameren Missouri repaid $350 million of long-term debt maturities, $170 million of net commercial paper borrowings, and $306 million of money pool borrowings.

During 2024, Ameren Missouri also utilized capital contributions from Ameren (parent) of $476 million along with cash provided by operating activities to fund, in part, capital expenditures.

In comparison, in 2023, Ameren Missouri utilized net proceeds of $499 million from the issuance of long-term debt for capital expenditures and to repay then-outstanding short-term debt.

Ameren Missouri also repaid net commercial paper borrowings totaling $159 million.

In addition, Ameren Missouri utilized net proceeds of $306 million from money pool borrowings along with cash provided by operating activities to fund, in part, capital expenditures.

In comparison, in 2022, Ameren Missouri utilized net proceeds of $524 million from the issuance of long-term debt to repay then-outstanding short-term debt and for capital expenditures.

Ameren Missouri also utilized proceeds from net commercial paper issuances of $164 million along with cash provided by operating activities to fund, in part, capital expenditures.

During 2023, Ameren Missouri paid common stock dividends of $9 million, compared with $46 million in dividend payments in 2022.

Ameren Illinois’ cash provided by financing activities increased $66 million during 2023, compared with 2022.

During 2023, Ameren Illinois utilized net proceeds of $498 million from the issuance of long-term debt to repay then-outstanding short-term debt and $100 million of long-term debt maturities.

In addition, during 2023, Ameren Missouri utilized net proceeds of $306 million from money pool borrowings along with cash provided by operating activities to fund, in part, capital expenditures.

Ameren Illinois’ cash provided by financing activities decreased $513 million during 2024, compared with 2023.

During 2024, Ameren Illinois utilized net proceeds of $624 million from the issuance of long-term debt to repay then-outstanding short-term debt.

In addition, Ameren Illinois repaid net commercial paper borrowings of $277 million and money pool borrowings of $98 million.

During 2024, Ameren Illinois also utilized capital contributions from Ameren (parent) of $36 million along with cash provided by operating activities to fund, in part, capital expenditures.

In comparison, in 2023, Ameren Illinois utilized net proceeds of $498 million from the issuance of long-term debt to repay then-outstanding short-term debt and $100 million of long-term debt maturities.

In addition, Ameren Illinois utilized proceeds from net commercial paper issuances of $102 million, proceeds of $135 million from money pool borrowings, and capital contributions from Ameren (parent) of $91 million along with cash provided by operating activities to fund, in part, capital expenditures.

In comparison, in 2022, Ameren Illinois utilized net proceeds of $848 million from the issuance of long-term debt to repay $400 million of maturities of long-term debt and to repay a portion of then-outstanding short-term debt.

Additionally, the proceeds from the issuance of long-term debt, proceeds from net commercial paper issuances of $161 million, capital contributions from Ameren (parent) of $15 million, and cash provided by operating activities were used to fund, in part, capital expenditures.

During 2023, Ameren Illinois paid common stock dividends of $41 million.

Credit Facility Borrowings 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, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings.

During 2024, Ameren Illinois paid common stock dividends of $110 million, compared with $41 million in dividend payments in 2023.

Short-term Debt and Liquidity

The liquidity needs of the Ameren Companies are supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings.

See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, commercial paper issuances, Ameren’s money pool arrangements and related borrowings, and relevant interest rates.

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The following table presents Ameren’s consolidated net available liquidity as of December 31, 2024:

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Missouri Credit Agreement – borrowing capacity

Ameren Missouri commercial paper outstanding

Ameren (parent) commercial paper outstanding

Letters of credit

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Illinois Credit Agreement – borrowing capacity

Ameren (parent) commercial paper outstanding

Ameren Illinois commercial paper outstanding

Letters of credit

Illinois Credit Agreement – subtotal

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Cash and cash equivalents 7

Net available liquidity $ 2,087

Net available liquidity (c)

(a) The maximum aggregate amount available to both Ameren (parent) and Ameren Missouri under the Missouri Credit Agreement is $1 billion.

(b) The maximum aggregate amount available to Ameren (parent) and Ameren Illinois under the Illinois Credit Agreement is $700 million and $1 billion, respectively.

See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information.

The Credit Agreements, among other things, provide $2.6 billion of credit until maturity in December 2028.

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The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements for changing business conditions.

When business conditions warrant, changes may be made to existing credit agreements or to other short-term borrowing arrangements, or other arrangements may be made.

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When business conditions warrant, changes may be made to the existing Credit Agreements or to other borrowing arrangements, or other arrangements may be made.

Long-term Debt and Equity

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Ameren Missouri:

5.25% First mortgage bonds due 2054 January 347 —

5.45% First mortgage bonds due 2053 March — 499

3.90% First mortgage bonds due 2052 (a)

5.20% First mortgage bonds due 2034 April 499 —

5.125% First mortgage bonds due 2055 October 449 —

4.85% Securitized utility tariff bonds due 2039 (a)

December 476 —

Ameren Illinois:

4.95% First mortgage bonds due 2033 May — 498

3.85% First mortgage bonds due 2032 August — 499

5.90% First mortgage bonds due 2052 (a)

November — 349

2.96% Senior unsecured notes Series B due 2052 August — 95

5.55% First mortgage bonds due 2054 June 624 —

5.17% Senior unsecured notes due 2039 August 70 —

5.42% Senior unsecured notes due 2053 August 70 —

Total Ameren long-term debt issuances $ 2,535 $ 2,295

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Maturities of Long-term Debt

2.50% Senior unsecured notes due 2024 September $ 450 $ —

Ameren Missouri:

Audrain County agreement (Audrain County CT) due 2023 January $ 240 $ —

1.60% 1992 Series bonds due 2022 November — 47

City of Bowling Green financing obligation (Peno Creek CT) December — 8

Audrain County agreement (Audrain County CT) due 2023 January — 240 (f)

3.50% Senior secured notes due 2024 April 350 —

Ameren Illinois:

0.375% First mortgage bonds due 2023 June — 100

2.70% Senior secured notes due 2022 September — 400

3.43% Senior unsecured notes due 2050 August 49 —

Total long-term debt redemptions, repurchases, and maturities $ 340 $ 505

(a) Ameren Missouri and Ameren Illinois intend to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.

Total Ameren long-term debt maturities $ 849 (g)

(a) These securitized utility tariff bonds were issued by AMF.

The securitized tariff bondholders have no recourse to Ameren Missouri.

(b) Ameren issued a total of 0.5 million and 0.6 million shares of common stock under its DRPlus and 401(k) plan in 2024 and 2023, respectively.

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(e) Excludes 0.2 million and 0.5 million shares of common stock valued at $16 million and $40 million issued for no cash consideration in connection with stock-based compensation in 2024 and 2023, respectively.

In January 2024, Ameren Missouri issued $350 million of 5.25% first mortgage bonds due January 2054, with interest payable semiannually on January 15 and July 15 of each year, beginning July 15, 2024.

Net proceeds from this issuance were used for capital expenditures and to repay short-term debt.

(f) 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.

(g) Excludes Ameren (parent)’s November and December 2024 purchases of senior secured notes and first mortgage bonds issued by Ameren Missouri and first mortgage bonds issued by Ameren Illinois for $44 million in aggregate.

The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such sales.

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At December 31, 2024, the Ameren Companies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements.

See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings

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under Part II, Item 8, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our credit agreements, certain of the Ameren Companies’ indentures and articles of incorporation, and ATXI’s note purchase agreements.

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

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 provided by our operating activities.

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See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.

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Credit Ratings

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Commercial paper P-2 A-2

AMF securitized utility tariff bonds Aaa AAA

Ameren Illinois:

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Our electric generation, transmission, and distribution and natural gas distribution and storage operations must comply with a variety of statutes and regulations relating to the protection of the environment and human health and safety, including permitting programs implemented by federal, state, and local authorities.

Such environmental laws address air emissions;

discharges to water bodies;

the storage, handling and disposal of hazardous substances and waste materials;

Such environmental laws regulate air emissions;

protect water bodies;

manage the handling and disposal of hazardous substances and waste materials;

siting and land use requirements;

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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 operations at some of Ameren Missouri’s energy centers.

Additionally, international agreements could lead to future federal or state legislation or regulations.

In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris

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Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius.

The Biden administration made a policy commitment regarding a reduction in greenhouse gas emissions for the United States, but rulemaking to achieve such reductions has not yet been implemented.

Actions taken to implement the Paris Agreement could result in future additional greenhouse gas reduction requirements in the United States.

In addition, the EPA has announced plans to implement new climate change programs, including potential regulation of greenhouse gas emissions from the utility industry.

Additionally, international agreements have in the past, and could again, lead to future federal or state legislation or regulations.

In 2015, the United Nations Framework Convention on Climate Change reached consensus among approximately 190 nations on an agreement, known as the Paris Agreement, that establishes a framework for greenhouse gas mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2 degrees Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5 degrees Celsius.

In accordance with the new presidential administration’s approach to United States energy policy, in January 2025, the United States withdrew from the Paris Agreement.

The current federal administration is expected to review, and has already revised, compliance requirements under a number of federal environmental regulatory programs;

however, differences in energy policy priorities adopted by future federal administrations could result in additional greenhouse gas reduction requirements in the United States.

We provide information regarding our sustainability initiatives through our website, including in our annual sustainability report, our responses to the annual climate change and water surveys conducted by CDP, and a sustainability investor presentation.

In addition, we issue an annual report in accordance with the Edison Electric Institute’s (EEI) and American Gas Association’s (AGA) ESG and sustainability-related reporting program.

We also issue a periodic climate risk report and a report on our management of CCR.

Additionally, we have posted a Task Force on Climate-related Financial Disclosures (TCFD) and Sustainability Accounting Standards Board (SASB) mapping of sustainability data.

In addition, we issue an annual report in accordance with the Edison Electric Institute’s (EEI) and American Gas Association’s (AGA) environmental, social, governance and sustainability-related reporting program.

We also issue a periodic climate risk report aligned with the Task Force on Climate-related Financial Disclosures (TCFD) and a report on our management of CCR.

Additionally, we have posted a Sustainability Accounting Standards Board (SASB) mapping of sustainability data.

The reports may be updated at any time.

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Below are some key trends, events, and uncertainties that may reasonably affect our results of operations, financial condition, or liquidity, as well as our ability to achieve strategic and financial objectives, for 2025 and beyond.

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

• We are observing inflationary pressures on the prices of labor, services, materials, and supplies, as well as high 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.

The inflationary pressures and high 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 high 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.

Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on 85% of 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.

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Pursuant to a Missouri law that became effective in August 2022, Ameren Missouri’s PISA election was extended through 2028 and an additional extension through 2033 is allowed if requested by Ameren Missouri and approved by the MoPSC, among other things.

• In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to 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 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.

The new rates became effective on July 9, 2023.

As a result of this order, Ameren Missouri expects a year-over-year increase to 2024 earnings, compared to 2023, of approximately $22 million ($11 million, $8 million, and $3 million expected in the first, second, and third quarter, respectively).

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• 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 December 2024.

Ameren Missouri intends to invest approximately $420 million over the life of the plan, including $76 million in 2024.

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 revenues by achieving certain customer energy-efficiency goals.

If the target program spending goal is achieved for 2024, the performance incentive would result in revenues of $12 million in 2024.

• In January 2024, Ameren Missouri filed a proposed customer energy-efficiency plan with the MoPSC under the MEEIA.

This filing proposed a three-year plan, which includes a portfolio of customer energy-efficiency programs, along with the continued use of the MEEIA rider discussed above.

If the plan is approved, Ameren Missouri intends to invest $123 million annually in the proposed customer energy-efficiency programs from 2025 to 2027.

In addition, Ameren Missouri requested performance incentives applicable to each plan year to earn revenues by achieving certain customer energy-efficiency savings and target spending goals.

If 100% of the goals are achieved, Ameren Missouri would earn performance incentive revenues totaling $56 million over the three-year plan.

Ameren Missouri also requested additional performance incentives applicable to each plan year totaling up to $14 million over the three-year plan, if Ameren Missouri exceeds 100% of the goals.

Ameren Missouri expects a decision by the MoPSC by October 2024 but cannot predict the ultimate outcome of this regulatory proceeding.

• In June 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service.

In February 2025, Ameren Missouri filed an updated electric rate increase request seeking approval to increase its annual revenues for electric service by $446 million.

Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be continued, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.

• In June 2024, the MoPSC issued a financing order authorizing the issuance of securitized utility tariff bonds by AMF related to the accelerated retirement of the Rush Island Energy Center.

The financing order also included a determination that the decision to retire the Rush Island Energy Center was reasonable and prudent.

The MoPSC did not make a determination regarding the prudency of Ameren Missouri's prior actions that resulted in the adverse ruling in the NSR and Clean Air Act litigation, however, claims regarding such actions could be considered in future regulatory proceedings.

Base rate revenues relating to the recovery of the Rush Island Energy Center are being deferred as a regulatory liability since the October 15, 2024 retirement date of the facility until new rates become effective related to the current electric service regulatory rate review.

The amortization period for the regulatory liability will be determined in a future regulatory rate review.

• In September 2024, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for natural gas delivery service by $40 million.

Ameren Missouri cannot predict the level of any natural gas delivery service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be continued, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.

• In November 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement for Ameren Missouri’s MEEIA 2025 plan, which includes a portfolio of customer energy-efficiency and demand response programs, along with the continued use of the MEEIA rider, which allows Ameren Missouri to collect from customers its actual MEEIA program costs, related lost electric revenues, and performance incentives.

Ameren Missouri intends to invest $51 million annually in 2025 and 2026 and $22 million in 2027 for customer energy-efficiency and demand response programs.

In addition, the order approved performance incentives applicable to each plan year to earn revenues by achieving certain spending and demand response goals.

If 100% of the goals are achieved in 2025, 2026, and 2027, Ameren Missouri would earn performance incentive revenues of $5 million, $5 million, and $2 million, respectively.

• Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business.

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• The allowed base ROE for FERC-regulated transmission rates previously charged under the MISO tariff has been the subject of pending proceedings since 2013.

Depending on the outcome of the proceedings, the transmission rates charged during previous periods and the currently effective rates may be subject to change and refund.

In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which increased the incentive ROE for participation in an RTO to 100 basis points from the current 50 basis points and revised the parameters for awarding incentives, while limiting the overall incentives to a cap of 250 basis points, among other things.

In October 2024, the FERC issued an order, which decreased the allowed base ROE from 10.02% to 9.98% and required refunds, with interest, for the periods from November 2013 to February 2015 and from late September 2016 forward.

In January 2025, the same parties filed an appeal of the October 2024 order to the United States Court of Appeals for the District of Columbia Circuit.

In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which proposed to increase the incentive ROE for participation in an RTO to 100 basis points from the current 50 basis points and revised the parameters for awarding incentives, while limiting the overall incentives to a cap of 250 basis points, among other things.

In April 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking, which proposed 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.

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The FERC is under no deadline to issue a final rule on this matter.

Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy, or any further order on base ROE.

A 50-basis-point change in the FERC-allowed ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $16 million and $11 million, respectively, based on each company’s 2024 projected rate base.

• Pursuant to December 2022 and March 2021 ICC orders, Ameren Illinois used the IEIMA formula framework to establish annual electric distribution service rates effective through 2023, and will reconcile the related revenue requirement for customer rates established for 2023.

Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy.

point change in the FERC-allowed ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $17 million and $12 million, respectively, based on each company’s 2025 projected rate base.

• Pursuant to December 2022 and March 2021 ICC orders, Ameren Illinois used the IEIMA formula framework to establish annual electric distribution service rates effective through 2023, and reconciled the related revenue requirement for customer rates established for 2023.

As such, Ameren Illinois’ 2023 revenues reflected 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 2023, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes.

In November 2023, the ICC issued an order approving Ameren Illinois’ 2022 electric distribution service revenue requirement reconciliation adjustment filing.

In December 2024, the ICC issued an order approving Ameren Illinois’ 2023 electric distribution service revenue requirement reconciliation adjustment filing.

This order approved a reconciliation adjustment of $158 million.

The approved reconciliation adjustment will be collected from customers in 2025.

In addition, Ameren Illinois will file its 2023 electric distribution service revenue requirement reconciliation with the ICC by May 2024, which will reflect its 2023 year-end rate base.

The 2023 reconciliation adjustment, if approved by the ICC, will be collected from customers in 2025.

• Pursuant to the CEJA, 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.

• Pursuant to the CEJA, 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

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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 is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes.

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.

Under the MYRP discussed below, Ameren Illinois’ 2025 electric distribution service revenues will be based on its 2025 actual recoverable costs, 2025 year-end rate base, and an ROE of 8.72%, as adjusted for any performance incentives or penalties, provided the actual revenue requirement does not exceed the reconciliation cap.

The regulatory balance is then 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.

• In December 2023, the ICC issued an order in Ameren Illinois' MYRP proceeding, approving revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,162 million, $1,210 million, $1,242 million, and $1,255 million, respectively.

These revenue requirements were established under an alternative methodology which used Ameren Illinois’ previously approved 2022 year-end rate base since the order rejected the Grid Plan that was filed by Ameren Illinois as a part of the MYRP proceeding.

The ICC concluded that the proposed Grid Plan did not meet certain statutory requirements and directed Ameren Illinois to file a revised Grid Plan within three months.

The 2022 year-end rate base will remain in effect through 2027, unless subsequently changed by the ICC in the rehearing discussed below or if approval of a revised Grid Plan results in an update of each year’s revenue requirement.

The ICC’s December 2023 order did not utilize a phase-in provision that is permitted by the CEJA for any initial rate increase.

In January 2024, Ameren Illinois filed a request for rehearing of the ICC's December 2023 order.

The filing contended that the use of the 2022 year-end rate base for each year of the MYRP, until a revised Grid Plan is approved, is unlawful and not in compliance with the CEJA.

In addition, the filing requested the ICC revise the order to include an allowed ROE of at least 9.82% for each year of the MYRP and include a base level of investments to maintain grid reliability in each year of the MYRP, among other things.

Additionally, the scope of the rehearing will include a review of certain operations and maintenance expenses in each year of the MYRP.

In February 2024, Ameren Illinois filed its request in the rehearing proceeding, which proposed updated revenue requirements of $1,214 million, $1,300 million, $1,371 million, and $1,420 million, for 2024, 2025, 2026, and 2027, respectively.

An ICC decision in this rehearing is expected by late June 2024.

The court is under no deadline to address the appeal.

Ameren Illinois intends to take prudent steps to align its 2024 operations with the ICC order, while continuing to ensure safe and adequate service is maintained.

This will include significant reductions to Ameren Illinois’ capital expenditure and operations and maintenance expense plans.

Additionally, the RBA ensures electric distribution service revenues are decoupled from sales volumes and wholesale and miscellaneous revenue differences from those assumed in the revenue requirement approved by the ICC.

The RBA remains effective whether Ameren Illinois elects to file an MYRP or a traditional regulatory rate review.

• In December 2024, the ICC issued an order in connection with a revised Grid Plan and a revised MYRP filed by Ameren Illinois in March 2024, approving revenue requirements for electric distribution services for 2024 through 2027 of $1,206 million, $1,287 million, $1,367 million, and $1,422 million, respectively.

Using the 2023 revenue requirement as a starting point, the approved revenue requirements in the ICC’s December 2024 order represent a cumulative four-year increase of $309 million.

Rate changes consistent with the December 2024 order became effective in December 2024.

Subsequently, in February 2025, the ICC denied the rehearing request.

Ameren Illinois intends to file an appeal of the ICC’s December 2024 order to the Illinois Appellate Court for the Fifth Judicial District.

In addition, Ameren Illinois has filed an appeal related to orders issued by the ICC in December 2023 and June 2024 related to this proceeding.

The appellate court is under no deadline to address the appeal, and Ameren Illinois cannot predict the ultimate outcome of the appeal.

• Pursuant to Illinois law, Ameren Illinois’ electric energy-efficiency investments are deferred as a regulatory asset and earn a return at the applicable WACC, with the ROE component based on the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points.

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While the ICC has approved a plan for Ameren Illinois to invest approximately $120 million per year in electric energy-efficiency programs through 2025, the ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs.

The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider.

• In November 2023, the ICC issued an order in Ameren Illinois’ January 2023 natural gas delivery service regulatory rate review, which resulted in an increase to its annual revenues for natural gas delivery service of $112 million.

The new rates became effective on November 28, 2023.

In December 2023, Ameren Illinois filed a request for rehearing with the ICC to revise the approved ROE and capital structure common equity percentage, and reverse an approximately $93 million reduction of planned distribution and transmission capital investments included in the order, among other things.

In January 2024, the ICC denied Ameren Illinois’ rehearing request.

The court is under no deadline to address the appeal.

Ameren Illinois cannot predict the ultimate outcome of this appeal.

• The ICC’s November 2023 natural gas delivery service rate order also required Ameren Illinois to submit a plan outlining how it expects to comply with new PHMSA rules for natural gas transmission pipelines, including proposing a capital expenditures plan necessary to meet the new rules.

In February 2024, Ameren Illinois filed its plan with the ICC, which included its proposal of natural gas transmission capital expenditures necessary to achieve compliance with the PHMSA rules.

The plan includes delays to certain natural gas

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transmission capital expenditures from 2024 to subsequent years to align with the November 2023 ICC order.

The ICC is under no obligation to issue an order regarding Ameren Illinois’ plan.

Ameren Illinois expects to file its next electric energy-efficiency plan for 2026 through 2029 in late February 2025.

• In January 2025, Ameren Illinois filed a request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $140 million.

A decision by the ICC in this proceeding is required by early December 2025, with new rates expected to be effective in December 2025.

Ameren Illinois 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 costs and to earn a reasonable return on investments when the rate changes go into effect.

• The November 2023 order also directed the ICC staff to develop a plan for a future of gas proceeding.

All of the Illinois natural gas utilities subject to ICC regulation will be included in this proceeding, which will explore issues involved with decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA.

Some of the issues expected to be addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others.

All of the Illinois natural gas utilities subject to ICC regulation are included in this proceeding, which is exploring issues involving the decarbonization of the natural gas distribution system in light of the state of Illinois’ goal of economy-wide 100% clean energy by 2050, pursuant to the CEJA.

Some of the issues being addressed include the mitigation of any natural gas distribution stranded assets, the role of energy efficiency in decarbonization, and the associated impacts of natural gas decarbonization to the electric distribution system, among others.

A final ICC staff report is expected in early 2026 and will be used by the ICC to guide further action, if any.

• Ameren Missouri’s next refueling and maintenance outage at its Callaway energy center is scheduled for the spring of 2025.

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In addition, Ameren Missouri may incur increased non-nuclear energy center maintenance costs in non-outage years.

• In September 2023, the United States District Court for the Eastern District of Missouri granted Ameren Missouri’s request to modify a September 2019 remedy order issued by the district court in 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.

In its amended remedy order, the district court established an October 15, 2024 retirement date and, in the interim, authorized Ameren Missouri to operate the energy center as directed by the MISO.

The MISO designated the energy center as a system support resource in 2022 and concluded that certain reliability 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 through August 2024, and in September 2023, an agreement between Ameren Missouri and the MISO was approved by the FERC that results in the Rush Island Energy Center only operating during peak demand times and emergencies.

The system support resource designation and the related agreement are subject to annual renewal and revision.

Construction activities are underway for the transmission upgrades approved by the MISO, with the majority of the upgrades expected to be completed in the fall of 2024.

Ameren Missouri expects to complete the last of the upgrades by mid-2025.

For additional information on the NSR and Clean Air Act litigation, see Note 14 – Commitments and Contingencies under Part II, Item 8, of this report.

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.

See below for information regarding Ameren Missouri’s petition filed with the MoPSC requesting the securitization of costs associated with the planned accelerated retirement of the Rush Island Energy Center.

• Pursuant to Illinois law, Ameren Missouri's natural gas-fired energy centers in Illinois are subject to annual limits on emissions, including CO 2 and NO x .

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Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, regulatory and 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, we expect the decreased demand to be offset by increased demand resulting from increased electrification of the economy, including in the transportation sector, and as a means to address economy-wide CO 2 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.

Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, 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.

We expect a net increase in demand resulting from the electrification of the economy, including in the transportation sector.

In addition, a new 250-MW data center is expected to be constructed in Ameren Missouri’s service territory with electric service starting in 2026.

Several other entities in various industries, including data center and manufacturing, are considering either locating or expanding their operations within our service territories.

To serve these new loads, we expect increased investments will be necessary, including expected future investments for environmental compliance, system reliability improvements, and new generation sources, that will result in rate base and revenue growth but also higher depreciation and financing costs.

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• In September 2023, Ameren Missouri filed its 2023 IRP with the MoPSC, which includes Ameren Missouri’s preferred plan for meeting customers’ projected long-term energy needs in a manner that maintains system reliability and customer affordability while transitioning to clean energy generation in an environmentally responsible manner.

In connection with this plan, Ameren is continuing to target net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels.

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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.

• As discussed above, several entities in various industries, including data center and manufacturing, are considering either locating or expanding their operations within Ameren Missouri’s service territory.

In order to address these load growth opportunities, Ameren Missouri expects to file a notice of change in its preferred resource plan with the MoPSC in February 2025.

Ameren is continuing to target net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels in a safe, reliable, and affordable manner.

Ameren’s goals include both reduction of 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 preferred plan includes, among other things, the following:

• adding an 800-MW natural gas-fired simple-cycle energy center by 2027 and an additional 1,200-MW natural gas-fired combined-cycle energy center by 2033;

• adding 2,800 MWs of renewable generation by 2030, which includes the solar generation facilities discussed below, and an additional 1,900 MWs by 2036;

The 2025 Change to the 2023 PRP is expected to include, among other things, the following:

• adding 1,600 MWs of natural gas-fired simple-cycle generation by 2030, which includes the 800-MW Castle Bluff Natural Gas Project discussed below, and an additional 1,200 MWs by 2043;

• adding 2,100 MWs of natural gas-fired combined-cycle generation by 2035 and an additional 1,200 MWs by 2040;

• adding 3,200 MWs of renewable generation by 2030, which includes the 900 MWs of solar generation projects discussed in Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report, and an additional 1,500 MWs by 2035;

• adding 1,000 MWs of battery storage by 2030 and an additional 800 MWs by 2042;

• adding 1,200 MWs of other clean dispatchable generation resources by 2040 and an additional 1,200 MWs by 2043;

• adding 1,500 MWs of nuclear generation by 2040;

• retiring all of Ameren Missouri’s coal-fired energy centers by 2042;

• accelerating the retirement date of the Rush Island coal-fired energy center from 2025 to 2024;

• extending the retirement date of the Sioux coal-fired energy center from 2030 to 2032 to ensure reliability during the transition to clean energy generation, which is subject to the approval of a change in depreciable lives of the energy center’s assets by the MoPSC;

• retiring 1,800 MWs of Ameren Missouri’s natural gas-fired energy centers by 2040 to comply with Illinois law;

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

Expected capital expenditures through 2028 related to the facilities discussed above are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below.

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 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 generation and acquire or construct that generation at a reasonable cost;

Ameren Missouri’s ability to obtain CCNs from the MoPSC, and any other required approvals for the addition of renewable resources, battery storage, or nuclear or natural gas-fired generation, retirement of energy centers, and new or continued customer energy-efficiency programs;

the ability to enter into agreements for renewable, natural gas-fired, or nuclear generation and acquire or construct that generation at a 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;

changes in the scope and

timing of projects;

the continued existence and 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 cost of nuclear generation;

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 CO 2 and other greenhouse gas emissions;

energy prices and demand;

energy prices;

Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion;

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and the ability to raise capital on reasonable terms.

The next integrated resource plan is expected to be filed in September 2026.

• Pursuant to Missouri law, in November 2023, Ameren Missouri petitioned the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance $519 million of costs related to the planned accelerated retirement of the Rush Island Energy Center, which includes the expected remaining unrecovered net plant balance associated with the facility.

Ameren Missouri requested to collect the amounts necessary to repay the bonds over approximately 15 years from the date of bond issuance.

Ameren Missouri expects a decision by the MoPSC by the end of June 2024, but cannot predict the ultimate outcome of this regulatory proceeding.

• 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 2023 IRP discussed above, and expected capital expenditures related to these facilities are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below.

• Ameren Missouri's 2023 IRP targets cleaner and more diverse sources of energy generation, including solar generation.

While rights to acquire build-transfer solar facilities and supplies for development-transfer and self-build solar facilities discussed above were secured through agreements, supply chain disruptions, including solar panel shortages and increasing material costs as a result of government tariffs and other factors, could affect the costs, as well as the timing, of these projects and other solar generation projects.

The supply of

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solar panel components to the United States was significantly disrupted as a result of an investigation conducted by the United States Department of Commerce that concluded in August 2023 and found that exporters and producers of solar panel components from four Southeast Asian countries, with several exceptions, have been circumventing tariffs imposed on imports from China.

As a result of the investigation, importers and exporters may submit certain certifications to the United States Department of Commerce to avoid the imposition of increased tariffs.

Failure to submit the applicable certifications, or denial of the submitted certifications by the United States Department of Commerce, could result in increased tariffs on solar panel components that were subject to the investigation and entered the United States on or after April 1, 2022.

Additionally, certain solar panel components from China have been subject to detention by the United States Customs and Border Protection Agency as a result of the Uyghur Forced Labor Prevention Act that became effective in June 2022.

Also, in June 2022, President Biden took executive action to temporarily lift certain tariffs on solar panel components imported from the four Southeast Asian countries investigated 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.

Any future tariffs or actions by the United States Customs and Border Protection Agency could affect the cost and the availability of solar panel components and the timing and amount of Ameren Missouri's estimated capital expenditures associated with solar generation investments.

The next preferred resource plan is required to be filed by October 2026.

• In October 2024, the MoPSC issued an order approving a nonunanimous stipulation and agreement filed by Ameren Missouri, the MoPSC staff, and other intervenors requesting a CCN for the Castle Bluff Natural Gas Project.

The order also includes the use of a post-construction cost deferral related to the project which allows Ameren Missouri to defer and recover depreciation expense, financing costs, and applicable income taxes incurred from the date the project is placed in service to the date when project costs are reflected in updated base rates as a result of a regulatory rate review.

The period of deferral would be limited to the earlier of the time the project costs are reflected in base rates or six months.

The Castle Bluff Natural Gas Project is aligned with the 2025 Change to the 2023 PRP discussed above, and related expected capital expenditures are included in Ameren’s and Ameren Missouri’s expected capital investments discussed below.

• Through 2029, 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.

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ATXI – up to $2.9 billion) of capital expenditures during the period from 2025 through 2029.

Ameren’s and Ameren Missouri’s estimates include $3.3 billion of renewable generation investments and $2.7 billion of dispatchable generation investments through 2028, consistent with Ameren Missouri’s 2023 IRP.

Ameren’s and Ameren Illinois’ estimates include investments necessary to meet compliance requirements of the CEJA, while continuing to ensure safe and adequate service is maintained.

Ameren Illinois’ estimates may be revised as a result of future ICC orders related to its MYRP.

These estimates include the MISO long-range transmission projects assigned to Ameren, as well as the first tranche competitive projects awarded to ATXI discussed below.

Ameren’s and Ameren Missouri’s estimates include approximately $1 billion in capital expenditures that may be necessary to comply with regulations issued by the EPA in 2024 relating to CO 2 emissions and MATS, if such regulations are not revised or overturned.

• 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.

In 2022, the MISO approved the first tranche of projects under 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.

In October 2023, the FERC issued an order that approved transmission rate incentives relating to the projects assigned to Ameren.

The incentives will allow construction work in progress to be included in rate base for projects constructed by ATXI, thereby improving the timeliness of cash recovery, and would allow recovery of prudently incurred costs, subject to FERC approval, for any portion of the projects if they are abandoned for reasons beyond the control of Ameren.

As a result of the order, ATXI will not capitalize allowance for funds used during construction on the related projects.

In 2022 and 2023, the MISO initiated requests for proposals for first tranche competitive bid projects.

In October and November 2023, first tranche competitive bid projects were awarded to ATXI and represent a total estimated investment of approximately $0.1 billion.

The remaining competitive-bid project is estimated by the MISO to cost approximately $0.6 billion and is expected to be awarded by mid-2024.

A decision by the ICC is expected by February 2025.

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 the MISO’s April 2022 capacity auction, the ICC issued an order requiring 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.

In January 2024, the ICC staff submitted a report recommending the ICC not take any action with regard to changing Ameren Illinois’ RTO membership.

The ICC is under no obligation to issue an order related to the cost-benefit study.

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• Environmental regulations, including those related to CO 2 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.

In addition, the MISO awarded three competitive bid projects to ATXI that represent a total estimated investment of approximately $220 million for ATXI.

A decision by the ICC is expected by mid-2025.

In 2024, ATXI filed requests for CCNs, among other things, with the MoPSC related to the MISO long-range transmission projects that it expects to construct within the MoPSC’s jurisdiction.

Decisions by the MoPSC are expected in 2025.

Also in December 2024, the MISO approved a first set of second tranche projects.

A portion of these projects were assigned to Ameren and are estimated to cost approximately $1.3 billion, based on the MISO’s cost estimate.

The competitive bid process is expected to take place through 2026.

The MISO is assessing future long-range transmission scenarios in the first quarter of 2025 and development of a second set of second tranche projects will follow this assessment.

• Grid reliability, environmental, or other regulations, including those related to CO 2 emissions, or other actions taken by federal or state regulators, 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 regulatory agencies, including the EPA.

See Note 14 – Commitments and Contingencies under Part II, Item 8, of this report, for additional information on environmental matters, including the NSR and Clean Air Act litigation.

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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 lag.

Ameren Missouri’s operating costs and 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.

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Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.

• The Ameren Companies have multiyear credit agreements that cumulatively provide $2.6 billion of credit through December 2027, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to increase the cumulative credit provided to $3.2 billion.

• The Ameren Companies have multiyear Credit Agreements that cumulatively provide $2.6 billion of credit through December 2028, subject to a 364-day repayment term for Ameren Missouri and Ameren Illinois, with the option to seek incremental commitments to

increase the cumulative credit provided to $3.2 billion.

See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the Credit Agreements.

See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for outstanding forward sale agreements under the ATM, long-term debt issuances through the date of this report, and maturities of long-term debt from 2025 to 2029 and beyond at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI.

The use of cash provided by operating activities and short-term borrowings to fund capital expenditures and other long-term investments at the Ameren Companies frequently results in a working capital deficit, defined as current liabilities exceeding current assets, as was the case at December 31, 2023, for Ameren, Ameren Missouri, and Ameren Illinois.

Ameren, Ameren Missouri, and Ameren Illinois each believe that their liquidity is adequate given their respective expected operating cash flows, capital expenditures, and financing plans, and expect to continue to have access to the capital and credit markets on reasonable terms when needed.

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As of December 31, 2024, Ameren had multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 2.5 million shares of common stock.

Ameren expects to settle approximately $230 million of the forward sale agreements with physical delivery of 2.9 million shares of common stock by December 31, 2024.

Including issuances under the DRPlus and employee benefit plans, Ameren plans to issue approximately $600 million of equity each year from 2025 to 2029.

Ameren expects its equity to total capitalization to support solid investment-grade credit ratings.

Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, adjustments of dividends to Ameren (parent), and/or capital contributions from Ameren (parent).

The Ameren Companies expect their equity to total capitalization and cash flow metrics to support solid investment-grade credit ratings.

Ameren Missouri and Ameren Illinois expect to fund cash flow needs through debt issuances, cash provided by operating activities, 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 law also creates clean energy tax credits for projects beginning construction 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.

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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 December 31, 2022.

In addition, the 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 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 IRA have been and 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.

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• Pursuant to the IRA discussed above, Ameren expects to transfer production tax credits generated by Ameren Missouri’s High Prairie Renewable and Atchison Renewable energy centers, as well as the solar facilities included in Ameren Missouri’s 2023 IRP discussed above, to unrelated parties from 2024 to 2028.

• In April 2023, the IRS issued guidance providing a safe harbor method of accounting for the capitalization or deduction of certain expenditures to maintain, repair, replace, or improve natural gas distribution property.

The safe harbor method of accounting may be implemented in the first, second, or third taxable year ending after May 1, 2023.

Ameren is currently evaluating the potential impact of this guidance, including the timing of adoption.

• As of December 31, 2023, Ameren had $176 million in tax benefits from federal and state income tax credit carryforwards and $42 million in tax benefits from state net operating loss carryforwards, which will be utilized in future periods.

• Pursuant to the IRA discussed above, Ameren Missouri expects to transfer production and investment tax credits to unrelated parties of approximately $300 million annually on average from 2025 to 2029.

Proceeds from these transfers are included in Ameren Missouri’s tracker related to production and investment tax credits allowed under the IRA or the RESRAM and are ultimately refunded to customers.

• In June 2024, the IRS issued a series of private letter rulings to another taxpayer which provided guidance on applying IRS normalization rules to the calculation of tax benefits related to net operating loss carryforwards.

The rulings concluded that for ratemaking purposes, net operating loss carryforwards should be reflected on a separate company basis and should not be reduced by payments received for the utilization of losses by other affiliates under a tax allocation agreement.

While a private letter ruling issued to another taxpayer may not be relied on as precedent, Ameren Missouri, Ameren Illinois, and ATXI are evaluating this guidance and are addressing potential impacts of the private letter rulings with the MoPSC, ICC, and FERC.

For Ameren Illinois and ATXI, these impacts could result in material reductions to their regulatory liabilities related to excess deferred income taxes resulting from the TCJA.

For Ameren Missouri and Ameren Illinois, these impacts could result in material increases to their accumulated deferred income tax assets for ratemaking purposes, which would result in overall increases to their rate bases.

Ameren Missouri, Ameren Illinois, and ATXI will record the impacts, if any, upon further evaluation with their respective regulatory commissions.

• As of December 31, 2024, Ameren had $410 million in tax benefits from federal and state income tax credit carryforwards, which included $229 million of production and investment tax credits that Ameren Missouri expects to transfer to third parties, $93 million in tax benefits from federal and state net operating loss carryforwards, and $22 million in tax overpayments, refunds, and receivables, 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.

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Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

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Accounting Estimate

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

• Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under the MYRP process, effective in 2024, which includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap

• Ameren Illinois’ assessment of and ability to estimate the current year’s electric distribution service costs to be reflected in revenues and recovered from customers in a subsequent year under the MYRP process, which includes a revenue requirement reconciliation, which may not allow for full recovery of actual costs due to a reconciliation cap

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

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We base our conclusion on certain factors including, but not limited to, orders issued by our regulatory commissions, enacted legislation, or historical experience, as well as discussions with legal counsel.

If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material.

If facts and circumstances lead us to

conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material.

Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or that are probable of future refunds to customers.

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The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC.

Variations in investments made or orders by the ICC can result in a subsequent change in Ameren Illinois’ resulting estimated regulatory assets or liabilities.

Orders by the ICC can result in a subsequent change in Ameren Illinois’ resulting estimated regulatory assets or liabilities.

Ameren Illinois and ATXI have received FERC approval to use a company-specific, forward-looking formula ratemaking framework in setting their transmission rates.

2 unchanged sentences

Variations in investments made or orders by the FERC or courts can result in a subsequent change in Ameren Illinois’ and ATXI’s estimated regulatory assets or liabilities.

Ameren Missouri estimates lost electric margins resulting from its MEEIA customer energy-efficiency programs, which are subsequently recovered through the MEEIA rider.

Ameren Missouri estimates lost electric revenues resulting from its MEEIA customer energy-efficiency programs, which are subsequently recovered through the MEEIA rider.

See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a description of our regulatory mechanisms and quantification of these assets or liabilities for each of the Ameren Companies.

Table of Conten t s

The following table reflects the gain and other comprehensive income, which would be offset by the removal of regulatory assets and liabilities and an increase in accumulated other comprehensive income, that would have resulted if accounting guidance for rate-regulated businesses had been eliminated as of December 31, 2024:

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Benefit Plan Accounting

Based on actuarial calculations, we accrue costs of providing future employee benefits for the benefit plans we offer our employees.

Based on actuarial calculations, we accrue postretirement costs of providing future employee benefits for the benefit plans we offer our employees.

See Note 10 – Retirement Benefits under Part II, Item 8, of this report.

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0.25% decrease in return on assets 12 (a) 4 (a)

0.25% increase in future compensation 3 11 (a) (a)

(a) Not applicable.

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• Outcome of legal proceedings, settlements, or other factors

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

Table of Conten t s

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

Basis for Judgment

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As additional information becomes available, we reassess the potential liability related to the contingency and revise our estimates.

The amount recorded for any contingency may differ from actual costs incurred when the contingency is resolved.

The amount recorded for any contingency may differ from actual costs incurred when the contingency is ultimately resolved.

Contingencies are normally resolved over long periods of time.

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• Results of audits and examinations by taxing authorities

• Ability to forecast production and investment tax credits

Basis for Judgment

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Basis for Judgment

Table of Conten t s

We record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and capitalize a corresponding amount as part of the book value of the related long-lived asset.

16 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis