0001002910srt:NaturalGasReservesMemberaee:AmerenIllinoisGasSegmentMemberus-gaap:OperatingSegmentsMemberaee:CommercialMember2021-04-012021-06-300001002910us-gaap:ElectricityMemberus-gaap:IntersegmentEliminationMember2023-01-012023-06-30
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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| ☒ | Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended June 30, 20222023 |
OR
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| ☐ | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for the transition period from to |
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Commission
File Number | Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number | IRS Employer
Identification No. |
| 1-14756 | Ameren Corporation | 43-1723446 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
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| 1-2967 | Union Electric Company | 43-0559760 |
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
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| 1-3672 | Ameren Illinois Company | 37-0211380 |
(Illinois Corporation)
10 Executive DriveRichard Mark Way
Collinsville, Illinois 62234
(618) 343-8150
Securities Registered Pursuant to Section 12(b) of the Act:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common Stock, $0.01 par value per share | AEE | New York Stock Exchange |
Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
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| Ameren Corporation | | Yes | | ☒ | | No | | ☐ |
| Union Electric Company | | Yes | | ☒ | | No | | ☐ |
| Ameren Illinois Company | | Yes | | ☒ | | No | | ☐ |
Indicate by check mark whether each registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
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| Ameren Corporation | | Yes | | ☒ | | No | | ☐ |
| Union Electric Company | | Yes | | ☒ | | No | | ☐ |
| Ameren Illinois Company | | Yes | | ☒ | | No | | ☐ |
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| Ameren Corporation | Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ |
| | | Smaller reporting company | ☐ | Emerging growth company | ☐ |
| Union Electric Company | Large accelerated filer | ☐ | Accelerated filer | ☐ | Non-accelerated filer | ☒ |
| | | Smaller reporting company | ☐ | Emerging growth company | ☐ |
| Ameren Illinois Company | Large accelerated filer | ☐ | Accelerated filer | ☐ | Non-accelerated filer | ☒ |
| | | Smaller reporting company | ☐ | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
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| Ameren Corporation | ☐ |
| Union Electric Company | ☐ |
| Ameren Illinois Company | ☐ |
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Corporation | | Yes | | ☐ | | No | | ☒ |
| Union Electric Company | | Yes | | ☐ | | No | | ☒ |
| Ameren Illinois Company | | Yes | | ☐ | | No | | ☒ |
The number of shares outstanding of each registrant’s classes of common stock as of July 29, 2022,31, 2023, was as follows:
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| Registrant | | Title of each class of common stock | Shares outstanding |
| Ameren Corporation | | Common stock, $0.01 par value per share | 258,370,605262,749,535 | |
| Union Electric Company | | Common stock, $5 par value per share, held by Ameren Corporation | 102,123,834 | |
| Ameren Illinois Company | | Common stock, no par value, held by Ameren Corporation | 25,452,373 | |
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This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.
TABLE OF CONTENTS
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GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to Ameren, Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as their various business activities are discussed. Refer to the Form 10-K for a complete listing of glossary terms and abbreviations. Only new or significantly changed terms and abbreviations are included below.
2020 IRPCCN – Integrated Resource Plan, a long-term nonbinding plan that Ameren Missouri filed with the MoPSC in September 2020.
2022 Change to the 2020 IRP – A change to Ameren Missouri’s 2020 IRP filed with the MoPSC in June 2022 reflecting certain modifications to Ameren Missouri’s preferred approach for meeting its customers’ projected long-term energy needs in a cost-effective manner while maintaining system reliabilityCertificate of convenience and achieving a goal of net-zero CO2 emissions by 2045.necessity.
Form 10-K – The combined Annual Report on Form 10-K for the year ended December 31, 2021,2022, filed by the Ameren Companies with the SEC.
PISA – Plant-in-service accounting regulatory mechanism, a mechanism under Missouri law that permits electric utilities to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC on rate base for certain property, plant, and equipment placed in service, and not included in base rates, subject to MoPSC prudence reviews. The rate base on which the return is calculated incorporates qualifying capital expenditures not included in base rates, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes. The regulatory asset for accumulated PISA deferrals earns a return at the applicable WACC. The PISA is effective through December 2028, unless Ameren Missouri requests and receives MoPSC approval of an extension through December 2033.
QTD – Three months ended June 30.
Smart Energy PlanYTD – Ameren Missouri’s plan to upgrade its electric grid through at least 2026. Planned upgrades include investments to improve reliability and accommodate more renewable energy.
YTD– Six months ended June 30.
YoY– Compared with the year-ago period.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, projections, strategies, targets, estimates, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed within Risk Factors in the Form 10-K, and in this report, and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
•regulatory, judicial, or legislative actions, and any changes in regulatory policies and ratemaking determinations, that may change regulatory recovery mechanisms, such as those that may result from the impact of a final ruling to be issued by the United States District Court for the Eastern District of Missouri regarding its September 2019 remedy order for the Rush Island Energy Center, the MoPSC staff review of the planned Rush Island Energy Center retirement, Ameren Missouri’s electric service regulatory rate reviewnonunanimous stipulation and agreement related to MEEIA 2019 filed with the MoPSC in August 2022,2023, Ameren Illinois’ MYRP electric distribution service regulatory rate review filed in January 2023 with the July 2020 appealICC, Ameren Illinois’ natural gas regulatory rate review filed by Ameren Missouri, Ameren Illinois, and ATXI challengingin January 2023 with the refund period related to the FERC’s May 2020 order determining the allowed base ROE under the MISO tariff, the July 2020 appeal filed by Ameren Missouri, Ameren Illinois, and ATXI challenging the FERC’s rehearing denials in the transmission formula rate revision cases,ICC, Ameren Illinois’ electric distribution service raterevenue requirement reconciliation adjustment request filed with the ICC in April 2023, and the August 2022 United States Court of Appeals for the District of Columbia Circuit ruling that vacated FERC’s MISO ROE-determining orders and Ameren Illinois’ annual electric energy-efficiency formula rate update filed withremanded the ICC in June 2022;proceedings to the FERC;
•the length and severity of the COVID-19 pandemic, and its impacts on our business continuity plans and our results of operations, financial position, and liquidity, including but not limited to changes in customer demand resulting in changes to sales volumes; customers’ payment for our services; the health, welfare, and availability of our workforce and contractors; supplier disruptions; delays in the completion of construction projects, which could impact our expected capital expenditures and rate base growth; changes in how we operate our business; and our ability to access the capital markets on reasonable termscontrol costs and when needed;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 affordability of our services for our customers;
•the effect of Ameren Illinois’ use of the performance-based formula ratemaking framework for its electric distribution service under the IEIMA, which will establishestablished and allowallows for a reconciliation of electric distribution service rates through 2023, its participation in electric energy-efficiency programs, and the related impact of the direct relationship between Ameren Illinois’ ROE and the 30-year United States Treasury bond yields;
•the effect and duration of Ameren Illinois’ election to either utilize traditional regulatory rate reviews or MYRPs for electric distribution service ratemaking effective for rates beginning in 2024;
•the effect on Ameren Missouri of any customer rate caps or limitations to increases toon increasing the electric service revenue requirement pursuant to Ameren Missouri’s election to use the PISA;
•the effects of changes in federal, state, Ameren Missouri’s ability to construct and/or local lawsacquire wind, solar, and other governmental actions,renewable energy generation facilities and battery storage, as well as natural gas-fired combined cycle energy centers, retire fossil fuel-fired energy centers, and implement new or existing customer energy-efficiency programs, including monetary, fiscal, foreign trade,any such construction, acquisition, retirement, or implementation in connection with its Smart Energy Plan, integrated resource plan, or emissions reduction goals, and to recover its cost of investment, a related return, and, in the case of customer energy-efficiency programs, any lost margins in a timely manner, each of which is affected by the ability to obtain all necessary regulatory and project approvals, including CCNs from the MoPSC or any other required approvals for the addition of renewable resources;
•Ameren Missouri’s ability to use or transfer federal production and investment tax credits related to renewable energy policies;projects; the cost of wind, solar, and other renewable generation and storage technologies; and our ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost for each facility;
•the effectssuccess of changes in federal, state, or local tax laws, regulations, interpretations, or rates, and challengescompetitive bids related to requests for proposals associated with the tax positions taken by the Ameren Companies, if any, as well as resulting effects on customer rates;MISO’s long-range transmission planning;
•the effectiveness of Ameren Missouri’s customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA programs;
•Ameren Illinois’ ability to achieve the performance standards applicable to its electric distribution business and electric customer energy-efficiency goals and the resulting impact on its allowed ROE;
•our ability to control costs and 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 affordability of our services for our customers;
•the cost and availability of fuel, such as low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power, zero emission credits, renewable energy credits, emission allowances, and natural gas for distribution; and the level and volatility of future market prices for such commodities and credits;
•disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from the one NRC-licensed supplier of such assemblies for Ameren Missouri’s Callaway Energy Center;
•the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy Ameren Missouri’s energy sales;
•the effectiveness of our risk management strategies and our use of financial and derivative instruments;
•the ability to obtain sufficient insurance, or in the absence of insurance, the ability to timely recover uninsured losses from our customers;
•increased data security risks as a result of remote working arrangements for a significant portion of our workforce;
•the impact of cyberattacks on us or our suppliers, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information;
•business and economic conditions, which have been affected by, and will be affected by the length and severity of, the COVID-19 pandemic, including the impact of such conditions on interest rates and inflation;
•disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity;
•the actions of credit rating agencies and the effects of such actions, including any impacts on our credit ratings that may result from the economic conditions of the COVID-19 pandemic;
•the inability of our counterparties to meet their obligations with respect to contracts, credit agreements, and financial instruments, including as they relate to the construction and acquisition of electric and natural gas utility infrastructure and the ability of counterparties to complete projects, which is dependent upon the availability of necessary materials and equipment, including those obligations that are affected by supply chain disruptions;
•advancements in energy technologies, including carbon capture, utilization, and sequestration, hydrogen fuel for electric production and energy storage, next generation nuclear, large-scale long-cycle battery energy storage, and the impact of federal and state energy and economic policies with respect to those technologies;
•the effects of changes in federal, state, or local laws and other governmental actions, including monetary, fiscal, foreign trade, and energy policies;
•the effects of changes in federal, state, or local tax laws or rates, including the effects of the IRA and the 15% minimum tax on adjusted financial statement income, as well as additional regulations, interpretations, amendments, or technical corrections to or in connection with the IRA, and challenges, if any, to the tax positions taken by the Ameren Companies, as well as resulting effects on customer rates and the recoverability of the minimum tax imposed under the IRA;
•the effects on energy prices and demand for our services resulting from technological advances, including advances in customer energy efficiency, electric vehicles, electrification of various industries, energy storage, and private generation sources, which generate electricity at the site of consumption and are becoming more cost-competitive;
•the cost and availability of fuel, such as low-sulfur coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of natural gas for distribution and purchased power, including capacity, zero emission credits, renewable energy credits, and emission allowances; and the level and volatility of future market prices for such commodities and credits;
•disruptions in the delivery of fuel, failure of our fuel suppliers to provide adequate quantities or quality of fuel, or lack of adequate inventories of fuel, including nuclear fuel assemblies from the one NRC-licensed supplier of Ameren Missouri’s Callaway Energy Center assemblies;
•the cost and availability of transmission capacity for the energy generated by Ameren Missouri’s energy centers or required to satisfy our energy sales;
•the effectiveness of our risk management strategies and our use of financial and derivative instruments;
•the ability to obtain sufficient insurance, or, in the absence of insurance, the ability to timely recover uninsured losses from our customers;
•the impact of cyberattacks and data security risks on us or our suppliers, which could, among other things, result in the loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or the loss of data, such as customer, employee, financial, and operating system information;
•acts of sabotage, which have increased in frequency and severity within the utility industry, war, terrorism, or other intentionally disruptive acts;
•business, economic, and capital market conditions, including the impact of such conditions on interest rates, inflation, and investments;
•the impact of inflation or a recession on our customers and the related impact on our results of operations, financial position, and liquidity;
•disruptions of the capital and credit markets, deterioration in credit metrics of the Ameren Companies, or other events that may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity, and our ability to access the capital and credit markets on reasonable terms when needed;
•the actions of credit rating agencies and the effects of such actions;
•the impact of weather conditions and other natural phenomena on us and our customers, including the impact of system outages and the level of wind and solar resources;
•the construction, installation, performance, and cost recovery of generation, transmission, and distribution assets;
•the ability to maintain system reliability during the transition to clean energy generation by Ameren Missouri and the electric utility industry, including within the MISO, as well as Ameren Missouri’s ability to meet generation capacity obligations;
•the effects of failures of electric generation, electric and natural gas transmission or distribution, or natural gas storage facilities systems and equipment, which could result in unanticipated liabilities or unplanned outages;
•the operation of Ameren Missouri’s Callaway Energy Center, including planned and unplanned outages, as well as the ability to recover costs associated with such outages and the impact of such outages on off-system sales and purchased power, among other things;
•Ameren Missouri’s ability to recover the remaining investment and decommissioning costs associated with the retirement of an energy center, as well as the ability to earn a return on that remaining investment and those decommissioning costs;
•the impact of current environmental laws and new, more stringent, or changing requirements, including those related to NSR, and CO2, NOx, andother emissions and discharges, Illinois emission standards, cooling water intake structures, CCR, energy efficiency, and wildlife protection, that could limit or terminate the operation of certain of Ameren Missouri’s energy centers, increase our operating costs or investment requirements, result in an impairment of our assets, cause us to sell our assets, reduce our customers’ demand for electricity or natural gas, or otherwise have a negative financial effect;
•the impact of complying with renewable energy standards in Missouri and Illinois and with the zero emission standard in Illinois;
•the effectiveness of Ameren Missouri’s ability to construct and/or acquire wind, solar, and other renewable energy generation facilities as well as natural gas-fired combined cycle energy centers, retire energy centers, and implement new or existing customer energy-efficiency programs and the related revenues and performance incentives earned under its MEEIA programs;
including any such construction, acquisition, retirement, or implementation in connection with•Ameren Illinois’ ability to achieve the performance standards applicable to its Smart Energy Plan, integrated resource plan, or emissions reductionelectric distribution business and electric customer energy-efficiency goals and to recoverthe resulting impact on its cost of investment, related return, and, in the case of customer energy-efficiency programs, any lost margins in a timely manner, which is affected by the ability to obtain all necessary regulatory and project approvals, including certificates of convenience and necessity from the MoPSC or any other required approvals for the addition of renewable resources;
•the availability of federal production and investment tax credits related to renewable energy and Ameren Missouri’s ability to use such credits; the cost of wind, solar, and other renewable generation and storage technologies; and our ability to obtain timely interconnection agreements with the MISO or other RTOs at an acceptable cost for each facility;
•advancements in energy technologies, including carbon capture, utilization, and sequestration, hydrogen fuel for electric production and energy storage, next generation nuclear, and large-scale long-cycle battery energy storage, and the impact of constructive federal and state energy and economic policies with respect to those technologies;allowed ROE;
•labor disputes, work force reductions, changes in future wage and employee benefits costs, including those resulting from changes in discount rates, mortality tables, returns on benefit plan assets, and other assumptions;
•the impact of negative opinions of us or our utility services that our customers, investors, legislators, regulators, creditors, or other stakeholders may have or develop, which could result from a variety of factors, including failures in system reliability, failure to implement our investment plans or to protect sensitive customer information, increases in rates, negative media coverage, or concerns about ESG practices;
•the impact of adopting new accounting guidance;
•the effects of strategic initiatives, including mergers, acquisitions, and divestitures;
•legal and administrative proceedings;
•pandemics or other health events, and their impacts on our results of operations, financial position, and liquidity; and
•the impacts of the Russian invasion of Ukraine, related sanctions imposed by the U.S. and other governments, and any broadening of the conflict, including potential impacts on the cost and availability of fuel, natural gas, enriched uranium, orand other commodities, materials, orand services, the inability of our counterparties to perform their obligations, disruptions in the capital and credit markets, and other impacts on business, economic, and geopolitical conditions, including inflation; and
•acts of sabotage, war, terrorism, or other intentionally disruptive acts.inflation.
New factors emerge from time to time, and it is not possible for managementus to predict all of such factors, nor can itwe assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(Unaudited) (In millions, except per share amounts)
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Operating Revenues: | Operating Revenues: | | | | | | | | Operating Revenues: | | | | | | | |
| Electric | Electric | $ | 1,513 | | | $ | 1,284 | | | $ | 2,831 | | | $ | 2,440 | | Electric | $ | 1,585 | | | $ | 1,513 | | | $ | 3,175 | | | $ | 2,831 | |
| Natural gas | Natural gas | 213 | | | 188 | | | 774 | | | 598 | | Natural gas | 175 | | | 213 | | | 647 | | | 774 | |
| Total operating revenues | Total operating revenues | 1,726 | | | 1,472 | | | 3,605 | | | 3,038 | | Total operating revenues | 1,760 | | | 1,726 | | | 3,822 | | | 3,605 | |
| Operating Expenses: | Operating Expenses: | | | | | | | | Operating Expenses: | | | | | | | |
| Fuel | Fuel | 83 | | | 173 | | | 259 | | | 238 | | Fuel | 152 | | | 83 | | | 265 | | | 259 | |
| Purchased power | Purchased power | 318 | | | 129 | | | 495 | | | 320 | | Purchased power | 328 | | | 318 | | | 823 | | | 495 | |
| Natural gas purchased for resale | Natural gas purchased for resale | 80 | | | 65 | | | 373 | | | 230 | | Natural gas purchased for resale | 42 | | | 80 | | | 250 | | | 373 | |
| Other operations and maintenance | Other operations and maintenance | 491 | | | 412 | | | 952 | | | 832 | | Other operations and maintenance | 450 | | | 491 | | | 898 | | | 952 | |
| | Depreciation and amortization | Depreciation and amortization | 316 | | | 285 | | | 615 | | | 566 | | Depreciation and amortization | 335 | | | 316 | | | 655 | | | 615 | |
| Taxes other than income taxes | Taxes other than income taxes | 129 | | | 122 | | | 271 | | | 250 | | Taxes other than income taxes | 124 | | | 129 | | | 251 | | | 271 | |
| Total operating expenses | Total operating expenses | 1,417 | | | 1,186 | | | 2,965 | | | 2,436 | | Total operating expenses | 1,431 | | | 1,417 | | | 3,142 | | | 2,965 | |
| Operating Income | Operating Income | 309 | | | 286 | | | 640 | | | 602 | | Operating Income | 329 | | | 309 | | | 680 | | | 640 | |
| | Other Income, Net | Other Income, Net | 62 | | | 49 | | | 122 | | | 95 | | Other Income, Net | 82 | | | 62 | | | 160 | | | 122 | |
| Interest Charges | Interest Charges | 126 | | | 96 | | | 230 | | | 196 | | Interest Charges | 134 | | | 126 | | | 261 | | | 230 | |
| Income Before Income Taxes | Income Before Income Taxes | 245 | | | 239 | | | 532 | | | 501 | | Income Before Income Taxes | 277 | | | 245 | | | 579 | | | 532 | |
| Income Taxes | Income Taxes | 36 | | | 31 | | | 70 | | | 58 | | Income Taxes | 38 | | | 36 | | | 75 | | | 70 | |
| | Net Income | Net Income | 209 | | | 208 | | | 462 | | | 443 | | Net Income | 239 | | | 209 | | | 504 | | | 462 | |
| Less: Net Income Attributable to Noncontrolling Interests | Less: Net Income Attributable to Noncontrolling Interests | 2 | | | 1 | | | 3 | | | 3 | | Less: Net Income Attributable to Noncontrolling Interests | 2 | | | 2 | | | 3 | | | 3 | |
| | Net Income Attributable to Ameren Common Shareholders | Net Income Attributable to Ameren Common Shareholders | $ | 207 | | | $ | 207 | | | $ | 459 | | | $ | 440 | | Net Income Attributable to Ameren Common Shareholders | $ | 237 | | | $ | 207 | | | $ | 501 | | | $ | 459 | |
| | | Net Income | Net Income | $ | 209 | | | $ | 208 | | | $ | 462 | | | $ | 443 | | Net Income | $ | 239 | | | $ | 209 | | | $ | 504 | | | $ | 462 | |
| Other Comprehensive Income (Loss), Net of Taxes | Other Comprehensive Income (Loss), Net of Taxes | | Other Comprehensive Income (Loss), Net of Taxes | |
| Pension and other postretirement benefit plan activity, net of income taxes of $—, $—, $—, and $—, respectively | Pension and other postretirement benefit plan activity, net of income taxes of $—, $—, $—, and $—, respectively | — | | | (1) | | | 1 | | | — | | Pension and other postretirement benefit plan activity, net of income taxes of $—, $—, $—, and $—, respectively | (1) | | | — | | | (2) | | | 1 | |
| Comprehensive Income | Comprehensive Income | 209 | | | 207 | | | 463 | | | 443 | | Comprehensive Income | 238 | | | 209 | | | 502 | | | 463 | |
| Less: Comprehensive Income Attributable to Noncontrolling Interests | Less: Comprehensive Income Attributable to Noncontrolling Interests | 2 | | | 1 | | | 3 | | | 3 | | Less: Comprehensive Income Attributable to Noncontrolling Interests | 2 | | | 2 | | | 3 | | | 3 | |
| Comprehensive Income Attributable to Ameren Common Shareholders | Comprehensive Income Attributable to Ameren Common Shareholders | $ | 207 | | | $ | 206 | | | $ | 460 | | | $ | 440 | | Comprehensive Income Attributable to Ameren Common Shareholders | $ | 236 | | | $ | 207 | | | $ | 499 | | | $ | 460 | |
| | | | Earnings per Common Share – Basic | Earnings per Common Share – Basic | $ | 0.80 | | | $ | 0.81 | | | $ | 1.78 | | | $ | 1.72 | | Earnings per Common Share – Basic | $ | 0.90 | | | $ | 0.80 | | | $ | 1.91 | | | $ | 1.78 | |
| | | Earnings per Common Share – Diluted | Earnings per Common Share – Diluted | $ | 0.80 | | | $ | 0.80 | | | $ | 1.77 | | | $ | 1.71 | | Earnings per Common Share – Diluted | $ | 0.90 | | | $ | 0.80 | | | $ | 1.90 | | | $ | 1.77 | |
| | Weighted-average Common Shares Outstanding – Basic | Weighted-average Common Shares Outstanding – Basic | 258.2 | | | 256.1 | | | 258.0 | | | 255.2 | | Weighted-average Common Shares Outstanding – Basic | 262.6 | | | 258.2 | | | 262.4 | | | 258.0 | |
| Weighted-average Common Shares Outstanding – Diluted | Weighted-average Common Shares Outstanding – Diluted | 259.4 | | | 257.2 | | | 259.2 | | | 256.5 | | Weighted-average Common Shares Outstanding – Diluted | 263.2 | | | 259.4 | | | 263.2 | | | 259.2 | |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)
| | | June 30,
2022 | | December 31, 2021 | | June 30,
2023 | | December 31, 2022 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current Assets: | Current Assets: | | Current Assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 7 | | | $ | 8 | | Cash and cash equivalents | $ | 7 | | | $ | 10 | |
| Accounts receivable – trade (less allowance for doubtful accounts of $30 and $29, respectively) | 519 | | | 434 | | |
| Accounts receivable – trade (less allowance for doubtful accounts of $39 and $31, respectively) | | Accounts receivable – trade (less allowance for doubtful accounts of $39 and $31, respectively) | 482 | | | 600 | |
| Unbilled revenue | Unbilled revenue | 400 | | | 301 | | Unbilled revenue | 378 | | | 446 | |
| Miscellaneous accounts receivable | Miscellaneous accounts receivable | 81 | | | 85 | | Miscellaneous accounts receivable | 63 | | | 54 | |
| Inventories | Inventories | 600 | | | 592 | | Inventories | 711 | | | 667 | |
| Mark-to-market derivative assets | 157 | | | 66 | | |
| | | Current regulatory assets | Current regulatory assets | 333 | | | 319 | | Current regulatory assets | 239 | | | 354 | |
| | Investment in industrial development revenue bonds | | Investment in industrial development revenue bonds | — | | | 240 | |
| Current collateral assets | Current collateral assets | 222 | | | 66 | | Current collateral assets | 20 | | | 142 | |
| Other current assets | Other current assets | 77 | | | 97 | | Other current assets | 119 | | | 155 | |
| | Total current assets | Total current assets | 2,396 | | | 1,968 | | Total current assets | 2,019 | | | 2,668 | |
| Property, Plant, and Equipment, Net | Property, Plant, and Equipment, Net | 30,086 | | | 29,261 | | Property, Plant, and Equipment, Net | 32,351 | | | 31,262 | |
| Investments and Other Assets: | Investments and Other Assets: | | Investments and Other Assets: | |
| Nuclear decommissioning trust fund | Nuclear decommissioning trust fund | 957 | | | 1,159 | | Nuclear decommissioning trust fund | 1,075 | | | 958 | |
| Goodwill | Goodwill | 411 | | | 411 | | Goodwill | 411 | | | 411 | |
| | Regulatory assets | Regulatory assets | 1,487 | | | 1,289 | | Regulatory assets | 1,790 | | | 1,426 | |
| Pension and other postretirement benefits | Pension and other postretirement benefits | 808 | | | 756 | | Pension and other postretirement benefits | 442 | | | 411 | |
| Other assets | Other assets | 963 | | | 891 | | Other assets | 859 | | | 768 | |
| | Total investments and other assets | Total investments and other assets | 4,626 | | | 4,506 | | Total investments and other assets | 4,577 | | | 3,974 | |
| TOTAL ASSETS | TOTAL ASSETS | $ | 37,108 | | | $ | 35,735 | | TOTAL ASSETS | $ | 38,947 | | | $ | 37,904 | |
| LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | | | | LIABILITIES AND EQUITY | | | |
| Current Liabilities: | Current Liabilities: | | Current Liabilities: | |
| Current maturities of long-term debt | Current maturities of long-term debt | $ | 605 | | | $ | 505 | | Current maturities of long-term debt | $ | 350 | | | $ | 340 | |
| Short-term debt | Short-term debt | 1,021 | | | 545 | | Short-term debt | 1,329 | | | 1,070 | |
| Accounts and wages payable | Accounts and wages payable | 897 | | | 1,095 | | Accounts and wages payable | 719 | | | 1,159 | |
| | Current regulatory liabilities | 241 | | | 113 | | |
| | | Other current liabilities | Other current liabilities | 824 | | | 568 | | Other current liabilities | 845 | | | 797 | |
| | Total current liabilities | Total current liabilities | 3,588 | | | 2,826 | | Total current liabilities | 3,243 | | | 3,366 | |
| Long-term Debt, Net | Long-term Debt, Net | 12,985 | | | 12,562 | | Long-term Debt, Net | 14,328 | | | 13,685 | |
| Deferred Credits and Other Liabilities: | Deferred Credits and Other Liabilities: | | Deferred Credits and Other Liabilities: | |
| Accumulated deferred income taxes and tax credits, net | Accumulated deferred income taxes and tax credits, net | 3,614 | | | 3,499 | | Accumulated deferred income taxes and tax credits, net | 3,913 | | | 3,804 | |
| | Regulatory liabilities | Regulatory liabilities | 5,727 | | | 5,848 | | Regulatory liabilities | 5,445 | | | 5,309 | |
| Asset retirement obligations | Asset retirement obligations | 774 | | | 757 | | Asset retirement obligations | 775 | | | 763 | |
| | Other deferred credits and liabilities | Other deferred credits and liabilities | 411 | | | 414 | | Other deferred credits and liabilities | 417 | | | 340 | |
| | Total deferred credits and other liabilities | Total deferred credits and other liabilities | 10,526 | | | 10,518 | | Total deferred credits and other liabilities | 10,550 | | | 10,216 | |
| Commitments and Contingencies (Notes 2, 9, and 10) | Commitments and Contingencies (Notes 2, 9, and 10) | 0 | | 0 | Commitments and Contingencies (Notes 2, 9, and 10) | | | |
| Shareholders’ Equity: | Shareholders’ Equity: | | Shareholders’ Equity: | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 258.4 and 257.7, respectively | 3 | | | 3 | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 262.7 and 262.0, respectively | | Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 262.7 and 262.0, respectively | 3 | | | 3 | |
| Other paid-in capital, principally premium on common stock | Other paid-in capital, principally premium on common stock | 6,527 | | | 6,502 | | Other paid-in capital, principally premium on common stock | 6,880 | | | 6,860 | |
| Retained earnings | Retained earnings | 3,336 | | | 3,182 | | Retained earnings | 3,817 | | | 3,646 | |
| Accumulated other comprehensive income | 14 | | | 13 | | |
| Accumulated other comprehensive loss | | Accumulated other comprehensive loss | (3) | | | (1) | |
| | Total shareholders’ equity | Total shareholders’ equity | 9,880 | | | 9,700 | | Total shareholders’ equity | 10,697 | | | 10,508 | |
| Noncontrolling Interests | Noncontrolling Interests | 129 | | | 129 | | Noncontrolling Interests | 129 | | | 129 | |
| Total equity | Total equity | 10,009 | | | 9,829 | | Total equity | 10,826 | | | 10,637 | |
| TOTAL LIABILITIES AND EQUITY | TOTAL LIABILITIES AND EQUITY | $ | 37,108 | | | $ | 35,735 | | TOTAL LIABILITIES AND EQUITY | $ | 38,947 | | | $ | 37,904 | |
The accompanying notes are an integral part of these consolidated financial statements.
| | AMEREN CORPORATION | AMEREN CORPORATION | AMEREN CORPORATION |
| CONSOLIDATED STATEMENT OF CASH FLOWS | CONSOLIDATED STATEMENT OF CASH FLOWS | CONSOLIDATED STATEMENT OF CASH FLOWS |
| (Unaudited) (In millions) | (Unaudited) (In millions) | (Unaudited) (In millions) |
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2023 | | 2022 |
| Cash Flows From Operating Activities: | Cash Flows From Operating Activities: | | | | Cash Flows From Operating Activities: | | | |
| Net income | Net income | $ | 462 | | | $ | 443 | | Net income | $ | 504 | | | $ | 462 | |
| | Adjustments to reconcile net income to net cash provided by operating activities: | Adjustments to reconcile net income to net cash provided by operating activities: | | Adjustments to reconcile net income to net cash provided by operating activities: | |
| | Depreciation and amortization | Depreciation and amortization | 665 | | | 596 | | Depreciation and amortization | 703 | | | 665 | |
| Amortization of nuclear fuel | Amortization of nuclear fuel | 28 | | | 20 | | Amortization of nuclear fuel | 36 | | | 28 | |
| Amortization of debt issuance costs and premium/discounts | Amortization of debt issuance costs and premium/discounts | 12 | | | 11 | | Amortization of debt issuance costs and premium/discounts | 8 | | | 12 | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 66 | | | 59 | | Deferred income taxes and investment tax credits, net | 66 | | | 66 | |
| Allowance for equity funds used during construction | Allowance for equity funds used during construction | (19) | | | (16) | | Allowance for equity funds used during construction | (23) | | | (19) | |
| Stock-based compensation costs | Stock-based compensation costs | 12 | | | 11 | | Stock-based compensation costs | 14 | | | 12 | |
| Other | Other | 33 | | | 2 | | Other | (19) | | | 33 | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Receivables | Receivables | (187) | | | (92) | | Receivables | 173 | | | (187) | |
| Inventories | Inventories | (8) | | | (5) | | Inventories | (44) | | | (8) | |
| Accounts and wages payable | Accounts and wages payable | (87) | | | (208) | | Accounts and wages payable | (335) | | | (87) | |
| Taxes accrued | Taxes accrued | 94 | | | 104 | | Taxes accrued | 93 | | | 94 | |
| Regulatory assets and liabilities | Regulatory assets and liabilities | (74) | | | (441) | | Regulatory assets and liabilities | (81) | | | (74) | |
| Assets, other | Assets, other | (35) | | | (36) | | Assets, other | (38) | | | (35) | |
| Liabilities, other | Liabilities, other | 45 | | | 13 | | Liabilities, other | 34 | | | 45 | |
| Pension and other postretirement benefits | Pension and other postretirement benefits | (32) | | | 1 | | Pension and other postretirement benefits | (114) | | | (32) | |
| Counterparty collateral, net | Counterparty collateral, net | (103) | | | (26) | | Counterparty collateral, net | 134 | | | (103) | |
| | Net cash provided by operating activities | Net cash provided by operating activities | 872 | | | 436 | | Net cash provided by operating activities | 1,111 | | | 872 | |
| Cash Flows From Investing Activities: | Cash Flows From Investing Activities: | | | | Cash Flows From Investing Activities: | | | |
| Capital expenditures | Capital expenditures | (1,538) | | | (1,763) | | Capital expenditures | (1,822) | | | (1,538) | |
| | Nuclear fuel expenditures | Nuclear fuel expenditures | (22) | | | (4) | | Nuclear fuel expenditures | (50) | | | (22) | |
| Purchases of securities – nuclear decommissioning trust fund | Purchases of securities – nuclear decommissioning trust fund | (122) | | | (203) | | Purchases of securities – nuclear decommissioning trust fund | (81) | | | (122) | |
| Sales and maturities of securities – nuclear decommissioning trust fund | Sales and maturities of securities – nuclear decommissioning trust fund | 114 | | | 208 | | Sales and maturities of securities – nuclear decommissioning trust fund | 65 | | | 114 | |
| | Other | Other | 16 | | | 2 | | Other | (1) | | | 16 | |
| | Net cash used in investing activities | Net cash used in investing activities | (1,552) | | | (1,760) | | Net cash used in investing activities | (1,889) | | | (1,552) | |
| Cash Flows From Financing Activities: | Cash Flows From Financing Activities: | | | | Cash Flows From Financing Activities: | | | |
| Dividends on common stock | Dividends on common stock | (305) | | | (282) | | Dividends on common stock | (330) | | | (305) | |
| Dividends paid to noncontrolling interest holders | Dividends paid to noncontrolling interest holders | (3) | | | (3) | | Dividends paid to noncontrolling interest holders | (3) | | | (3) | |
| Short-term debt, net | Short-term debt, net | 475 | | | (59) | | Short-term debt, net | 260 | | | 475 | |
| | Maturities of long-term debt | | Maturities of long-term debt | (100) | | | — | |
| | Issuances of long-term debt | Issuances of long-term debt | 524 | | | 1,423 | | Issuances of long-term debt | 997 | | | 524 | |
| Issuances of common stock | Issuances of common stock | 17 | | | 258 | | Issuances of common stock | 16 | | | 17 | |
| | Redemptions of Ameren Illinois preferred stock | — | | | (13) | | |
| | Employee payroll taxes related to stock-based compensation | Employee payroll taxes related to stock-based compensation | (16) | | | (17) | | Employee payroll taxes related to stock-based compensation | (20) | | | (16) | |
| Debt issuance costs | Debt issuance costs | (6) | | | (13) | | Debt issuance costs | (9) | | | (6) | |
| Other | Other | — | | | (4) | | Other | (3) | | | — | |
| | Net cash provided by financing activities | Net cash provided by financing activities | 686 | | | 1,290 | | Net cash provided by financing activities | 808 | | | 686 | |
| Net change in cash, cash equivalents, and restricted cash | Net change in cash, cash equivalents, and restricted cash | 6 | | | (34) | | Net change in cash, cash equivalents, and restricted cash | 30 | | | 6 | |
| Cash, cash equivalents, and restricted cash at beginning of year | Cash, cash equivalents, and restricted cash at beginning of year | 155 | | | 301 | | Cash, cash equivalents, and restricted cash at beginning of year | 216 | | | 155 | |
| | Cash, cash equivalents, and restricted cash at end of period | Cash, cash equivalents, and restricted cash at end of period | $ | 161 | | | $ | 267 | | Cash, cash equivalents, and restricted cash at end of period | $ | 246 | | | $ | 161 | |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(Unaudited) (In millions, except per share amounts)
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| | Common Stock | Common Stock | $ | 3 | | | $ | 3 | | | $ | 3 | | | $ | 3 | | Common Stock | $ | 3 | | | $ | 3 | | | $ | 3 | | | $ | 3 | |
| | | Other Paid-in Capital: | Other Paid-in Capital: | | Other Paid-in Capital: | |
| Beginning of period | Beginning of period | 6,507 | | | 6,295 | | | 6,502 | | | 6,179 | | Beginning of period | 6,861 | | | 6,507 | | | 6,860 | | | 6,502 | |
| Settlement of forward sale agreement through common shares issuance | — | | | — | | | — | | | 113 | | |
| Shares issued under the ATM program | — | | | 121 | | | — | | | 121 | | |
| | Shares issued under the DRPlus and 401(k) plan | Shares issued under the DRPlus and 401(k) plan | 12 | | | 12 | | | 25 | | | 24 | | Shares issued under the DRPlus and 401(k) plan | 11 | | | 12 | | | 23 | | | 25 | |
| Stock-based compensation activity | Stock-based compensation activity | 8 | | | 8 | | | — | | | (1) | | Stock-based compensation activity | 8 | | | 8 | | | (3) | | | — | |
| | Other paid-in capital, end of period | Other paid-in capital, end of period | 6,527 | | | 6,436 | | | 6,527 | | | 6,436 | | Other paid-in capital, end of period | 6,880 | | | 6,527 | | | 6,880 | | | 6,527 | |
| | Retained Earnings: | Retained Earnings: | | Retained Earnings: | |
| Beginning of period | Beginning of period | 3,282 | | | 2,850 | | | 3,182 | | | 2,757 | | Beginning of period | 3,745 | | | 3,282 | | | 3,646 | | | 3,182 | |
| Net income attributable to Ameren common shareholders | Net income attributable to Ameren common shareholders | 207 | | | 207 | | | 459 | | | 440 | | Net income attributable to Ameren common shareholders | 237 | | | 207 | | | 501 | | | 459 | |
| Dividends on common stock | Dividends on common stock | (153) | | | (142) | | | (305) | | | (282) | | Dividends on common stock | (165) | | | (153) | | | (330) | | | (305) | |
| | Retained earnings, end of period | Retained earnings, end of period | 3,336 | | | 2,915 | | | 3,336 | | | 2,915 | | Retained earnings, end of period | 3,817 | | | 3,336 | | | 3,817 | | | 3,336 | |
| | Accumulated Other Comprehensive Income: | | |
| Accumulated Other Comprehensive Income (Loss): | | Accumulated Other Comprehensive Income (Loss): | |
| | Deferred retirement benefit costs, beginning of period | Deferred retirement benefit costs, beginning of period | 14 | | | — | | | 13 | | | (1) | | Deferred retirement benefit costs, beginning of period | (2) | | | 14 | | | (1) | | | 13 | |
| | Change in deferred retirement benefit costs | Change in deferred retirement benefit costs | — | | | (1) | | | 1 | | | — | | Change in deferred retirement benefit costs | (1) | | | — | | | (2) | | | 1 | |
| | Deferred retirement benefit costs, end of period | Deferred retirement benefit costs, end of period | 14 | | | (1) | | | 14 | | | (1) | | Deferred retirement benefit costs, end of period | (3) | | | 14 | | | (3) | | | 14 | |
| Total accumulated other comprehensive income, end of period | 14 | | | (1) | | | 14 | | | (1) | | |
| Total accumulated other comprehensive income (loss), end of period | | Total accumulated other comprehensive income (loss), end of period | (3) | | | 14 | | | (3) | | | 14 | |
| Total Shareholders’ Equity | Total Shareholders’ Equity | $ | 9,880 | | | $ | 9,353 | | | $ | 9,880 | | | $ | 9,353 | | Total Shareholders’ Equity | $ | 10,697 | | | $ | 9,880 | | | $ | 10,697 | | | $ | 9,880 | |
| | Noncontrolling Interests: | Noncontrolling Interests: | | Noncontrolling Interests: | |
| Beginning of period | Beginning of period | 129 | | | 129 | | | 129 | | | 142 | | Beginning of period | 129 | | | 129 | | | 129 | | | 129 | |
| Net income attributable to noncontrolling interest holders | Net income attributable to noncontrolling interest holders | 2 | | | 1 | | | 3 | | | 3 | | Net income attributable to noncontrolling interest holders | 2 | | | 2 | | | 3 | | | 3 | |
| Dividends paid to noncontrolling interest holders | Dividends paid to noncontrolling interest holders | (2) | | | (1) | | | (3) | | | (3) | | Dividends paid to noncontrolling interest holders | (2) | | | (2) | | | (3) | | | (3) | |
| Redemptions of Ameren Illinois preferred stock | — | | | — | | | — | | | (13) | | |
| | | Noncontrolling interests, end of period | Noncontrolling interests, end of period | 129 | | | 129 | | | 129 | | | 129 | | Noncontrolling interests, end of period | 129 | | | 129 | | | 129 | | | 129 | |
| Total Equity | Total Equity | $ | 10,009 | | | $ | 9,482 | | | $ | 10,009 | | | $ | 9,482 | | Total Equity | $ | 10,826 | | | $ | 10,009 | | | $ | 10,826 | | | $ | 10,009 | |
| | | Common stock shares outstanding at beginning of period | Common stock shares outstanding at beginning of period | 258.2 | | | 255.5 | | | 257.7 | | | 253.3 | | Common stock shares outstanding at beginning of period | 262.6 | | | 258.2 | | | 262.0 | | | 257.7 | |
| Shares issued under forward sale agreement | — | | | — | | | — | | | 1.6 | | |
| Shares issued under the ATM program | — | | | 1.4 | | | — | | | 1.4 | | |
| | Shares issued under the DRPlus and 401(k) plan | Shares issued under the DRPlus and 401(k) plan | 0.2 | | | 0.2 | | | 0.3 | | | 0.3 | | Shares issued under the DRPlus and 401(k) plan | 0.1 | | | 0.2 | | | 0.2 | | | 0.3 | |
| Shares issued for stock-based compensation | Shares issued for stock-based compensation | — | | | — | | | 0.4 | | | 0.5 | | Shares issued for stock-based compensation | — | | | — | | | 0.5 | | | 0.4 | |
| Common stock shares outstanding at end of period | Common stock shares outstanding at end of period | 258.4 | | | 257.1 | | | 258.4 | | | 257.1 | | Common stock shares outstanding at end of period | 262.7 | | | 258.4 | | | 262.7 | | | 258.4 | |
| | Dividends per common share | Dividends per common share | $ | 0.59 | | | $ | 0.55 | | | $ | 1.18 | | | $ | 1.10 | | Dividends per common share | $ | 0.63 | | | $ | 0.59 | | | $ | 1.26 | | | $ | 1.18 | |
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Operating Revenues: | Operating Revenues: | | | | | | | | Operating Revenues: | | | | | | | |
| Electric | Electric | $ | 890 | | | $ | 789 | | | $ | 1,628 | | | $ | 1,430 | | Electric | $ | 918 | | | $ | 890 | | | $ | 1,759 | | | $ | 1,628 | |
| Natural gas | Natural gas | 29 | | | 20 | | | 109 | | | 83 | | Natural gas | 23 | | | 29 | | | 105 | | | 109 | |
| | Total operating revenues | Total operating revenues | 919 | | | 809 | | | 1,737 | | | 1,513 | | Total operating revenues | 941 | | | 919 | | | 1,864 | | | 1,737 | |
| Operating Expenses: | Operating Expenses: | | | | | | | | Operating Expenses: | | | | | | | |
| Fuel | Fuel | 83 | | | 173 | | | 259 | | | 238 | | Fuel | 152 | | | 83 | | | 265 | | | 259 | |
| Purchased power | Purchased power | 161 | | | 50 | | | 211 | | | 138 | | Purchased power | 137 | | | 161 | | | 345 | | | 211 | |
| Natural gas purchased for resale | Natural gas purchased for resale | 12 | | | 5 | | | 58 | | | 36 | | Natural gas purchased for resale | 9 | | | 12 | | | 56 | | | 58 | |
| Other operations and maintenance | Other operations and maintenance | 260 | | | 218 | | | 492 | | | 443 | | Other operations and maintenance | 237 | | | 260 | | | 476 | | | 492 | |
| | Depreciation and amortization | Depreciation and amortization | 178 | | | 157 | | | 342 | | | 313 | | Depreciation and amortization | 186 | | | 178 | | | 362 | | | 342 | |
| Taxes other than income taxes | Taxes other than income taxes | 90 | | | 85 | | | 175 | | | 162 | | Taxes other than income taxes | 88 | | | 90 | | | 168 | | | 175 | |
| Total operating expenses | Total operating expenses | 784 | | | 688 | | | 1,537 | | | 1,330 | | Total operating expenses | 809 | | | 784 | | | 1,672 | | | 1,537 | |
| Operating Income | Operating Income | 135 | | | 121 | | | 200 | | | 183 | | Operating Income | 132 | | | 135 | | | 192 | | | 200 | |
| | Other Income, Net | Other Income, Net | 24 | | | 24 | | | 47 | | | 47 | | Other Income, Net | 22 | | | 24 | | | 41 | | | 47 | |
| Interest Charges | Interest Charges | 60 | | | 36 | | | 99 | | | 75 | | Interest Charges | 52 | | | 60 | | | 103 | | | 99 | |
| Income Before Income Taxes | Income Before Income Taxes | 99 | | | 109 | | | 148 | | | 155 | | Income Before Income Taxes | 102 | | | 99 | | | 130 | | | 148 | |
| Income Taxes Benefit | Income Taxes Benefit | (2) | | | (3) | | | (4) | | | (5) | | Income Taxes Benefit | (1) | | | (2) | | | (2) | | | (4) | |
| Net Income | Net Income | 101 | | | 112 | | | 152 | | | 160 | | Net Income | 103 | | | 101 | | | 132 | | | 152 | |
| | Preferred Stock Dividends | Preferred Stock Dividends | 1 | | | 1 | | | 2 | | | 2 | | Preferred Stock Dividends | 1 | | | 1 | | | 2 | | | 2 | |
| Net Income Available to Common Shareholder | Net Income Available to Common Shareholder | $ | 100 | | | $ | 111 | | | $ | 150 | | | $ | 158 | | Net Income Available to Common Shareholder | $ | 102 | | | $ | 100 | | | $ | 130 | | | $ | 150 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)
| | | June 30,
2022 | | December 31, 2021 | | June 30,
2023 | | December 31, 2022 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current Assets: | Current Assets: | | Current Assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | — | | | $ | — | | Cash and cash equivalents | $ | — | | | $ | — | |
| | Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | 201 | | | 190 | | Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | 185 | | | 244 | |
| Accounts receivable – affiliates | Accounts receivable – affiliates | 55 | | | 44 | | Accounts receivable – affiliates | 49 | | | 51 | |
| Unbilled revenue | Unbilled revenue | 244 | | | 142 | | Unbilled revenue | 248 | | | 184 | |
| Miscellaneous accounts receivable | Miscellaneous accounts receivable | 50 | | | 71 | | Miscellaneous accounts receivable | 19 | | | 18 | |
| Inventories | Inventories | 426 | | | 419 | | Inventories | 515 | | | 434 | |
| Mark-to-market derivative assets | 89 | | | 38 | | |
| | Current regulatory assets | Current regulatory assets | 232 | | | 127 | | Current regulatory assets | 144 | | | 254 | |
| Investment in industrial development revenue bonds | | Investment in industrial development revenue bonds | — | | | 240 | |
| Current collateral assets | Current collateral assets | 199 | | | 66 | | Current collateral assets | 20 | | | 101 | |
| Other current assets | Other current assets | 23 | | | 38 | | Other current assets | 44 | | | 66 | |
| Total current assets | Total current assets | 1,519 | | | 1,135 | | Total current assets | 1,224 | | | 1,592 | |
| Property, Plant, and Equipment, Net | Property, Plant, and Equipment, Net | 15,635 | | | 15,296 | | Property, Plant, and Equipment, Net | 16,560 | | | 16,124 | |
| Investments and Other Assets: | Investments and Other Assets: | | Investments and Other Assets: | |
| Nuclear decommissioning trust fund | Nuclear decommissioning trust fund | 957 | | | 1,159 | | Nuclear decommissioning trust fund | 1,075 | | | 958 | |
| | Regulatory assets | Regulatory assets | 640 | | | 523 | | Regulatory assets | 676 | | | 594 | |
| Pension and other postretirement benefits | Pension and other postretirement benefits | 225 | | | 208 | | Pension and other postretirement benefits | 111 | | | 98 | |
| Other assets | Other assets | 425 | | | 401 | | Other assets | 138 | | | 140 | |
| Total investments and other assets | Total investments and other assets | 2,247 | | | 2,291 | | Total investments and other assets | 2,000 | | | 1,790 | |
| TOTAL ASSETS | TOTAL ASSETS | $ | 19,401 | | | $ | 18,722 | | TOTAL ASSETS | $ | 19,784 | | | $ | 19,506 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | Current Liabilities: | | Current Liabilities: | |
| Current maturities of long-term debt | Current maturities of long-term debt | $ | 55 | | | $ | 55 | | Current maturities of long-term debt | $ | 350 | | | $ | 240 | |
| Short-term debt | Short-term debt | 285 | | | 165 | | Short-term debt | 373 | | | 329 | |
| | Accounts and wages payable | Accounts and wages payable | 388 | | | 631 | | Accounts and wages payable | 275 | | | 606 | |
| Accounts payable – affiliates | Accounts payable – affiliates | 37 | | | 46 | | Accounts payable – affiliates | 40 | | | 43 | |
| Taxes accrued | Taxes accrued | 134 | | | 34 | | Taxes accrued | 127 | | | 29 | |
| Interest accrued | 75 | | | 60 | | |
| Mark-to-market derivative liabilities | 145 | | | 53 | | |
| | Current regulatory liabilities | 130 | | | 57 | | |
| | Other current liabilities | Other current liabilities | 134 | | | 116 | | Other current liabilities | 253 | | | 323 | |
| Total current liabilities | Total current liabilities | 1,383 | | | 1,217 | | Total current liabilities | 1,418 | | | 1,570 | |
| Long-term Debt, Net | Long-term Debt, Net | 6,084 | | | 5,564 | | Long-term Debt, Net | 5,991 | | | 5,846 | |
| Deferred Credits and Other Liabilities: | Deferred Credits and Other Liabilities: | | Deferred Credits and Other Liabilities: | |
| Accumulated deferred income taxes and tax credits, net | Accumulated deferred income taxes and tax credits, net | 1,901 | | | 1,852 | | Accumulated deferred income taxes and tax credits, net | 2,015 | | | 1,982 | |
| | Regulatory liabilities | Regulatory liabilities | 3,121 | | | 3,354 | | Regulatory liabilities | 2,972 | | | 2,871 | |
| Asset retirement obligations | Asset retirement obligations | 770 | | | 753 | | Asset retirement obligations | 771 | | | 759 | |
| | Other deferred credits and liabilities | Other deferred credits and liabilities | 81 | | | 71 | | Other deferred credits and liabilities | 60 | | | 51 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 5,873 | | | 6,030 | | Total deferred credits and other liabilities | 5,818 | | | 5,663 | |
| Commitments and Contingencies (Notes 2, 8, 9, and 10) | Commitments and Contingencies (Notes 2, 8, 9, and 10) | 0 | | 0 | Commitments and Contingencies (Notes 2, 8, 9, and 10) | | | |
| Shareholders’ Equity: | Shareholders’ Equity: | | Shareholders’ Equity: | |
| Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | | | 511 | | Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | | | 511 | |
| Other paid-in capital, principally premium on common stock | Other paid-in capital, principally premium on common stock | 2,725 | | | 2,725 | | Other paid-in capital, principally premium on common stock | 2,725 | | | 2,725 | |
| Preferred stock | Preferred stock | 80 | | | 80 | | Preferred stock | 80 | | | 80 | |
| Retained earnings | Retained earnings | 2,745 | | | 2,595 | | Retained earnings | 3,241 | | | 3,111 | |
| Total shareholders’ equity | Total shareholders’ equity | 6,061 | | | 5,911 | | Total shareholders’ equity | 6,557 | | | 6,427 | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 19,401 | | | $ | 18,722 | | TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 19,784 | | | $ | 19,506 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash Flows From Operating Activities: | Cash Flows From Operating Activities: | | | | Cash Flows From Operating Activities: | | | |
| Net income | Net income | $ | 152 | | | $ | 160 | | Net income | $ | 132 | | | $ | 152 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | Adjustments to reconcile net income to net cash provided by operating activities: | | Adjustments to reconcile net income to net cash provided by operating activities: | |
| | Depreciation and amortization | Depreciation and amortization | 393 | | | 343 | | Depreciation and amortization | 410 | | | 393 | |
| Amortization of nuclear fuel | Amortization of nuclear fuel | 28 | | | 20 | | Amortization of nuclear fuel | 36 | | | 28 | |
| | Amortization of debt issuance costs and premium/discounts | Amortization of debt issuance costs and premium/discounts | 3 | | | 3 | | Amortization of debt issuance costs and premium/discounts | 3 | | | 3 | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 19 | | | (2) | | Deferred income taxes and investment tax credits, net | 10 | | | 19 | |
| Allowance for equity funds used during construction | Allowance for equity funds used during construction | (10) | | | (10) | | Allowance for equity funds used during construction | (12) | | | (10) | |
| Other | Other | 4 | | | 6 | | Other | (20) | | | 4 | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Receivables | Receivables | (105) | | | (135) | | Receivables | (9) | | | (105) | |
| Inventories | Inventories | (7) | | | (8) | | Inventories | (81) | | | (7) | |
| Accounts and wages payable | Accounts and wages payable | (159) | | | (172) | | Accounts and wages payable | (231) | | | (159) | |
| Taxes accrued | Taxes accrued | 81 | | | 167 | | Taxes accrued | 103 | | | 81 | |
| Regulatory assets and liabilities | Regulatory assets and liabilities | (128) | | | (165) | | Regulatory assets and liabilities | 28 | | | (128) | |
| Assets, other | Assets, other | 12 | | | 23 | | Assets, other | 13 | | | 12 | |
| Liabilities, other | Liabilities, other | 24 | | | 19 | | Liabilities, other | 21 | | | 24 | |
| Pension and other postretirement benefits | Pension and other postretirement benefits | (8) | | | 5 | | Pension and other postretirement benefits | (41) | | | (8) | |
| Counterparty collateral, net | Counterparty collateral, net | (118) | | | (30) | | Counterparty collateral, net | 81 | | | (118) | |
| Net cash provided by operating activities | Net cash provided by operating activities | 181 | | | 224 | | Net cash provided by operating activities | 443 | | | 181 | |
| Cash Flows From Investing Activities: | Cash Flows From Investing Activities: | | | | Cash Flows From Investing Activities: | | | |
| Capital expenditures | Capital expenditures | (806) | | | (1,101) | | Capital expenditures | (914) | | | (806) | |
| | Nuclear fuel expenditures | Nuclear fuel expenditures | (22) | | | (4) | | Nuclear fuel expenditures | (50) | | | (22) | |
| Purchases of securities – nuclear decommissioning trust fund | Purchases of securities – nuclear decommissioning trust fund | (122) | | | (203) | | Purchases of securities – nuclear decommissioning trust fund | (81) | | | (122) | |
| Sales and maturities of securities – nuclear decommissioning trust fund | Sales and maturities of securities – nuclear decommissioning trust fund | 114 | | | 208 | | Sales and maturities of securities – nuclear decommissioning trust fund | 65 | | | 114 | |
| | Money pool advances, net | — | | | 47 | | |
| | Other | Other | 18 | | | — | | Other | — | | | 18 | |
| Net cash used in investing activities | Net cash used in investing activities | (818) | | | (1,053) | | Net cash used in investing activities | (980) | | | (818) | |
| Cash Flows From Financing Activities: | Cash Flows From Financing Activities: | | | | Cash Flows From Financing Activities: | | | |
| | Dividends on preferred stock | Dividends on preferred stock | (2) | | | (2) | | Dividends on preferred stock | (2) | | | (2) | |
| Short-term debt, net | Short-term debt, net | 120 | | | — | | Short-term debt, net | 44 | | | 120 | |
| | Issuances of long-term debt | Issuances of long-term debt | 524 | | | 524 | | Issuances of long-term debt | 499 | | | 524 | |
| Capital contribution from parent | — | | | 183 | | |
| | Debt issuance costs | Debt issuance costs | (6) | | | (4) | | Debt issuance costs | (6) | | | (6) | |
| Other | | Other | (3) | | | — | |
| Net cash provided by financing activities | Net cash provided by financing activities | 636 | | | 701 | | Net cash provided by financing activities | 532 | | | 636 | |
| Net change in cash, cash equivalents, and restricted cash | Net change in cash, cash equivalents, and restricted cash | (1) | | | (128) | | Net change in cash, cash equivalents, and restricted cash | (5) | | | (1) | |
| Cash, cash equivalents, and restricted cash at beginning of year | Cash, cash equivalents, and restricted cash at beginning of year | 8 | | | 145 | | Cash, cash equivalents, and restricted cash at beginning of year | 13 | | | 8 | |
| Cash, cash equivalents, and restricted cash at end of period | Cash, cash equivalents, and restricted cash at end of period | $ | 7 | | | $ | 17 | | Cash, cash equivalents, and restricted cash at end of period | $ | 8 | | | $ | 7 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI)
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(Unaudited) (In millions)
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Common Stock | Common Stock | $ | 511 | | | $ | 511 | | | $ | 511 | | | $ | 511 | | Common Stock | $ | 511 | | | $ | 511 | | | $ | 511 | | | $ | 511 | |
| | Other Paid-in Capital: | | |
| Beginning of period | 2,725 | | | 2,631 | | | 2,725 | | | 2,518 | | |
| Capital contributions from parent | — | | | 70 | | | — | | | 183 | | |
| Other Paid-in Capital | | Other Paid-in Capital | 2,725 | | | 2,725 | | | 2,725 | | | 2,725 | |
| | Other paid-in capital, end of period | 2,725 | | | 2,701 | | | 2,725 | | | 2,701 | | |
| | | | Preferred Stock | Preferred Stock | 80 | | | 80 | | | 80 | | | 80 | | Preferred Stock | 80 | | | 80 | | | 80 | | | 80 | |
| | Retained Earnings: | Retained Earnings: | | Retained Earnings: | |
| Beginning of period | Beginning of period | 2,645 | | | 2,148 | | | 2,595 | | | 2,101 | | Beginning of period | 3,139 | | | 2,645 | | | 3,111 | | | 2,595 | |
| Net income | Net income | 101 | | | 112 | | | 152 | | | 160 | | Net income | 103 | | | 101 | | | 132 | | | 152 | |
| | Dividends on preferred stock | Dividends on preferred stock | (1) | | | (1) | | | (2) | | | (2) | | Dividends on preferred stock | (1) | | | (1) | | | (2) | | | (2) | |
| Retained earnings, end of period | Retained earnings, end of period | 2,745 | | | 2,259 | | | 2,745 | | | 2,259 | | Retained earnings, end of period | 3,241 | | | 2,745 | | | 3,241 | | | 2,745 | |
| | Total Shareholders’ Equity | Total Shareholders’ Equity | $ | 6,061 | | | $ | 5,551 | | | $ | 6,061 | | | $ | 5,551 | | Total Shareholders’ Equity | $ | 6,557 | | | $ | 6,061 | | | $ | 6,557 | | | $ | 6,061 | |
The accompanying notes as they relate to Ameren Missouri are an integral part of these consolidated financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF INCOME
(Unaudited) (In millions)
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Operating Revenues: | Operating Revenues: | | | | | | | | Operating Revenues: | | | | | | | |
| Electric | Electric | $ | 585 | | | $ | 461 | | | $ | 1,128 | | | $ | 937 | | Electric | $ | 627 | | | $ | 585 | | | $ | 1,337 | | | $ | 1,128 | |
| Natural gas | Natural gas | 184 | | | 168 | | | 665 | | | 515 | | Natural gas | 152 | | | 184 | | | 543 | | | 665 | |
| Total operating revenues | Total operating revenues | 769 | | | 629 | | | 1,793 | | | 1,452 | | Total operating revenues | 779 | | | 769 | | | 1,880 | | | 1,793 | |
| Operating Expenses: | Operating Expenses: | | | | | | | | Operating Expenses: | | | | | | | |
| Purchased power | Purchased power | 158 | | | 84 | | | 289 | | | 190 | | Purchased power | 192 | | | 158 | | | 479 | | | 289 | |
| Natural gas purchased for resale | Natural gas purchased for resale | 68 | | | 60 | | | 315 | | | 194 | | Natural gas purchased for resale | 33 | | | 68 | | | 194 | | | 315 | |
| Other operations and maintenance | Other operations and maintenance | 225 | | | 193 | | | 448 | | | 387 | | Other operations and maintenance | 201 | | | 225 | | | 403 | | | 448 | |
| Depreciation and amortization | Depreciation and amortization | 128 | | | 117 | | | 252 | | | 232 | | Depreciation and amortization | 138 | | | 128 | | | 271 | | | 252 | |
| Taxes other than income taxes | Taxes other than income taxes | 35 | | | 34 | | | 88 | | | 80 | | Taxes other than income taxes | 32 | | | 35 | | | 74 | | | 88 | |
| Total operating expenses | Total operating expenses | 614 | | | 488 | | | 1,392 | | | 1,083 | | Total operating expenses | 596 | | | 614 | | | 1,421 | | | 1,392 | |
| Operating Income | Operating Income | 155 | | | 141 | | | 401 | | | 369 | | Operating Income | 183 | | | 155 | | | 459 | | | 401 | |
| | Other Income, Net | Other Income, Net | 25 | | | 16 | | | 49 | | | 30 | | Other Income, Net | 41 | | | 25 | | | 78 | | | 49 | |
| Interest Charges | Interest Charges | 41 | | | 40 | | | 83 | | | 82 | | Interest Charges | 50 | | | 41 | | | 97 | | | 83 | |
| Income Before Income Taxes | Income Before Income Taxes | 139 | | | 117 | | | 367 | | | 317 | | Income Before Income Taxes | 174 | | | 139 | | | 440 | | | 367 | |
| Income Taxes | Income Taxes | 35 | | | 31 | | | 94 | | | 81 | | Income Taxes | 44 | | | 35 | | | 112 | | | 94 | |
| Net Income | Net Income | 104 | | | 86 | | | 273 | | | 236 | | Net Income | 130 | | | 104 | | | 328 | | | 273 | |
| | Preferred Stock Dividends | Preferred Stock Dividends | 1 | | | — | | | 1 | | | 1 | | Preferred Stock Dividends | 1 | | | 1 | | | 1 | | | 1 | |
| Net Income Available to Common Shareholder | Net Income Available to Common Shareholder | $ | 103 | | | $ | 86 | | | $ | 272 | | | $ | 235 | | Net Income Available to Common Shareholder | $ | 129 | | | $ | 103 | | | $ | 327 | | | $ | 272 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
BALANCE SHEET
(Unaudited) (In millions)
| | | June 30,
2022 | | December 31, 2021 | | June 30,
2023 | | December 31, 2022 |
| ASSETS | ASSETS | | | | ASSETS | | | |
| Current Assets: | Current Assets: | | Current Assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | — | | | $ | — | | Cash and cash equivalents | $ | — | | | $ | — | |
| | Accounts receivable – trade (less allowance for doubtful accounts of $18 and $16, respectively) | 302 | | | 228 | | |
| Accounts receivable – trade (less allowance for doubtful accounts of $27 and $18, respectively) | | Accounts receivable – trade (less allowance for doubtful accounts of $27 and $18, respectively) | 281 | | | 341 | |
| Accounts receivable – affiliates | Accounts receivable – affiliates | 9 | | | 24 | | Accounts receivable – affiliates | 10 | | | 12 | |
| Unbilled revenue | Unbilled revenue | 156 | | | 159 | | Unbilled revenue | 130 | | | 262 | |
| Miscellaneous accounts receivable | Miscellaneous accounts receivable | 16 | | | 1 | | Miscellaneous accounts receivable | 29 | | | 23 | |
| Inventories | Inventories | 174 | | | 173 | | Inventories | 196 | | | 233 | |
| Mark-to-market derivative assets | 68 | | | 28 | | |
| | | Current regulatory assets | Current regulatory assets | 94 | | | 180 | | Current regulatory assets | 88 | | | 87 | |
| | Other current assets | Other current assets | 46 | | | 30 | | Other current assets | 36 | | | 98 | |
| Total current assets | Total current assets | 865 | | | 823 | | Total current assets | 770 | | | 1,056 | |
| Property, Plant, and Equipment, Net | Property, Plant, and Equipment, Net | 12,688 | | | 12,223 | | Property, Plant, and Equipment, Net | 13,955 | | | 13,353 | |
| Investments and Other Assets: | Investments and Other Assets: | | Investments and Other Assets: | |
| Goodwill | Goodwill | 411 | | | 411 | | Goodwill | 411 | | | 411 | |
| Regulatory assets | Regulatory assets | 828 | | | 752 | | Regulatory assets | 1,091 | | | 821 | |
| Pension and other postretirement benefits | Pension and other postretirement benefits | 449 | | | 427 | | Pension and other postretirement benefits | 335 | | | 318 | |
| Other assets | Other assets | 478 | | | 399 | | Other assets | 548 | | | 482 | |
| Total investments and other assets | Total investments and other assets | 2,166 | | | 1,989 | | Total investments and other assets | 2,385 | | | 2,032 | |
| TOTAL ASSETS | TOTAL ASSETS | $ | 15,719 | | | $ | 15,035 | | TOTAL ASSETS | $ | 17,110 | | | $ | 16,441 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities: | Current Liabilities: | | Current Liabilities: | |
| Current maturities of long-term debt | Current maturities of long-term debt | $ | 500 | | | $ | 400 | | Current maturities of long-term debt | $ | — | | | $ | 100 | |
| Short-term debt | Short-term debt | 141 | | | 103 | | Short-term debt | 117 | | | 264 | |
| | Accounts and wages payable | Accounts and wages payable | 428 | | | 361 | | Accounts and wages payable | 357 | | | 451 | |
| Accounts payable – affiliates | Accounts payable – affiliates | 118 | | | 64 | | Accounts payable – affiliates | 68 | | | 93 | |
| | Customer deposits | | Customer deposits | 111 | | | 87 | |
| | Current regulatory liabilities | Current regulatory liabilities | 111 | | | 54 | | Current regulatory liabilities | 82 | | | 64 | |
| Other current liabilities | Other current liabilities | 277 | | | 251 | | Other current liabilities | 212 | | | 232 | |
| Total current liabilities | Total current liabilities | 1,575 | | | 1,233 | | Total current liabilities | 947 | | | 1,291 | |
| Long-term Debt, Net | Long-term Debt, Net | 3,894 | | | 3,992 | | Long-term Debt, Net | 5,232 | | | 4,735 | |
| Deferred Credits and Other Liabilities: | Deferred Credits and Other Liabilities: | | Deferred Credits and Other Liabilities: | |
| Accumulated deferred income taxes and investment tax credits, net | Accumulated deferred income taxes and investment tax credits, net | 1,626 | | | 1,558 | | Accumulated deferred income taxes and investment tax credits, net | 1,783 | | | 1,699 | |
| | Regulatory liabilities | Regulatory liabilities | 2,484 | | | 2,374 | | Regulatory liabilities | 2,344 | | | 2,313 | |
| | Other deferred credits and liabilities | Other deferred credits and liabilities | 228 | | | 238 | | Other deferred credits and liabilities | 309 | | | 235 | |
| Total deferred credits and other liabilities | Total deferred credits and other liabilities | 4,338 | | | 4,170 | | Total deferred credits and other liabilities | 4,436 | | | 4,247 | |
| Commitments and Contingencies (Notes 2, 8, and 9) | Commitments and Contingencies (Notes 2, 8, and 9) | 0 | | 0 | Commitments and Contingencies (Notes 2, 8, and 9) | | | |
| Shareholders’ Equity: | Shareholders’ Equity: | | Shareholders’ Equity: | |
| Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | — | | | — | | Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | — | | | — | |
| Other paid-in capital | Other paid-in capital | 2,914 | | | 2,914 | | Other paid-in capital | 2,929 | | | 2,929 | |
| Preferred stock | Preferred stock | 49 | | | 49 | | Preferred stock | 49 | | | 49 | |
| Retained earnings | Retained earnings | 2,949 | | | 2,677 | | Retained earnings | 3,517 | | | 3,190 | |
| | Total shareholders’ equity | Total shareholders’ equity | 5,912 | | | 5,640 | | Total shareholders’ equity | 6,495 | | | 6,168 | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 15,719 | | | $ | 15,035 | | TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 17,110 | | | $ | 16,441 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
| | | Six Months Ended June 30, | | Six Months Ended June 30, |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Cash Flows From Operating Activities: | Cash Flows From Operating Activities: | | | | Cash Flows From Operating Activities: | | | |
| Net income | Net income | $ | 273 | | | $ | 236 | | Net income | $ | 328 | | | $ | 273 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | Adjustments to reconcile net income to net cash provided by operating activities: | | Adjustments to reconcile net income to net cash provided by operating activities: | |
| Depreciation and amortization | Depreciation and amortization | 251 | | | 231 | | Depreciation and amortization | 271 | | | 251 | |
| Amortization of debt issuance costs and premium/discounts | Amortization of debt issuance costs and premium/discounts | 6 | | | 6 | | Amortization of debt issuance costs and premium/discounts | 2 | | | 6 | |
| Deferred income taxes and investment tax credits, net | Deferred income taxes and investment tax credits, net | 55 | | | 84 | | Deferred income taxes and investment tax credits, net | 70 | | | 55 | |
| | Allowance for equity funds used during construction | Allowance for equity funds used during construction | (9) | | | (6) | | Allowance for equity funds used during construction | (10) | | | (9) | |
| Other | Other | 6 | | | 5 | | Other | 12 | | | 6 | |
| Changes in assets and liabilities: | Changes in assets and liabilities: | | Changes in assets and liabilities: | |
| Receivables | Receivables | (76) | | | 43 | | Receivables | 182 | | | (76) | |
| Inventories | Inventories | (1) | | | 3 | | Inventories | 37 | | | (1) | |
| Accounts and wages payable | Accounts and wages payable | 76 | | | (23) | | Accounts and wages payable | (92) | | | 76 | |
| Taxes accrued | Taxes accrued | 62 | | | 36 | | Taxes accrued | (36) | | | 62 | |
| Regulatory assets and liabilities | Regulatory assets and liabilities | 55 | | | (273) | | Regulatory assets and liabilities | (105) | | | 55 | |
| Assets, other | Assets, other | (66) | | | (46) | | Assets, other | (42) | | | (43) | |
| Liabilities, other | Liabilities, other | 61 | | | (2) | | Liabilities, other | 13 | | | 23 | |
| Pension and other postretirement benefits | Pension and other postretirement benefits | (18) | | | (8) | | Pension and other postretirement benefits | (46) | | | (18) | |
| | Counterparty collateral, net | | Counterparty collateral, net | 53 | | | 15 | |
| | Net cash provided by operating activities | Net cash provided by operating activities | 675 | | | 286 | | Net cash provided by operating activities | 637 | | | 675 | |
| Cash Flows From Investing Activities: | Cash Flows From Investing Activities: | | | | Cash Flows From Investing Activities: | | | |
| Capital expenditures | Capital expenditures | (699) | | | (646) | | Capital expenditures | (844) | | | (699) | |
| Money pool advances, net | — | | | (20) | | |
| | Other | Other | — | | | (2) | | Other | (2) | | | — | |
| Net cash used in investing activities | Net cash used in investing activities | (699) | | | (668) | | Net cash used in investing activities | (846) | | | (699) | |
| Cash Flows From Financing Activities: | Cash Flows From Financing Activities: | | | | Cash Flows From Financing Activities: | | | |
| | Dividends on preferred stock | Dividends on preferred stock | (1) | | | (1) | | Dividends on preferred stock | (1) | | | (1) | |
| Short-term debt, net | Short-term debt, net | 38 | | | — | | Short-term debt, net | (147) | | | 38 | |
| Money pool borrowings, net | — | | | (19) | | |
| | Maturities of long-term debt | | Maturities of long-term debt | (100) | | | — | |
| Issuances of long-term debt | Issuances of long-term debt | — | | | 449 | | Issuances of long-term debt | 498 | | | — | |
| Capital contributions from parent | — | | | 70 | | |
| Redemption of preferred stock | — | | | (13) | | |
| | | Debt issuance costs | Debt issuance costs | — | | | (5) | | Debt issuance costs | (3) | | | — | |
| Other | — | | | (4) | | |
| | Net cash provided by financing activities | Net cash provided by financing activities | 37 | | | 477 | | Net cash provided by financing activities | 247 | | | 37 | |
| Net change in cash, cash equivalents, and restricted cash | Net change in cash, cash equivalents, and restricted cash | 13 | | | 95 | | Net change in cash, cash equivalents, and restricted cash | 38 | | | 13 | |
| Cash, cash equivalents and restricted cash at beginning of year | Cash, cash equivalents and restricted cash at beginning of year | 133 | | | 147 | | Cash, cash equivalents and restricted cash at beginning of year | 191 | | | 133 | |
| Cash, cash equivalents, and restricted cash at end of period | Cash, cash equivalents, and restricted cash at end of period | $ | 146 | | | $ | 242 | | Cash, cash equivalents, and restricted cash at end of period | $ | 229 | | | $ | 146 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
STATEMENT OF SHAREHOLDERS’ EQUITY
(Unaudited) (In millions)
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Common Stock | Common Stock | $ | — | | | $ | — | | | $ | — | | | $ | — | | Common Stock | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | Other Paid-in Capital: | | |
| Beginning of period | 2,914 | | | 2,692 | | | 2,914 | | | 2,652 | | |
| Capital contributions from parent | — | | | 30 | | | — | | | 70 | | |
| | Other paid-in capital, end of period | 2,914 | | | 2,722 | | | 2,914 | | | 2,722 | | |
| Other Paid-in Capital | | Other Paid-in Capital | 2,929 | | | 2,914 | | | 2,929 | | | 2,914 | |
| | | Preferred Stock: | | |
| Beginning of period | 49 | | | 49 | | | 49 | | | 62 | | |
| Redemptions of preferred stock | — | | | — | | | — | | | (13) | | |
| | Preferred stock, end of period | 49 | | | 49 | | | 49 | | | 49 | | |
| | | | Preferred Stock | | Preferred Stock | 49 | | | 49 | | | 49 | | | 49 | |
| | | Retained Earnings: | Retained Earnings: | | Retained Earnings: | |
| Beginning of period | Beginning of period | 2,846 | | | 2,401 | | | 2,677 | | | 2,252 | | Beginning of period | 3,388 | | | 2,846 | | | 3,190 | | | 2,677 | |
| Net income | Net income | 104 | | | 86 | | | 273 | | | 236 | | Net income | 130 | | | 104 | | | 328 | | | 273 | |
| | Dividends on preferred stock | Dividends on preferred stock | (1) | | | — | | | (1) | | | (1) | | Dividends on preferred stock | (1) | | | (1) | | | (1) | | | (1) | |
| | Retained earnings, end of period | Retained earnings, end of period | 2,949 | | | 2,487 | | | 2,949 | | | 2,487 | | Retained earnings, end of period | 3,517 | | | 2,949 | | | 3,517 | | | 2,949 | |
| | | Total Shareholders’ Equity | Total Shareholders’ Equity | $ | 5,912 | | | $ | 5,258 | | | $ | 5,912 | | | $ | 5,258 | | Total Shareholders’ Equity | $ | 6,495 | | | $ | 5,912 | | | $ | 6,495 | | | $ | 5,912 | |
The accompanying notes as they relate to Ameren Illinois are an integral part of these financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated) (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS
(Unaudited)
June 30, 20222023
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren has other subsidiaries that conduct other activities, such as providing shared services.
•Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.
•Ameren Illinois Company, doing business as Ameren Illinois, operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.
•ATXI operates a FERC rate-regulated electric transmission business in the MISO.
The COVID-19 pandemic continues to affect our results of operations, financial position, and liquidity. While our electric sales volumes, excluding the estimated effects of weather and customer energy-efficiency programs, increased in the first six months of 2022, compared to the same period in 2021, they were comparable to pre-pandemic levels at Ameren Missouri and remain below pre-pandemic levels at Ameren Illinois. However, revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission businesses are decoupled from changes in sales volumes. Earnings at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers are exposed to such changes. There has also been a shift in sales volumes by customer class at both Ameren Missouri and Ameren Illinois, which began in 2020, with an increase in residential sales, and a decrease in commercial and industrial sales. The continued effect of the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions.
Ameren’s and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri’s subsidiaries were created for the ownershipacquisition of renewable generation projects. Ameren Illinois has no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The results of operations for an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and accompanying notes included in the Form 10-K.
Variable Interest Entities
As of June 30, 2022,2023, and December 31, 2021,2022, Ameren had unconsolidated variable interests as a limited partner in various equity method investments, primarily to advance clean and resilient energy technologies, totaling $61$72 million and $56$68 million, respectively, included in “Other assets” on Ameren’s consolidated balance sheet. Any earnings or losses related to these investments are included in “Other Income, Net” on Ameren’s consolidated statement of income and comprehensive income. Ameren is not the primary beneficiary of these investments because it does not have the power to direct matters that most significantly affect the activities of these variable interest entities. As of June 30, 2022, the2023, Ameren’s maximum exposure to loss related to these variable interests is limited to theits investment in these partnerships of $61$72 million plus associated outstanding funding commitments of $22$16 million.
Company-owned Life InsuranceCOLI
Ameren and Ameren Illinois have company-owned life insurance,COLI, which is recorded at the net cash surrender value. The net cash surrender value is the amount that can be realized under the insurance policies at the balance sheet date. As of June 30, 2022,2023, the cash surrender value of company-owned life insuranceCOLI at Ameren and Ameren Illinois was $244$255 million (December 31, 20212022 – $278$246 million) and $115$122 million (December 31, 20212022 – $117$118 million), respectively, while total borrowings against the policies were $108$115 million (December 31, 20212022 – $109$110 million) at both Ameren and Ameren Illinois. Ameren and Ameren Illinois have the right to offset the borrowings against the cash surrender value of the policies and, consequently, present the net asset in “Other assets” on their respective balance sheets. The net cash surrender value of Ameren’s company-owned life insuranceCOLI is affected by the investment performance of a separate account in which Ameren holds a beneficial interest.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of updates to significant regulatory proceedings and related legal proceedings. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K for additional information and a summary of our regulatory frameworks. We are unable to predict the ultimate outcome of these matters, the timing of final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.
Missouri
2022June 2023 MoPSC Electric Service Regulatory Rate ReviewOrder
In August 2022, Ameren Missouri filed a request withJune 2023, the MoPSC seeking approvalissued an order in Ameren Missouri’s 2022 electric service regulatory rate review, approving a nonunanimous stipulation and agreement. The order resulted in an increase of $140 million to increase itsAmeren Missouri’s annual revenuesrevenue requirement for electric service by $316 million.retail service. The electric rate increase requestapproved revenue requirement is based on a 10.2% ROE, a capital structure composed of 51.9% common equity, a rate base of $11.6 billion, and a test year ended March 31, 2022, with certain pro-forma adjustments expected through an anticipated true-up dateinfrastructure investments as of December 31, 2022. Ameren Missouri also requested2022, 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 costs that the MoPSC previously authorized in earlier electric rate orders, as well as the use of an electric property tax tracker. It also includes a tracker for the utilization of production and investment tax credits or proceeds from the sale of tax credits allowed under Missouri Senate Bill 745 discussed below.the IRA. For additional information regarding the property tax tracker and the IRA, see Note 2 – Rate and Regulatory Matters and Note 12 – Income Taxes under Part II, Item 8, in the Form 10-K. The electric rate increase request reflectsorder increased the following:
•increased infrastructure investments made under Ameren Missouri’s Smart Energy Plan, including increased costannualized base level of capital and depreciation expense;
•increased net fuel expense due to reduced off system sales, primarily driven by expected reduced operations at the Rush Island Energy Center; and
•extending the retirement date of the Sioux Energy Center from 2028 to 2030, consistent with Ameren Missouri’s 2022 Change to the 2020 IRP, in order to ensure reliability during the transition to clean energy generation.
In connection with the planned accelerated retirement of the Rush Island Energy Center, Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute. As such, Ameren Missouri did not request a change inFAC by approximately $40 million from the depreciation rates related to the Rush Island Energy Center in this electric service regulatory rate review.
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 June 2023 and new rates effective by July 2023. Ameren Missouri cannot predict thebase level of any electric service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be approved, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.
Missouri Senate Bill 745
In June 2022, Missouri Senate Bill 745 was enacted and will become effective on August 28, 2022. The law extended Ameren Missouri’s PISA election through December 2028 and allows for an additional five-year extension through December 2033 if requested by Ameren Missouri and approved by the MoPSC, among other things. The law established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024, and will be based on the revenue requirement established in the immediately precedingMoPSC’s December 2021 electric rate order. The current rate limitation, which is effective through 2023, is a 2.85% caporder 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 the compound annual growth rate in the average overall customer rate per kilowatthour, based on the electricAmeren’s and Ameren Missouri’s consolidated statements of income. The new rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in a July 2018 MoPSC order. The law also established electric and natural gas property tax trackers that allow Ameren Missouri to defer the difference between actual property taxes
incurred and related taxes included in customer rates as a regulatory asset or regulatory liability, with the difference expected to be reflected in rate base in a subsequent rate order.9, 2023.
Solar Generation Facilities
In FebruaryDuring 2022 and 2023, Ameren Missouri, through a subsidiary,and certain subsidiaries of Ameren Missouri, entered into a build-transfer agreementagreements to acquire after construction, a 150-MWand/or construct various solar generation facility, whichfacilities. The following table provides information with respect to each agreement:
| | | | | | | | | | | | | | | | | | | | |
| Boomtown Solar Project(a) | Huck Finn Solar Project(b) | Split Rail Solar Project(c) | Cass County Solar Project(c) | Vandalia Solar Project(c) | Bowling Green Solar Project(c) |
| Agreement type | Build-transfer | Build-transfer | Build-transfer | Development-transfer(d) | Self-build(e) | Self-build(e) |
| Facility size | 150-MW | 200-MW | 300-MW | 150-MW | 50-MW | 50-MW |
| Status of MoPSC CCN | Approved April 2023 | Approved February 2023 | Filed June 2023(f) | Filed June 2023(f) | Filed June 2023(f) | Filed June 2023(f) |
| Status of FERC approval of acquisition | Requested May 2023 | Received March 2023 | Expect to request by mid-2024 | Not applicable | Not applicable | Not applicable |
Earliest completion date(g)(h) | Fourth quarter 2024 | Fourth quarter 2024 | Mid-2026 | Fourth quarter 2024 | Fourth quarter 2025 | First quarter 2026 |
(a)The Boomtown Solar Project is expected to be located in southeastern Illinoissupport Ameren Missouri’s transition to renewable energy generation and if approved by the MoPSC, serve customers under Ameren Missouri’sthe Renewable Solutions Program discussed below. In June 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, a 200-MW solar generation facility, which
(b)The Huck Finn Solar Project represents approximately $0.35 billion of capital expenditures and is expected to be located in central Missouri and support Ameren Missouri’s compliance with the state of Missouri’s requirement of achieving 15% of retail sales from renewable energy sources, of which 2% muststandard. Investments in the project will be derived fromeligible for recovery under the RESRAM.
(c)These solar projects are expected to support Ameren Missouri’s transition to renewable energy sources. The acquisitions are aligned with the 2022 Change to the 2020 IRP, which generation.
(d)Ameren Missouri filed withentered into an agreement to acquire the Cass County Solar Project, which includes project design, land rights, and engineering, supply, and construction agreements for a solar generation facility. Ameren Missouri will construct the facility after obtaining a CCN from the MoPSC and acquiring the project. Acquisition of the project is expected by mid-2024.
(e)Ameren Missouri entered into engineering, supply, and construction agreements to construct these solar projects.
(f)Ameren Missouri expects decisions by the MoPSC in June 2022, and are subject to certain conditions, including the issuancefirst quarter of certificates of convenience and necessity2024.
(g)Expected completion dates may be impacted by the MoPSC, obtaining MISO transmission interconnection agreements, and approval by the FERC. In July 2022, Ameren Missouri filed for certificates of convenience and necessity with the MoPSC for both facilities and expects decisions by March 2023 and April 2023 for the 200-MW facility and the 150-MW facility, respectively. Depending on the timing of regulatory approvals and the impact of potential sourcing issues resulting from a United States Department of Commerce investigation of solar panelspanel components imported from 4four Southeast Asian countries initiated in late March 2022 and the detention of certain solar panelspanel components sourced from China as a result of the Uyghur Forced Labor Prevention Act that was passedbecame effective in December 2021,June 2022.
(h)Expected completion dates are dependent on the projects could be completed as early as the fourth quartertiming of 2024.regulatory approvals, among other things.
Renewable Solutions Program
In July 2022,The April 2023 MoPSC order approving the CCN for the Boomtown Solar Project also approved Ameren Missouri filed a request with the MoPSC seeking approval of itsMissouri’s Renewable Solutions Program and a tariff related to participation in the program. The program wouldwill allow certain commercial, industrial, and governmental customers who enroll in the program to receive up to 100% of their energy from renewable resources. Based on customer contracts, the program would enable Ameren Missouri to supply renewable solar energy generated by the 150-MW facility discussed above to customers that enroll in the program.
MoPSC Staff Review of Planned Rush Island Energy Center Retirement
In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center as a result of the NSR and Clean Air Act Litigation discussed in Note 9 – Commitments and Contingencies. The MoPSC staff’s review includes potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, which is expected to be addressed in the current electric service regulatory rate review, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. In Ameren Missouri’s electric service regulatory rate review discussed above, the MoPSC staff recommended a lower rate base for the Rush Island Energy Center claiming imprudent actions by Ameren Missouri. While the nonunanimous stipulation and agreement approved by the June 2023 MoPSC electric rate order did not specify any rate base disallowance, it did not preclude parties to the agreement from raising issues regarding the prudence of Ameren Missouri’s actions and decisions with regard to the energy center in future proceedings. Ameren Missouri is unable to predict the results of this matter. Results of the review could be used in other MoPSC proceedings, which could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.
December 2021 MoPSC Electric and Natural Gas Rate OrdersMEEIA
In December 2021,March 2023, Ameren Missouri filed a proposed three-year customer energy-efficiency plan with the MoPSC issued ordersunder the MEEIA. As a result of a nonunanimous stipulation and agreement filed with the MoPSC in August 2023 by Ameren Missouri, the MoPSC staff, and the MoOPC to extend Ameren Missouri’s 2021 electric serviceMEEIA 2019 program through 2024, Ameren Missouri expects to revise the proposed three-year plan in 2024. The stipulation and natural gas delivery service regulatory rate reviews.agreement, which is subject to MoPSC approval, includes the establishment of a portfolio of customer energy-efficiency programs for 2024 and performance incentives that would provide Ameren Missouri an opportunity to earn revenues, including $12 million if Ameren Missouri achieves certain energy-efficiency goals in 2024. If approved, Ameren Missouri expects to invest $76 million in energy-efficiency programs in 2024. The new electric and natural gas rates approved by these orders went into effect on February 28, 2022.MoPSC is under no deadline to issue an order in this proceeding.
Illinois
MYRP ROE Performance Metrics
UnderIn January 2023, Ameren Illinois filed an MYRP with the ICC, which was subsequently revised in July 2023, to be used in setting electric distribution service rates for 2024 through 2027. Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of the four-year period. In July 2023, the ICC staff submitted its recommendation for electric distribution service rates for 2024 through 2027 under the MYRP. The following table includes the forecasted revenue requirement, the requested and recommended ROE, the requested and recommended capital structure common equity percentage, and the forecasted average annual rate base for 2024 through 2027, as reflected in Ameren Illinois’ revised MYRP filing and the ICC staff’s filing:
| | | | | | | | | | | | | | |
| Year | Forecasted Revenue Requirement (in millions)(a) | Requested/Recommended ROE(b)(c) | Requested/Recommended Capital Structure Common Equity Percentage(b)(d) | Forecasted Average Annual Rate Base (in billions) |
| Ameren Illinois’ July 2023 Filing: | | | | |
| 2024 | $1,291 | 10.5% | 53.99% | $4.3 |
| 2025 | $1,387 | 10.5% | 53.97% | $4.6 |
| 2026 | $1,484 | 10.5% | 54.02% | $4.9 |
| 2027 | $1,560 | 10.5% | 54.03% | $5.2 |
| ICC Staff’s July 2023 Filing: | | | | |
| 2024 | $1,211 | 8.9% | 50.00% | $4.1 |
| 2025 | $1,292 | 8.9% | 50.00% | $4.4 |
| 2026 | $1,371 | 8.9% | 50.00% | $4.6 |
| 2027 | $1,429 | 8.9% | 50.00% | $4.8 |
(a)If an initial rate increase phase-in provision, discussed below, is approved by the ICC, it would be subject tonot affect the annual adjustments duringrevenue requirement, but would affect the four-year periodtiming of associated recovery from customers.
(b)ROE and capital structure common equity percentage requested in Ameren Illinois’ July 2023 filing and recommended in the ICC staff’s July 2023 filing.
(c)The ICC staff filing recommended an ROE based on certain performance metrics, with aggregate symmetrical performance-based ROE incentives and penalties ranging from 20 to 60the annual average of the monthly yields of the 30-year United States Treasury bonds plus 580 basis points, annually. In January 2022, Ameren Illinois filed a request withto be updated annually for each applicable calendar year of the ICC proposing performance metrics that would beMYRP. An estimated ROE of 8.9% was used to calculate the forecasted revenue requirements in determining ROE incentives and penalties. In April 2022, Ameren Illinois filed a revised request proposing total ROE incentives and penalties of 24 basis points, allocated evenly among 8 proposed performance metrics. In May 2022, the ICC staff recommended thatfiling, which is based on the ICC allow ROE incentives and penaltiesaverage monthly yields of no less than 20 basis points and no more than 24 basis points, allocated evenly across the number of performance metrics ultimately approved by the ICC.30-year United States Treasury bonds for 2022. The ICC staff proposed that variances in the revenue requirement resulting from a change in the ROE would be excluded from the reconciliation cap discussed below.
(d)A capital structure of up to and including 50% common equity is required to issue an order on this matterdeemed prudent and reasonable by September 30, 2022.
Electric Distribution Service Rates Under IEIMA
In April 2022, Ameren Illinois filed its annual electric distribution service performance-based formula rate update with thelaw. A higher equity ratio requires specific ICC to be used for 2023 rates. In July 2022, Ameren Illinois filed a revised request seeking to increase its annual revenues for electric distribution service by $84 million. The updated request reflects an increase to the annual performance-based formula rate based on 2021 actual recoverable costsapproval.
and expected net plant additions for 2022,Under an MYRP, the IETL permits any initial rate increase to include the 2021 revenue requirement reconciliation adjustment including a capital structure composed of 54% common equity, and a decrease for the conclusionbe phased in, with at least 50% of the 2020 revenue requirement reconciliation adjustment, which willfirst annual period’s approved rate increase reflected in rates in the first annual period, with the remaining portion deferred as a regulatory asset that earns a return at the applicable WACC and is collected from customers over a period not to exceed two years beginning within one year after the second annual period’s rates are effective. Ameren Illinois’ revised MYRP filing utilizes this phase-in provision and proposes to defer 50% of the requested 2024 rate increase of $179 million as a regulatory asset to be fully collected from customers in 2026. Ameren Illinois recognizes revenues that have been authorized for rate recovery when amounts are expected to be collected from customers within two years from the end of an applicable year. The ICC staff’s filing does not utilize a phase-in provision. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024. Ameren Illinois cannot predict the level of any electric distribution service rate change the ICC may approve, or whether any rate change that may eventually be approved will be sufficient for Ameren Illinois to recover its costs to the extent those costs are subject to and exceed the reconciliation cap discussed below and earn a reasonable return on its investments when the rate change goes into effect.
The MYRP also allows Ameren Illinois to reconcile its actual revenue requirement, as adjusted for certain cost variations, to ICC-approved electric distribution service rates on an annual basis, subject to a reconciliation cap. The reconciliation cap limits the annual adjustment to 105% of the annual revenue requirement approved by the ICC. Certain variations from forecasted costs would be excluded from the reconciliation cap, including those associated with major storms; new business and facility relocations; changes in the timing of certain expenditures or investments into or out of the applicable calendar year; and changes in interest rates, income taxes, taxes other than income taxes, pension and other post-retirement benefits costs, and amortization of certain assets. The reconciliation cap also excludes costs recovered through riders outside of base rates, such as riders for electric energy-efficiency investments, power procurement and transmission services, renewable energy credit compliance, zero emission credits, certain environmental costs, and bad debt write-offs, among others. Ameren Illinois’ existing riders will remain effective and electric distribution service revenues will continue to be decoupled from sales volumes under the MYRP. The actual revenue requirement for a particular year would incorporate Ameren Illinois’ year-end rate base and actual capital structure for such year, provided that the common equity ratio in such capital structure may not exceed that approved by the ICC in the MYRP. Excluding the phase-in of the initial rate increase discussed above, and subject to the reconciliation cap, if a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment would be made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance would then be collected from, or refunded to, customers within two years from the end of the applicable annual period.
Under the MYRP, the ROE approved by the ICC will be subject to annual adjustments based on performance metrics. In 2022, consistentthe ICC issued an order approving total ROE incentives and penalties of 24 basis points, allocated among seven performance metrics. These performance metrics include improvements in service reliability in both the frequency and duration of outages, a reduction in peak loads, an increased percentage of spend with diverse suppliers, a reduction in disconnections for certain customers, and improved timeliness in response to customer requests for interconnection of distributed energy resources. These performance metrics will apply annually from 2024 through 2027 under the MYRP, and the impact of any incentives and penalties will be excluded from the reconciliation cap described above.
2022 Electric Distribution Revenue Requirement Reconciliation Adjustment Request
In April 2023, Ameren Illinois filed for a reconciliation adjustment to its 2022 electric distribution service revenue requirement with the ICC’s December 2021 annual update filing order.ICC. In July 2023, Ameren Illinois filed a revised reconciliation adjustment, requesting recovery of $125 million. The reconciliation adjustment reflects Ameren Illinois’ actual 2022 recoverable costs, year-end rate base, and capital structure, which was composed of 53.99% common equity. In June 2022,2023, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing,reconciliation adjustment, recommending a $60recovery of $109 million, increase in Ameren Illinois’ electric distribution service rates, which is based on a capital structure composed of 50% common equity. An ICC decision in this proceeding is required by December 2022, with new rates effective2023, and any approved adjustment would be collected from customers in January 2023.2024.
Electric Customer Energy-Efficiency Investments
In June 2022,May 2023, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to increase its rates by $17$27 million with the ICC. An ICC decision in this proceeding is required by December 2022,2023, with new rates effective January 2023.2024.
2023 Natural Gas Delivery Service Regulatory Rate Review
In June 2022,January 2023, Ameren Illinois filed a request with the ICC issuedseeking approval to increase its annual revenues for natural gas delivery service. In July 2023, Ameren Illinois filed a revised request seeking to increase its annual revenues by $148 million, which includes an order approving Ameren Illinois’ revised energy-efficiency plan that includes annual investments in electric energy-efficiency programs of approximately $120estimated $77 million per year through 2025, which reflects the increased level of annual investments allowedrevenues that would otherwise be recovered under the IETL.QIP and other riders. The ICC has the abilityrequest is based on a 10.3% allowed ROE, a capital structure composed of 53.99% common equity, and a rate base of $2.9 billion. In an attempt to reduce regulatory lag, Ameren Illinois used a 2024 future test year in this proceeding. In July 2023, the amountICC staff recommended an increase to annual revenues for natural gas delivery service of electric energy-efficiency savings goals$128 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the QIP and other riders. The recommendation is based on a 9.89% ROE, a capital structure composed of 50% common equity, and a rate base of $2.9 billion. Other intervenors recommended an increase to annual revenues ranging from
$98 million to $106 million, which were based on varying rate base amounts, a 9.5% ROE, and a capital structure composed of 52% common equity. A decision by the ICC in future plan program years if there are insufficient cost-effective programs available, which could reduce the investmentsthis proceeding is required by late November 2023, with new rates expected to be effective in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not recovered through the electric distribution service performance-based formula ratemaking framework.
early December 2023. Ameren Illinois Senate Bill 3866
In May 2022, Illinois Senate Bill 3866 was enacted and became effective. This legislation makes certain amendments to the IETL, including amendments to increasecannot predict the level of funding forany delivery service rate change the Energy Transition Assistance Fund. As a result of this legislation,ICC may approve, nor whether any rate change that may eventually be approved will be sufficient to enable Ameren Illinois expects to collect uprecover its costs and to $50 million annually related to this fund, beginning in January 2023. Funds collected by Ameren Illinois will be remitted inearn a reasonable return on investments when the month following collection to an Illinois state agency, with no impact to results of operations.rate changes go into effect.
RTO Cost BenefitCost-Benefit Study
In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from MISO’s April 2022 capacity auction, the ICC issued an order requiring Ameren Illinois to perform a cost benefitcost-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 benefitcost-benefit study will examineexamined 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 ICC order requires Ameren Illinois to filestudy concluded that continued participation in the MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. Comments on the study are due by Julylate August 2023. A 30-day comment period will follow. The ICC is under no obligation to issue an order in this matter.
QIP Reconciliation Hearing
In March 2020, Ameren Illinois filed its annual request with the ICC for a reconciliation hearing to determine the accuracy and prudence of natural gas capital investments recovered under the QIP rider during 2019. In August 2021, the Illinois Attorney General’s office challenged the recovery of capital investments that were made during 2019, alleging that the ICC should disallow approximately $70 million in natural gas capital investments as improper and imprudent, providing a potential over-recovery of approximately $3 million in 2019. In August and December 2021, the ICC staff filed testimony that supports the prudence and reasonableness of the capital investments made during 2019. Ameren Illinois’ 2019 QIP rate recovery request under review by the ICC is within the rate increase limitations allowed by law. The ICC is under no deadline to issue an order in this proceeding.
Federal
Transmission Formula Rate Revisions
In February 2020, the MISO, on behalf of Ameren Missouri, Ameren Illinois, and ATXI, filed requests with the FERC to revise each company’s transmission formula rate calculations with respect to the calculation used for materials and supplies inventories included in rate base. In May 2020, the FERC issued orders approving the revisions prospectively. In addition, the FERC declined to order refunds for earlier periods, as requested by intervenors in Ameren Illinois’ filing, but directed its audit staff to review historical rate recovery in connection with an ongoing FERC audit. Separately, in March 2021, the FERC issued an order related to an intervenor challenge to Ameren Illinois’ 2020 transmission formula rate update. As a result of this order, in March 2021, Ameren Illinois recorded a regulatory liability of $9 million, largely as a reduction of electric operating revenues, to reflect expected refunds, including interest, primarily related to the historical rate recovery of materials and supplies inventories included in rate base. The refund amount was reflected in rates as of January 2022 and will be refunded to customers by the end of 2022. Ameren Missouri, Ameren Illinois, and ATXI filed appeals of the FERC’s May 2020 and March 2021 orders, and related FERC orders denying requests for rehearing, to the United States Court of Appeals for the District of Columbia Circuit. In January 2022, the appeals were consolidated by the court. The court is under no deadline to address the appeal. Regardless of the outcome of thecost-benefit study.
appeal, the impact of the May 2020 and March 2021 orders is not expected to be material to Ameren’s, Ameren Missouri’s, or Ameren Illinois’ results of operations, financial position, or liquidity.Federal
FERC Complaint Cases
Since November 2013, the allowed base ROE for FERC-regulated transmission rate base under the MISO tariff has been subject to customer complaint cases and has been changed by various FERC orders. In May 2020, the FERC issued an order, which set the allowed base ROE to 10.02%, and required refunds, with interest, for the periods November 2013 to February 2015 and from late September 2016 forward. Ameren and Ameren Illinois paid these refunds, including interest, by March 31, 2022. In June 2020, various parties filed requests for rehearing with the FERC, challenging the new ROE methodology established by the May 2020 order. In July 2020, the FERC denied the rehearing requests without addressing the issues raised, and indicated it will address the requests for rehearing in a future order. Also in July 2020, Ameren Missouri, Ameren Illinois, and ATXI, filed an appeal of the May 2020 order toas well as various customers, petitioned the United States Court of Appeals for the District of Columbia Circuit for review of the May 2020 order, challenging certain aspects of the new ROE methodology established. The petition filed by Ameren Missouri, Ameren Illinois, and ATXI challenged the refunds required for the period from September 2016 to May 2020. In August 2022, the court issued a ruling that granted the customers’ petition for review, vacated the FERC’s previous MISO ROE-determining orders, and remanded the proceedings to the FERC. The court elected not to rule on the issues raised by Ameren Missouri, Ameren Illinois, and ATXI. The currently allowed base ROE of 10.02% will remain effective for customer billings, but is subject to refund if the base ROE is changed by the FERC in a future order. The FERC is under no deadline to addressissue an order related to these proceedings. A 50-basis-point change in the appeal.
AmerenFERC-allowed ROE would affect Ameren’s and Ameren Illinois have paid the refunds, including interest, associated with the allowed base ROE setIllinois’ annual revenue by the May 2020 order.an estimated $19 million and $13 million, respectively, based on each company’s 2023 projected rate base.
NOTE 3 – SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under committed credit agreements, commercial paper issuances, and, 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, in the Form 10-K for a description of our indebtedness provisions and other covenants as well as a description of money pool arrangements.
Short-term Borrowings
The Missouri Credit Agreement and the Illinois Credit Agreement are available to support issuances under Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper programs, respectively, subject to borrowing sublimits, and the issuance of letters of credit. As of June 30, 2022,2023, based on commercial paper outstanding and letters of credit issued under the Credit Agreements, along with cash and cash equivalents, the net liquidity available to Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, was $1.3 billion. The Ameren Companies were in compliance with the covenants in their Credit Agreements as of June 30, 2022.2023. As of June 30, 2022,2023, the ratios of consolidated indebtedness to consolidated total capitalization, calculated in accordance with the provisions of the Credit Agreements, were 59%60%, 51%, and 44%45% for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
The following table presents commercial paper outstanding, net of issuance discounts, as of June 30, 2022,2023, and December 31, 2021.2022. There were no borrowings outstanding under the Credit Agreements as of June 30, 2022,2023, or December 31, 2021.2022.
| | | June 30, 2022 | | December 31, 2021 | | June 30, 2023 | | December 31, 2022 |
| Ameren (parent) | Ameren (parent) | $ | 595 | | | $ | 277 | | Ameren (parent) | $ | 839 | | | $ | 477 | |
| Ameren Missouri | Ameren Missouri | 285 | | | 165 | | Ameren Missouri | 373 | | | 329 | |
| Ameren Illinois | Ameren Illinois | 141 | | | 103 | | Ameren Illinois | 117 | | | 264 | |
| Ameren consolidated | Ameren consolidated | $ | 1,021 | | | $ | 545 | | Ameren consolidated | $ | 1,329 | | | $ | 1,070 | |
The following table summarizes the activity and relevant interest rates for Ameren (parent)’s, Ameren Missouri’s, and Ameren Illinois’ commercial paper issuances and borrowings under the Credit Agreements in the aggregate for the six months ended June 30, 20222023 and 2021:2022:
| | | Ameren
(parent) | | Ameren
Missouri | | Ameren
Illinois | | Ameren
Consolidated | | | Ameren
(parent) | | Ameren
Missouri | | Ameren
Illinois | | Ameren
Consolidated | |
| 2023 | | 2023 | |
| Average daily amount outstanding | | Average daily amount outstanding | | $ | 595 | | | $ | 343 | | | $ | 230 | | | $ | 1,168 | | |
| | Weighted-average interest rate | | Weighted-average interest rate | | 5.14 | % | | 5.04 | % | | 5.10 | % | | 5.10 | % | |
Peak amount outstanding during period(a) | | Peak amount outstanding during period(a) | | $ | 841 | | | $ | 592 | | | $ | 450 | | | $ | 1,381 | | |
| Peak interest rate | | Peak interest rate | | 5.55 | % | | 5.55 | % | | 5.60 | % | | 5.60 | % | |
| 2022 | 2022 | | 2022 | |
| Average daily amount outstanding | Average daily amount outstanding | | $ | 374 | | | $ | 271 | | | $ | 57 | | | $ | 702 | | | Average daily amount outstanding | | $ | 374 | | | $ | 271 | | | $ | 57 | | | $ | 702 | | |
| | Weighted-average interest rate | Weighted-average interest rate | | 0.87 | % | | 0.65 | % | | 0.47 | % | | 0.75 | % | | Weighted-average interest rate | | 0.87 | % | | 0.65 | % | | 0.47 | % | | 0.75 | % | |
Peak amount outstanding during period(a) | Peak amount outstanding during period(a) | | $ | 595 | | | $ | 539 | | | $ | 142 | | | $ | 1,101 | | | Peak amount outstanding during period(a) | | $ | 595 | | | $ | 539 | | | $ | 142 | | | $ | 1,101 | | |
| Peak interest rate | Peak interest rate | | 2.05 | % | | 2.05 | % | | 2.05 | % | | 2.05 | % | | Peak interest rate | | 2.05 | % | | 2.05 | % | | 2.05 | % | | 2.05 | % | |
| 2021 | | |
| Average daily amount outstanding | | $ | 388 | | | $ | 183 | | | $ | 211 | | | $ | 782 | | | |
| | Weighted-average interest rate | | 0.24 | % | | 0.22 | % | | 0.22 | % | | 0.23 | % | | |
Peak amount outstanding during period(a) | | $ | 650 | | | $ | 546 | | | $ | 485 | | | $ | 1,134 | | | |
| Peak interest rate | | 0.33 | % | | 0.25 | % | | 0.25 | % | | 0.33 | % | | |
(a)The timing of peak outstanding commercial paper issuances and borrowings under the Credit Agreements varies by company. Therefore, the sum of individual company peak amounts may not equal the Ameren consolidated peak for the period.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. The average interest rate for borrowings under the utility money pool for the three and six months ended June 30, 2022,2023, was 5.28% and 5.04%, respectively (2022 – 0.98% and 0.69%, respectively (2021 – 0.22% and 0.22%, respectively). See Note 8 – Related-party Transactions for the amount of interest income and expense from the utility money pool arrangements recorded by Ameren Missouri and Ameren Illinois for the three and six months ended June 30, 20222023 and 2021.2022.
NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS
Ameren
For the three and six months ended June 30, 2022,2023, Ameren issued a total of 0.20.1 million and 0.30.2 million shares of common stock, respectively, under its DRPlus and 401(k) plan, and received proceeds of $4 million and $17$16 million, respectively, andrespectively. As of June 30, 2023, Ameren had a receivable of $8$7 million as of June 30, 2022.related to its DRPlus and 401(k) plan. In addition, in the first quarter of 2022,2023, Ameren issued 0.40.5 million shares of common stock valued at $31$37 million upon the settlement of stock-based compensation awards.
In May 2021, Ameren entered into an equity distribution sales agreement pursuant to which Ameren may offer and sell from time to time up to $750 million of its common stock through an ATM program, which includes the ability to enter into forward sales agreements. There were no shares issued under the ATM program for the three and six months ended June 30, 2022.2023. As of June 30, 2022,2023, Ameren had approximately $90$910 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of June 30, 2022,2023, discussed below.
Ameren has entered into multiple forward sale agreements, including the July 2022 forward sale agreement discussed below, under the ATM program with various counterparties relating to 5.8 million shares of common stock. Ameren expects to settle approximately $300 million of the forward sale agreements by December 31, 2022.
Related to theThe forward sale agreements outstanding as of June 30, 2022, these agreements2023, can be settled at Ameren’s discretion on or prior to dates ranging from May 3, 2023January 10, 2024 to February 22, 2024.28, 2025. On a settlement date or dates, if Ameren elects to physically settle thea forward sale agreement, Ameren will issue shares of common stock to the counterparties at the then-applicable forward sale price. The initial forward sale price for the agreements ranged from $86.35$81.83 to $94.80$94.63, with an average initial forward sale price of $89.78.$91.23. Each initial forward sale price is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the forward sale agreements by specified amounts related to expected dividends on shares of the common stock during the term of the forward sale agreements. If the overnight bank funding rate is less than the spread on any day, the interest rate factor will result in a reduction of the forward sale price. The forward sale agreements will be physically settled unless Ameren elects to settle in cash or to net share settle. At June 30, 2022,2023, Ameren could have settled the forward sale agreements with physical delivery of 5.64.3 million shares of common stock to the respective counterparties in exchange for cash of $500$389 million. Alternatively, the forward sale agreements could have also been settled at June 30, 2022,2023, with delivery ofthe counterparties delivering approximately $8$41 million of cash or approximately 0.10.5 million shares of common stock to the counterparties.Ameren. In connection towith the forward sale agreements outstanding at June 30, 2023, the various counterparties, or their affiliates, borrowed from third parties and sold 5.64.3 million shares of common stock. The gross sales price of these shares totaled $510$392 million. In connection with such sales in the three months ended June 30, 2023, the counterparties were deemed to have received commissions of $5less than $1 million. Ameren has not received any proceeds from such sales of borrowed shares. The forward sale agreements have been classified as equity transactions.
In July 2022, Ameren entered into a forward sale agreement under the ATM program relating to 0.2 million shares of common stock. The July 2022 forward sale agreement can be settled at Ameren’s discretion on or prior to March 8, 2024. The initial forward sale price was $90.77 for the July 2022 forward sale agreement.
Ameren Missouri
In April 2022, Ameren Missouri issued $525 million of 3.90% first mortgage bonds due April 2052, with interest payable semiannually on April 1 and October 1 of each year, beginning October 1, 2022. Ameren Missouri received net proceeds of $519 million, which were used to repay short-term debt and for near-term capital expenditures. Ameren Missouri intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligibility criteria.
ATXI
In November 2021, pursuant to a note purchase agreement, ATXI agreed to issue $95 million of its 2.96% senior unsecured notes due 2052, with interest payable semiannually on February 25 and August 25 of each year, beginning February 25, 2023, through a private placement offering exempt from registration under the Securities Act of 1933, as amended. ATXI expects to issue the notes and receive net proceeds of $95 million in August 2022, which will be used to refinance the remaining portion of an intercompany long-term note with Ameren
(parent), repayAmeren Missouri
In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a $50financing 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 paymentamount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri. Ownership of the energy center was transferred to Ameren Missouri in January 2023, at which time the property, plant, and equipment became subject to the lien of the Ameren Missouri mortgage bond indenture.
In March 2023, Ameren Missouri issued $500 million of 5.45% first mortgage bonds due March 2053, with interest payable semiannually on March 15 and September 15 of each year, beginning September 15, 2023. Ameren Missouri received net proceeds of $495 million, which were used for capital expenditures and to repay short-term debt.
Ameren Illinois
In May 2023, Ameren Illinois issued $500 million of 4.95% first mortgage bonds due June 2033, with interest payable semiannually on June 1 and December 1 of each year, beginning December 1, 2023. Ameren Illinois received net proceeds of $495 million, which were used to repay $100 million principal amount of its 3.43% senior unsecured notes,0.375% first mortgage bonds that matured in June 2023 and to repay short-term debt.
Indenture Provisions and Other Covenants
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, in the Form 10-K for a description of our indenture provisions and other covenants, as well as restrictions on the payment of dividends. At June 30, 2022,2023, the Ameren Companies were in compliance with the provisions and covenants contained in their indentures and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements.
Off-balance-sheet Arrangements
At June 30, 2022,2023, none of the Ameren Companies had any significantmaterial off-balance-sheet financing arrangements, other than Ameren’s investment in variable interest entities and the multiple forward sale agreements under the ATM program relating to common stock. See Note 1 – Summary of Significant Accounting Policies for further detail concerning variable interest entities.
NOTE 5 – OTHER INCOME, NET
The following table presents the components of “Other Income, Net” in the Ameren Companies’ statements of income for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months | | Six Months | | | Three Months | | Six Months | |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 | | 2023 | | 2022 | |
| Ameren: | Ameren: | | Ameren: | |
| | Allowance for equity funds used during construction | Allowance for equity funds used during construction | $ | 11 | | | $ | 9 | | | $ | 19 | | | $ | 16 | | | Allowance for equity funds used during construction | $ | 14 | | | $ | 11 | | | $ | 23 | | | $ | 19 | | |
| Interest income on industrial development revenue bonds | Interest income on industrial development revenue bonds | 6 | | | 6 | | | 12 | | | 12 | | | Interest income on industrial development revenue bonds | — | | | 6 | | | 1 | | | 12 | | |
| Non-service cost components of net periodic benefit income(a) | Non-service cost components of net periodic benefit income(a) | 47 | | | 34 | | | 93 | | | 68 | | | Non-service cost components of net periodic benefit income(a) | 63 | | | 47 | | | 127 | | | 93 | | |
| Miscellaneous income | Miscellaneous income | 6 | | | 7 | | | 13 | | | 12 | | | Miscellaneous income | 11 | | | 5 | | | 20 | | | 9 | | |
| Earnings related to equity method investments | | Earnings related to equity method investments | — | | | 1 | | | 2 | | | 4 | | |
| Donations | Donations | (2) | | | (1) | | | (4) | | | (4) | | | Donations | (2) | | | (2) | | | (4) | | | (4) | | |
| Miscellaneous expense | Miscellaneous expense | (6) | | | (6) | | | (11) | | | (9) | | | Miscellaneous expense | (4) | | | (6) | | | (9) | | | (11) | | |
| Total Other Income, Net | Total Other Income, Net | $ | 62 | | | $ | 49 | | | $ | 122 | | | $ | 95 | | | Total Other Income, Net | $ | 82 | | | $ | 62 | | | $ | 160 | | | $ | 122 | | |
| Ameren Missouri: | Ameren Missouri: | | Ameren Missouri: | |
| | Allowance for equity funds used during construction | Allowance for equity funds used during construction | $ | 6 | | | $ | 6 | | | $ | 10 | | | $ | 10 | | | Allowance for equity funds used during construction | $ | 8 | | | $ | 6 | | | $ | 12 | | | $ | 10 | | |
| Interest income on industrial development revenue bonds | Interest income on industrial development revenue bonds | 6 | | | 6 | | | 12 | | | 12 | | | Interest income on industrial development revenue bonds | — | | | 6 | | | 1 | | | 12 | | |
| Non-service cost components of net periodic benefit income(a) | Non-service cost components of net periodic benefit income(a) | 14 | | | 14 | | | 28 | | | 28 | | | Non-service cost components of net periodic benefit income(a) | 14 | | | 14 | | | 28 | | | 28 | | |
| Miscellaneous income | Miscellaneous income | 1 | | | — | | | 3 | | | 1 | | | Miscellaneous income | 3 | | | 1 | | | 7 | | | 3 | | |
| Donations | Donations | (1) | | | (1) | | | (2) | | | (1) | | | Donations | (1) | | | (1) | | | (2) | | | (2) | | |
| Miscellaneous expense | Miscellaneous expense | (2) | | | (1) | | | (4) | | | (3) | | | Miscellaneous expense | (2) | | | (2) | | | (5) | | | (4) | | |
| Total Other Income, Net | Total Other Income, Net | $ | 24 | | | $ | 24 | | | $ | 47 | | | $ | 47 | | | Total Other Income, Net | $ | 22 | | | $ | 24 | | | $ | 41 | | | $ | 47 | | |
| Ameren Illinois: | Ameren Illinois: | | Ameren Illinois: | |
| | Allowance for equity funds used during construction | Allowance for equity funds used during construction | $ | 5 | | | $ | 3 | | | $ | 9 | | | $ | 6 | | | Allowance for equity funds used during construction | $ | 6 | | | $ | 5 | | | $ | 10 | | | $ | 9 | | |
| | Non-service cost components of net periodic benefit income | Non-service cost components of net periodic benefit income | 21 | | | 14 | | | 42 | | | 28 | | | Non-service cost components of net periodic benefit income | 31 | | | 21 | | | 62 | | | 42 | | |
| Miscellaneous income | Miscellaneous income | 3 | | | 3 | | | 5 | | | 4 | | | Miscellaneous income | 7 | | | 3 | | | 12 | | | 5 | | |
| Donations | Donations | (1) | | | — | | | (2) | | | (3) | | | Donations | (1) | | | (1) | | | (2) | | | (2) | | |
| Miscellaneous expense | Miscellaneous expense | (3) | | | (4) | | | (5) | | | (5) | | | Miscellaneous expense | (2) | | | (3) | | | (4) | | | (5) | | |
| Total Other Income, Net | Total Other Income, Net | $ | 25 | | | $ | 16 | | | $ | 49 | | | $ | 30 | | | Total Other Income, Net | $ | 41 | | | $ | 25 | | | $ | 78 | | | $ | 49 | | |
(a)For the three and six months ended June 30, 2022,2023 the non-service cost components of net periodic benefit income were adjusted by amounts deferred of $5$17 million and $11$34 million, respectively, due to a regulatory tracking mechanism for the difference between the level of such costs incurred by Ameren Missouri under GAAP and the level of such costs included in rates. The deferral was $(3)$5 million and $11 million, respectively, for both the three and six months ended June 30, 2021.2022. See Note 11–11 – Retirement Benefits for additional information.
NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives to manage the risk of changes in market prices for natural gas, power, and uranium, as well as the risk of changes in rail transportation surcharges through fuel oil hedges. Such price fluctuations may cause the following:
•an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory;
•actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays; and
•actual off-system sales revenues that differ from anticipated revenues.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
All contracts considered to be derivative instruments are required to be recorded on the balance sheet at their fair values, unless the NPNS exception applies. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery. The following disclosures exclude NPNS contracts and other non-derivative commodity contracts that are accounted for under the accrual method of accounting.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine whether the resulting gains or losses qualify for regulatory deferral. Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or liabilities in the period in which the change occurs. We believe derivative losses and gains deferred as regulatory assets and liabilities are probable of recovery, or refund, through future rates charged to customers. Regulatory assets and liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income. As of June 30, 2022,2023, and December 31, 2021,2022, all contracts that met the definition of a derivative and were not eligible for the NPNS exception received regulatory deferral. Cash flows for all derivative financial instruments are classified in cash flows from operating activities.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of June 30, 2022,2023, and December 31, 2021.2022. As of June 30, 2022,2023, these contracts extended through October 2024,2026, October 2027,2029, May 2032 and March 2024 for fuel oils, natural gas, power and uranium, respectively:respectively.
| | | Quantity (in millions) | | Quantity (in millions) |
| | June 30, 2022 | December 31, 2021 | | June 30, 2023 | December 31, 2022 |
| Commodity | Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
| Fuel oils (in gallons) | Fuel oils (in gallons) | 21 | | — | | 21 | | 30 | | — | | 30 | | Fuel oils (in gallons) | 18 | | — | | 18 | | 18 | | — | | 18 | |
| Natural gas (in mmbtu) | Natural gas (in mmbtu) | 44 | | 152 | | 196 | | 35 | | 144 | | 179 | | Natural gas (in mmbtu) | 57 | | 218 | | 275 | | 48 | | 157 | | 205 | |
| Power (in MWhs) | Power (in MWhs) | 3 | | 6 | | 9 | | 6 | | 6 | | 12 | | Power (in MWhs) | 1 | | 5 | | 6 | | 1 | | 6 | | 7 | |
| Uranium (pounds in thousands) | Uranium (pounds in thousands) | 496 | | — | | 496 | | 586 | | — | | 586 | | Uranium (pounds in thousands) | 186 | | — | | 186 | | 514 | | — | | 514 | |
The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of June 30, 2022,2023, and December 31, 2021:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2022 | December 31, 2021 |
| Balance Sheet Location | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren | | | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Fuel oils | Mark-to-market derivative assets | $ | 22 | | | $ | — | | | $ | 22 | | | | $ | 8 | | | $ | — | | | $ | 8 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Other assets | | 8 | | | | — | | | | 8 | | | | | 5 | | | | — | | | | 5 | |
| Natural gas | Mark-to-market derivative assets | | 14 | | | | 59 | | | | 73 | | | | | 7 | | | | 28 | | | | 35 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Other assets | | 14 | | | | 27 | | | | 41 | | | | | 5 | | | | 13 | | | | 18 | |
| Power | Mark-to-market derivative assets | | 50 | | | | 9 | | | | 59 | | | | | 23 | | | | — | | | | 23 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Other assets | | — | | | | 1 | | | | 1 | | | | | — | | | | — | | | | — | |
| Uranium | Mark-to-market derivative assets | | 3 | | | | — | | | | 3 | | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Other assets | | 1 | | | | — | | | | 1 | | | | | 1 | | | | — | | | | 1 | |
| Total assets | $ | 112 | | | $ | 96 | | | $ | 208 | | | | $ | 49 | | | $ | 41 | | | $ | 90 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Natural gas | Mark-to-market derivative liabilities | | 4 | | | | (a) | | | (a) | | | | 2 | | | | (a) | | | (a) |
| | | | | | | | | | | | | | | | | | | |
| Other current liabilities | | — | | | | 7 | | | | 11 | | | | | — | | | | 6 | | | | 8 | |
| Other deferred credits and liabilities | | 2 | | | | 4 | | | | 6 | | | | | 1 | | | | 2 | | | | 3 | |
| Power | Mark-to-market derivative liabilities | | 141 | | | | (a) | | | (a) | | | | 50 | | | | (a) | | | (a) |
| | | | | | | | | | | | | | | | | | | |
| Other current liabilities | | — | | | | 1 | | | | 142 | | | | | — | | | | 9 | | | | 59 | |
| Other deferred credits and liabilities | | 24 | | | | 53 | | | | 77 | | | | | 23 | | | | 108 | | | | 131 | |
| Uranium | Mark-to-market derivative liabilities | | — | | | | (a) | | | (a) | | | | 1 | | | | (a) | | | (a) |
| | | | | | | | | | | | | | | | | | | |
| Other current liabilities | | — | | | | — | | | | — | | | | | — | | | | — | | | | 1 | |
| | | | | | | | | | | | | | | | | | | |
| Total liabilities | $ | 171 | | | $ | 65 | | | $ | 236 | | | | $ | 77 | | | $ | 125 | | | $ | 202 | |
(a)Balance sheet line item not applicable to registrant.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2023 | December 31, 2022 |
| Balance Sheet Location | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren | | | | Ameren
Missouri | | | Ameren
Illinois | | | Ameren |
| | | | | | | | | | | | | | | | | | |
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| Fuel oils | Other current assets | | $ | 5 | | | | $ | — | | | | $ | 5 | | | | | $ | 13 | | | | $ | — | | | | $ | 13 | |
| Other assets | | 1 | | | | — | | | | 1 | | | | | 3 | | | | — | | | | 3 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Natural gas | Other current assets | | 2 | | | | 8 | | | | 10 | | | | | 7 | | | | 23 | | | | 30 | |
| Other assets | | 5 | | | | 5 | | | | 10 | | | | | 9 | | | | 11 | | | | 20 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Power | Other current assets | | 15 | | | | — | | | | 15 | | | | | 14 | | | | 2 | | | | 16 | |
| Other assets | | — | | | | — | | | | — | | | | | — | | | | 4 | | | | 4 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Uranium | Other current assets | | 2 | | | | — | | | | 2 | | | | | 2 | | | | — | | | | 2 | |
| Other assets | | — | | | | — | | | | — | | | | | 1 | | | | — | | | | 1 | |
| Total assets | | $ | 30 | | | | $ | 13 | | | | $ | 43 | | | | | $ | 49 | | | | $ | 40 | | | | $ | 89 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Fuel oils | Other current liabilities | | $ | 1 | | | | $ | — | | | | $ | 1 | | | | | $ | — | | | | $ | — | | | | $ | — | |
| Other deferred credits and liabilities | | 1 | | | | — | | | | 1 | | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Natural gas | Other current liabilities | | 8 | | | | 27 | | | | 35 | | | | | 7 | | | | 20 | | | | 27 | |
| Other deferred credits and liabilities | | 8 | | | | 19 | | | | 27 | | | | | 2 | | | | 9 | | | | 11 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Power | Other current liabilities | | 13 | | | | 10 | | | | 23 | | | | | 59 | | | | 2 | | | | 61 | |
| Other deferred credits and liabilities | | — | | | | 58 | | | | 58 | | | | | — | | | | 37 | | | | 37 | |
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| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Total liabilities | | $ | 31 | | | | $ | 114 | | | | $ | 145 | | | | | $ | 68 | | | | $ | 68 | | | | $ | 136 | |
We believe that entering into master netting arrangements or similar agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. These master netting arrangements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master netting arrangement or similar agreement level by counterparty.
The following table providesprovides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of June 30, 2022,2023, and December 31, 2021:2022:
| | | Gross Amounts Not Offset in the Balance Sheet | | | Gross Amounts Not Offset in the Balance Sheet | |
| Commodity Contracts Eligible to be Offset | Commodity Contracts Eligible to be Offset | | Gross Amounts Recognized in the Balance Sheet | | Derivative Instruments | | Cash Collateral Received/Posted(a) | | Net
Amount | Commodity Contracts Eligible to be Offset | | Gross Amounts Recognized in the Balance Sheet | | Derivative Instruments | | Cash Collateral Received/Posted(a) | | Net Amount |
| June 30, 2022 | | |
| June 30, 2023 | | June 30, 2023 | |
| Assets: | Assets: | | Assets: | |
| Ameren Missouri | Ameren Missouri | | $ | 112 | | | $ | 36 | | | $ | 15 | | | $ | 61 | | Ameren Missouri | | $ | 30 | | | $ | 9 | | | $ | — | | | $ | 21 | |
| Ameren Illinois | Ameren Illinois | | 96 | | | 16 | | | 15 | | | 65 | | Ameren Illinois | | 13 | | | 9 | | | — | | | 4 | |
| Ameren | Ameren | | $ | 208 | | | $ | 52 | | | $ | 30 | | | $ | 126 | | Ameren | | $ | 43 | | | $ | 18 | | | $ | — | | | $ | 25 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Ameren Missouri | Ameren Missouri | | $ | 171 | | | $ | 36 | | | $ | 127 | | | $ | 8 | | Ameren Missouri | | $ | 31 | | | $ | 9 | | | $ | 12 | | | $ | 10 | |
| Ameren Illinois | Ameren Illinois | | 65 | | | 16 | | | — | | | 49 | | Ameren Illinois | | 114 | | | 9 | | | — | | | 105 | |
| Ameren | Ameren | | $ | 236 | | | $ | 52 | | | $ | 127 | | | $ | 57 | | Ameren | | $ | 145 | | | $ | 18 | | | $ | 12 | | | $ | 115 | |
| December 31, 2021 | | |
| December 31, 2022 | | December 31, 2022 | |
| Assets: | Assets: | | Assets: | |
| Ameren Missouri | Ameren Missouri | | $ | 49 | | | $ | 15 | | | $ | — | | | $ | 34 | | Ameren Missouri | | $ | 49 | | | $ | 9 | | | $ | — | | | $ | 40 | |
| Ameren Illinois | Ameren Illinois | | 41 | | | 4 | | | — | | | 37 | | Ameren Illinois | | 40 | | | 20 | | | — | | | 20 | |
| Ameren | Ameren | | $ | 90 | | | $ | 19 | | | $ | — | | | $ | 71 | | Ameren | | $ | 89 | | | $ | 29 | | | $ | — | | | $ | 60 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Ameren Missouri | Ameren Missouri | | $ | 77 | | | $ | 15 | | | $ | 47 | | | $ | 15 | | Ameren Missouri | | $ | 68 | | | $ | 9 | | | $ | 56 | | | $ | 3 | |
| Ameren Illinois | Ameren Illinois | | 125 | | | 4 | | | — | | | 121 | | Ameren Illinois | | 68 | | | 20 | | | — | | | 48 | |
| Ameren | Ameren | | $ | 202 | | | $ | 19 | | | $ | 47 | | | $ | 136 | | Ameren | | $ | 136 | | | $ | 29 | | | $ | 56 | | | $ | 51 | |
| |
(a)Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current“Current collateral assets” and “Other assets” on the balance sheet.sheet for Ameren and Ameren Missouri and “Other current assets” and “Other assets” for Ameren Illinois.
Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. As of June 30, 2022,2023, if counterparty groups were to fail completely to perform on contracts, the Ameren Ameren Missouri, and Ameren Illinois’Companies’ maximum exposure related to derivative assets, predominantly from financial institutions, was $172 million, $83 million, and $89 million, respectively. The potential loss on counterparty exposures may be reducedwould have been immaterial with or eliminated by the application of master netting arrangements or similar agreements and collateral held. As of June 30, 2022, the potential loss afterwithout consideration of the application of master netting arrangements or similar agreements and collateral held for Ameren, Ameren Missouri, and Ameren Illinois was $108 million, $42 million, and $66 million, respectively.held.
Certain of our derivative instruments contain collateral provisions tied to the Ameren Companies’ credit ratings. If our credit ratings were downgraded below investment grade, or if a counterparty with reasonable grounds for uncertainty regarding our ability to satisfy an obligation requested adequate assurance of performance, additional collateral postings might be required. The additional collateral required is the net liability position allowed under master netting arrangements or similar agreements, assuming (1) the credit risk-related contingent features underlying these arrangements were triggered and (2) those counterparties with rights to do so requested collateral. The following table presents, as of June 30, 2022,2023, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that counterparties could require:
| | | | Aggregate Fair Value of Derivative Liabilities(a) | | Cash
Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) | | Aggregate Fair Value of Derivative Liabilities(a) | | Cash
Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| Ameren Missouri | Ameren Missouri | $ | 76 | | | $ | 29 | | | $ | 12 | | Ameren Missouri | $ | 19 | | | $ | — | | | $ | 10 | |
| Ameren Illinois | Ameren Illinois | 12 | | | — | | | 4 | | Ameren Illinois | 46 | | | — | | | 37 | |
| Ameren | Ameren | $ | 88 | | | $ | 29 | | | $ | 16 | | Ameren | $ | 65 | | | $ | — | | | $ | 47 | |
(a)Before consideration of master netting arrangements or similar agreements.
(b)As collateral requirements with certain counterparties are based on master netting arrangements or similar agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such arrangements.
NOTE 7 – FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value measurements are classified in three levels based on the fair value hierarchy as defined by GAAP. See Note 8 – Fair Value Measurements under Part II, Item 8, of the Form 10-K for information related to hierarchy levels and valuation techniques.
We consider nonperformance risk in our valuation of derivative instruments by analyzing our own credit standing and the credit standing of our counterparties, and by considering any credit enhancements (e.g., collateral). Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. No material gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri, or Ameren Illinois in the three and six months ended June 30, 20222023 or 2021.2022. At June 30, 2022,2023, and December 31, 2021,2022, the counterparty default risk valuation adjustment related to derivative contracts was immaterial for Ameren, Ameren Missouri, and Ameren Illinois.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2022,2023, and December 31, 2021:2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2022 | | | December 31, 2021 | |
| | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Fuel oils | $ | 27 | | $ | — | | $ | 3 | | $ | 30 | | | | $ | 13 | | $ | — | | $ | — | | $ | 13 | | |
| Natural gas | 1 | | 27 | | — | | 28 | | | | — | | 12 | | — | | 12 | | |
| Power | 21 | | — | | 29 | | 50 | | | | 10 | | — | | 13 | | 23 | | |
| Uranium | — | | — | | 4 | | 4 | | | | — | | — | | 1 | | 1 | | |
| Total derivative assets – commodity contracts | $ | 49 | | $ | 27 | | $ | 36 | | $ | 112 | | | | $ | 23 | | $ | 12 | | $ | 14 | | $ | 49 | | |
| Nuclear decommissioning trust fund: | | | | | | | | | | | |
| | | | | | | | | | | | |
| Equity securities: | | | | | | | | | | | |
| U.S. large capitalization | $ | 602 | | $ | — | | $ | — | | $ | 602 | | | | $ | 824 | | $ | — | | $ | — | | $ | 824 | | |
| Debt securities: | | | | | | | | | | | |
| U.S. Treasury and agency securities | — | | 173 | | — | | 173 | | | | — | | 141 | | — | | 141 | | |
| Corporate bonds | — | | 121 | | — | | 121 | | | | — | | 131 | | — | | 131 | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Other | — | | 54 | | — | | 54 | | | | — | | 56 | | — | | 56 | | |
| Total nuclear decommissioning trust fund | $ | 602 | | $ | 348 | | $ | — | | $ | 950 | | (a) | | $ | 824 | | $ | 328 | | $ | — | | $ | 1,152 | | (a) |
| Total Ameren Missouri | $ | 651 | | $ | 375 | | $ | 36 | | $ | 1,062 | | | | $ | 847 | | $ | 340 | | $ | 14 | | $ | 1,201 | | |
| Ameren Illinois | | | | | | | | | | | |
| Derivative assets – commodity contracts: | | | | | | | | | | | |
| Natural gas | $ | 5 | | $ | 71 | | $ | 10 | | $ | 86 | | | | $ | 1 | | $ | 33 | | $ | 7 | | $ | 41 | | |
| Power | — | | — | | 10 | | 10 | | | | — | | — | | — | | — | | |
| Total Ameren Illinois | $ | 5 | | $ | 71 | | $ | 20 | | $ | 96 | | | | $ | 1 | | $ | 33 | | $ | 7 | | $ | 41 | | |
| Ameren | | | | | | | | | | | |
| Derivative assets – commodity contracts(b) | $ | 54 | | $ | 98 | | $ | 56 | | $ | 208 | | | | $ | 24 | | $ | 45 | | $ | 21 | | $ | 90 | | |
| Nuclear decommissioning trust fund(c) | 602 | | 348 | | — | | 950 | | (a) | | 824 | | 328 | | — | | 1,152 | | (a) |
| Total Ameren | $ | 656 | | $ | 446 | | $ | 56 | | $ | 1,158 | | | | $ | 848 | | $ | 373 | | $ | 21 | | $ | 1,242 | | |
| Liabilities: | | | | | | | | | | | |
| Ameren Missouri | | | | | | | | | | | |
| Derivative liabilities – commodity contracts: | | | | | | | | | | | |
| | | | | | | | | | | | |
| Natural gas | $ | — | | $ | 4 | | $ | 2 | | $ | 6 | | | | $ | — | | $ | 2 | | $ | 1 | | $ | 3 | | |
| Power | 100 | | — | | 65 | | 165 | | | | 45 | | — | | 28 | | 73 | | |
| Uranium | — | | — | | — | | — | | | | — | | — | | 1 | | 1 | | |
| Total Ameren Missouri | $ | 100 | | $ | 4 | | $ | 67 | | $ | 171 | | | | $ | 45 | | $ | 2 | | $ | 30 | | $ | 77 | | |
| | | | June 30, 2023 | | | December 31, 2022 | |
| | | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | |
| Assets: | | Assets: | | | |
| Ameren Missouri | | Ameren Missouri | | | |
| | | Derivative assets – commodity contracts: | | | |
| | | Fuel oils | $ | 6 | | $ | — | | $ | — | | $ | 6 | | | | $ | 16 | | $ | — | | $ | — | | $ | 16 | | |
| | | Natural gas | — | | 7 | | — | | 7 | | | | 1 | | 15 | | — | | 16 | | |
| | | Power | — | | — | | 15 | | 15 | | | | — | | — | | 14 | | 14 | | |
| | | Uranium | — | | — | | 2 | | 2 | | | | — | | — | | 3 | | 3 | | |
| | | Total derivative assets – commodity contracts | $ | 6 | | $ | 7 | | $ | 17 | | $ | 30 | | | | $ | 17 | | $ | 15 | | $ | 17 | | $ | 49 | | |
| | | Nuclear decommissioning trust fund: | | | |
| | | | Equity securities: | | | |
| | | U.S. large capitalization | $ | 727 | | $ | — | | $ | — | | $ | 727 | | | | $ | 618 | | $ | — | | $ | — | | $ | 618 | | |
| | | Debt securities: | | | |
| | | U.S. Treasury and agency securities | — | | 147 | | — | | 147 | | | | — | | 137 | | — | | 137 | | |
| | | Corporate bonds | — | | 126 | | — | | 126 | | | | — | | 122 | | — | | 122 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other | — | | 69 | | — | | 69 | | | | — | | 70 | | — | | 70 | | |
| | June 30, 2022 | | | December 31, 2021 | | | Total nuclear decommissioning trust fund | $ | 727 | | $ | 342 | | $ | — | | $ | 1,069 | | (a) | | $ | 618 | | $ | 329 | | $ | — | | $ | 947 | | (a) |
| | Level 1 | Level 2 | Level 3 | Total | | | Level 1 | Level 2 | Level 3 | Total | | | Total Ameren Missouri | $ | 733 | | $ | 349 | | $ | 17 | | $ | 1,099 | | | | $ | 635 | | $ | 344 | | $ | 17 | | $ | 996 | | |
| Ameren Illinois | Ameren Illinois | | | | Ameren Illinois | | | |
| | Derivative liabilities – commodity contracts: | | | | | Derivative assets – commodity contracts: | | | |
| | Natural gas | $ | — | | $ | 6 | | $ | 5 | | $ | 11 | | | | $ | — | | $ | 5 | | $ | 3 | | $ | 8 | | | | Natural gas | $ | — | | $ | 9 | | $ | 4 | | $ | 13 | | | | $ | 1 | | $ | 28 | | $ | 5 | | $ | 34 | | |
| | Power | — | | — | | 54 | | 54 | | | | — | | — | | 117 | | 117 | | | | Power | — | | — | | — | | — | | | | — | | — | | 6 | | 6 | | |
| | Total Ameren Illinois | $ | — | | $ | 6 | | $ | 59 | | $ | 65 | | | | $ | — | | $ | 5 | | $ | 120 | | $ | 125 | | | | Total Ameren Illinois | $ | — | | $ | 9 | | $ | 4 | | $ | 13 | | | | $ | 1 | | $ | 28 | | $ | 11 | | $ | 40 | | |
| Ameren | Ameren | | | | Ameren | | | |
| | Derivative liabilities – commodity contracts(b) | $ | 100 | | $ | 10 | | $ | 126 | | $ | 236 | | | | $ | 45 | | $ | 7 | | $ | 150 | | $ | 202 | | | | Derivative assets – commodity contracts(b) | $ | 6 | | $ | 16 | | $ | 21 | | $ | 43 | | | | $ | 18 | | $ | 43 | | $ | 28 | | $ | 89 | | |
| | | Nuclear decommissioning trust fund(c) | 727 | | 342 | | — | | 1,069 | | (a) | | 618 | | 329 | | — | | 947 | | (a) |
| | | Total Ameren | $ | 733 | | $ | 358 | | $ | 21 | | $ | 1,112 | | | | $ | 636 | | $ | 372 | | $ | 28 | | $ | 1,036 | | |
| Liabilities: | | Liabilities: | | | |
| Ameren Missouri | | Ameren Missouri | | | |
| | | Derivative liabilities – commodity contracts: | | | |
| | | Fuel oils | $ | 2 | | $ | — | | $ | — | | $ | 2 | | | | $ | — | | $ | — | | $ | — | | $ | — | | |
| | | Natural gas | — | | 13 | | 3 | | 16 | | | | — | | 6 | | 3 | | 9 | | |
| | | Power | 12 | | — | | 1 | | 13 | | | | 57 | | — | | 2 | | 59 | | |
| | | | Total Ameren Missouri | $ | 14 | | $ | 13 | | $ | 4 | | $ | 31 | | | | $ | 57 | | $ | 6 | | $ | 5 | | $ | 68 | | |
| Ameren Illinois | | Ameren Illinois | | | |
| | | Derivative liabilities – commodity contracts: | | | |
| | | Natural gas | $ | 1 | | $ | 38 | | $ | 7 | | $ | 46 | | | | $ | — | | $ | 19 | | $ | 10 | | $ | 29 | | |
| | | Power | — | | — | | 68 | | 68 | | | | — | | — | | 39 | | 39 | | |
| | | Total Ameren Illinois | $ | 1 | | $ | 38 | | $ | 75 | | $ | 114 | | | | $ | — | | $ | 19 | | $ | 49 | | $ | 68 | | |
| Ameren | | Ameren | | | |
| | | Derivative liabilities – commodity contracts(b) | $ | 15 | | $ | 51 | | $ | 79 | | $ | 145 | | | | $ | 57 | | $ | 25 | | $ | 54 | | $ | 136 | | |
(a)Balance excludes $7excludes $6 million and $11 million of cash and cash equivalents, receivables, payables, and accrued income, net, for both June 30, 2022,2023, and December 31, 2021.2022, respectively.
(b)See the Ameren Missouri and Ameren Illinois sections of the table for a breakout of the fair value of Ameren’s derivative assets and liabilities by type of commodity.
(c)See the Ameren Missouri section of the table for a breakout of the fair value of Ameren’s nuclear decommissioning trust fund by investment type.
Level 3 fuel oils, natural gas, and uranium derivative contract assets and liabilities measured at fair value on a recurring basis were immaterial for all periods presented. The following table presents the fair value reconciliation of Level 3 power derivative contract assets and liabilities measured at fair value on a recurring basis for the three and six months ended June 30, 20222023 and 2021:2022:
| | | 2022 | | | 2021 | | 2023 | | | 2022 |
| | Ameren Missouri | Ameren Illinois | | Ameren | | | Ameren Missouri | Ameren Illinois | Ameren | | Ameren Missouri | Ameren Illinois | | Ameren | | | Ameren Missouri | Ameren Illinois | Ameren |
| For the three months ended June 30: | For the three months ended June 30: | | | | | | For the three months ended June 30: | | | | | |
| Beginning balance at April 1 | Beginning balance at April 1 | $ | (53) | | $ | (74) | | | $ | (127) | | | | $ | (3) | | $ | (185) | | $ | (188) | | Beginning balance at April 1 | $ | 5 | | $ | (52) | | | $ | (47) | | | | $ | (53) | | $ | (74) | | $ | (127) | |
| Realized and unrealized gains/(losses) included in regulatory assets/liabilities | Realized and unrealized gains/(losses) included in regulatory assets/liabilities | (5) | | 32 | | | 27 | | | | (1) | | 15 | | 14 | | Realized and unrealized gains/(losses) included in regulatory assets/liabilities | 14 | | (20) | | | (6) | | | | (5) | | 32 | | 27 | |
| | Settlements | Settlements | 22 | | (2) | | | 20 | | | | (1) | | 4 | | 3 | | Settlements | (5) | | 4 | | | (1) | | | | 22 | | (2) | | 20 | |
| | Ending balance at June 30 | Ending balance at June 30 | $ | (36) | | $ | (44) | | | $ | (80) | | | | $ | (5) | | $ | (166) | | $ | (171) | | Ending balance at June 30 | $ | 14 | | $ | (68) | | | $ | (54) | | | | $ | (36) | | $ | (44) | | $ | (80) | |
| Change in unrealized gains/(losses) related to assets/liabilities held at June 30 | Change in unrealized gains/(losses) related to assets/liabilities held at June 30 | $ | 2 | | $ | 30 | | | $ | 32 | | | | $ | (2) | | $ | 15 | | $ | 13 | | Change in unrealized gains/(losses) related to assets/liabilities held at June 30 | $ | 14 | | $ | (20) | | | $ | (6) | | | | $ | 2 | | $ | 30 | | $ | 32 | |
| For the six months ended June 30: | For the six months ended June 30: | | | | | | For the six months ended June 30: | | | | | |
| Beginning balance at January 1 | Beginning balance at January 1 | $ | (15) | | $ | (117) | | | $ | (132) | | | | $ | 2 | | $ | (198) | | $ | (196) | | Beginning balance at January 1 | $ | 12 | | $ | (33) | | | $ | (21) | | | | $ | (15) | | $ | (117) | | $ | (132) | |
| Realized and unrealized gains/(losses) included in regulatory assets/liabilities | Realized and unrealized gains/(losses) included in regulatory assets/liabilities | (45) | | 74 | | | 29 | | | | (6) | | 24 | | 18 | | Realized and unrealized gains/(losses) included in regulatory assets/liabilities | 8 | | (41) | | | (33) | | | | (45) | | 74 | | 29 | |
| | Settlements | Settlements | 24 | | (1) | | | 23 | | | | (1) | | 8 | | 7 | | Settlements | (6) | | 6 | | | — | | | | 24 | | (1) | | 23 | |
| | Ending balance at June 30 | Ending balance at June 30 | $ | (36) | | $ | (44) | | | $ | (80) | | | | $ | (5) | | $ | (166) | | $ | (171) | | Ending balance at June 30 | $ | 14 | | $ | (68) | | | $ | (54) | | | | $ | (36) | | $ | (44) | | $ | (80) | |
| Change in unrealized gains/(losses) related to assets/liabilities held at June 30 | Change in unrealized gains/(losses) related to assets/liabilities held at June 30 | $ | (36) | | $ | 72 | | | $ | 36 | | | | $ | (3) | | $ | 24 | | $ | 21 | | Change in unrealized gains/(losses) related to assets/liabilities held at June 30 | $ | 14 | | $ | (35) | | | $ | (21) | | | | $ | (36) | | $ | 72 | | $ | 36 | |
All gains or losses related to our Level 3 derivative commodity contracts are expected to be recovered or returned through customer rates; therefore, there is no impact to either net income or other comprehensive income resulting from changes in the fair value of these instruments.
The following table describes the valuation techniques and significant unobservable inputs utilized for the fair value of our Level 3 power derivative contract assets and liabilities as of June 30, 2022,2023, and December 31, 2021:2022:
| | | Fair Value | | Weighted Average(b) | | | Fair Value | | Weighted Average(b) | |
| | Commodity | | Assets | | Liabilities | Valuation Technique(s) | Unobservable Input(a) | Range | | | Commodity | | Assets | | Liabilities | Valuation Technique(s) | Unobservable Input(a) | Range | |
| | 2023 | | 2023 | Power(c) | $ | 15 | $ | (69) | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 32 – 67 | 43 | |
| | | | Nodal basis ($/MWh) | (9) – (1) | (5) | |
| | 2022 | 2022 | Power(c) | $ | 39 | $ | (119) | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 36 – 122 | 65 | | 2022 | Power(d) | $ | 20 | $ | (41) | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 38 – 89 | 51 | |
| | | Nodal basis ($/MWh) | (17) – 3 | (6) | | | Nodal basis ($/MWh) | (10) – (1) | (4) | |
| | | Trend rate (%) | 0 – 3 | 2 | | | Trend rate (%) | 0 – 1 | 0 | |
| | 2021 | Power(d) | $ | 13 | $ | (145) | Discounted cash flow | Average forward peak and off-peak pricing – forwards/swaps ($/MWh) | 32 – 55 | 40 | | |
| | Nodal basis ($/MWh) | (14) – 0 | (2) | | |
| | Trend rate (%) | (e) | 0 | | |
|
(a)Generally, significant increases (decreases) in these inputs in isolation would result in a significantly higher (lower) fair value measurement.
(b)Unobservable inputs were weighted by relative fair value.
(c)Valuations use visible forward prices adjusted for nodal-to-hub basis differentials.
(d)Valuations through 2031 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2031 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
(d)Valuations through 2029 use visible forward prices adjusted for nodal-to-hub basis differentials. Valuations beyond 2029 use a trend rate factor and are similarly adjusted for nodal-to-hub basis differentials.
(e)No meaningful range around weighted average.
The following table sets forth the carrying amount and, by level within the fair value hierarchy, the fair value of financial assets and liabilities disclosed, but not recorded, at fair value as of June 30, 2022,2023, and December 31, 2021:2022:
| | | Carrying
Amount | | Fair Value | | | Carrying
Amount | | Fair Value | |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| | June 30, 2022 | | June 30, 2023 |
| Ameren: | Ameren: | | Ameren: | |
| Cash, cash equivalents, and restricted cash | Cash, cash equivalents, and restricted cash | $ | 161 | | | $ | 161 | | | $ | — | | | $ | — | | | $ | 161 | | Cash, cash equivalents, and restricted cash | $ | 246 | | | $ | 246 | | | $ | — | | | $ | — | | | $ | 246 | |
Investments in industrial development revenue bonds(a) | 248 | | | — | | | 248 | | | — | | | 248 | | |
| | Short-term debt | Short-term debt | 1,021 | | | — | | | 1,021 | | | — | | | 1,021 | | Short-term debt | 1,329 | | | — | | | 1,329 | | | — | | | 1,329 | |
Long-term debt (including current portion)(a) | 13,590 | | (b) | — | | | 12,016 | | | 500 | | (c) | 12,516 | | |
| Long-term debt (including current portion) | | Long-term debt (including current portion) | 14,678 | | (a) | — | | | 12,745 | | | 453 | | (b) | 13,198 | |
| Ameren Missouri: | Ameren Missouri: | | Ameren Missouri: | |
| Cash, cash equivalents, and restricted cash | Cash, cash equivalents, and restricted cash | $ | 7 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | 7 | | Cash, cash equivalents, and restricted cash | $ | 8 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | |
| Investments in industrial development revenue bonds(a) | 248 | | | — | | | 248 | | | — | | | 248 | | |
| | Short-term debt | Short-term debt | 285 | | | — | | | 285 | | | — | | | 285 | | Short-term debt | 373 | | | — | | | 373 | | | — | | | 373 | |
| Long-term debt (including current portion)(a) | 6,139 | | (b) | — | | | 5,641 | | | — | | | 5,641 | | |
| Long-term debt (including current portion) | | Long-term debt (including current portion) | 6,341 | | (a) | — | | | 5,688 | | | — | | | 5,688 | |
| Ameren Illinois: | Ameren Illinois: | | Ameren Illinois: | |
| Cash, cash equivalents, and restricted cash | Cash, cash equivalents, and restricted cash | $ | 146 | | | $ | 146 | | | $ | — | | | $ | — | | | $ | 146 | | Cash, cash equivalents, and restricted cash | $ | 229 | | | $ | 229 | | | $ | — | | | $ | — | | | $ | 229 | |
| | Short-term debt | Short-term debt | 141 | | | — | | | 141 | | | — | | | 141 | | Short-term debt | 117 | | | — | | | 117 | | | — | | | 117 | |
| | Long-term debt (including current portion) | Long-term debt (including current portion) | 4,394 | | (b) | — | | | 4,037 | | | — | | | 4,037 | | Long-term debt (including current portion) | 5,232 | | (a) | — | | | 4,735 | | | — | | | 4,735 | |
| | December 31, 2021 | | December 31, 2022 |
| Ameren: | Ameren: | | Ameren: | |
| Cash, cash equivalents, and restricted cash | Cash, cash equivalents, and restricted cash | $ | 155 | | | $ | 155 | | | $ | — | | | $ | — | | | $ | 155 | | Cash, cash equivalents, and restricted cash | $ | 216 | | | $ | 216 | | | $ | — | | | $ | — | | | $ | 216 | |
Investments in industrial development revenue bonds(a) | 248 | | | — | | | 248 | | | — | | | 248 | | |
Investment in industrial development revenue bonds(c) | | Investment in industrial development revenue bonds(c) | 240 | | | — | | | 240 | | | — | | | 240 | |
| Short-term debt | Short-term debt | 545 | | | — | | | 545 | | | — | | | 545 | | Short-term debt | 1,070 | | | — | | | 1,070 | | | — | | | 1,070 | |
Long-term debt (including current portion)(a) | 13,067 | | (b) | — | | | 13,930 | | | 591 | | (c) | 14,521 | | |
Long-term debt (including current portion)(c) | | Long-term debt (including current portion)(c) | 14,025 | | (a) | — | | | 11,989 | | | 464 | | (b) | 12,453 | |
| Ameren Missouri: | Ameren Missouri: | | Ameren Missouri: | |
| Cash, cash equivalents, and restricted cash | Cash, cash equivalents, and restricted cash | $ | 8 | | | $ | 8 | | | $ | — | | | $ | — | | | $ | 8 | | Cash, cash equivalents, and restricted cash | $ | 13 | | | $ | 13 | | | $ | — | | | $ | — | | | $ | 13 | |
| Investments in industrial development revenue bonds(a) | 248 | | | — | | | 248 | | | — | | | 248 | | |
Investment in industrial development revenue bonds(c) | | Investment in industrial development revenue bonds(c) | 240 | | | — | | | 240 | | | — | | | 240 | |
| Short-term debt | Short-term debt | 165 | | | — | | | 165 | | | — | | | 165 | | Short-term debt | 329 | | | — | | | 329 | | | — | | | 329 | |
Long-term debt (including current portion)(a) | 5,619 | | (b) | — | | | 6,321 | | | — | | | 6,321 | | |
Long-term debt (including current portion)(c) | | Long-term debt (including current portion)(c) | 6,086 | | (a) | — | | | 5,365 | | | — | | | 5,365 | |
| Ameren Illinois: | Ameren Illinois: | | Ameren Illinois: | |
| Cash, cash equivalents, and restricted cash | Cash, cash equivalents, and restricted cash | $ | 133 | | | $ | 133 | | | $ | — | | | $ | — | | | $ | 133 | | Cash, cash equivalents, and restricted cash | $ | 191 | | | $ | 191 | | | $ | — | | | $ | — | | | $ | 191 | |
| Short-term debt | Short-term debt | 103 | | | — | | | 103 | | | — | | | 103 | | Short-term debt | 264 | | | — | | | 264 | | | — | | | 264 | |
| | Long-term debt (including current portion) | Long-term debt (including current portion) | 4,392 | | (b) | — | | | 4,971 | | | — | | | 4,971 | | Long-term debt (including current portion) | 4,835 | | (a) | — | | | 4,320 | | | — | | | 4,320 | |
(a)Ameren and Ameren Missouri have investments in industrial development revenue bonds, classified as held-to-maturity and recorded in “Other Assets,” that are equal to the finance obligations for the Peno Creek and Audrain CT energy centers. As of June 30, 2022, and December 31, 2021, the carrying amount of both the investments in industrial development revenue bonds and the finance obligations approximated fair value.
(b)Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $97$105 million, $43$45 million, and $37$47 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2022.2023. Included unamortized debt issuance costs, which were excluded from the fair value measurement, of $94$99 million, $38$41 million, and $39$44 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2021.2022.
(c)(b)The Level 3 fair value amount consists of ATXI’s senior unsecured notes.
(c)Ameren and Ameren Missouri had an investment in industrial development revenue bonds, classified as held-to-maturity, that were equal to the finance obligation for the Audrain CT energy center. As of December 31, 2022, the carrying amount of the investment in industrial development revenue bonds and the finance obligation approximated fair value.
NOTE 8 – RELATED-PARTY TRANSACTIONS
In the ordinary course of business, Ameren Missouri and Ameren Illinois have engaged in, and may in the future engage in, affiliate transactions. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between Ameren’s subsidiaries are reported as affiliate transactions on their individual financial statements, but those transactions are eliminated in consolidation for Ameren’s consolidated financial statements. For a discussion of material related-party agreements and money pool arrangements, see Note 13 – Related-party Transactions and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, of the Form 10-K.
Support Services Agreements
Ameren Missouri and Ameren Illinois had long-term receivables included in “Other assets” from Ameren Services of $80$33 million and $83$35 million, respectively, as of June 30, 2022,2023, and $77$41 million and $80$43 million, respectively, as of December 31, 2021,2022, related to Ameren Services’ allocated portion of Ameren’s pension and postretirement benefit plans.
Tax Allocation Agreement
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for a discussion of the tax allocation agreement. The following table presents the affiliate balances related to income taxes for Ameren Missouri and Ameren Illinois as of June 30, 2022,2023, and December 31, 2021:2022:
| | | | | | | | | | | | | | | | | | | | |
| June 30, 2022 | | | December 31, 2021 |
| Ameren Missouri | Ameren Illinois | | | Ameren Missouri | Ameren Illinois |
Income taxes payable to parent(a) | $ | — | | $ | 82 | | | | $ | — | | $ | 8 | |
Income taxes receivable from parent(b) | 45 | | — | | | | 27 | | 18 | |
| | | | | | | | | | | | | | | | | | | | |
| June 30, 2023 | | | December 31, 2022 |
| Ameren Missouri | Ameren Illinois | | | Ameren Missouri | Ameren Illinois |
Income taxes payable to parent(a) | $ | — | $ | 28 | | | $ | — | $ | 50 |
Income taxes receivable from parent(b) | 38 | — | | | 39 | — |
(a)Included in “Accounts payable – affiliates” on the balance sheet.
(b)Included in “Accounts receivable – affiliates” on the balance sheet.
Effects of Related-party Transactions on the Statement of Income
The following table presents the impact on Ameren Missouri and Ameren Illinois of related-party transactions for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months | | Six Months | | Three Months | | Six Months |
| Agreement | Agreement | Income Statement
Line Item | | Ameren
Missouri | | Ameren
Illinois | | Ameren
Missouri | | Ameren
Illinois | Agreement | Income Statement
Line Item | | Ameren
Missouri | | Ameren
Illinois | | Ameren
Missouri | | Ameren
Illinois |
| Ameren Missouri power supply | Ameren Missouri power supply | Operating Revenues | 2022 | $ | 1 | | $ | (a) | $ | 5 | | $ | (a) | Ameren Missouri power supply | Operating Revenues | 2023 | $ | (b) | $ | (a) | $ | (b) | $ | (a) |
| agreements with Ameren Illinois | agreements with Ameren Illinois | | 2021 | | 3 | | | (a) | | 5 | | | (a) | agreements with Ameren Illinois | | 2022 | | 1 | | | (a) | | 5 | | | (a) |
| Ameren Missouri and Ameren Illinois | Ameren Missouri and Ameren Illinois | Operating Revenues | 2022 | $ | 6 | | $ | (b) | $ | 12 | | $ | (b) | Ameren Missouri and Ameren Illinois | Operating Revenues | 2023 | $ | 8 | | $ | (b) | $ | 18 | | $ | (b) |
| rent and facility services | rent and facility services | | 2021 | | 7 | | | (b) | | 14 | | | (b) | rent and facility services | | 2022 | | 6 | | | (b) | | 12 | | | (b) |
| Ameren Missouri and Ameren Illinois miscellaneous | Ameren Missouri and Ameren Illinois miscellaneous | Operating Revenues | 2022 | $ | (b) | $ | (b) | $ | (b) | $ | 1 | | Ameren Missouri and Ameren Illinois miscellaneous | Operating Revenues | 2023 | $ | (b) | $ | (b) | $ | (b) | $ | (b) |
| support services and other services provided to ATXI | | 2021 | | (b) | | 2 | | | (b) | | 2 | | |
| support services | | support services | | 2022 | | (b) | | (b) | | (b) | | 1 | |
| Total Operating Revenues | Total Operating Revenues | | 2022 | $ | 7 | | $ | (b) | $ | 17 | | $ | 1 | | Total Operating Revenues | | 2023 | $ | 8 | | $ | (b) | $ | 18 | | $ | (b) |
| | 2021 | | 10 | | | 2 | | | 19 | | | 2 | | | 2022 | | 7 | | | (b) | | 17 | | | 1 | |
| Ameren Illinois power supply | Ameren Illinois power supply | Purchased Power | 2022 | $ | (a) | $ | 1 | | $ | (a) | $ | 5 | | Ameren Illinois power supply | Purchased Power | 2023 | $ | (a) | $ | (b) | $ | (a) | $ | (b) |
| agreements with Ameren Missouri | agreements with Ameren Missouri | | 2021 | | (a) | | 3 | | | (a) | | 5 | | agreements with Ameren Missouri | | 2022 | | (a) | | 1 | | | (a) | | 5 | |
| Ameren Missouri and Ameren Illinois | Ameren Missouri and Ameren Illinois | Purchased Power | 2022 | $ | (b) | $ | (b) | $ | (b) | $ | (b) | Ameren Missouri and Ameren Illinois | Purchased Power | 2023 | $ | 1 | | $ | (b) | $ | 1 | | $ | (b) |
| transmission services from ATXI | transmission services from ATXI | | 2021 | | 1 | | | 1 | | | 2 | | | 1 | | transmission services from ATXI | | 2022 | | (b) | | (b) | | (b) | | (b) |
| Total Purchased Power | Total Purchased Power | | 2022 | $ | (b) | $ | 1 | | $ | (b) | $ | 5 | | Total Purchased Power | | 2023 | $ | 1 | | $ | (b) | $ | 1 | | $ | (b) |
| | 2021 | | 1 | | | 4 | | | 2 | | | 6 | | | 2022 | | (b) | | 1 | | | (b) | | 5 | |
| Ameren Missouri and Ameren Illinois | Ameren Missouri and Ameren Illinois | Other Operations and Maintenance | 2022 | $ | (b) | $ | (b) | $ | (b) | $ | 1 | | Ameren Missouri and Ameren Illinois | Other Operations and Maintenance | 2023 | $ | (b) | $ | (b) | $ | (b) | $ | 2 | |
| rent and facility services | rent and facility services | | 2021 | | (b) | | 1 | | | (b) | | 2 | | rent and facility services | | 2022 | | (b) | | (b) | | (b) | | 1 | |
| Ameren Services support services | Ameren Services support services | Other Operations and Maintenance | 2022 | $ | 33 | | $ | 32 | | $ | 71 | | $ | 67 | | Ameren Services support services | Other Operations and Maintenance | 2023 | $ | 35 | | $ | 33 | | $ | 70 | | $ | 68 | |
| agreement | agreement | | 2021 | | 34 | | | 31 | | | 69 | | | 64 | | agreement | | 2022 | | 33 | | | 32 | | | 71 | | | 67 | |
| Total Other Operations and | Total Other Operations and | | 2022 | $ | 33 | | $ | 32 | | $ | 71 | | $ | 68 | | Total Other Operations and | | 2023 | $ | 35 | | $ | 33 | | $ | 70 | | $ | 70 | |
| Maintenance | Maintenance | | 2021 | | 34 | | | 32 | | | 69 | | | 66 | | Maintenance | | 2022 | | 33 | | | 32 | | | 71 | | | 68 | |
| Money pool borrowings (advances) | Money pool borrowings (advances) | (Interest Charges)/Other Income, Net | 2022 | $ | (b) | $ | (b) | $ | (b) | $ | (b) | Money pool borrowings (advances) | (Interest Charges)/Other Income, Net | 2023 | $ | (b) | $ | (b) | $ | (b) | $ | (b) |
| | 2021 | | (b) | | (b) | | (b) | | (b) | | 2022 | | (b) | | (b) | | (b) | | (b) |
(a)Not applicable.
(b)Amount less than $1 million.
NOTE 9 – COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements in this report and in the Form 10-K, will not have a material adverse effect on our results of operations, financial position, or liquidity.
Reference is made to Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 9 – Callaway Energy Center, Note 13 – Related-party Transactions, and Note 14 – Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 8 – Related-party Transactions, and Note 10 – Callaway Energy Center of this report.
Environmental Matters
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 viaby 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; siting and land use requirements; and potential ecological impacts. Complex and lengthy processes are required to obtain and renew approvals, permits, and licenses for new, existing, or modified energy-
related facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures. We employ dedicated personnel knowledgeable in environmental matters to oversee our business activities’ compliance with regulatory requirements.requirements of environmental laws.
Environmental regulations have a significant impact on the electric utility industry and compliance with these regulations could be costly for Ameren Missouri, which operates coal-fired power plants. Regulations under the Clean Air Act that apply to the electric utility industry include the NSPS, the CSAPR, the MATS, and the National Ambient Air Quality Standards, which are subject to periodic review for certain pollutants. Collectively, these regulations cover a variety of pollutants, such as SO2, particulate matter, NOx,NOx, mercury, toxic metals and acid gases, and CO2 emissions from new power plants.emissions. Regulations implementing the Clean Water Act govern both intake and discharges of water, and may requireas well as evaluation of the ecological and biological impact of our operations, and could require modifications to water intake structures or more stringent limitations on wastewater discharges. Depending upon the scope of modifications ultimately required by state regulators, capital expenditures associated with these modifications could be significant. The management and disposal of coal ash is regulated under the Resource Conservation and Recovery Act and the CCR Rule, which require the closure of certain surface impoundments at Ameren Missouri’s coal-fired energy centers. The individual or combined effects of compliance with existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of operations at some of Ameren Missouri’s energy centers. Ameren and Ameren Missouri expect that such compliance costs would be recoverable through rates, subject to MoPSC prudence review, but the timing of costs and their recovery could be subject to regulatory lag.
Additionally, Ameren Missouri’s wind generation facilities may be subject to operating restrictions to limit the impact on protected species. Nighttime operating restrictions may be required during the critical biological season, which typically occurs fromFrom April through October. Seasonal nighttime curtailment began at theOctober, since 2021, Ameren Missouri’s High Prairie Renewable Energy Center atcurtailed nighttime operations to limit impacts on protected species. Seasonal nighttime curtailment began again in April 2023 as the end of March 2022,critical biological season resumed, but the extent and duration of the curtailment is unknown at this time as assessment of mitigation technologies is ongoing. Ameren Missouri does not anticipate these operating curtailments to result in significant impactshave a material impact on its results of operations, financial position, or liquidity.
Ameren and Ameren Missouri estimate that they will need to make capital expenditures of $125$90 million to $175$120 million from 20222023 through 20262027 in order to comply with existing environmental regulations. Additional capital expenditures for environmental controls beyond 20262027 could be required. This estimate of capital expenditures includes ash pondsurface impoundment closure and corrective action measures required by the CCR Rule and the effluent limitation guidelines applicable to steam electric generating units, and potential modifications to cooling water intake structures at existing power plants under Clean Water Act rules, all of which are discussed below. In addition to planned retirements of fossil fuel-firedcoal-fired energy centers as set forth in the 2022 Change to the 2020 IRP filed with the MoPSC in June 2022 and as noted in the NSR and Clean Air Act litigation discussed below and Illinois emissions standards discussed below,in Note 14 – Commitments and Contingencies under Part II, Item 8, of the Form 10-K, Ameren Missouri’s current plan for compliance with existing air emission regulations includes burning low-sulfur coal and installing new or optimizing existing air pollution control equipment. The actual amount of capital expenditures required to comply with existing environmental regulations may vary substantially from the above estimates because of uncertainty as to future permitting requirements made by state regulators and the EPA, potential revisions to regulatory obligations, and thevarying cost of potential compliance strategies, among other things.
The following sections describe the more significant environmental laws and rules and environmental enforcement and remediation matters that affect or could affect our operations. The EPA has initiated an administrative review of severalperiodically amends and revises its regulations and proposedproposes amendments to regulations and guidelines, including the CSAPR, which could ultimately result in the revision of all or part of such rules.
Clean Air Act
Federal and state laws, including the CSAPR, regulate emissions of SO2 and NOx through the reduction of emissions at their source and the use and retirement of emission allowances. CSAPR is implemented through a series of phases, and the second phase became effective in 2017. In April 2022, the EPA proposed plans for additional NOx emission reductions from power plants in Missouri, Illinois, and other states through revisions to the CSAPR;CSAPR. In January 2023, the EPA issued its final disapproval of Missouri’s proposed state implementation plan for addressing the transport of ozone under the Good Neighbor Plan of the Clean Air Act. The disapproval of the state plan allows the EPA to implement revisions to the CSAPR through a federal implementation plan. In March 2023, the EPA announced federal implementation plan requirements, which were subsequently published to the Federal Register in June 2023, reducing the amount of NOx allowances available for state budgets and additionalimposing NOx emission reduction requirements may apply in subsequent years. The EPA expects to issue a final rule in March 2023.limits on electric generating units for Missouri, Illinois, and other states under the Good Neighbor Plan of the Clean Air Act. In April 2023, the Missouri Attorney General and Ameren Missouri compliesseparately filed lawsuits in the United States Court of Appeals for the Eighth Circuit challenging the EPA’s disapproval of the Missouri state plan and sought a stay of the EPA’s disapproval of the Missouri state plan. The United States Court of Appeals for the Eighth Circuit in May 2023 granted those stay motions thereby preventing the EPA from imposing the federal implementation plan until the court of appeals issues a ruling, which is expected in 2024. Ameren Missouri has complied with the current CSAPR requirements by minimizing emissions through the use of low-sulfur coal, operation of 2two scrubbers at its Sioux Energy Center, and optimization of other existing NOxair pollution control equipment. Restrictions on the use of state budget NOx allowances for compliance with NOx emission limits could result in additional controls being required on Ameren Missouri could incur additional costs to lower its emissions at one Missouri’s generating units and/or morethe reduction of its energy centers to comply with additional CSAPR requirements in future years. Theseoperations. Any additional costs for compliance are expected to be recovered from customers, subject to MoPSC prudence review, through the FAC or higher base rates.
CO2 Emissions Standards
In June 2022, the United States Supreme Court issued its decision in West Virginia v. EPA,. The decision clarifies clarifying that there are limits on how the EPA may regulate greenhouse gases absent further direction from the United States Congress. The court concluded that emission caps that would causethe EPA’s proposed rules were designed to shift generation shifting from fossil-fuel-fired power plants to renewable energy facilities, would requirewhich was improper absent specific congressional authorization andauthorization. In May 2023, the EPA issued a proposed rule that such authorization had not been given under the Clean Air Act. The decision by the United States Supreme Court may affect the EPA’s development of any new regulations to addresswould set CO2 emissions from coal-emission standards for new and existing fossil-fuel-fired power plants based on the adoption of carbon capture technology, natural gas co-firing, and co-firing hydrogen fuel to reduce emissions. If the proposed rule were adopted, the affected fossil-fuel-fired power plants would be required to comply with the rule through a phased-in approach or retire. Capacity restrictions for coal-fired units could apply as early as 2030. Larger natural gas-fired power plants; however, at this time,plants would be required to co-fire with hydrogen by 2032, with additional requirements by 2038. The EPA expects to issue a final rule in 2024. Legal challenges to the final rule, if adopted, are expected. Ameren Missouri cannot predict the results of any such challenges. Ameren Missouri is currently reviewing the proposed rule and cannot predict the impact of any such regulations or the decision by the United States Supreme Court on the results of operations, financial position, and liquidity of Ameren or Ameren Missouri.
NSR and Clean Air Act Litigation
In January 2011, the United States Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri alleging that projects performed in performing projects2007 and 2010 at itsthe coal-fired Rush Island Energy Center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2017, the district court issued a liability ruling against Ameren Missouri and, in September 2019, entered a remedy order that required Ameren Missouri to install a flue gas desulfurization system at the Rush Island Energy Center and a dry sorbent injection system at the Labadie Energy Center. Following an appeal from Ameren Missouri in August 2021, the United States Court of Appeals for the Eighth Circuit affirmed the liability ruling and the district court’s remedy order as it related to the installation of a flue gas desulfurization system at the Rush Island Energy Center, but reversed the order as it related to the installation of a dry sorbent injection system at the Labadie Energy Center. In November 2021, the court of appeals issued an order denying requests for consideration previouslyre-consideration sought by both Ameren Missouri and the United States Department of Justice.
Based on its assessment of available legal, operational, and regulatory alternatives, Ameren Missouri filed a motion in December 2021, with the district court to modify the remedy order to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. In June 2022, Ameren Missouri supplemented its filing with the district court by proposing reduced operations, mostly operating during peak demand times and emergencies until the energy center is retired. The March 31,30, 2024 compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. In July 2022, in response to an Ameren Missouri request for a final, binding reliability assessment, the MISO designated the Rush Island Energy Center as a system support resource and concluded that certain mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation for the Rush Island Energy Center through August 2024, and in July 2023, an agreement between Ameren Missouri and the MISO was filed with the FERC for approval that details the manner of continued operation for the Rush Island Energy Center that results in operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. The FERC is under no deadline to issue an order. The transmission upgrade projects have been approved by the MISO, and Ameren Missouri has started design and procurementconstruction activities necessary to complete the upgrades andare underway. Ameren Missouri expects to complete the last of the upgrades by late 2025. The FERC will needmid-2025. In August 2023, Ameren Missouri requested the district court to approve a system support resource agreement detailingextend the manner of continued operation ofMarch 30, 2024 compliance date to October 15, 2024, at which point Ameren Missouri proposes to retire the Rush Island Energy Center, as well as aCenter. In addition, in October 2022, the FERC established hearing and settlement procedures in response to an August 2022 request from Ameren Missouri for recovery of non-energy costs under the related MISO tariff. In May 2023, a settlement agreement between Ameren Missouri and certain intervenors in the non-energy costs proceeding at the FERC, which provides for recovery of substantially all of Ameren Missouri’s requested non-energy costs through August 2023, was filed with the FERC for approval. The agreement, if approved, would have a term of 12 months. The system support resource designation and the related agreement are subjectFERC is under no deadline to renewal and revision. Any difference between revenuesissue an order. Revenues and costs under the MISO tariff is expected to beare included in the FAC. The district court has the authority to determine the retirement date and operating parameters for the Rush Island Energy Center and is not bound by the MISO determination of the Rush Island Energy Center as a system support resource or the FERC’s approval. While theThe district court is under no deadline to issue a ruling modifying the remedy order, a decision is expected in the near term.order. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review the planned accelerated retirement of the Rush Island Energy Center. See Note 2 – Rate and Regulatory Matters for additional information.
In connection with the planned accelerated retirement of the Rush Island Energy Center, Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the MissouriMissouri’s securitization statute. As such, Ameren Missouri did not request a change in the depreciation rates related to the Rush Island Energy Center in the electric regulatory rate review filed in August 2022. See Note 2 – Rate and Regulatory Matters for additional information on the August 2022 electric regulatory rate review. As of June 30, 2022,2023, the Rush Island Energy Center had a net plant balance of approximately $0.6 billion$550 million included in plant to be abandoned, net, within “Property, Plant, and Equipment, Net” and a rate base of approximately $0.5 billion. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of the Form 10-K for additional information regarding plant to be abandoned, net. In addition, Ameren Missouri filed a 2022 Change to the 2020 IRP with the MoPSC in June 2022 to reflect, among other things, the planned acceleration of the retirement of the Rush Island Energy Center from 2039, the retirement year for the facility as reflected in the 2020 IRP and reflected in depreciation rates approved by the December 2021 MoPSC electric rate order.
Ameren Missouri is unable to predict the ultimate resolution of this matter; however, such resolution could have a material adverse effect on the results of operations, financial position, and liquidity of Ameren and Ameren Missouri.
Clean Water Act
The EPA’s regulations implementing Section 316(b) of the Clean Water Act require power plant operators to evaluate cooling water intake structures and identify measures for reducing the number of aquatic organisms impinged on a power plant’s cooling water intake screens or entrained through the plant’s cooling water system. All of Ameren Missouri’s coal-fired and nuclear energy centers are subject to the cooling water intake structures rule. Requirements of the rule are implemented by state regulators through the permit renewal process of each power plant’s water discharge permit, which is expected to be completed by 2023permit. Permits for Ameren Missouri.Missouri’s coal-fired and nuclear energy centers have been issued or are in the process of renewal.
In 2015, the EPA issued a rule to revise the effluent limitation guidelines applicable to steam electric generating units. These guidelines established national standards for water discharges, prohibit effluent discharges of certain waste streams, and impose more stringent limitations on certain water discharges from power plants.plants by 2025. To meet the requirements of thecomply with these guidelines, Ameren Missouri installed dry ash handling systems and in 2020 completed construction of wastewater treatment facilities at 3 of its 4 coal-fired energy centers. The Meramec Energy Center is scheduled to retire in 2022 and, as a result, does not require new wastewater and dry ash handling systems.
CCR Management
The EPA’s CCR Rule establishes requirements for the management and disposal of CCR from coal-fired power plants and will resulthas resulted in the closure of certain surface impoundments at Ameren Missouri’s energy centers. Ameren Missouri completed the closure of all surface impoundments at its Labadie and Rush Island energy centers in 2021, and has made significant progress by closing several surface impoundments at its Sioux and Meramec energy centers. Ameren Missouri plans to substantially complete the closures of the remaining surface impoundments at its Sioux Energy Center and retired Meramec Energy Center as required by the CCR Rule in 2023. In January 2022, Ameren Missouri received notice of a proposed determination by the EPA that it has rejectedend of 2024. Ameren Missouri’s requests to extend the timeline for operating certain surface impoundments located at the SiouxCCR management compliance plan includes installation of groundwater monitoring equipment and Meramec energy centers. Pursuant to the terms of the proposed determination, compliance with the CCR Rule’s requirements for closure of the surface impoundments would be required 135 days after the EPA issues a final determination. In February 2022, Ameren Missouri filed comments with the EPA requesting additional time to construct a CCR Rule-compliant impoundment at the Sioux Energy Center and complete the closure of the surface impoundments at the Meramec Energy Center. The EPA is under no deadline to issue a final determination. If Ameren Missouri was no longer able to use the surface impoundments at the Sioux or Meramec energy centers, Ameren Missouri would not be able to operate the energy centers unless an alternative for handling the CCR material was available. Ameren Missouri will retire the Meramec Energy Center in 2022, and construction of a CCR Rule-compliant surface impoundment at the Sioux Energy Center is expected to be completed by the fall of 2022 to allow for continued operations. Ameren Missouri does not expect that this matter will have a material adverse effect on its results of operations, financial position, or liquidity.
groundwater treatment facilities. Ameren and Ameren Missouri have AROs of $77$45 million recorded on their respective balance sheets as of June 30, 2022,2023, associated with CCR storage facilities. Ameren Missouri estimates it will need to make capital expenditures of $60 million to $80 million from 2022 through 2026 to implement its CCR management compliance plan, which includes installation of groundwater monitoring equipment and groundwater treatment facilities.
Remediation
The Ameren Companies are involved in a number of remediation actions to clean up sites impacted by the use or disposal of materials containing hazardous substances. Federal and state laws can require responsible parties to fund remediation regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site.
As of June 30, 2022,2023, Ameren Illinois has remediated the majority of the 44 former MGP sites in Illinois and could substantially conclude remediation efforts at the remaining sites byin 2023. The ICC allows Ameren Illinois to recover such remediation and related litigation costs from its electric and natural gas utility customers through environmental cost riders that are subject to annual prudence reviews by the ICC. As of June 30, 2022,2023, Ameren Illinois estimated the remaining obligation related to these former MGP sites at $78$61 million to $147$112 million. Ameren and Ameren Illinois recorded a liability of $78$61 million to represent the estimated minimum obligation for these sites, as no other amount within the range was a better estimate. About half of the remaining liability recorded relates to remediation activities that are expected to be completed after 2023.
The scope of the remediation activities at these former MGP sites may increase as remediation efforts continue. Considerable uncertainty remains in these estimates because many site-specific factors can influence the actual costs, including unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs and timing of completion may vary substantially from these estimates.
Our operations or those of our predecessor companies involve the use of, disposal of, and, in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such historical practices will result in future environmental commitments, including additional or more stringent cleanup standards, or will affect our results of operations, financial position, or liquidity.
Illinois Emission Standards
The IETL established emission standards that became effective in September 2021. Ameren Missouri’s natural gas-fired energy centers in Illinois are subject to limits on emissions, including CO2 and NOx, equal to their unit-specific average emissions from 2018 through 2020, for any rolling twelve-month period beginning October 1, 2021, through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by 2029. The reductions could also limit the operations of Ameren Missouri’s other 4 natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to conditions in the IETL, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service as necessary. Ameren Missouri filed a 2022 Change to the 2020 IRP with the MoPSC in June 2022 to reflect, among other things, the updated scheduled retirement dates of the natural gas-fired energy centers located in the state of Illinois.
NOTE 10 – CALLAWAY ENERGY CENTER
See Note 9 – Callaway Energy Center under Part II, Item 8, of the Form 10-K for information regarding spent nuclear fuel recovery, recovery of decommissioning costs, and the nuclear decommissioning trust fund. The fair value of the trust fund for Ameren Missouri’s Callaway Energy Center is reported as “Nuclear decommissioning trust fund” in Ameren’s and Ameren Missouri’s balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability. Ameren and Ameren Missouri have recorded an ARO for the Callaway Energy Center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Annual decommissioning costs of $7 million are included in the costs used to establish electric rates for Ameren Missouri’s customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway Energy Center. An updated cost study and funding analysis was filed with the MoPSC in November 2020 and reflected within the ARO. In February 2021, the MoPSC approved no change in electric rates for decommissioning costs based on Ameren Missouri’s updated cost study funding analysis. See Note 13 – Supplemental Information for more information on Ameren Missouri’s AROs.
Maintenance Outage
See Note 9 – Callaway Energy Center under Part II, Item 8, of the Form 10-K for information regarding a maintenance outage from a non-nuclear operating issue related to the Callaway Energy Center’s generator in late December 2020 and subsequent return to service on August 4, 2021, along with the related insurance claims. In April 2022, Ameren Missouri received $22 million from NEIL related to lost sales insurance claims.
Insurance
The following table presents insurance coverage at Ameren Missouri’s Callaway Energy Center at June 30, 2022:2023:
| | Type and Source of Coverage | Type and Source of Coverage | Most Recent
Renewal Date | Maximum Coverages | | Maximum Assessments
for Single Incidents | | Type and Source of Coverage | Most Recent
Renewal Date | Maximum Coverages | | Maximum Assessments
for Single Incidents | |
| Public liability and nuclear worker liability: | Public liability and nuclear worker liability: | | Public liability and nuclear worker liability: | |
| American Nuclear Insurers | American Nuclear Insurers | January 1, 2022 | $ | 450 | | | $ | — | | | American Nuclear Insurers | January 1, 2023 | $ | 450 | | | $ | — | | |
| Pool participation | Pool participation | (a) | 13,073 | | (a) | 138 | | (b) | Pool participation | (a) | 13,210 | | (a) | 138 | | (b) |
| | $ | 13,523 | | (c) | $ | 138 | | | | $ | 13,660 | | (c) | $ | 138 | | |
| Property damage: | Property damage: | | Property damage: | |
| NEIL and EMANI | NEIL and EMANI | April 1, 2022 | $ | 3,200 | | (d) | $ | 26 | | (e) | NEIL and EMANI | April 1, 2023 | $ | 3,200 | | (d) | $ | 28 | | (e) |
| Accidental outage: | Accidental outage: | | Accidental outage: | |
| NEIL | NEIL | April 1, 2022 | $ | 490 | | (f) | $ | 7 | | (e) | NEIL | April 1, 2023 | $ | 490 | | (f) | $ | 9 | | (e) |
(a)Provided through mandatory participation in an industrywide retrospective premium assessment program. The maximum coverage available is dependent on the number of United States commercial reactors participating in the program.
(b)Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $450 million in the event of an incident at any licensed United States commercial reactor, payable at $21 million per year.
(c)Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This limit is subject to change to account for the effects of inflation and changes in the number of licensed power reactors.
(d)NEIL provides $2.7 billion in property damage, stabilization, decontamination, and premature decommissioning insurance for radiation events and $2.3 billion in property damage insurance for nonradiation events. EMANI provides $490 million in property damage insurance for both radiation and nonradiation events.
(e)All NEIL-insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.
(f)Accidental outage insurance provides for lost sales in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first 12 weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are limited to $328 million.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The most recent five-year inflationary adjustment became effective in November 2018. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities insured by NEIL are subject to industrywide aggregates, such that terrorist acts against one or more commercial nuclear power plants within a stated time period would be treated as a single event, and the owners of the nuclear power plants would share the limit of liability. NEIL policies have an aggregate limit of $3.2 billion within a 12-month period for radiation events, or $1.8 billion for events not involving radiation contamination, resulting from terrorist attacks. The EMANI policies are not subject to industrywide aggregates in the event of terrorist attacks on nuclear facilities.
If losses from a nuclear incident at the Callaway Energy Center exceed theinsurance limits, of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.
NOTE 11 – RETIREMENT BENEFITS
The following table presents the components of the net periodic benefit cost (income) incurred for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Pension Benefits | | | Postretirement Benefits | | Pension Benefits | | | Postretirement Benefits |
| | Three Months | | Six Months | | | Three Months | | Six Months | | Three Months | | Six Months | | | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 | | | 2023 | | 2022 | | 2023 | | 2022 |
Service cost(a) | Service cost(a) | $ | 31 | | | $ | 34 | | | $ | 64 | | | $ | 67 | | | | $ | 5 | | | $ | 6 | | | $ | 10 | | | $ | 12 | | Service cost(a) | $ | 23 | | | $ | 31 | | | $ | 46 | | | $ | 64 | | | | $ | 3 | | | $ | 5 | | | $ | 6 | | | $ | 10 | |
| Non-service cost components: | Non-service cost components: | | | | Non-service cost components: | | | |
| Interest cost | Interest cost | 41 | | | 38 | | | 81 | | | 76 | | | | 9 | | | 8 | | | 17 | | | 16 | | Interest cost | 56 | | | 41 | | | 111 | | | 81 | | | | 12 | | | 9 | | | 23 | | | 17 | |
Expected return on plan assets | Expected return on plan assets | (80) | | | (74) | | | (160) | | | (149) | | | | (22) | | | (20) | | | (43) | | | (40) | | Expected return on plan assets | (84) | | | (80) | | | (167) | | | (160) | | | | (23) | | | (22) | | | (46) | | | (43) | |
| Amortization of: | | | | |
Amortization of(b): | | Amortization of(b): | | | |
| | Prior service benefit | Prior service benefit | — | | | — | | | — | | | — | | | | (1) | | | (1) | | | (2) | | | (2) | | Prior service benefit | — | | | — | | | — | | | — | | | | (1) | | | (1) | | | (2) | | | (2) | |
| Actuarial loss (gain) | Actuarial loss (gain) | 6 | | | 20 | | | 12 | | | 37 | | | | (5) | | | (2) | | | (9) | | | (3) | | Actuarial loss (gain) | (28) | | | 6 | | | (57) | | | 12 | | | | (12) | | | (5) | | | (23) | | | (9) | |
Total non-service cost components(b)(c) | Total non-service cost components(b)(c) | $ | (33) | | | $ | (16) | | | $ | (67) | | | $ | (36) | | | | $ | (19) | | | $ | (15) | | | $ | (37) | | | $ | (29) | | Total non-service cost components(b)(c) | $ | (56) | | | $ | (33) | | | $ | (113) | | | $ | (67) | | | | $ | (24) | | | $ | (19) | | | $ | (48) | | | $ | (37) | |
| Net periodic benefit cost (income)(c) | $ | (2) | | | $ | 18 | | | $ | (3) | | | $ | 31 | | | | $ | (14) | | | $ | (9) | | | $ | (27) | | | $ | (17) | | |
Net periodic benefit income(d) | | Net periodic benefit income(d) | $ | (33) | | | $ | (2) | | | $ | (67) | | | $ | (3) | | | | $ | (21) | | | $ | (14) | | | $ | (42) | | | $ | (27) | |
(a)Service cost, net of capitalization, is reflected in “Operating Expenses – Other operations and maintenance” on Ameren’s statement of income.
(b)Prior service benefit is amortized on a straight-line basis over the average future service of active participants benefiting under a plan amendment. Net actuarial gains or losses related to the net benefit obligation subject to amortization are amortized on a straight-line basis over 10 years. The difference between the actual and expected return on plan assets is amortized over 4 years.
(c)Non-service cost components are reflected in “Other Income, Net” on Ameren’s consolidated statement of income. See Note 5 – Other Income, Net for additional information.
(c)(d)Does not include the impact of the regulatory tracking mechanismtracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
Ameren Missouri and Ameren Illinois are responsible for their respective share of Ameren’s pension and other postretirement costs. The following table presents the respective share of net periodic pension and other postretirement benefit costs (income) incurred for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Pension Benefits | | | Postretirement Benefits | | Pension Benefits | | | Postretirement Benefits |
| | Three Months | | Six Months | | | Three Months | | Six Months | | Three Months | | Six Months | | | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 | | | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 | | | 2023 | | 2022 | | 2023 | | 2022 |
Ameren Missouri(a) | Ameren Missouri(a) | $ | (1) | | | $ | 9 | | | $ | (2) | | | $ | 15 | | | | $ | (4) | | | $ | (1) | | | $ | (7) | | | $ | (2) | | Ameren Missouri(a) | $ | (17) | | | $ | (1) | | | $ | (35) | | | $ | (2) | | | | $ | (7) | | | $ | (4) | | | $ | (15) | | | $ | (7) | |
| Ameren Illinois | Ameren Illinois | — | | | 9 | | | 1 | | | 17 | | | | (10) | | | (8) | | | (20) | | | (15) | | Ameren Illinois | (13) | | | — | | | (27) | | | 1 | | | | (14) | | | (10) | | | (27) | | | (20) | |
| Other | Other | (1) | | | — | | | (2) | | | (1) | | | | — | | | — | | | — | | | — | | Other | (3) | | | (1) | | | (5) | | | (2) | | | | — | | | — | | | — | | | — | |
Ameren(a) | Ameren(a) | $ | (2) | | | $ | 18 | | | $ | (3) | | | $ | 31 | | | | $ | (14) | | | $ | (9) | | | $ | (27) | | | $ | (17) | | Ameren(a) | $ | (33) | | | $ | (2) | | | $ | (67) | | | $ | (3) | | | | $ | (21) | | | $ | (14) | | | $ | (42) | | | $ | (27) | |
(a)Does not include the impact of the regulatory tracking mechanismtracker for the difference between the level of pension and postretirement benefit costs (income) incurred by Ameren Missouri under GAAP and the level of such costs included in rates.
NOTE 12 – INCOME TAXES
The following table presents a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Ameren | | Ameren Missouri | | Ameren Illinois | | | Ameren | | Ameren Missouri | | Ameren Illinois | |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2022 | | 2021 | | | 2023 | | 2022 | | 2023 | | 2022 | | 2023 | | 2022 | |
| Three Months | Three Months | | Three Months | |
| Federal statutory corporate income tax rate | Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | | Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | |
| Increases (decreases) from: | Increases (decreases) from: | | Increases (decreases) from: | |
| Amortization of deferred investment tax credit | Amortization of deferred investment tax credit | — | | | — | | | (1) | | | (1) | | | — | | | — | | | Amortization of deferred investment tax credit | — | | | — | | | — | | | (1) | | | — | | | — | | |
Amortization of excess deferred taxes(a) | Amortization of excess deferred taxes(a) | (8) | | | (9) | |
| (15) | | | (17) | |
| (2) | | | (2) | | | Amortization of excess deferred taxes(a) | (7) | | | (8) | |
| (15) | | | (15) | |
| (2) | | | (2) | | |
| Depreciation differences | Depreciation differences | — | | | — | | | — | | | 1 | | | (1) | | | 1 | | | Depreciation differences | — | | | — | | | — | | | — | | | (1) | | | (1) | | |
| Other | Other | 1 | | | — | | | — | | | — | | | — | | | — | | | Other | — | | | 1 | | | — | | | — | | | — | | | — | | |
Renewable and other tax credits(b) | Renewable and other tax credits(b) | (4) | | | (4) | | | (10) | | | (10) | | | — | | | (1) | | | Renewable and other tax credits(b) | (5) | | | (4) | | | (10) | | | (10) | | | — | | | — | | |
| State tax | State tax | 5 | | | 5 | | | 3 | | | 3 | | | 7 | | | 7 | | | State tax | 5 | | | 5 | | | 3 | | | 3 | | | 7 | | | 7 | | |
| | | Effective income tax rate | Effective income tax rate | 15 | % | | 13 | % | | (2) | % | | (3) | % | | 25 | % | | 26 | % | | Effective income tax rate | 14 | % | | 15 | % | | (1) | % | | (2) | % | | 25 | % | | 25 | % | |
| Six Months | Six Months | | Six Months | |
| Federal statutory corporate income tax rate | Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | | Federal statutory corporate income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | | 21 | % | |
| Increases (decreases) from: | Increases (decreases) from: | | Increases (decreases) from: | |
| Amortization of deferred investment tax credit | Amortization of deferred investment tax credit | — | | | — | | | (1) | | | (1) | | | — | | | — | | | Amortization of deferred investment tax credit | — | | | — | | | — | | | (1) | | | — | | | — | | |
Amortization of excess deferred taxes(a) | Amortization of excess deferred taxes(a) | (8) | | | (9) | |
| (16) | | | (17) | |
| (2) | | | (3) | | | Amortization of excess deferred taxes(a) | (8) | | | (8) | |
| (15) | | | (16) | |
| (2) | | | (2) | | |
| Depreciation differences | Depreciation differences | — | | | — | | | — | | | 1 | | | — | | | — | | | Depreciation differences | — | | | — | | | — | | | — | | | (1) | | | — | | |
| Renewable and other tax credits(b) | Renewable and other tax credits(b) | (5) | | | (5) | | | (10) | | | (10) | | | — | | | — | | | Renewable and other tax credits(b) | (4) | | | (5) | | | (10) | | | (10) | | | — | | | — | | |
| State tax | State tax | 5 | | | 5 | | | 3 | | | 3 | | | 7 | | | 7 | | | State tax | 5 | | | 5 | | | 3 | | | 3 | | | 7 | | | 7 | | |
| | Other permanent items | | Other permanent items | (1) | | | — | | | — | | | — | | | — | | | — | | |
| Effective income tax rate | Effective income tax rate | 13 | % | | 12 | % | | (3) | % | | (3) | % | | 26 | % | | 25 | % | | Effective income tax rate | 13 | % | | 13 | % | | (1) | % | | (3) | % | | 25 | % | | 26 | % | |
(a)Reflects the amortization of amounts resulting from the revaluation of deferred income taxes subject to regulatory ratemaking, which are being refunded to customers. Deferred income taxes are revalued when federal or state income tax rates change, and the offset to the revaluation of deferred income taxes subject to regulatory ratemaking is recorded to a regulatory asset or liability.
(b)Includes credits associated with the High Prairie and Atchison renewable energy centers. Ameren Missouri placed the High Prairie Renewable Energy Center in service in December 2020. Additionally, Ameren Missouri placed in service the wind turbines at its Atchison Renewable Energy Center throughout the first half of 2021. The benefit of the credits associated with Missouri renewable energy standard compliance is refunded to customers through the RESRAM.
NOTE 13 – SUPPLEMENTAL INFORMATION
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets and the statements of cash flows at June 30, 2022,2023, and December 31, 2021:2022:
| | | June 30, 2022 | | | December 31, 2021 | | June 30, 2023 | | | December 31, 2022 |
| Ameren | | Ameren
Missouri | | Ameren
Illinois | | | Ameren | | Ameren
Missouri | | Ameren
Illinois | Ameren | | Ameren
Missouri | | Ameren
Illinois | | | Ameren | | Ameren
Missouri | | Ameren
Illinois |
| “Cash and cash equivalents” | “Cash and cash equivalents” | $ | 7 | | | $ | — | | | $ | — | | | | $ | 8 | | | $ | — | | | $ | — | | “Cash and cash equivalents” | $ | 7 | | | $ | — | | | $ | — | | | | $ | 10 | | | $ | — | | | $ | — | |
| | Restricted cash included in “Other current assets” | Restricted cash included in “Other current assets” | 7 | | | 2 | | | 4 | | | | 16 | | | 4 | | | 6 | | Restricted cash included in “Other current assets” | 13 | | | 5 | | | 6 | | | | 13 | | | 5 | | | 6 | |
| Restricted cash included in “Other assets” | Restricted cash included in “Other assets” | 142 | | | — | | | 142 | | | | 127 | | | — | | | 127 | | Restricted cash included in “Other assets” | 223 | | | — | | | 223 | | | | 185 | | | — | | | 185 | |
| Restricted cash included in “Nuclear decommissioning trust fund” | Restricted cash included in “Nuclear decommissioning trust fund” | 5 | | | 5 | | | — | | | | 4 | | | 4 | | | — | | Restricted cash included in “Nuclear decommissioning trust fund” | 3 | | | 3 | | | — | | | | 8 | | | 8 | | | — | |
| Total cash, cash equivalents, and restricted cash | Total cash, cash equivalents, and restricted cash | $ | 161 | | | $ | 7 | | | $ | 146 | | | | $ | 155 | | | $ | 8 | | | $ | 133 | | Total cash, cash equivalents, and restricted cash | $ | 246 | | | $ | 8 | | | $ | 229 | | | | $ | 216 | | | $ | 13 | | | $ | 191 | |
Restricted cash included in “Other current assets” primarily represents funds held by an irrevocable Voluntary Employee Beneficiary Association (VEBA) trust, which provides health care benefits for active employees. Restricted cash included in “Other assets” on Ameren’s and Ameren Illinois’ balance sheets primarily represents amounts collected under a cost recovery rider restricted for use in the procurement of renewable energy credits and amounts in a trust fund restricted for the use of funding certain asbestos-related claims.
Accounts Receivable
“Accounts receivable – trade” on Ameren’s and Ameren Illinois’ balance sheets include certain receivables purchased at a discount from alternative retail electric suppliers that elect to participate in the utility consolidated billing program. At June 30, 2022,2023, and December 31, 2021,2022, “Other current liabilities” on Ameren’s and Ameren Illinois’ balance sheets included payables for purchased receivables of $32$37 million and $27$31 million, respectively.
The following table provides a reconciliation of the beginning and ending amount of the allowance for doubtful accounts for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months | | Six Months | | Three Months | | Six Months |
| | 2022 | | 2021 | | | 2022 | | 2021 | | | 2023 | | 2022 | | | 2023 | | 2022 | |
| Ameren: | Ameren: | | | | Ameren: | | | |
| Beginning of period | Beginning of period | $ | 28 | | | $ | 47 | | | | $ | 29 | | | $ | 50 | | | Beginning of period | $ | 34 | | | $ | 28 | | | | $ | 31 | | | $ | 29 | | |
| Bad debt expense | Bad debt expense | 7 | | | (3) | | | | 11 | | | 1 | | | Bad debt expense | 13 | | | 6 | | | | 23 | | | 9 | | |
Charged to other accounts(a) | | Charged to other accounts(a) | 1 | | | 1 | | | | 1 | | | 2 | | |
| Net write-offs | Net write-offs | (5) | | | (2) | | | | (10) | | | (9) | | | Net write-offs | (9) | | | (5) | | | | (16) | | | (10) | | |
| End of period | End of period | $ | 30 | | | $ | 42 | | | | $ | 30 | | | $ | 42 | | | End of period | $ | 39 | | | $ | 30 | | | | $ | 39 | | | $ | 30 | | |
| Ameren Missouri: | Ameren Missouri: | | | | Ameren Missouri: | | | |
| Beginning of period | Beginning of period | $ | 11 | | | $ | 15 | | | | $ | 13 | | | $ | 16 | | | Beginning of period | $ | 12 | | | $ | 11 | | | | $ | 13 | | | $ | 13 | | |
| Bad debt expense | Bad debt expense | 2 | | | 2 | | | | 3 | | | 3 | | | Bad debt expense | 2 | | | 2 | | | | 4 | | | 3 | | |
| Net write-offs | Net write-offs | (1) | | | (1) | | | | (4) | | | (3) | | | Net write-offs | (2) | | | (1) | | | | (5) | | | (4) | | |
| End of period | End of period | $ | 12 | | | $ | 16 | | | | $ | 12 | | | $ | 16 | | | End of period | $ | 12 | | | $ | 12 | | | | $ | 12 | | | $ | 12 | | |
Ameren Illinois:(a) | | | | |
Ameren Illinois:(b) | | Ameren Illinois:(b) | | | |
| Beginning of period | Beginning of period | $ | 17 | | | $ | 32 | | | | $ | 16 | | | $ | 34 | | | Beginning of period | $ | 22 | | | $ | 17 | | | | $ | 18 | | | $ | 16 | | |
| Bad debt expense | Bad debt expense | 5 | |
| (5) | | (b) | | 8 | | | (2) | | (b) | Bad debt expense | 11 | |
| 4 | | | | 19 | | | 6 | | |
Charged to other accounts(a) | | Charged to other accounts(a) | 1 | | | 1 | | | | 1 | | | 2 | | |
| Net write-offs | Net write-offs | (4) | | | (1) | | | | (6) | | | (6) | | | Net write-offs | (7) | | | (4) | | | | (11) | | | (6) | | |
| End of period | End of period | $ | 18 | | | $ | 26 | | | | $ | 18 | | | $ | 26 | | | End of period | $ | 27 | | | $ | 18 | | | | $ | 27 | | | $ | 18 | | |
(a)Amounts associated with the allowance for doubtful accounts related to receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public Utilities Act.
(b)Ameren Illinois has rate-adjustment mechanismsriders that allow it to recover the difference between its actual net bad debt write-offs under GAAP, including those associated with receivables purchased from alternative retail electric suppliers, and the amount of net bad debt write-offs included in its base rates. The table above does not include the impact related to the riders.
(b)In the three and six months endedAs of June 30, 2021,2023, accounts receivable balances that were 30 days or greater past due or that were a part of a deferred payment arrangement represented 26%, 15%, and 35%, or $133 million, $28 million, and $106 million, of Ameren’s, Ameren Missouri’s, and Ameren Illinois’ bad debt expense was reducedcustomer trade receivables before allowance for doubtful accounts, respectively. In comparison, as a result of state funding receivedJune 30, 2022, these percentages were 19%, 14%, and 24%, or $107 million, $29 million, and $78 million, for customer bill assistance.Ameren, Ameren Missouri, and Ameren Illinois, respectively.
Supplemental Cash Flow Information
Capital expenditures for the six months ended June 30, 2021, at Ameren and Ameren Missouri included wind generation expenditures of $417 million.
The following table provides noncash financing and investing activity excluded from the statements of cash flows for the six months ended June 30, 20222023 and 2021:2022:
| | | June 30, 2022 | | June 30, 2021 | | June 30, 2023 | | June 30, 2022 |
| Ameren | Ameren
Missouri | | Ameren
Illinois | Ameren | Ameren
Missouri | Ameren
Illinois | | Ameren | Ameren
Missouri | | Ameren
Illinois | Ameren | Ameren
Missouri | Ameren
Illinois |
| Investing | | | | |
| Investing: | | Investing: | | | |
| Accrued capital expenditures | Accrued capital expenditures | $ | 408 | | $ | 204 | | | $ | 193 | | | $ | 434 | | $ | 259 | | $ | 174 | | Accrued capital expenditures | $ | 325 | | $ | 132 | | | $ | 173 | | | $ | 408 | | $ | 204 | | $ | 193 | |
| | Net realized and unrealized gain/(loss) – nuclear decommissioning trust fund | Net realized and unrealized gain/(loss) – nuclear decommissioning trust fund | (211) | | (211) | | | — | | | 85 | | 85 | | — | | Net realized and unrealized gain/(loss) – nuclear decommissioning trust fund | 105 | | 105 | | | — | | | (211) | | (211) | | — | |
| Financing | | | | |
Return of investment in industrial development revenue bonds(a) | | Return of investment in industrial development revenue bonds(a) | 240 | | 240 | | | — | | | — | | — | | — | |
| Financing: | | Financing: | | | |
| Issuance of common stock for stock-based compensation | Issuance of common stock for stock-based compensation | $ | 31 | | $ | — | | | $ | — | | | $ | 33 | | $ | — | | $ | — | | Issuance of common stock for stock-based compensation | $ | 37 | | $ | — | | | $ | — | | | $ | 31 | | $ | — | | $ | — | |
| Issuance of common stock under the DRPlus | Issuance of common stock under the DRPlus | 8 | | — | | | — | | | — | | — | | — | | Issuance of common stock under the DRPlus | 7 | | — | | | — | | | 8 | | — | | — | |
Termination of a financing obligation(a) | | Termination of a financing obligation(a) | 240 | | 240 | | | — | | | — | | — | | — | |
(a)In January 2023, Ameren Missouri and Audrain County mutually agreed to terminate a financing obligation agreement related to the CT energy center in Audrain County, which was scheduled to expire in December 2023. No cash was exchanged in connection with the termination of the agreement as the $240 million principal amount of the financing obligation due from Ameren Missouri was equal to the amount of bond service payments due to Ameren Missouri.
Asset Retirement Obligations
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the six months ended June 30, 2022:2023:
| | | | | | | | | | | | | | | | | | | | | | |
| Ameren
Missouri | | Ameren
Illinois | | | | Ameren | |
| Balance at December 31, 2021 | $ | 760 | | (a) | $ | 4 | | | | (b) | $ | 764 | | (a) |
| | | | | | | | |
| | | | | | | | |
| Accretion | 15 | | (c) | — | | | |
| 15 | | (c) |
| Change in estimates | 2 | | | — | | | | | 2 | | |
| Balance at June 30, 2022 | $ | 777 | | (a) | $ | 4 | | | | (b) | $ | 781 | | (a) |
| | | | | | | | | | | | | | | | | | | | | | |
| Ameren
Missouri | | Ameren
Illinois | | | | Ameren | |
| Balance at December 31, 2022 | $ | 782 | | (a) | $ | 4 | | | | (b) | $ | 786 | | (a) |
| | | | | | | | |
| Liabilities settled | (4) | | | — | | | | | (4) | | |
| Accretion | 16 | | (c) | — | | | |
| 16 | | (c) |
| | | | | | | | |
| Balance at June 30, 2023 | $ | 794 | | (a) | $ | 4 | | | | (b) | $ | 798 | | (a) |
(a)Balance included $7$23 million in “Other current liabilities” on the balance sheet as of both June 30, 2022,2023, and December 31, 2021.2022.
(b)Included in “Other deferred credits and liabilities” on the balance sheet.
(c)Accretion expense attributable to Ameren Missouri was recorded as a decrease to regulatory liabilities.
Stock-based Compensation
Ameren’s long-term incentive plan available for eligible employees, the 2014 Omnibus Incentive Compensation Plan (2014 Plan), was replaced prospectively for new grants only by the 2022 Omnibus Incentive Compensation Plan (2022 Plan) effective May 12, 2022. The 2022 Plan provides for a maximum of 8.8 million common shares to be available for grant to eligible employees and directors, and retains many of the features of the 2014 Plan. The 2022 Plan permits the grant of restricted stock, restricted stock units, stock options (incentive stock options and nonqualified stock options), stock appreciation rights, performance awards, cash-based awards and other stock-based awards.
In the first quarter of 2022 under the 2014 Plan,2023, Ameren granted 267,849265,422 performance share units with a grant date fair value of $25$24 million and 122,882116,701 restricted share units with a grant date fair value of $11$10 million. Awards vest approximately 3 years after the grant date or on a pro-rata basis upon death or eligible retirement. The performance share units vest based on the achievement of certain specified market performance measures (229,566(227,494 performance share units) or clean energy transition targets (38,283(37,928 performance share units). The exact number of shares issued pursuant to a performance share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.
For the six months ended June 30, 20222023 and 2021,2022, excess tax benefits associated with the settlement of stock-based compensation awards reduced income tax expense by $6 million and $5 million, in both periods.respectively.
Deferred Compensation
At June 30, 2022,2023, and December 31, 2021,2022, the present value of benefits to be paid for deferred compensation obligations was $89$85 million and $91$87 million, respectively, which was primarily reflected in “Other deferred credits and liabilities” on Ameren’s consolidated balance sheet.
Operating Revenues
As of June 30, 20222023 and 2021,2022, our remaining performance obligations for contracts with a term greater than one year were immaterial. The Ameren Companies elected not to disclose the aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied as of the end of the reporting period for contracts with an initial expected term of one year or less.
See Note 14 – Segment Information for disaggregated revenue information.
Excise Taxes
Ameren Missouri and Ameren Illinois collect from their customers excise taxes, including municipal and state excise taxes and gross receipts taxes that are levied on the sale or distribution of natural gas and electricity. The following table presents the excise taxes recorded on a gross basis in “Operating Revenues – Electric,” “Operating Revenues – Natural gas” and “Operating Expenses – Taxes other than income taxes” on the statements of income for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months | | Six Months | | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Ameren Missouri | Ameren Missouri | $ | 39 | | | $ | 35 | | | $ | 73 | | | $ | 66 | | Ameren Missouri | $ | 39 | | | $ | 39 | | | $ | 73 | | | $ | 73 | |
| Ameren Illinois | Ameren Illinois | 28 | | | 27 | | | 73 | | | 66 | | Ameren Illinois | 26 | | | 28 | | | 63 | | | 73 | |
| Ameren | Ameren | $ | 67 | | | $ | 62 | | | $ | 146 | | | $ | 132 | | Ameren | $ | 65 | | | $ | 67 | | | $ | 136 | | | $ | 146 | |
Earnings per Share
The following table reconciles the basic weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months | | Six Months | | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| | Weighted-average Common Shares Outstanding – Basic | Weighted-average Common Shares Outstanding – Basic | 258.2 | | | 256.1 | | | 258.0 | | | 255.2 | | Weighted-average Common Shares Outstanding – Basic | 262.6 | | | 258.2 | | | 262.4 | | | 258.0 | |
| Assumed settlement of performance share units and restricted stock units | Assumed settlement of performance share units and restricted stock units | 1.0 | | | 1.1 | | | 1.1 | | | 1.3 | | Assumed settlement of performance share units and restricted stock units | 0.6 | | | 1.0 | | | 0.8 | | | 1.1 | |
| Dilutive effect of forward sale agreements | Dilutive effect of forward sale agreements | 0.2 | | | — | | | 0.1 | | | — | | Dilutive effect of forward sale agreements | — | | | 0.2 | | | — | | | 0.1 | |
Weighted-average Common Shares Outstanding – Diluted(a) | Weighted-average Common Shares Outstanding – Diluted(a) | 259.4 | | | 257.2 | | | 259.2 | | | 256.5 | | Weighted-average Common Shares Outstanding – Diluted(a) | 263.2 | | | 259.4 | | | 263.2 | | | 259.2 | |
|
(a)There was an immaterial number of anti-dilutive securitiesperformance share units excluded from the earnings per diluted share calculations for the three and six months ended June 30, 2023 and 2022. ThereThe outstanding forward sale agreements as of June 30, 2023, were no anti-dilutive securities excluded from the earnings per diluted share calculations for the three and six months ended June 30, 2021.2023, and excluded from the earnings per diluted share calculation as calculated using the treasury stock method.
NOTE 14 – SEGMENT INFORMATION
The following tables present revenues, net income attributable to common shareholders, and capital expenditures by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 20222023 and 2021.2022. Ameren, Ameren Missouri, and Ameren Illinois management review segment capital expenditure information rather than any individual or total asset amount. For additional information about our segments, see Note 16 – Segment Information under Part II, Item 8, of the Form 10-K.
Ameren
| | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren | | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Other | | Intersegment Eliminations | | Ameren | |
| Three Months 2023: | | Three Months 2023: | |
| External revenues | | External revenues | $ | 933 | | | $ | 540 | | | $ | 152 | | | $ | 135 | | | $ | — | | | $ | — | | | $ | 1,760 | | |
| Intersegment revenues | | Intersegment revenues | 8 | | | — | | | — | | | 26 | | | — | | | (34) | | | — | | |
| Net income (loss) attributable to Ameren common shareholders | | Net income (loss) attributable to Ameren common shareholders | 102 | | | 66 | | | 11 | | | 72 | | (a) | (14) | | | — | | | 237 | | |
| Capital expenditures | | Capital expenditures | 433 | | | 180 | | | 90 | | | 197 | | | 2 | | | (11) | | | 891 | | |
| Three Months 2022: | Three Months 2022: | | Three Months 2022: | |
| External revenues | External revenues | $ | 912 | | | $ | 504 | | | $ | 184 | | | $ | 126 | | | $ | — | | | $ | — | | | $ | 1,726 | | | External revenues | $ | 912 | | | $ | 504 | | | $ | 184 | | | $ | 126 | | | $ | — | | | $ | — | | | $ | 1,726 | | |
| Intersegment revenues | Intersegment revenues | 7 | | | — | | | — | | | 24 | | | — | | | (31) | | | — | | | Intersegment revenues | 7 | | | — | | | — | | | 24 | | | — | | | (31) | | | — | | |
| Net income (loss) attributable to Ameren common shareholders | Net income (loss) attributable to Ameren common shareholders | 100 | | | 51 | | | 6 | | | 63 | | (a) | (13) | | | — | | | 207 | | | Net income (loss) attributable to Ameren common shareholders | 100 | | | 51 | | | 6 | | | 63 | | (a) | (13) | | | — | | | 207 | | |
| Capital expenditures | Capital expenditures | 392 | | | 143 | | | 69 | | | 160 | | | 1 | | | (1) | | | 764 | | | Capital expenditures | 392 | | | 143 | | | 69 | | | 160 | | | 1 | | | (1) | | | 764 | | |
| Three Months 2021: | | |
| Six Months 2023: | | Six Months 2023: | |
| External revenues | External revenues | $ | 799 | | | $ | 386 | | | $ | 168 | | | $ | 119 | | | $ | — | | | $ | — | | | $ | 1,472 | | | External revenues | $ | 1,846 | | | $ | 1,164 | | | $ | 543 | | | $ | 269 | | | $ | — | | | $ | — | | | $ | 3,822 | | |
| Intersegment revenues | Intersegment revenues | 10 | | | 2 | | | — | | | 17 | | | — | | | (29) | | | — | | | Intersegment revenues | 18 | | | — | | | — | | | 55 | | | — | | | (73) | | | — | | |
| Net income (loss) attributable to Ameren common shareholders | 111 | | | 41 | | | 8 | | | 55 | | (a) | (8) | | | — | | | 207 | | | |
| Net income attributable to Ameren common shareholders | | Net income attributable to Ameren common shareholders | 130 | | | 127 | | | 98 | | | 143 | | (a) | 3 | | | — | | | 501 | | |
| Capital expenditures | Capital expenditures | 567 | | (b) | 129 | | | 61 | | | 131 | | | — | | | (12) | | | 876 | | (b) | Capital expenditures | 914 | | | 350 | | | 141 | | | 410 | | | 5 | | | 2 | | | 1,822 | | |
| Six Months 2022: | Six Months 2022: | | Six Months 2022: | |
| External revenues | External revenues | $ | 1,720 | | | $ | 968 | | | $ | 665 | | | $ | 252 | | | $ | — | | | $ | — | | | $ | 3,605 | | | External revenues | $ | 1,720 | | | $ | 968 | | | $ | 665 | | | $ | 252 | | | $ | — | | | $ | — | | | $ | 3,605 | | |
| Intersegment revenues | Intersegment revenues | 17 | | | 1 | | | — | | | 44 | | | — | | | (62) | | | — | | | Intersegment revenues | 17 | | | 1 | | | — | | | 44 | | | — | | | (62) | | | — | | |
| Net income attributable to Ameren common shareholders | Net income attributable to Ameren common shareholders | 150 | | | 100 | | | 86 | | | 121 | | (a) | 2 | | | — | | | 459 | | | Net income attributable to Ameren common shareholders | 150 | | | 100 | | | 86 | | | 121 | | (a) | 2 | | | — | | | 459 | | |
| Capital expenditures | Capital expenditures | 806 | | | 281 | | | 118 | | | 332 | | | 3 | | | (2) | | | 1,538 | | | Capital expenditures | 806 | | | 281 | | | 118 | | | 332 | | | 3 | | | (2) | | | 1,538 | | |
| Six Months 2021: | | |
| External revenues | $ | 1,494 | | | $ | 797 | | | $ | 515 | | | $ | 232 | | | $ | — | | | $ | — | | | $ | 3,038 | | | |
| Intersegment revenues | 19 | | | 2 | | | — | | | 34 | | | — | | | (55) | | | — | | | |
| Net income attributable to Ameren common shareholders | 158 | | | 87 | | | 83 | | | 102 | | (a) | 10 | | | — | | | 440 | | | |
| Capital expenditures | 1,101 | | (b) | 286 | | | 109 | | | 272 | | | 1 | | | (6) | | | 1,763 | | (b) | |
(a)Ameren Transmission earnings reflect an allocation of financing costs from Ameren (parent).
(b)Includes $224 million and $417 million at Ameren and Ameren Missouri for wind generation expenditures for the three and six months ended June 30, 2021, respectively.
Ameren Illinois
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois |
| Three Months 2022: | | | | | | | | | |
| External revenues | $ | 504 | | | $ | 184 | | | $ | 81 | | | $ | — | | | $ | 769 | |
| Intersegment revenues | — | | | — | | | 24 | | | (24) | | | — | |
| Net income available to common shareholder | 51 | | | 6 | | | 46 | | | — | | | 103 | |
| Capital expenditures | 143 | | | 69 | | | 145 | | | — | | | 357 | |
| Three Months 2021: | | | | | | | | | |
| External revenues | $ | 388 | | | $ | 168 | | | $ | 73 | | | $ | — | | | $ | 629 | |
| Intersegment revenues | — | | | — | | | 15 | | | (15) | | | — | |
| Net income available to common shareholder | 41 | | | 8 | | | 37 | | | — | | | 86 | |
| Capital expenditures | 129 | | | 61 | | | 119 | | | — | | | 309 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois |
| Six Months 2022: | | | | | | | | | |
| External revenues | $ | 969 | | | $ | 665 | | | $ | 159 | | | $ | — | | | $ | 1,793 | |
| Intersegment revenues | — | | | — | | | 44 | | | (44) | | | — | |
| Net income available to common shareholder | 100 | | | 86 | | | 86 | | | — | | | 272 | |
| Capital expenditures | 281 | | | 118 | | | 300 | | | — | | | 699 | |
| Six Months 2021: | | | | | | | | | |
| External revenues | $ | 799 | | | $ | 515 | | | $ | 138 | | | $ | — | | | $ | 1,452 | |
| Intersegment revenues | — | | | — | | | 31 | | | (31) | | | — | |
| Net income available to common shareholder | 87 | | | 83 | | | 65 | | | — | | | 235 | |
| Capital expenditures | 286 | | | 109 | | | 251 | | | — | | | 646 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois |
| Three Months 2023: | | | | | | | | | |
| External revenues | $ | 540 | | | $ | 152 | | | $ | 87 | | | $ | — | | | $ | 779 | |
| Intersegment revenues | — | | | — | | | 26 | | | (26) | | | — | |
| Net income available to common shareholder | 66 | | | 11 | | | 52 | | | — | | | 129 | |
| Capital expenditures | 180 | | | 90 | | | 167 | | | — | | | 437 | |
| Three Months 2022: | | | | | | | | | |
| External revenues | $ | 504 | | | $ | 184 | | | $ | 81 | | | $ | — | | | $ | 769 | |
| Intersegment revenues | — | | | — | | | 24 | | | (24) | | | — | |
| Net income available to common shareholder | 51 | | | 6 | | | 46 | | | — | | | 103 | |
| Capital expenditures | 143 | | | 69 | | | 145 | | | — | | | 357 | |
| Six Months 2023: | | | | | | | | | |
| External revenues | $ | 1,164 | | | $ | 543 | | | $ | 173 | | | $ | — | | | $ | 1,880 | |
| Intersegment revenues | — | | | — | | | 54 | | | (54) | | | — | |
| Net income available to common shareholder | 127 | | | 98 | | | 102 | | | — | | | 327 | |
| Capital expenditures | 350 | | | 141 | | | 353 | | | — | | | 844 | |
| Six Months 2022: | | | | | | | | | |
| External revenues | $ | 969 | | | $ | 665 | | | $ | 159 | | | $ | — | | | $ | 1,793 | |
| Intersegment revenues | — | | | — | | | 44 | | | (44) | | | — | |
| Net income available to common shareholder | 100 | | | 86 | | | 86 | | | — | | | 272 | |
| Capital expenditures | 281 | | | 118 | | | 300 | | | — | | | 699 | |
The following tables present disaggregated revenues by segment at Ameren and Ameren Illinois for the three and six months ended June 30, 20222023 and 2021.2022. Economic factors affect the nature, timing, amount, and uncertainty of revenues and cash flows in a similar manner across customer classes. Revenues from alternative revenue programs have a similar distribution among customer classes as revenues from contracts with customers. Other revenues not associated with contracts with customers are presented in the Other customer classification, along with electric transmission, off-system sales, and off-systemcapacity revenues.
Ameren
| | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | | Intersegment Eliminations | | Ameren | | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | | Intersegment Eliminations | | Ameren | |
| Three Months 2022: | | | | |
| Three Months 2023: | | Three Months 2023: | | | |
| Residential | Residential | $ | 371 | | | $ | 284 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 655 | | | Residential | $ | 360 | | | $ | 337 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 697 | | |
| Commercial | Commercial | 298 | | | 180 | | | — | | | — | | | | — | | | 478 | | | Commercial | 311 | | | 193 | | | — | | | — | | | | — | | | 504 | | |
| Industrial | Industrial | 73 | | | 53 | | | — | | | — | | | | — | | | 126 | | | Industrial | 75 | | | 48 | | | — | | | — | | | | — | | | 123 | | |
| Other | Other | 148 | | | (13) | |
| — | | | 150 | | | | (31) | | | 254 | | | Other | 172 | | | (38) | | (a) | — | | | 161 | | | | (34) | | | 261 | | |
| Total electric revenues | Total electric revenues | $ | 890 | | | $ | 504 | | | $ | — | | | $ | 150 | | | | $ | (31) | | | $ | 1,513 | | | Total electric revenues | $ | 918 | | | $ | 540 | | | $ | — | | | $ | 161 | | | | $ | (34) | | | $ | 1,585 | | |
| Residential | Residential | $ | 16 | | | $ | — | | | $ | 117 | | | $ | — | | | | $ | — | | | $ | 133 | | | Residential | $ | 13 | | | $ | — | | | $ | 98 | | | $ | — | | | | $ | — | | | $ | 111 | | |
| Commercial | Commercial | 8 | | | — | | | 30 | | | — | | | | — | | | 38 | | | Commercial | 6 | | | — | | | 25 | | | — | | | | — | | | 31 | | |
| Industrial | Industrial | 1 | | | — | | | 11 | | | — | | | | — | | | 12 | | | Industrial | 1 | | | — | | | 2 | | | — | | | | — | | | 3 | | |
| Other | Other | 4 | | | — | | | 26 | |
| — | | | | — | | | 30 | | | Other | 3 | | | — | | | 27 | |
| — | | | | — | | | 30 | | |
| Total natural gas revenues | Total natural gas revenues | $ | 29 | | | $ | — | | | $ | 184 | | | $ | — | | | | $ | — | | | $ | 213 | | | Total natural gas revenues | $ | 23 | | | $ | — | | | $ | 152 | | | $ | — | | | | $ | — | | | $ | 175 | | |
Total revenues(a)(b) | Total revenues(a)(b) | $ | 919 | | | $ | 504 | | | $ | 184 | | | $ | 150 | | | | $ | (31) | | | $ | 1,726 | | | Total revenues(a)(b) | $ | 941 | | | $ | 540 | | | $ | 152 | | | $ | 161 | | | | $ | (34) | | | $ | 1,760 | | |
| Three Months 2021: | | | | |
| Residential | $ | 328 | | | $ | 218 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 546 | | | |
| Commercial | 271 | | | 127 | | | — | | | — | | | | — | | | 398 | | | |
| Industrial | 71 | | | 34 | | | — | | | — | | | | — | | | 105 | | | |
| Other | 119 | |
| 9 | | | — | | | 136 | | | | (29) | | | 235 | |
| |
| Total electric revenues | $ | 789 | | | $ | 388 | | | $ | — | | | $ | 136 | | | | $ | (29) | | | $ | 1,284 | | | |
| Residential | $ | 11 | | | $ | — | | | $ | 112 | | | $ | — | | | | $ | — | | | $ | 123 | | | |
| Commercial | 4 | | | — | | | 29 | | | — | | | | — | | | 33 | | | |
| Industrial | 1 | | | — | | | 3 | | | — | | | | — | | | 4 | | | |
| Other | 4 | | | — | | | 24 | | | — | | | | — | | | 28 | | | |
| Total natural gas revenues | $ | 20 | | | $ | — | | | $ | 168 | | | $ | — | | | | $ | — | | | $ | 188 | | | |
Total revenues(a) | $ | 809 | | | $ | 388 | | | $ | 168 | | | $ | 136 | | | | $ | (29) | | | $ | 1,472 | | | |
| | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | | Intersegment Eliminations | | Ameren | | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | | Intersegment Eliminations | | Ameren | |
| Three Months 2022: | | Three Months 2022: | | | |
| Residential | | Residential | $ | 371 | | | $ | 284 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 655 | | |
| Commercial | | Commercial | 298 | | | 180 | | | — | | | — | | | | — | | | 478 | | |
| Industrial | | Industrial | 73 | | | 53 | | | — | | | — | | | | — | | | 126 | | |
| Other | | Other | 148 | |
| (13) | | (a) | — | | | 150 | | | | (31) | | | 254 | |
|
| Total electric revenues | | Total electric revenues | $ | 890 | | | $ | 504 | | | $ | — | | | $ | 150 | | | | $ | (31) | | | $ | 1,513 | | |
| Residential | | Residential | $ | 16 | | | $ | — | | | $ | 117 | | | $ | — | | | | $ | — | | | $ | 133 | | |
| Commercial | | Commercial | 8 | | | — | | | 30 | | | — | | | | — | | | 38 | | |
| Industrial | | Industrial | 1 | | | — | | | 11 | | | — | | | | — | | | 12 | | |
| Other | | Other | 4 | | | — | | | 26 | | | — | | | | — | | | 30 | | |
| Total natural gas revenues | | Total natural gas revenues | $ | 29 | | | $ | — | | | $ | 184 | | | $ | — | | | | $ | — | | | $ | 213 | | |
Total revenues(b) | | Total revenues(b) | $ | 919 | | | $ | 504 | | | $ | 184 | | | $ | 150 | | | | $ | (31) | | | $ | 1,726 | | |
| Six Months 2023: | | Six Months 2023: | | | |
| Residential | | Residential | $ | 684 | | | $ | 719 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 1,403 | | |
| Commercial | | Commercial | 558 | | | 393 | | | — | | | — | | | | — | | | 951 | | |
| Industrial | | Industrial | 136 | | | 96 | | | — | | | — | | | | — | | | 232 | | |
| Other | | Other | 381 | | | (44) | | (a) | — | | | 324 | | | | (72) | | | 589 | | |
| Total electric revenues | | Total electric revenues | $ | 1,759 | | | $ | 1,164 | | | $ | — | | | $ | 324 | | | | $ | (72) | | | $ | 3,175 | | |
| Residential | | Residential | $ | 65 | | | $ | — | | | $ | 394 | | | $ | — | | | | $ | — | | | $ | 459 | | |
| Commercial | | Commercial | 29 | | | — | | | 102 | | | — | | | | — | | | 131 | | |
| Industrial | | Industrial | 3 | | | — | | | 9 | | | — | | | | — | | | 12 | | |
| Other | | Other | 8 | | | — | | | 38 | | | — | | | | (1) | | | 45 | | |
| Total natural gas revenues | | Total natural gas revenues | $ | 105 | | | $ | — | | | $ | 543 | | | $ | — | | | | $ | (1) | | | $ | 647 | | |
Total revenues(b) | | Total revenues(b) | $ | 1,864 | | | $ | 1,164 | | | $ | 543 | | | $ | 324 | | | | $ | (73) | | | $ | 3,822 | | |
| Six Months 2022: | Six Months 2022: | | | | Six Months 2022: | | | |
| Residential | Residential | $ | 703 | | | $ | 547 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 1,250 | | | Residential | $ | 703 | | | $ | 547 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 1,250 | | |
| Commercial | Commercial | 538 | | | 338 | | | — | | | — | | | | — | | | 876 | | | Commercial | 538 | | | 338 | | | — | | | — | | | | — | | | 876 | | |
| Industrial | Industrial | 130 | | | 98 | | | — | | | — | | | | — | | | 228 | | | Industrial | 130 | | | 98 | | | — | | | — | | | | — | | | 228 | | |
| Other | Other | 257 | | | (14) | | | — | | | 296 | | | | (62) | | | 477 | | | Other | 257 | | | (14) | | (a) | — | | | 296 | | | | (62) | | | 477 | | |
| Total electric revenues | Total electric revenues | $ | 1,628 | | | $ | 969 | | | $ | — | | | $ | 296 | | | | $ | (62) | | | $ | 2,831 | | | Total electric revenues | $ | 1,628 | | | $ | 969 | | | $ | — | | | $ | 296 | | | | $ | (62) | | | $ | 2,831 | | |
| Residential | Residential | $ | 67 | | | $ | — | | | $ | 486 | | | $ | — | | | | $ | — | | | $ | 553 | | | Residential | $ | 67 | | | $ | — | | | $ | 486 | | | $ | — | | | | $ | — | | | $ | 553 | | |
| Commercial | Commercial | 30 | | | — | | | 127 | | | — | | | | — | | | 157 | | | Commercial | 30 | | | — | | | 127 | | | — | | | | — | | | 157 | | |
| Industrial | Industrial | 3 | | | — | | | 28 | | | — | | | | — | | | 31 | | | Industrial | 3 | | | — | | | 28 | | | — | | | | — | | | 31 | | |
| Other | Other | 9 | | | — | | | 24 | | | — | | | | — | | | 33 | | | Other | 9 | | | — | | | 24 | | | — | | | | — | | | 33 | | |
| Total natural gas revenues | Total natural gas revenues | $ | 109 | | | $ | — | | | $ | 665 | | | $ | — | | | | $ | — | | | $ | 774 | | | Total natural gas revenues | $ | 109 | | | $ | — | | | $ | 665 | | | $ | — | | | | $ | — | | | $ | 774 | | |
Total revenues(a) | $ | 1,737 | | | $ | 969 | | | $ | 665 | | | $ | 296 | | | | $ | (62) | | | $ | 3,605 | | | |
| Six Months 2021: | | | | |
| Residential | $ | 640 | | | $ | 447 | | | $ | — | | | $ | — | | | | $ | — | | | $ | 1,087 | | | |
| Commercial | 487 | | | 259 | | | — | | | — | | | | — | | | 746 | | | |
| Industrial | 123 | | | 68 | | | — | | | — | | | | — | | | 191 | | | |
| Other | 180 | | | 25 | | | — | | | 266 | | | | (55) | | | 416 | | | |
| Total electric revenues | $ | 1,430 | | | $ | 799 | | | $ | — | | | $ | 266 | | | | $ | (55) | | | $ | 2,440 | | | |
| Residential | $ | 45 | | | $ | — | | | $ | 363 | | | $ | — | | | | $ | — | | | $ | 408 | | | |
| Commercial | 19 | | | — | | | 93 | | | — | | | | — | | | 112 | | | |
| Industrial | 2 | | | — | | | 17 | | | — | | | | — | | | 19 | | | |
| Other | 17 | | | — | | | 42 | | | — | | | | — | | | 59 | | | |
| Total natural gas revenues | $ | 83 | | | $ | — | | | $ | 515 | | | $ | — | | | | $ | — | | | $ | 598 | | | |
Total revenues(a) | $ | 1,513 | | | $ | 799 | | | $ | 515 | | | $ | 266 | | | | $ | (55) | | | $ | 3,038 | | | |
Total revenues(b) | | Total revenues(b) | $ | 1,737 | | | $ | 969 | | | $ | 665 | | | $ | 296 | | | | $ | (62) | | | $ | 3,605 | | |
(a)Includes over-recoveries of various riders.
(b)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Ameren | | | Ameren Missouri | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Transmission | | Ameren | |
| Three Months 2023: | | Three Months 2023: | |
| Revenues from alternative revenue programs | | Revenues from alternative revenue programs | $ | — | | | $ | 60 | | | $ | 9 | | | $ | 5 | | | $ | 74 | | |
| Other revenues not from contracts with customers | | Other revenues not from contracts with customers | (2) | | (a) | 2 | | | 1 | | | — | | | 1 | | (a) |
| Three Months 2022: | Three Months 2022: | | Three Months 2022: | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | — | | | $ | 41 | | | $ | 3 | | | $ | (4) | | | $ | 40 | | | Revenues from alternative revenue programs | $ | — | | | $ | 41 | | | $ | 3 | | | $ | (4) | | | $ | 40 | | |
| Other revenues not from contracts with customers | Other revenues not from contracts with customers | (36) | | | 1 | | | 1 | | | — | | | (34) | | | Other revenues not from contracts with customers | (36) | | (a) | 1 | | | 1 | | | — | | | (34) | | (a) |
| Three Months 2021: | | |
| Six Months 2023: | | Six Months 2023: | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | (5) | | | $ | 34 | | | $ | 2 | | | $ | 5 | | | $ | 36 | | | Revenues from alternative revenue programs | $ | (2) | | | $ | 124 | | | $ | 37 | | | $ | 13 | | | $ | 172 | | |
| Other revenues not from contracts with customers | Other revenues not from contracts with customers | 66 | | (a) | — | | | 1 | | | — | | | 67 | | (a) | Other revenues not from contracts with customers | (8) | | (a) | 4 | | | 2 | | | — | | | (2) | | (a) |
| Six Months 2022: | Six Months 2022: | | Six Months 2022: | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | (6) | | | $ | 96 | | | $ | (2) | | | $ | (3) | | | $ | 85 | | | Revenues from alternative revenue programs | $ | (6) | | | $ | 96 | | | $ | (2) | | | $ | (3) | | | $ | 85 | | |
| Other revenues not from contracts with customers | Other revenues not from contracts with customers | (36) | | (a) | 3 | | | 2 | | | — | | | (31) | | (a) | Other revenues not from contracts with customers | (36) | | (a) | 3 | | | 2 | | | — | | | (31) | | (a) |
| Six Months 2021: | | |
| Revenues from alternative revenue programs | $ | (15) | | | $ | 95 | | | $ | 5 | | | $ | 4 | | | $ | 89 | | | |
| Other revenues not from contracts with customers | 64 | | (a) | 3 | | | 2 | | | — | | | 69 | | (a) | |
(a)Includes insurance recoveries related to lost sales associated with the Callaway Energy Center maintenance outage. See Note 9 – Callaway Energy Center under Part II, Item 8, of the Form 10-K for additional information.net realized losses on derivative power contracts.
Ameren Illinois
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| Three Months 2023: | | | | | | | | | | |
| Residential | $ | 337 | | | $ | 98 | | | $ | — | | | $ | — | | | $ | 435 | | |
| Commercial | 193 | | | 25 | | | — | | | — | | | 218 | | |
| Industrial | 48 | | | 2 | | | — | | | — | | | 50 | | |
| Other | (38) | | (a) | 27 | |
| 113 | | | (26) | | | 76 | | |
Total revenues(b) | $ | 540 | | | $ | 152 | | | $ | 113 | | | $ | (26) | | | $ | 779 | | |
| Three Months 2022: | | | | | | | | | | |
| Residential | $ | 284 | | | $ | 117 | | | $ | — | | | $ | — | | | $ | 401 | | |
| Commercial | 180 | | | 30 | | | — | | | — | | | 210 | | |
| Industrial | 53 | | | 11 | | | — | | | — | | | 64 | | |
| Other | (13) | | (a) | 26 | | | 105 | | | (24) | | | 94 | | |
Total revenues(b) | $ | 504 | | | $ | 184 | | | $ | 105 | | | $ | (24) | | | $ | 769 | | |
| Six Months 2023: | | | | | | | | | | |
| Residential | $ | 719 | | | $ | 394 | | | $ | — | | | $ | — | | | $ | 1,113 | | |
| Commercial | 393 | | | 102 | | | — | | | — | | | 495 | | |
| Industrial | 96 | | | 9 | | | — | | | — | | | 105 | | |
| Other | (44) | | (a) | 38 | | | 227 | | | (54) | | | 167 | | |
Total revenues(b) | $ | 1,164 | | | $ | 543 | | | $ | 227 | | | $ | (54) | | | $ | 1,880 | | |
| Six Months 2022: | | | | | | | | | | |
| Residential | $ | 547 | | | $ | 486 | | | $ | — | | | $ | — | | | $ | 1,033 | | |
| Commercial | 338 | | | 127 | | | — | | | — | | | 465 | | |
| Industrial | 98 | | | 28 | | | — | | | — | | | 126 | | |
| Other | (14) | | (a) | 24 | | | 203 | | | (44) | | | 169 | | |
Total revenues(b) | $ | 969 | | | $ | 665 | | | $ | 203 | | | $ | (44) | | | $ | 1,793 | | |
Ameren Illinois
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Intersegment Eliminations | | Ameren Illinois | |
| Three Months 2022: | | | | | | | | | | |
| Residential | $ | 284 | | | $ | 117 | | | $ | — | | | $ | — | | | $ | 401 | | |
| Commercial | 180 | | | 30 | | | — | | | — | | | 210 | | |
| Industrial | 53 | | | 11 | | | — | | | — | | | 64 | | |
| Other | (13) | |
| 26 | |
| 105 | | | (24) | | | 94 | | |
Total revenues(a) | $ | 504 | | | $ | 184 | | | $ | 105 | | | $ | (24) | | | $ | 769 | | |
| Three Months 2021: | | | | | | | | | | |
| Residential | $ | 218 | | | $ | 112 | | | $ | — | | | $ | — | | | $ | 330 | | |
| Commercial | 127 | | | 29 | | | — | | | — | | | 156 | | |
| Industrial | 34 | | | 3 | | | — | | | — | | | 37 | | |
| Other | 9 | | | 24 | | | 88 | | | (15) | | | 106 | | |
Total revenues(a) | $ | 388 | | | $ | 168 | | | $ | 88 | | | $ | (15) | | | $ | 629 | | |
| Six Months 2022: | | | | | | | | | | |
| Residential | $ | 547 | | | $ | 486 | | | $ | — | | | $ | — | | | $ | 1,033 | | |
| Commercial | 338 | | | 127 | | | — | | | — | | | 465 | | |
| Industrial | 98 | | | 28 | | | — | | | — | | | 126 | | |
| Other | (14) | | | 24 | | | 203 | | | (44) | | | 169 | | |
Total revenues(a) | $ | 969 | | | $ | 665 | | | $ | 203 | | | $ | (44) | | | $ | 1,793 | | |
| Six Months 2021: | | | | | | | | | | |
| Residential | $ | 447 | | | $ | 363 | | | $ | — | | | $ | — | | | $ | 810 | | |
| Commercial | 259 | | | 93 | | | — | | | — | | | 352 | | |
| Industrial | 68 | | | 17 | | | — | | | — | | | 85 | | |
| Other | 25 | | | 42 | | | 169 | | | (31) | | | 205 | | |
Total revenues(a) | $ | 799 | | | $ | 515 | | | $ | 169 | | | $ | (31) | | | $ | 1,452 | | |
(a)(b)The following table presents increases/(decreases) in revenues from alternative revenue programs and other revenues not from contracts with customers for the Ameren Illinois segments for the three and six months ended June 30, 20222023 and 2021:2022:
| | | | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois |
| Three Months 2023: | | Three Months 2023: | |
| Revenues from alternative revenue programs | | Revenues from alternative revenue programs | $ | 60 | | | $ | 9 | | | $ | 3 | | | $ | 72 | |
| Other revenues not from contracts with customers | | Other revenues not from contracts with customers | 2 | | | 1 | | | — | | | 3 | |
| | Ameren Illinois Electric Distribution | | Ameren Illinois Natural Gas | | Ameren Illinois Transmission | | Ameren Illinois | |
| Three Months 2022: | Three Months 2022: | | Three Months 2022: | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | 41 | | | $ | 3 | | | $ | (3) | | | $ | 41 | | Revenues from alternative revenue programs | $ | 41 | | | $ | 3 | | | $ | (3) | | | $ | 41 | |
| Other revenues not from contracts with customers | Other revenues not from contracts with customers | 1 | | | 1 | | | — | | | 2 | | Other revenues not from contracts with customers | 1 | | | 1 | | | — | | | 2 | |
| | Three Months 2021: | | |
| Six Months 2023: | | Six Months 2023: | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | 34 | | | $ | 2 | | | $ | 2 | | | $ | 38 | | Revenues from alternative revenue programs | $ | 124 | | | $ | 37 | | | $ | 10 | | | $ | 171 | |
| Other revenues not from contracts with customers | Other revenues not from contracts with customers | — | | | 1 | | | — | | | 1 | | Other revenues not from contracts with customers | 4 | | | 2 | | | — | | | 6 | |
| | Six Months 2022: | Six Months 2022: | | Six Months 2022: | |
| Revenues from alternative revenue programs | Revenues from alternative revenue programs | $ | 96 | | | $ | (2) | | | $ | (2) | | | $ | 92 | | Revenues from alternative revenue programs | $ | 96 | | | $ | (2) | | | $ | (2) | | | $ | 92 | |
| Other revenues not from contracts with customers | Other revenues not from contracts with customers | 3 | | | 2 | | | — | | | 5 | | Other revenues not from contracts with customers | 3 | | | 2 | | | — | | | 5 | |
| | Six Months 2021: | | |
| Revenues from alternative revenue programs | $ | 95 | | | $ | 5 | | | $ | 1 | | | $ | 101 | | |
| Other revenues not from contracts with customers | 3 | | | 2 | | | — | | | 5 | | |
|
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q, as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of our business segments to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company whose primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. Dividends on
Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Ameren has other subsidiaries that conduct other activities, such as providing shared services.
•Union Electric Company, doing business as Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business and a rate-regulated natural gas distribution business in Missouri.
•Ameren Illinois Company, doing business as Ameren Illinois operates rate-regulated electric transmission, electric distribution, and natural gas distribution businesses in Illinois.
•ATXI operates a FERC rate-regulated electric transmission business in the MISO.
Ameren’s and Ameren Missouri’s financial statements are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries. All intercompany transactions have been eliminated. Ameren Missouri’s subsidiaries were created for the ownershipacquisition of renewable generation projects. Ameren Illinois has no subsidiaries. All tabular dollar amounts are in millions, unless otherwise indicated.
In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share.
OVERVIEW
Net income attributable to Ameren common shareholders in the three months ended June 30, 2023, was $237 million, or $0.90 per diluted share, compared with $207 million, or $0.80 per diluted share, in both the three months ended June 30, 2022 and 2021.year-ago period. Net income attributable to Ameren common shareholders in the six months ended June 30, 2022,2023, was $459$501 million, or $1.77$1.90 per diluted share, compared with $440$459 million, or $1.71$1.77 per diluted share, in the year-ago period. Net income for the three and six months ended June 30, 2022,2023, was favorably affected by increased rate base investments across all segments, and a higher recognized ROE at Ameren Illinois Electric Distribution due to a higher estimated annual average of the monthly yields of the 30-year United States Treasury bonds, and increased retail electric sales volumes at Ameren Missouri, primarily resulting from colder winter and warmer early summer temperatures experienced in 2022. Net income for the three and six months ended June 30, 2022, compared with the year-ago periods, were unfavorably affected by increaseddecreased other operations and maintenance expenses not subject to formula rates, riders, or trackers, primarily due to a reductionincluding an increase in the cash surrender value of company-owned life insurance, higher transmissionCOLI. Net income for the three and distribution expenses due tosix months ended June 30, 2023, compared with the timing of expenses and disciplined project management, and an increase due to the expiration of contracts relating to refined coal tax credits year-ago periods, was unfavorably affected by decreased electric retail sales at Ameren Missouri, primarily resulting from milder spring and early summer temperatures in 2021. Net income comparisonsthe three month period ended June 30, 2023, as well as
warmer winter temperatures in boththe six month period ended June 30, 2023, compared with the same periods were also unfavorably affected byin 2022; and increased financing costs from the issuance of long-term debt issuances. Earnings per share comparisons in both periods were unfavorably affected by an increase in the weighted-average basic common shares outstanding.at Ameren Missouri and higher interest rates on increased levels of short-term borrowings.
Ameren’s strategic plan includes investing and operating its utilities in a manner consistent with existingrate-regulated energy infrastructure, enhancing regulatory frameworks, enhancing those frameworks and advocating for responsible energypolicies, and economic policies, as well as creating and capitalizingoptimizing operating performance to capitalize on opportunities for investment for theto benefit of itsour customers, our shareholders, and the environment. Ameren remains focused on disciplined cost management and strategic capital allocation. Ameren invested $1.5$1.8 billion in its rate-regulated businesses in the six months ended June 30, 2022.2023.
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 COVID-19 pandemic continuesapproved revenue requirement is based on infrastructure investments as of December 31, 2022, and included an extension of the depreciable lives of the Sioux Energy Center’s assets from 2028 to affect our results2030. The order did not explicitly specify an ROE, capital structure, or rate base. The order provides for the continued use of operations, financial position,the FAC and liquidity. While ourtrackers for pension and postretirement benefits, uncertain income tax positions, certain excess deferred income taxes, and renewable energy standard costs that the MoPSC previously authorized in earlier electric sales volumes, excludingrate orders, as well as the estimated effectsuse of weatheran electric property tax tracker. It also includes a tracker for the utilization of production and customer energy-efficiency programs,investment tax credits or proceeds from the sale of 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.
In June 2023, Ameren Missouri filed for CCNs with the MoPSC for four solar generation facilities and expects decisions in the first six monthsquarter of 2022, compared to2024. These facilities include the same period in 2021, they were comparable to pre-pandemic levels at Ameren Missouri and remain below pre-pandemic levels at Ameren Illinois. However, revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission businesses are decoupled from changes in sales volumes. Earnings at Ameren Missouri and those associated with Ameren Illinois’ large nonresidential natural gas customers are exposed to such changes. There has also been a shift in sales volumes by customer class at both Ameren Missouri and Ameren Illinois, which began in 2020, with an increase in residential sales, and a decrease in commercial and industrial sales. The continued effect ofSplit Rail Solar Project (300-MW facility, build-transfer agreement), the COVID-19 pandemic on our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto,Cass County Solar Project (150-MW facility, development-transfer agreement), the Vandalia Solar Project (50-MW facility, self-build), and the resulting impact on business, economic,Bowling Green Solar Project (50-MW facility, self-build). The Cass County Solar Project is expected to be located in central Illinois and capital market conditions. We continuethe other three projects are expected to assessbe located in central Missouri. Each project is expected to support Ameren Missouri’s transition to renewable generation. In February and April 2023, the impactsMoPSC issued orders approving requested CCNs for the COVID-19 pandemic is having on our businesses, including impacts on electricHuck Finn and natural gas sales volumes, liquidity, bad debt expense, and supply chain operations. For further discussion of these and other matters discussed below, see Note 1 – Summary of Significant Accounting Policies and Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report, and Results of Operations, Liquidity and Capital Resources, and Outlook sections below.Boomtown solar projects, respectively.
In December 2021,March 2023, Ameren Missouri filed a motionproposed three-year customer energy-efficiency plan with the United States District Court forMoPSC under the Eastern DistrictMEEIA. As a result of Missouri to modify a September 2019 remedy order issuednonunanimous stipulation and agreement filed with the MoPSC in August 2023 by the district court to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. In June 2022, Ameren Missouri, supplemented its filing with the district court by proposing reduced operations, mostly operating during peak demand timesMoPSC staff, and emergencies until the energy center is retired. The March 31,MoOPC to extend Ameren Missouri’s MEEIA 2019 program through 2024, compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. In July 2022, in response to an Ameren Missouri requestexpects to revise the proposed three-year plan in 2024. The stipulation and agreement, which is subject to MoPSC approval, includes the establishment of a portfolio of customer energy-efficiency programs for a final, binding reliability assessment, the MISO
designated the Rush Island Energy Center as a system support resource2024 and concludedperformance incentives that certain mitigation measures, including transmission upgrades, should occur before the energy center is retired. The transmission upgrade projects have been approved by the MISO, andwould provide Ameren Missouri has started design and procurement activities necessaryan opportunity to complete the upgrades andearn revenues, including $12 million if Ameren Missouri achieves certain energy-efficiency goals in 2024. If approved, Ameren Missouri expects to complete the upgrades by late 2025.invest $76 million in energy-efficiency programs in 2024. The FERC will need to approve a system support resource agreement detailing the manner of continued operation of the Rush Island Energy Center, as well as a request from Ameren Missouri for recovery of non-energy costs under the related MISO tariff. The agreement, if approved, would have a term of 12 months. The system support resource designation and the related agreement are subject to renewal and revision. Any difference between revenues and costs under the MISO tariff is expected to be included in the FAC. The district court has the authority to determine the retirement date and operating parameters for the Rush Island Energy Center and is not bound by the MISO determination of the Rush Island Energy Center as a system support resource or the FERC’s approval. While the district courtMoPSC is under no deadline to issue a ruling modifying the remedy order, a decision is expected in the near term. Related to this matter, in February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center, including potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, which is expected to be addressed in the current electric service regulatory rate review, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. Ameren Missouri expects to seek approval from the MoPSC to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds pursuant to the Missouri securitization statute. See Note 9 – Commitments and Contingencies under Part I, Item 1, of this report for additional information.proceeding.
In February 2022,2023, 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 2022.2023. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4$9.9 billion over the five-year period from 20222023 through 2026,2027, with expenditures largely recoverable under the PISA and the RESRAM. Ameren Missouri’s Smart Energy Plan excludes investments in its natural gas distribution business, as well as removal costs, net of salvage.
In February 2022,July 2023, Ameren Missouri, throughIllinois filed a subsidiary, entered into a build-transfer agreement to acquire, after construction, a 150-MW solar generation facility, which is expectedrevised MYRP with the ICC to be locatedused in southeastern Illinoissetting electric distribution service rates for 2024 through 2027. Under the MYRP, the ICC would approve base rates for electric distribution service to be charged to customers for each calendar year of the four-year period. The following table includes the forecasted revenue requirement, the requested ROE, the requested capital structure common equity percentage, and ifthe forecasted average annual rate base for 2024 through 2027, as reflected in Ameren Illinois’ revised MYRP filing:
| | | | | | | | | | | | | | |
| Year | Forecasted Revenue Requirement (in millions)(a) | Requested ROE | Requested Capital Structure Common Equity Percentage(b) | Forecasted Average Annual Rate Base (in billions) |
| 2024 | $1,291 | 10.5% | 53.99% | $4.3 |
| 2025 | $1,387 | 10.5% | 53.97% | $4.6 |
| 2026 | $1,484 | 10.5% | 54.02% | $4.9 |
| 2027 | $1,560 | 10.5% | 54.03% | $5.2 |
(a)If an initial rate increase phase-in provision, discussed below, is approved by the MoPSC, serve customers under Ameren Missouri’s Renewable Solutions Program. In June 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, a 200-MW solar generation facility, which is expected to be located in central Missouri and support Ameren Missouri’s compliance withICC, it would not affect the state of Missouri’sannual revenue requirement, of achieving 15% of retail sales from renewable energy sources, of which 2% must be derived from solar energy sources. The acquisitionsare aligned with the 2022 Change to the 2020 IRP, which Ameren Missouri filed with the MoPSC in June 2022, and are subject to certain conditions, including the issuance of certificates of convenience and necessity by the MoPSC, obtaining MISO transmission interconnection agreements, and approval by the FERC. In July 2022, Ameren Missouri filed for certificates of convenience and necessity with the MoPSC for both facilities and expects decisions by March 2023 and April 2023 for the 200-MW facility and the 150-MW facility, respectively. Depending onbut would affect the timing of regulatory approvals and the impact of potential sourcing issues resultingassociated recovery from a Department of Commerce investigation of solar panels imported from four Southeast Asian countries initiated in late March 2022 and the detention of certain solar panels sourced from China as a result of the Uyghur Forced Labor Prevention Act that was passed in December 2021, the projects could be completed as early as the fourth quarter of 2024.customers.
In June 2022, Missouri Senate Bill 745 was enacted and will become effective on August 28, 2022. The law extended Ameren Missouri’s PISA election through December 2028 and allows for an additional five-year extension through December 2033 if requested by Ameren Missouri and approved by the MoPSC, among other things. The law established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024, and will be based on the revenue requirement established in the immediately preceding rate order. The current rate limitation, which is effective through 2023, is a 2.85% cap on the compound annual growth rate in the average overall customer rate per kilowatthour, based on the electric rates that became effective in April 2017, less half of the annual savings from the TCJA that was passed on to customers as approved in a July 2018 MoPSC order. The law also established electric and natural gas property tax trackers that allow Ameren Missouri to defer the difference between actual property taxes incurred and related taxes included in customer rates as a regulatory asset or regulatory liability, with the difference expected to be reflected in rate base in a subsequent rate order.
In August 2022, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $316 million. The electric rate increase request is based on a 10.2% ROE, a(b)A capital structure composed of 51.9% common equity, a rate base of $11.6 billion, and a test year ended March 31, 2022, with certain pro-forma adjustments expected through an anticipated true-up date of December 31, 2022. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, with a decisionand including 50% common equity is deemed prudent and reasonable by the MoPSC expected by June 2023 and new rates effective by July 2023.law. A higher equity ratio requires specific ICC approval.
In January 2022, Ameren Illinois filed a requestUnder an MYRP, the IETL permits any initial rate increase to be phased in, with at least 50% of the first annual period’s approved rate increase reflected in rates in the first annual period, with the ICC proposing performance metricsremaining portion deferred as a regulatory asset that would be used in determining ROE incentivesearns a return at the applicable WACC and penalties under an MYRP. In April 2022,is collected from customers over a period not to exceed two years beginning within one year after the second annual period’s rates are effective. Ameren Illinois filedIllinois’ revised MYRP filing utilizes this phase-in provision and proposes to defer 50% of the requested 2024 rate increase of $179 million as a revised request proposing total ROE incentives and penalties of 24 basis points, allocated evenly among eight proposed performance metrics. In May 2022, the ICC staff recommended that the ICC allow ROE incentives and penalties of no less than 20 basis points and no more than 24 basis points, allocated evenly across the number of performance metrics ultimately approved by the ICC. The ICC is required to issue an order on this matter by September 30, 2022.
In April 2022, Ameren Illinois filed its annual electric distribution service performance-based formula rate update with the ICCregulatory asset to be used for 2023 rates. In July 2022, Ameren Illinois filed a revised request seeking to increase its annual revenues for electric distribution service by $84 million. In June 2022, the ICC staff submitted its calculation of the revenue requirement includedcollected from customers in Ameren Illinois’ update filing, recommending a $60 million increase in Ameren Illinois’ electric distribution service rates.2026. An ICC decision in this proceeding is required by December 2022,2023, with new rates effective starting in January 2023.2024.
In July 2023, Ameren Illinois filed a revised reconciliation adjustment to its 2022 electric distribution service revenue requirement with the ICC, requesting recovery of $125 million. The reconciliation adjustment reflects Ameren Illinois’ actual 2022 recoverable costs, year-end rate base, and capital structure, which was composed of 54% common equity. An ICC decision in this proceeding is required by December 2023, and any approved adjustment would be collected from customers in 2024.
In June 2022,July 2023, Ameren Illinois filed a revised request with the ICC seeking approval to increase its annual revenues for natural gas delivery service by $148 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the QIP and other riders. The request is based on a 10.3% allowed ROE, a capital structure composed of 53.99% common equity, and a rate base of $2.9 billion. In an attempt to reduce regulatory lag, Ameren Illinois used a 2024 future test year in this proceeding.A decision by the ICC in this proceeding is required by late November 2023, with new rates expected to be effective in early December 2023.
In May 2023, Ameren Illinois filed its annual electric customer energy-efficiency formula rate update to increase its rates by $17 $27 million with the ICC. An ICC decision in this proceeding is required by December 2022,2023, with new rates effective January 2023.2024.
In June 2022,For further information on the ICC issued an order approving Ameren Illinois’ revised energy-efficiency plan that includes annual investments in electric energy-efficiency programsmatters discussed above, see Note 2 – Rate and Regulatory Matters under Part I, Item I, of approximately $120 million per year through 2025, which reflects the increased level of annual investments allowed under the IETL. The ICC has the ability to reduce the amount of electric energy-efficiency savings goals in future plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investmentsthis report, and the return on those investments are collected from customers through a rider and are not recovered through the electric distribution service performance-based formula ratemaking framework.Outlook section below.
RESULTS OF OPERATIONS
Our results of operations and financial position are affected by many factors. Economic conditions, including those resulting from the COVID-19 pandemic discussed below, energy-efficiency investments by our customers and by us, technological advances, distributed generation, and the actions of key customers can significantly affect the demand for our services. Ameren and Ameren Missouri results are also affected by seasonal fluctuations in winter heating and summer cooling demands and by weather conditions, such as storms, as well as by energy center maintenance outages. Additionally, fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing, our pension and postretirement benefits costs, and the cash surrender value of company-owned life insurance.COLI, and the asset value of Ameren Missouri’s nuclear decommissioning trust fund. Almost all of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the rates we charge customers for our services. Our results of operations, financial position, and liquidity are affected by our ability to align our overall spending, both operating and capital, with the frameworks established by our regulators. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K for additional information regarding Ameren Missouri’s, Ameren Illinois’, and ATXI’s regulatory mechanisms.
We continueare observing inflationary pressures on the prices of certain commodities, labor, services, materials, and supplies, as well as increasing interest rates. Ameren Missouri and Ameren Illinois are generally allowed to monitor the impacts of the COVID-19 pandemicpass on our businesses, including impacts on electricto customers prudently incurred costs for fuel, purchased power, and natural gas sales volumes, liquidity, supply chain operations,supply. Additionally, for certain non-commodity cost changes, the use of trackers, riders, formula ratemaking, and bad debt expense. Regarding uncollectible accounts receivable, Ameren Illinois’ electric distribution and natural gas distribution businesses have bad debt riders, which provide for recovery of bad debt write-offs, net of any subsequent recoveries. Ameren Missouri does not have a bad debt rider or tracker, and thus its earnings are exposed to increases in bad debt expense, absent regulatory relief. However, Ameren Missouri has not experienced and does not expect a material impact to earnings from increases in bad debt expense.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. Ameren Illinois purchases power and natural gas for its customers. The prices for these commodities can fluctuate significantly because of the global economic and political environment, weather, supply, demand, and many other factors. 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. The reliability of Ameren Missouri’s energy centers and our transmission and distribution systems, and the level and timing of operations and maintenance costs and capital investment, are key factors that we seek to manage in order to optimize our results of operations, financial position, and liquidity.
Earnings Summary
The following table presents a summary of Ameren’s earnings for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months | | Six Months | | Three Months | | Six Months |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Net income attributable to Ameren common shareholders | Net income attributable to Ameren common shareholders | $ | 207 | | | $ | 207 | | | $ | 459 | | | $ | 440 | | Net income attributable to Ameren common shareholders | $ | 237 | | | $ | 207 | | | $ | 501 | | | $ | 459 | |
Earnings per common share – diluted | Earnings per common share – diluted | 0.80 | | | 0.80 | | | 1.77 | | | 1.71 | | Earnings per common share – diluted | 0.90 | | | 0.80 | | | 1.90 | | | 1.77 | |
Net income attributable to Ameren common shareholders was comparable between the three months ended June 30, 2022, and the same period in 2021. Net income increased $10 million and $8 million at Ameren Illinois Electric Distribution and Ameren Transmission, respectively. The net income increases were offset by net income decreases of $11 million and $2 million at Ameren Missouri and Ameren Illinois Natural Gas, respectively, and an increase in net loss of $5 million for activity not reported as part of a segment, primarily at Ameren (parent).
Net income attributable to Ameren common shareholders increased $19$30 million, or 610 cents per diluted share, in the three months ended June 30, 2023, compared with the year-ago period, primarily due to net income increases of $15 million, $9 million, $5 million, and $2 million at Ameren Illinois Electric Distribution, Ameren Transmission, Ameren Illinois Natural Gas and Ameren Missouri, respectively.
Net income attributable to Ameren common shareholders increased $42 million, or 13 cents per diluted share, in the six months ended June 30, 2022, 2023, compared with the year-ago period. The increase was due to net income increases of $19$27 million, $13$22 million, and $3$12 million at Ameren Transmission, Ameren Illinois Electric Distribution, Ameren Transmission, and Ameren Illinois Natural Gas, respectively. These increases wererespectively, partially offset by an $8a $20 million decrease in net income decrease at Ameren Missouri and an $8 million decrease in the net income for activity not reported as part of a segment, primarily at Ameren (parent).Missouri.
Earnings per diluted share were favorably affected in the three and six months ended June 30, 2022,2023, compared to the year-ago periods (except where a specific period is referenced), by:
•, 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, primarily at Ameren Missouri and Ameren Illinois Natural Gas (9 cents and 12 cents per share, respectively);
•increased rate base investments at Ameren Transmission and Ameren Illinois Electric Distribution and a higher recognized ROE due to a higher estimated annual average of the monthly yields of the 30-year United States Treasury bonds at Ameren Illinois Electric Distribution, which increased revenues at these segments (6(5 cents and 1012 cents per share, respectively);
•increased electric retail salesbase rate revenues at Ameren Missouri primarily resulting from colder winter temperatures and warmer early summer temperatures experienced in 2022 (estimated at 5 cents and 8 cents per share, respectively);
•increased base rate revenues for the inclusion of previously deferred interest charges pursuant to the December 2021 MoPSC electric rate order effective February 28, 2022, partially offset in the six months ended June 30, 2023, by lower deferral ofincreased interest charges resulting from lower deferrals related to infrastructure investments associated with the PISA and RESRAM (2 cents and 54 cents per share, respectively);
•increaseddecreased taxes other than income taxes, primarily at Ameren Illinois Natural Gas earningsMissouri, largely resulting from investments in qualifying infrastructure recoveredemployee retention tax credits received under the QIPCoronavirus Aid, Relief, and higher base rates pursuant toEconomic Security Act in the ICC’s January 2021 natural gas rate ordersix months ended June 30, 2023 (1 cent and 43 cents per share, respectively);
•increased other income, net, primarilylargely due to increased non-service cost components of net periodic benefit income not subject to formula rates or trackers (2 cents per share for the six months ended June 30, 2022)2023);
•decreased income tax expense not subject to formula rates or riders, resulting, in part, from the absenceeffect of favorable market returns on COLI, compared with unfavorable returns in 2022 of the FERC’s March 2021 order, primarily related to the historical recovery of materials and supplies inventories, which decreased Ameren Transmission revenues in 2021 (3year-ago periods (2 cents per share for the six months ended June 30, 2022)both periods); and
•higher base ratesrecovery of previously incurred expenses at Ameren Illinois Electric Distribution (2 cents per share for both periods);
•increased base rate revenues at Ameren Missouri effective February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, partially offset by the amortization of previously deferred depreciation expense under the PISA and RESRAM, financing costs otherwise recoverable under the PISA and RESRAM, a higher base level of expenses, and the net recovery for amounts associated with the reduction in sales volumes resulting from MEEIA programs (2 cents(1 cent per share for both periods)the six months ended June 30, 2023); and
•increased Ameren Illinois Natural Gas earnings from investments in qualifying infrastructure recovered under the QIP (1 cent per share for the six months ended June 30, 2023).
Earnings per diluted share were unfavorably affected in the three and six months ended June 30, 2022,2023, compared to the year-ago periods, by:
•increased other operations and maintenance expenses not subject to formula rates, riders, or trackers, primarily due to a reduction in the cash surrender value of company-owned life insurance, higher transmission and distribution expenses due to the timing of expenses and disciplined project management, and an increase due to the expiration of contracts relating to refined coal tax credits decreased electric retail sales at Ameren Missouri, primarily resulting from milder spring and early summer temperatures in 2021 (13the three months ended June 30, 2023, as well as warmer winter temperatures in the six months ended June 30, 2023, compared with the same periods in 2022 (estimated at 6 cents and 2116 cents per share, respectively);
•increased financing costs, primarily at Ameren (parent) and Ameren Missouri, largely due to higher interest rates on increased levels of short-term borrowings and higher long-term debt balances (4at Ameren Missouri (3 cents and 67 cents per share, respectively); and
•increased weighted-average basic common shares outstanding resulting from issuances of common shares as detailed in Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report, and Note 5 – Long TermLong-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K (1 cent and 23 cents per share, respectively).
The cents per share variances above are presented based on the weighted-average basic common shares outstanding in the three and six months ended June 30, 2021,2022, and do not reflect the impact of dilution on earnings per share, unless otherwise noted. The amounts above other than variances related to income taxes have been presented net of income taxes using Ameren’s 20222023 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.
Below is Ameren’s table of income statement components by segment for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Ameren
Missouri | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren Transmission | | Other /
Intersegment
Eliminations | | Ameren | | Ameren
Missouri | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren Transmission | | Other /
Intersegment
Eliminations | | Ameren |
| Three Months 2023: | | Three Months 2023: | |
| Electric revenues | | Electric revenues | $ | 918 | | | $ | 540 | | | $ | — | | | $ | 161 | | | $ | (34) | | | $ | 1,585 | |
| Fuel | | Fuel | (152) | | | — | | | — | | | — | | | — | | | (152) | |
| Purchased power | | Purchased power | (137) | | | (218) | | | — | | | — | | | 27 | | | (328) | |
| Electric margins | | Electric margins | 629 | | | 322 | | | — | | | 161 | | | (7) | | | 1,105 | |
| Natural gas revenues | | Natural gas revenues | 23 | | | — | | | 152 | | | — | | | — | | | 175 | |
| Natural gas purchased for resale | | Natural gas purchased for resale | (9) | | | — | | | (33) | | | — | | | — | | | (42) | |
| Natural gas margins | | Natural gas margins | 14 | | | — | | | 119 | | | — | | | — | | | 133 | |
| Other operations and maintenance expenses | | Other operations and maintenance expenses | (237) | | | (133) | | | (58) | | | (13) | | | (9) | | | (450) | |
| Depreciation and amortization expenses | | Depreciation and amortization expenses | (186) | | | (87) | | | (27) | | | (34) | | | (1) | | | (335) | |
| Taxes other than income taxes | | Taxes other than income taxes | (88) | | | (18) | | | (13) | | | (2) | | | (3) | | | (124) | |
| Operating income (loss) | | Operating income (loss) | 132 | | | 84 | | | 21 | | | 112 | | | (20) | | | 329 | |
| Other income, net | | Other income, net | 22 | | | 26 | | | 8 | | | 8 | | | 18 | | | 82 | |
| Interest charges | | Interest charges | (52) | | | (22) | | | (13) | | | (23) | | | (24) | | | (134) | |
| Income (taxes) benefit | | Income (taxes) benefit | 1 | | | (21) | | | (5) | | | (25) | | | 12 | | | (38) | |
| Net income (loss) | | Net income (loss) | 103 | | | 67 | | | 11 | | | 72 | | | (14) | | | 239 | |
Noncontrolling interests – preferred stock dividends | | Noncontrolling interests – preferred stock dividends | (1) | | | (1) | | | — | | | — | | | — | | | (2) | |
| Net income (loss) attributable to Ameren common shareholders | | Net income (loss) attributable to Ameren common shareholders | $ | 102 | | | $ | 66 | | | $ | 11 | | | $ | 72 | | | $ | (14) | | | $ | 237 | |
| Three Months 2022: | Three Months 2022: | | Three Months 2022: | |
| Electric revenues | Electric revenues | $ | 890 | | | $ | 504 | | | $ | — | | | $ | 150 | | | $ | (31) | | | $ | 1,513 | | Electric revenues | $ | 890 | | | $ | 504 | | | $ | — | | | $ | 150 | | | $ | (31) | | | $ | 1,513 | |
| Fuel | Fuel | (83) | | | — | | | — | | | — | | | — | | | (83) | | Fuel | (83) | | | — | | | — | | | — | | | — | | | (83) | |
| Purchased power | Purchased power | (161) | | | (182) | | | — | | | — | | | 25 | | | (318) | | Purchased power | (161) | | | (182) | | | — | | | — | | | 25 | | | (318) | |
| Electric margins | Electric margins | 646 | | | 322 | | | — | | | 150 | | | (6) | | | 1,112 | | Electric margins | 646 | | | 322 | | | — | | | 150 | | | (6) | | | 1,112 | |
| Natural gas revenues | Natural gas revenues | 29 | | | — | | | 184 | | | — | | | — | | | 213 | | Natural gas revenues | 29 | | | — | | | 184 | | | — | | | — | | | 213 | |
| Natural gas purchased for resale | Natural gas purchased for resale | (12) | | | — | | | (68) | | | — | | | — | | | (80) | | Natural gas purchased for resale | (12) | | | — | | | (68) | | | — | | | — | | | (80) | |
| Natural gas margins | Natural gas margins | 17 | | | — | | | 116 | | | — | | | — | | | 133 | | Natural gas margins | 17 | | | — | | | 116 | | | — | | | — | | | 133 | |
| Other operations and maintenance expenses | Other operations and maintenance expenses | (260) | | | (148) | | | (63) | | | (16) | | | (4) | | | (491) | | Other operations and maintenance expenses | (260) | | | (148) | | | (63) | | | (16) | | | (4) | | | (491) | |
| Depreciation and amortization expenses | Depreciation and amortization expenses | (178) | | | (82) | | | (25) | | | (30) | | | (1) | | | (316) | | Depreciation and amortization expenses | (178) | | | (82) | | | (25) | | | (30) | | | (1) | | | (316) | |
| Taxes other than income taxes | Taxes other than income taxes | (90) | | | (19) | | | (16) | | | (2) | | | (2) | | | (129) | | Taxes other than income taxes | (90) | | | (19) | | | (16) | | | (2) | | | (2) | | | (129) | |
| Operating income (loss) | Operating income (loss) | 135 | | | 73 | | | 12 | | | 102 | | | (13) | | | 309 | | Operating income (loss) | 135 | | | 73 | | | 12 | | | 102 | | | (13) | | | 309 | |
| Other income, net | Other income, net | 24 | | | 15 | | | 6 | | | 4 | | | 13 | | | 62 | | Other income, net | 24 | | | 15 | | | 6 | | | 4 | | | 13 | | | 62 | |
| Interest charges | Interest charges | (60) | | | (18) | | | (11) | | | (20) | | | (17) | | | (126) | | Interest charges | (60) | | | (18) | | | (11) | | | (20) | | | (17) | | | (126) | |
| Income (taxes) benefit | Income (taxes) benefit | 2 | | | (18) | | | (1) | | | (23) | | | 4 | | | (36) | | Income (taxes) benefit | 2 | | | (18) | | | (1) | | | (23) | | | 4 | | | (36) | |
| Net income (loss) | Net income (loss) | 101 | | | 52 | | | 6 | | | 63 | | | (13) | | | 209 | | Net income (loss) | 101 | | | 52 | | | 6 | | | 63 | | | (13) | | | 209 | |
Noncontrolling interests – preferred stock dividends | Noncontrolling interests – preferred stock dividends | (1) | | | (1) | | | — | | | — | | | — | | | (2) | | Noncontrolling interests – preferred stock dividends | (1) | | | (1) | | | — | | | — | | | — | | | (2) | |
| Net income (loss) attributable to Ameren common shareholders | Net income (loss) attributable to Ameren common shareholders | $ | 100 | | | $ | 51 | | | $ | 6 | | | $ | 63 | | | $ | (13) | | | $ | 207 | | Net income (loss) attributable to Ameren common shareholders | $ | 100 | | | $ | 51 | | | $ | 6 | | | $ | 63 | | | $ | (13) | | | $ | 207 | |
| Three Months 2021: | | |
| Electric revenues | $ | 789 | | | $ | 388 | | | $ | — | | | $ | 136 | | | $ | (29) | | | $ | 1,284 | | |
| Fuel | (173) | | | — | | | — | | | — | | | — | | | (173) | | |
| Purchased power | (50) | | | (99) | | | — | | | — | | | 20 | | | (129) | | |
| Electric margins | 566 | | | 289 | | | — | | | 136 | | | (9) | | | 982 | | |
| Natural gas revenues | 20 | | | — | | | 168 | | | — | | | — | | | 188 | | |
| Natural gas purchased for resale | (5) | | | — | | | (60) | | | — | | | — | | | (65) | | |
| Natural gas margins | 15 | | | — | | | 108 | | | — | | | — | | | 123 | | |
| Other operations and maintenance expenses | (218) | | | (129) | | | (53) | | | (14) | | | 2 | | | (412) | | |
| Depreciation and amortization expenses | (157) | | | (77) | | | (22) | | | (27) | | | (2) | | | (285) | | |
| Taxes other than income taxes | (85) | | | (18) | | | (15) | | | (2) | | | (2) | | | (122) | | |
| Operating income (loss) | 121 | | | 65 | | | 18 | | | 93 | | | (11) | | | 286 | | |
| Other income, net | 24 | | | 11 | | | 3 | | | 2 | | | 9 | | | 49 | | |
| Interest charges | (36) | | | (19) | | | (10) | | | (20) | | | (11) | | | (96) | | |
| Income (taxes) benefit | 3 | | | (16) | | | (3) | | | (20) | | | 5 | | | (31) | | |
| Net income (loss) | 112 | | | 41 | | | 8 | | | 55 | | | (8) | | | 208 | | |
Noncontrolling interests – preferred stock dividends | (1) | | | — | | | — | | | — | | | — | | | (1) | | |
| Net income (loss) attributable to Ameren common shareholders | $ | 111 | | | $ | 41 | | | $ | 8 | | | $ | 55 | | | $ | (8) | | | $ | 207 | | |
| | | Ameren
Missouri | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren Transmission | | Other /
Intersegment
Eliminations | | Ameren | | Ameren
Missouri | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren Transmission | | Other /
Intersegment
Eliminations | | Ameren |
| Six Months 2023: | | Six Months 2023: | |
| Electric revenues | | Electric revenues | $ | 1,759 | | | $ | 1,164 | | | $ | — | | | $ | 324 | | | $ | (72) | | | $ | 3,175 | |
| Fuel | | Fuel | (265) | | | — | | | — | | | — | | | — | | | (265) | |
| Purchased power | | Purchased power | (345) | | | (533) | | | — | | | — | | | 55 | | | (823) | |
| Electric margins | | Electric margins | 1,149 | | | 631 | | | — | | | 324 | | | (17) | | | 2,087 | |
| Natural gas revenues | | Natural gas revenues | 105 | | | — | | | 543 | | | — | | | (1) | | | 647 | |
| Natural gas purchased for resale | | Natural gas purchased for resale | (56) | | | — | | | (194) | | | — | | | — | | | (250) | |
| Natural gas margins | | Natural gas margins | 49 | | | — | | | 349 | | | — | | | (1) | | | 397 | |
| Other operations and maintenance expenses | | Other operations and maintenance expenses | (476) | | | (262) | | | (117) | | | (29) | | | (14) | | | (898) | |
| Depreciation and amortization expenses | | Depreciation and amortization expenses | (362) | | | (171) | | | (53) | | | (67) | | | (2) | | | (655) | |
| Taxes other than income taxes | | Taxes other than income taxes | (168) | | | (36) | | | (36) | | | (4) | | | (7) | | | (251) | |
| Operating income (loss) | | Operating income (loss) | 192 | | | 162 | | | 143 | | | 224 | | | (41) | | | 680 | |
| Other income, net | | Other income, net | 41 | | | 50 | | | 16 | | | 14 | | | 39 | | | 160 | |
| Interest charges | | Interest charges | (103) | | | (43) | | | (26) | | | (45) | | | (44) | | | (261) | |
| Income (taxes) benefit | | Income (taxes) benefit | 2 | | | (41) | | | (35) | | | (50) | | | 49 | | | (75) | |
| Net income | | Net income | 132 | | | 128 | | | 98 | | | 143 | | | 3 | | | 504 | |
Noncontrolling interests – preferred stock dividends | | Noncontrolling interests – preferred stock dividends | (2) | | | (1) | | | — | | | — | | | — | | | (3) | |
| Net income attributable to Ameren common shareholders | | Net income attributable to Ameren common shareholders | $ | 130 | | | $ | 127 | | | $ | 98 | | | $ | 143 | | | $ | 3 | | | $ | 501 | |
| Six Months 2022: | Six Months 2022: | | Six Months 2022: | |
| Electric revenues | Electric revenues | $ | 1,628 | | | $ | 969 | | | $ | — | | | $ | 296 | | | $ | (62) | | | $ | 2,831 | | Electric revenues | $ | 1,628 | | | $ | 969 | | | $ | — | | | $ | 296 | | | $ | (62) | | | $ | 2,831 | |
| Fuel | Fuel | (259) | | | — | | | — | | | — | | | — | | | (259) | | Fuel | (259) | | | — | | | — | | | — | | | — | | | (259) | |
| Purchased power | Purchased power | (211) | | | (333) | | | — | | | — | | | 49 | | | (495) | | Purchased power | (211) | | | (333) | | | — | | | — | | | 49 | | | (495) | |
| Electric margins | Electric margins | 1,158 | | | 636 | | | — | | | 296 | | | (13) | | | 2,077 | | Electric margins | 1,158 | | | 636 | | | — | | | 296 | | | (13) | | | 2,077 | |
| Natural gas revenues | Natural gas revenues | 109 | | | — | | | 665 | | | — | | | — | | | 774 | | Natural gas revenues | 109 | | | — | | | 665 | | | — | | | — | | | 774 | |
| Natural gas purchased for resale | Natural gas purchased for resale | (58) | | | — | | | (315) | | | — | | | — | | | (373) | | Natural gas purchased for resale | (58) | | | — | | | (315) | | | — | | | — | | | (373) | |
| Natural gas margins | Natural gas margins | 51 | | | — | | | 350 | | | — | | | — | | | 401 | | Natural gas margins | 51 | | | — | | | 350 | | | — | | | — | | | 401 | |
| Other operations and maintenance expenses | Other operations and maintenance expenses | (492) | | | (295) | | | (126) | | | (32) | | | (7) | | | (952) | | Other operations and maintenance expenses | (492) | | | (295) | | | (126) | | | (32) | | | (7) | | | (952) | |
| Depreciation and amortization expenses | Depreciation and amortization expenses | (342) | | | (163) | | | (48) | | | (60) | | | (2) | | | (615) | | Depreciation and amortization expenses | (342) | | | (163) | | | (48) | | | (60) | | | (2) | | | (615) | |
| Taxes other than income taxes | Taxes other than income taxes | (175) | | | (39) | | | (47) | | | (4) | | | (6) | | | (271) | | Taxes other than income taxes | (175) | | | (39) | | | (47) | | | (4) | | | (6) | | | (271) | |
| Operating income (loss) | Operating income (loss) | 200 | | | 139 | | | 129 | | | 200 | | | (28) | | | 640 | | Operating income (loss) | 200 | | | 139 | | | 129 | | | 200 | | | (28) | | | 640 | |
| Other income, net | Other income, net | 47 | | | 31 | | | 10 | | | 7 | | | 27 | | | 122 | | Other income, net | 47 | | | 31 | | | 10 | | | 7 | | | 27 | | | 122 | |
| Interest charges | Interest charges | (99) | | | (36) | | | (22) | | | (42) | | | (31) | | | (230) | | Interest charges | (99) | | | (36) | | | (22) | | | (42) | | | (31) | | | (230) | |
| Income (taxes) benefit | Income (taxes) benefit | 4 | | | (33) | | | (31) | | | (44) | | | 34 | | | (70) | | Income (taxes) benefit | 4 | | | (33) | | | (31) | | | (44) | | | 34 | | | (70) | |
| Net income | Net income | 152 | | | 101 | | | 86 | | | 121 | | | 2 | | | 462 | | Net income | 152 | | | 101 | | | 86 | | | 121 | | | 2 | | | 462 | |
Noncontrolling interests – preferred stock dividends | Noncontrolling interests – preferred stock dividends | (2) | | | (1) | | | — | | | — | | | — | | | (3) | | Noncontrolling interests – preferred stock dividends | (2) | | | (1) | | | — | | | — | | | — | | | (3) | |
| Net income attributable to Ameren common shareholders | Net income attributable to Ameren common shareholders | $ | 150 | | | $ | 100 | | | $ | 86 | | | $ | 121 | | | $ | 2 | | | $ | 459 | | Net income attributable to Ameren common shareholders | $ | 150 | | | $ | 100 | | | $ | 86 | | | $ | 121 | | | $ | 2 | | | $ | 459 | |
| Six Months 2021: | | |
| Electric revenues | $ | 1,430 | | | $ | 799 | | | $ | — | | | $ | 266 | | | $ | (55) | | | $ | 2,440 | | |
| Fuel | (238) | | | — | | | — | | | — | | | — | | | (238) | | |
| Purchased power | (138) | | | (221) | | | — | | | — | | | 39 | | | (320) | | |
| Electric margins | 1,054 | | | 578 | | | — | | | 266 | | | (16) | | | 1,882 | | |
| Natural gas revenues | 83 | | | — | | | 515 | | | — | | | — | | | 598 | | |
| Natural gas purchased for resale | (36) | | | — | | | (194) | | | — | | | — | | | (230) | | |
| Natural gas margins | 47 | | | — | | | 321 | | | — | | | — | | | 368 | | |
| Other operations and maintenance expenses | (443) | | | (254) | | | (109) | | | (30) | | | 4 | | | (832) | | |
| Depreciation and amortization expenses | (313) | | | (152) | | | (44) | | | (55) | | | (2) | | | (566) | | |
| Taxes other than income taxes | (162) | | | (38) | | | (40) | | | (4) | | | (6) | | | (250) | | |
| Operating income (loss) | 183 | | | 134 | | | 128 | | | 177 | | | (20) | | | 602 | | |
| Other income, net | 47 | | | 19 | | | 6 | | | 5 | | | 18 | | | 95 | | |
| Interest charges | (75) | | | (37) | | | (20) | | | (43) | | | (21) | | | (196) | | |
| Income (taxes) benefit | 5 | | | (28) | | | (31) | | | (37) | | | 33 | | | (58) | | |
| Net income | 160 | | | 88 | | | 83 | | | 102 | | | 10 | | | 443 | | |
Noncontrolling interests – preferred stock dividends | (2) | | | (1) | | | — | | | — | | | — | | | (3) | | |
| Net income attributable to Ameren common shareholders | $ | 158 | | | $ | 87 | | | $ | 83 | | | $ | 102 | | | $ | 10 | | | $ | 440 | | |
Below is Ameren Illinois’ table of income statement components by segment for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren
Illinois Transmission | | Other /
Intersegment
Eliminations | | Ameren Illinois | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren
Illinois Transmission | | Other /
Intersegment
Eliminations | | Ameren Illinois |
| Three Months 2023: | | Three Months 2023: | |
| Electric revenues | | Electric revenues | $ | 540 | | | $ | — | | | $ | 113 | | | $ | (26) | | | 627 | |
| Purchased power | | Purchased power | (218) | | | — | | | — | | | 26 | | | (192) | |
| Electric margins | | Electric margins | 322 | | | — | | | 113 | | | — | | | 435 | |
| Natural gas revenues | | Natural gas revenues | — | | | 152 | | | — | | | — | | | 152 | |
| Natural gas purchased for resale | | Natural gas purchased for resale | — | | | (33) | | | — | | | — | | | (33) | |
| Natural gas margins | | Natural gas margins | — | | | 119 | | | — | | | — | | | 119 | |
| Other operations and maintenance expenses | | Other operations and maintenance expenses | (133) | | | (58) | | | (10) | | | — | | | (201) | |
| Depreciation and amortization expenses | | Depreciation and amortization expenses | (87) | | | (27) | | | (24) | | | — | | | (138) | |
| Taxes other than income taxes | | Taxes other than income taxes | (18) | | | (13) | | | (1) | | | — | | | (32) | |
| Operating income (loss) | | Operating income (loss) | 84 | | | 21 | | | 78 | | | — | | | 183 | |
| Other income, net | | Other income, net | 26 | | | 8 | | | 7 | | | — | | | 41 | |
| Interest charges | | Interest charges | (22) | | | (13) | | | (15) | | | — | | | (50) | |
| Income taxes | | Income taxes | (21) | | | (5) | | | (18) | | | — | | | (44) | |
| Net income | | Net income | 67 | | | 11 | | | 52 | | | — | | | 130 | |
| Preferred stock dividends | | Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | |
| Net income attributable to common shareholder | | Net income attributable to common shareholder | $ | 66 | | | $ | 11 | | | $ | 52 | | | $ | — | | | $ | 129 | |
| Three Months 2022: | Three Months 2022: | | Three Months 2022: | |
| Electric revenues | Electric revenues | $ | 504 | | | $ | — | | | $ | 105 | | | $ | (24) | | | 585 | | Electric revenues | 504 | | | $ | — | | | $ | 105 | | | $ | (24) | | | 585 | |
| Purchased power | Purchased power | (182) | | | — | | | — | | | 24 | | | (158) | | Purchased power | (182) | | | — | | | — | | | 24 | | | (158) | |
| Electric margins | Electric margins | 322 | | | — | | | 105 | | | — | | | 427 | | Electric margins | 322 | | | — | | | 105 | | | — | | | 427 | |
| Natural gas revenues | Natural gas revenues | — | | | 184 | | | — | | | — | | | 184 | | Natural gas revenues | — | | | 184 | | | — | | | — | | | 184 | |
| Natural gas purchased for resale | Natural gas purchased for resale | — | | | (68) | | | — | | | — | | | (68) | | Natural gas purchased for resale | — | | | (68) | | | — | | | — | | | (68) | |
| Natural gas margins | Natural gas margins | — | | | 116 | | | — | | | — | | | 116 | | Natural gas margins | — | | | 116 | | | — | | | — | | | 116 | |
| Other operations and maintenance expenses | Other operations and maintenance expenses | (148) | | | (63) | | | (14) | | | — | | | (225) | | Other operations and maintenance expenses | (148) | | | (63) | | | (14) | | | — | | | (225) | |
| Depreciation and amortization expenses | Depreciation and amortization expenses | (82) | | | (25) | | | (21) | | | — | | | (128) | | Depreciation and amortization expenses | (82) | | | (25) | | | (21) | | | — | | | (128) | |
| Taxes other than income taxes | Taxes other than income taxes | (19) | | | (16) | | | — | | | — | | | (35) | | Taxes other than income taxes | (19) | | | (16) | | | — | | | — | | | (35) | |
| Operating income (loss) | Operating income (loss) | 73 | | | 12 | | | 70 | | | — | | | 155 | | Operating income (loss) | 73 | | | 12 | | | 70 | | | — | | | 155 | |
| Other income, net | Other income, net | 15 | | | 6 | | | 4 | | | — | | | 25 | | Other income, net | 15 | | | 6 | | | 4 | | | — | | | 25 | |
| Interest charges | Interest charges | (18) | | | (11) | | | (12) | | | — | | | (41) | | Interest charges | (18) | | | (11) | | | (12) | | | — | | | (41) | |
| Income taxes | Income taxes | (18) | | | (1) | | | (16) | | | — | | | (35) | | Income taxes | (18) | | | (1) | | | (16) | | | — | | | (35) | |
| Net income | Net income | 52 | | | 6 | | | 46 | | | — | | | 104 | | Net income | 52 | | | 6 | | | 46 | | | — | | | 104 | |
| Preferred stock dividends | Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | | Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | |
| Net income attributable to common shareholder | Net income attributable to common shareholder | $ | 51 | | | $ | 6 | | | $ | 46 | | | $ | — | | | $ | 103 | | Net income attributable to common shareholder | $ | 51 | | | $ | 6 | | | $ | 46 | | | $ | — | | | $ | 103 | |
| Three Months 2021: | | |
| Electric revenues | 388 | | | $ | — | | | $ | 88 | | | $ | (15) | | | 461 | | |
| Purchased power | (99) | | | — | | | — | | | 15 | | | (84) | | |
| Electric margins | 289 | | | — | | | 88 | | | — | | | 377 | | |
| Natural gas revenues | — | | | 168 | | | — | | | — | | | 168 | | |
| Natural gas purchased for resale | — | | | (60) | | | — | | | — | | | (60) | | |
| Natural gas margins | — | | | 108 | | | — | | | — | | | 108 | | |
| Other operations and maintenance expenses | (129) | | | (53) | | | (11) | | | — | | | (193) | | |
| Depreciation and amortization expenses | (77) | | | (22) | | | (18) | | | — | | | (117) | | |
| Taxes other than income taxes | (18) | | | (15) | | | (1) | | | — | | | (34) | | |
| Operating income (loss) | 65 | | | 18 | | | 58 | | | — | | | 141 | | |
| Other income, net | 11 | | | 3 | | | 2 | | | — | | | 16 | | |
| Interest charges | (19) | | | (10) | | | (11) | | | — | | | (40) | | |
| Income taxes | (16) | | | (3) | | | (12) | | | — | | | (31) | | |
| | Net income attributable to common shareholder | $ | 41 | | | $ | 8 | | | $ | 37 | | | $ | — | | | $ | 86 | | |
| | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren
Illinois Transmission | | Other /
Intersegment
Eliminations | | Ameren Illinois | | Ameren
Illinois
Electric
Distribution | | Ameren
Illinois
Natural Gas | | Ameren
Illinois Transmission | | Other /
Intersegment
Eliminations | | Ameren Illinois |
| Six Months 2023: | | Six Months 2023: | |
| Electric revenues | | Electric revenues | $ | 1,164 | | | $ | — | | | $ | 227 | | | $ | (54) | | | $ | 1,337 | |
| Purchased power | | Purchased power | (533) | | | — | | | — | | | 54 | | | (479) | |
| Electric margins | | Electric margins | 631 | | | — | | | 227 | | | — | | | 858 | |
| Natural gas revenues | | Natural gas revenues | — | | | 543 | | | — | | | — | | | 543 | |
| Natural gas purchased for resale | | Natural gas purchased for resale | — | | | (194) | | | — | | | — | | | (194) | |
| Natural gas margins | | Natural gas margins | — | | | 349 | | | — | | | — | | | 349 | |
| Other operations and maintenance expenses | | Other operations and maintenance expenses | (262) | | | (117) | | | (24) | | | — | | | (403) | |
| Depreciation and amortization expenses | | Depreciation and amortization expenses | (171) | | | (53) | | | (47) | | | — | | | (271) | |
| Taxes other than income taxes | | Taxes other than income taxes | (36) | | | (36) | | | (2) | | | — | | | (74) | |
| Operating income (loss) | | Operating income (loss) | 162 | | | 143 | | | 154 | | | — | | | 459 | |
| Other income, net | | Other income, net | 50 | | | 16 | | | 12 | | | — | | | 78 | |
| Interest charges | | Interest charges | (43) | | | (26) | | | (28) | | | — | | | (97) | |
| Income taxes | | Income taxes | (41) | | | (35) | | | (36) | | | — | | | (112) | |
| Net income | | Net income | 128 | | | 98 | | | 102 | | | — | | | 328 | |
| Preferred stock dividends | | Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | |
| Net income attributable to common shareholder | | Net income attributable to common shareholder | $ | 127 | | | $ | 98 | | | $ | 102 | | | $ | — | | | $ | 327 | |
| Six Months 2022: | Six Months 2022: | | Six Months 2022: | |
| Electric revenues | Electric revenues | $ | 969 | | | $ | — | | | $ | 203 | | | $ | (44) | | | $ | 1,128 | | Electric revenues | $ | 969 | | | $ | — | | | $ | 203 | | | $ | (44) | | | $ | 1,128 | |
| Purchased power | Purchased power | (333) | | | — | | | — | | | 44 | | | (289) | | Purchased power | (333) | | | — | | | — | | | 44 | | | (289) | |
| Electric margins | Electric margins | 636 | | | — | | | 203 | | | — | | | 839 | | Electric margins | 636 | | | — | | | 203 | | | — | | | 839 | |
| Natural gas revenues | Natural gas revenues | — | | | 665 | | | — | | | — | | | 665 | | Natural gas revenues | — | | | 665 | | | — | | | — | | | 665 | |
| Natural gas purchased for resale | Natural gas purchased for resale | — | | | (315) | | | — | | | — | | | (315) | | Natural gas purchased for resale | — | | | (315) | | | — | | | — | | | (315) | |
| Natural gas margins | Natural gas margins | — | | | 350 | | | — | | | — | | | 350 | | Natural gas margins | — | | | 350 | | | — | | | — | | | 350 | |
| Other operations and maintenance expenses | Other operations and maintenance expenses | (295) | | | (126) | | | (27) | | | — | | | (448) | | Other operations and maintenance expenses | (295) | | | (126) | | | (27) | | | — | | | (448) | |
| Depreciation and amortization expenses | Depreciation and amortization expenses | (163) | | | (48) | | | (41) | | | — | | | (252) | | Depreciation and amortization expenses | (163) | | | (48) | | | (41) | | | — | | | (252) | |
| Taxes other than income taxes | Taxes other than income taxes | (39) | | | (47) | | | (2) | | | — | | | (88) | | Taxes other than income taxes | (39) | | | (47) | | | (2) | | | — | | | (88) | |
| Operating income (loss) | Operating income (loss) | 139 | | | 129 | | | 133 | | | — | | | 401 | | Operating income (loss) | 139 | | | 129 | | | 133 | | | — | | | 401 | |
| Other income, net | Other income, net | 31 | | | 10 | | | 8 | | | — | | | 49 | | Other income, net | 31 | | | 10 | | | 8 | | | — | | | 49 | |
| Interest charges | Interest charges | (36) | | | (22) | | | (25) | | | — | | | (83) | | Interest charges | (36) | | | (22) | | | (25) | | | — | | | (83) | |
| Income taxes | Income taxes | (33) | | | (31) | | | (30) | | | — | | | (94) | | Income taxes | (33) | | | (31) | | | (30) | | | — | | | (94) | |
| Net income | Net income | 101 | | | 86 | | | 86 | | | — | | | 273 | | Net income | 101 | | | 86 | | | 86 | | | — | | | 273 | |
| Preferred stock dividends | Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | | Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | |
| Net income attributable to common shareholder | Net income attributable to common shareholder | $ | 100 | | | $ | 86 | | | $ | 86 | | | $ | — | | | $ | 272 | | Net income attributable to common shareholder | $ | 100 | | | $ | 86 | | | $ | 86 | | | $ | — | | | $ | 272 | |
| Six Months 2021: | | |
| Electric revenues | $ | 799 | | | $ | — | | | $ | 169 | | | $ | (31) | | | $ | 937 | | |
| Purchased power | (221) | | | — | | | — | | | 31 | | | (190) | | |
| Electric margins | 578 | | | — | | | 169 | | | — | | | 747 | | |
| Natural gas revenues | — | | | 515 | | | — | | | — | | | 515 | | |
| Natural gas purchased for resale | — | | | (194) | | | — | | | — | | | (194) | | |
| Natural gas margins | — | | | 321 | | | — | | | — | | | 321 | | |
| Other operations and maintenance expenses | (254) | | | (109) | | | (24) | | | — | | | (387) | | |
| Depreciation and amortization expenses | (152) | | | (44) | | | (36) | | | — | | | (232) | | |
| Taxes other than income taxes | (38) | | | (40) | | | (2) | | | — | | | (80) | | |
| Operating income (loss) | 134 | | | 128 | | | 107 | | | — | | | 369 | | |
| Other income, net | 19 | | | 6 | | | 5 | | | — | | | 30 | | |
| Interest charges | (37) | | | (20) | | | (25) | | | — | | | (82) | | |
| Income taxes | (28) | | | (31) | | | (22) | | | — | | | (81) | | |
| Net income | 88 | | | 83 | | | 65 | | | — | | | 236 | | |
| Preferred stock dividends | (1) | | | — | | | — | | | — | | | (1) | | |
| Net income attributable to common shareholder | $ | 87 | | | $ | 83 | | | $ | 65 | | | $ | — | | | $ | 235 | | |
Electric and Natural Gas Margins
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 to complement 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.
(a)Includes other/intersegment eliminations of $(7) million, $(6) million, $(9) million, $(13)$(17) million, and $(16)$(13) million in the three months ended June 30, 20222023 and 2021,2022, and six months ended June 30, 20222023, and 2021,2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Electric Distribution | | Ameren Transmission | | | Other/Intersegment Eliminations | |
Natural Gas Margins
| | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) by Segment | |
| | | Overall Ameren IncreaseChange of $10$- Million (QTD YoY) | | Overall Ameren IncreaseDecrease of $33$4 Million (YTD YoY) | |
| Total by Segment(a) | | | |
(a)Includes other/intersegment eliminations of $(1) million in the six months ended June 30, 2023. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
The following tables present the favorable (unfavorable) variations by Ameren segment for electric and natural gas margins for the three and six months ended June 30, 2022,2023, compared with the year-ago periods:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins | | | | | |
| Three Months | Ameren Missouri | | Ameren Illinois
Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /Intersegment Eliminations | | Ameren | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | 21 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 21 | | | | | | |
Base rates (estimate)(c) | 59 | | | 28 | | | — | | | 14 | | | — | | | 101 | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Off-system sales, capacity, and FAC revenues, net | 2 | | | — | | | — | | | — | | | — | | | 2 | | | | | | |
| Ameren Illinois energy-efficiency program investment revenues | — | | | 3 | | | — | | | — | | | — | | | 3 | | | | | | |
| Other | 2 | | | 2 | | | — | | | — | | | — | | | 4 | | | | | | |
Cost recovery mechanisms – offset in fuel and purchased power(d) | 4 | | | 83 | | | — | | | — | | | (2) | | | 85 | | | | | | |
Other cost recovery mechanisms(e) | 13 | | | — | | | — | | | — | | | — | | | 13 | | | | | | |
| Total electric revenue change | $ | 101 | | | $ | 116 | | | $ | — | | | $ | 14 | | | $ | (2) | | | $ | 229 | | | | | | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | (8) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (8) | | | | | | |
Effect of weather (estimate)(b) | (4) | | | — | | | — | | | — | | | — | | | (4) | | | | | | |
| Effect of higher net energy costs included in base rates | (3) | | | — | | | — | | | — | | | — | | | (3) | | | | | | |
| Transmission services charges | (1) | | | — | | | — | | | — | | | — | | | (1) | | | | | | |
| Other | (1) | | | — | | | — | | | — | | | 3 | | | 2 | | | | | | |
Cost recovery mechanisms – offset in electric revenue(d) | (4) | | | (83) | | | — | | | — | | | 2 | | | (85) | | | | | | |
| Total fuel and purchased power change | $ | (21) | | | $ | (83) | | | $ | — | | | $ | — | | | $ | 5 | | | $ | (99) | | | | | | |
| Net change in electric margins | $ | 80 | | | $ | 33 | | | $ | — | | | $ | 14 | | | $ | 3 | | | $ | 130 | | | | | | |
| Natural gas revenue change: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Base rates (estimate) | $ | 2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 2 | | | | | | |
| | | | | | | | | | | | | | | | |
| QIP rider | — | | | — | | | 6 | | | — | | | — | | | 6 | | | | | | |
| | | | | | | | | | | | | | | | |
| Other | — | | | — | | | 2 | | | — | | | — | | | 2 | | | | | | |
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | 7 | | | — | | | 8 | | | — | | | — | | | 15 | | | | | | |
| | | | | | | | | | | | | | | | |
| Total natural gas revenue change | $ | 9 | | | $ | — | | | $ | 16 | | | $ | — | | | $ | — | | | $ | 25 | | | | | | |
| Natural gas purchased for resale change: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Cost recovery mechanisms – offset in natural gas revenue(d) | $ | (7) | | | $ | — | | | $ | (8) | | | $ | — | | | $ | — | | | $ | (15) | | | | | | |
| Total natural gas purchased for resale change | $ | (7) | | | $ | — | | | $ | (8) | | | $ | — | | | $ | — | | | $ | (15) | | | | | | |
| Net change in natural gas margins | $ | 2 | | | $ | — | | | $ | 8 | | | $ | — | | | $ | — | | | $ | 10 | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric and Natural Gas Margins | | | | | |
| Three Months | Ameren Missouri | | Ameren Illinois
Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /Intersegment Eliminations | | Ameren | | | | | |
| Electric revenue change: | | | | | | | | | | | | | | | | |
Base rates (estimate)(b) | $ | — | | | $ | 2 | | | $ | — | | | $ | 11 | | | $ | — | | | $ | 13 | | | | | | |
Effect of weather (estimate)(c) | (23) | | | — | | | — | | | — | | | — | | | (23) | | | | | | |
| Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | (6) | | | — | | | — | | | — | | | — | | | (6) | | | | | | |
| | | | | | | | | | | | | | | | |
| Off-system sales, capacity, and FAC revenues, net | 28 | | | — | | | — | | | — | | | — | | | 28 | | | | | | |
| Ameren Illinois energy-efficiency program investment revenues | — | | | 5 | | | — | | | — | | | — | | | 5 | | | | | | |
| Other | (1) | | | (1) | | | — | | | — | | | (1) | | | (3) | | | | | | |
Cost recovery mechanisms – offset in fuel and purchased power(d) | 28 | | | 36 | | | — | | | — | | | (2) | | | 62 | | | | | | |
Other cost recovery mechanisms(e) | 2 | | | (6) | | | — | | | — | | | — | | | (4) | | | | | | |
| Total electric revenue change | $ | 28 | | | $ | 36 | | | $ | — | | | $ | 11 | | | $ | (3) | | | $ | 72 | | | | | | |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | |
| Energy costs (excluding the estimated effect of weather) | $ | (22) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (22) | | | | | | |
Effect of weather (estimate)(c) | 3 | | | — | | | — | | | — | | | — | | | 3 | | | | | | |
| | | | | | | | | | | | | | | | |
| Other | 2 | | | — | | | — | | | — | | | — | | | 2 | | | | | | |
Cost recovery mechanisms – offset in electric revenue(d) | (28) | | | (36) | | | — | | | — | | | 2 | | | (62) | | | | | | |
| Total fuel and purchased power change | $ | (45) | | | $ | (36) | | | $ | — | | | $ | — | | | $ | 2 | | | $ | (79) | | | | | | |
| Net change in electric margins | $ | (17) | | | $ | — | | | $ | — | | | $ | 11 | | | $ | (1) | | | $ | (7) | | | | | | |
| Natural gas revenue change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(c) | $ | (1) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | | | | | | |
| Sales volumes (excluding the estimated effect of weather) | (2) | | | — | | | — | | | — | | | — | | | (2) | | | | | | |
| QIP | — | | | — | | | 3 | | | — | | | — | | | 3 | | | | | | |
| | | | | | | | | | | | | | | | |
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | (2) | | | — | | | (35) | | | — | | | — | | | (37) | | | | | | |
Other cost recovery mechanisms(e) | (1) | | | — | | | — | | | — | | | — | | | (1) | | | | | | |
| Total natural gas revenue change | $ | (6) | | | $ | — | | | $ | (32) | | | $ | — | | | $ | — | | | $ | (38) | | | | | | |
| Natural gas purchased for resale change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(c) | $ | 1 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1 | | | | | | |
Cost recovery mechanisms – offset in natural gas revenue(d) | 2 | | | — | | | 35 | | | — | | | — | | | 37 | | | | | | |
| Total natural gas purchased for resale change | $ | 3 | | | $ | — | | | $ | 35 | | | $ | — | | | $ | — | | | $ | 38 | | | | | | |
| Net change in natural gas margins | $ | (3) | | | $ | — | | | $ | 3 | | | $ | — | | | $ | — | | | $ | — | | | | | | |
| | Electric and Natural Gas Margins | | Electric and Natural Gas Margins | |
| Six Months | Six Months | Ameren Missouri | | Ameren Illinois
Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /Intersegment Eliminations | | Ameren | | Six Months | Ameren Missouri | | Ameren Illinois
Electric Distribution | | Ameren Illinois
Natural Gas | | Ameren Transmission(a) | | Other /Intersegment Eliminations | | Ameren | |
| Electric revenue change: | Electric revenue change: | | | Electric revenue change: | | |
Effect of weather (estimate)(b) | $ | 28 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 28 | | | |
Base rates (estimate)(c)(b) | Base rates (estimate)(c)(b) | 77 | | | 47 | | | — | | | 30 | | | — | | | 154 | | | Base rates (estimate)(c)(b) | $ | 38 | | | $ | (2) | | | $ | — | | | $ | 28 | | | $ | — | | | $ | 64 | | |
| Effect of weather (estimate)(c) | | Effect of weather (estimate)(c) | (56) | | | — | | | — | | | — | | | — | | | (56) | | |
| Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | 4 | | | — | | | — | | | — | | | — | | | 4 | | | Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA) | (13) | | | — | | | — | | | — | | | — | | | (13) | | |
| | Off-system sales, capacity, and FAC revenues, net | Off-system sales, capacity, and FAC revenues, net | 54 | | | — | | | — | | | — | | | — | | | 54 | | | Off-system sales, capacity, and FAC revenues, net | 118 | | | — | | | — | | | — | | | — | | | 118 | | |
| Ameren Illinois energy-efficiency program investment revenues | Ameren Illinois energy-efficiency program investment revenues | — | | | 6 | | | — | | | — | | | — | | | 6 | | | Ameren Illinois energy-efficiency program investment revenues | — | | | 9 | | | — | | | — | | | — | | | 9 | | |
| Other | Other | 1 | | | 2 | | | — | | | — | | | — | | | 3 | | | Other | 1 | | | 2 | | | — | | | — | | | (4) | | | (1) | | |
Cost recovery mechanisms – offset in fuel and purchased power(d) | Cost recovery mechanisms – offset in fuel and purchased power(d) | 28 | | | 112 | | | — | | | — | | | (7) | | | 133 | | | Cost recovery mechanisms – offset in fuel and purchased power(d) | 40 | | | 200 | | | — | | | — | | | (6) | | | 234 | | |
Other cost recovery mechanisms(e) | Other cost recovery mechanisms(e) | 6 | | | 3 | | | — | | | — | | | — | | | 9 | | | Other cost recovery mechanisms(e) | 3 | | | (14) | | | — | | | — | | | — | | | (11) | | |
| Total electric revenue change | Total electric revenue change | $ | 198 | | | $ | 170 | | | $ | — | | | $ | 30 | | | $ | (7) | | | $ | 391 | | | Total electric revenue change | $ | 131 | | | $ | 195 | | | $ | — | | | $ | 28 | | | $ | (10) | | | $ | 344 | | |
| Fuel and purchased power change: | Fuel and purchased power change: | | | Fuel and purchased power change: | | |
| Energy costs (excluding the estimated effect of weather) | Energy costs (excluding the estimated effect of weather) | $ | (55) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (55) | | | Energy costs (excluding the estimated effect of weather) | $ | (112) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (112) | | |
Effect of weather (estimate)(b) | (5) | | | — | | | — | | | — | | | — | | | (5) | | | |
Effect of weather (estimate)(c) | | Effect of weather (estimate)(c) | 10 | | | — | | | — | | | — | | | — | | | 10 | | |
| Effect of higher net energy costs included in base rates | Effect of higher net energy costs included in base rates | (3) | | | — | | | — | | | — | | | — | | | (3) | | | Effect of higher net energy costs included in base rates | (1) | | | — | | | — | | | — | | | — | | | (1) | | |
| Transmission services charges | (1) | | | — | | | — | | | — | | | — | | | (1) | | | |
| Other | Other | (2) | | | — | | | — | | | — | | | 3 | | | 1 | | | Other | 3 | | | — | | | — | | | — | | | — | | | 3 | | |
Cost recovery mechanisms – offset in electric revenue(d) | Cost recovery mechanisms – offset in electric revenue(d) | (28) | | | (112) | | | — | | | — | | | 7 | | | (133) | | | Cost recovery mechanisms – offset in electric revenue(d) | (40) | | | (200) | | | — | | | — | | | 6 | | | (234) | | |
| Total fuel and purchased power change | Total fuel and purchased power change | $ | (94) | | | $ | (112) | | | $ | — | | | $ | — | | | $ | 10 | | | $ | (196) | | | Total fuel and purchased power change | $ | (140) | | | $ | (200) | | | $ | — | | | $ | — | | | $ | 6 | | | $ | (334) | | |
| Net change in electric margins | Net change in electric margins | $ | 104 | | | $ | 58 | | | $ | — | | | $ | 30 | | | $ | 3 | | | $ | 195 | | | Net change in electric margins | $ | (9) | | | $ | (5) | | | $ | — | | | $ | 28 | | | $ | (4) | | | $ | 10 | | |
| Natural gas revenue change: | Natural gas revenue change: | | | | Natural gas revenue change: | | |
| | Base rates (estimate) | $ | 3 | | | $ | — | | | $ | 3 | | | $ | — | | | $ | — | | | $ | 6 | | | |
| Change in rate design | — | | | — | | | 1 | | | — | | | — | | | 1 | | | |
| QIP rider | — | | | — | | | 15 | | | — | | | — | | | 15 | | | |
| Effect of weather (estimate)(c) | | Effect of weather (estimate)(c) | $ | (10) | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (10) | | |
| Sales volumes (excluding the estimated effect of weather) | | Sales volumes (excluding the estimated effect of weather) | (2) | | | — | | | — | | | — | | | — | | | (2) | | |
| QIP | | QIP | — | | | — | | | 6 | | | — | | | — | | | 6 | | |
| Other | Other | — | | | — | | | 4 | | | — | | | — | | | 4 | | | Other | 2 | | | — | | | — | | | — | | | (1) | | | 1 | | |
Cost recovery mechanisms – offset in natural gas purchased for resale(d) | Cost recovery mechanisms – offset in natural gas purchased for resale(d) | 22 | | | — | | | 121 | | | — | | | — | | | 143 | | | Cost recovery mechanisms – offset in natural gas purchased for resale(d) | 7 | | | — | | | (121) | | | — | | | — | | | (114) | | |
Other cost recovery mechanisms(e) | Other cost recovery mechanisms(e) | 1 | | | — | | | 6 | | | — | | | — | | | 7 | | | Other cost recovery mechanisms(e) | (1) | | | — | | | (7) | | | — | | | — | | | (8) | | |
| Total natural gas revenue change | Total natural gas revenue change | $ | 26 | | | $ | — | | | $ | 150 | | | $ | — | | | $ | — | | | $ | 176 | | | Total natural gas revenue change | $ | (4) | | | $ | — | | | $ | (122) | | | $ | — | | | $ | (1) | | | $ | (127) | | |
| Natural gas purchased for resale change: | Natural gas purchased for resale change: | | | Natural gas purchased for resale change: | | |
| Effect of weather (estimate)(c) | | Effect of weather (estimate)(c) | $ | 9 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 9 | | |
Cost recovery mechanisms – offset in natural gas revenue(d) | Cost recovery mechanisms – offset in natural gas revenue(d) | $ | (22) | | | $ | — | | | $ | (121) | | | $ | — | | | $ | — | | | $ | (143) | | | Cost recovery mechanisms – offset in natural gas revenue(d) | (7) | | | — | | | 121 | | | — | | | — | | | 114 | | |
| Total natural gas purchased for resale change | Total natural gas purchased for resale change | $ | (22) | | | $ | — | | | $ | (121) | | | $ | — | | | $ | — | | | $ | (143) | | | Total natural gas purchased for resale change | $ | 2 | | | $ | — | | | $ | 121 | | | $ | — | | | $ | — | | | $ | 123 | | |
| Net change in natural gas margins | Net change in natural gas margins | $ | 4 | | | $ | — | | | $ | 29 | | | $ | — | | | $ | — | | | $ | 33 | | | Net change in natural gas margins | $ | (2) | | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | | | $ | (4) | | |
|
(a)Includes an increase in transmission margins of $17$8 million and $34$24 million at Ameren Illinois for the three and six months ended June 30, 2022,2023, compared with the year-ago periods.
(b)Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the year-ago periods; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.
(c)For Ameren Illinois Electric Distribution and Ameren Transmission, base rates include increases or decreases to operating revenues related to the revenue requirement reconciliation adjustment under formula rates. For Ameren Missouri, base rates exclude an increase for the recovery of lost electric margins resulting from the MEEIA customer energy-efficiency programs and an increasea decrease in base rates for RESRAM. These changes in Ameren Missouri base rates are included in the “Sales volumes and changes in customer usage patterns (excluding the estimated effects of weather and MEEIA)” and “Cost recovery mechanisms - offset in fuel and purchased power” line items, respectively.
(c)Represents the estimated variation resulting primarily from changes in cooling and heating degree-days on electric and natural gas demand compared with the year-ago periods; this variation is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories.
(d)Electric and natural gas revenue changes are offset by corresponding changes in “Fuel,” “Purchased power,” and “Natural gas purchased for resale” on the statement of 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. See Note 8 – Related-party Transactions and Note 14 – Segment Information under Part I, Item 1, 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 and "Income Taxes" in the statement of income. These items have no overall impact on earnings.
Ameren
Ameren’s electric margins increased $130decreased $7 million, or 13%, and $195 million, or 10%1%, for the three andmonths ended June 30, 2023, compared with the year-ago period, due to decreased margins at Ameren Missouri, partially offset by increased margins at Ameren Transmission, as discussed below. Ameren’s electric margins increased $10 million, or less than 1%, for the six months ended June 30, 2022, respectively,2023, compared with the year-ago periodsperiod, due to increased margins at Ameren Transmission, partially offset by decreased margins at Ameren Missouri and Ameren Illinois Electric Distribution, and Ameren Transmission, as discussed below. Ameren’s natural gas margins increased $10were comparable for the three months ended June 30, 2023, and decreased $4 million, or 8%1%, for the six months ended June 30, 2023, compared with the year-ago period, due to decreased margins at Ameren Missouri Natural Gas and Ameren Illinois Natural Gas, as discussed below.
Ameren Transmission
Ameren Transmission’s margins increased $11 million, or 7%, and $33$28 million, or 9%, for the three and six months ended June 30, 2022, respectively, compared with the year-ago periods, due to increased margins at Ameren Illinois Natural Gas and Ameren Missouri, as discussed below.
Ameren Transmission
Ameren Transmission’s margins increased $14 million, or 10%, and $30 million, or 11%, for the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods. Base rate revenues were favorably affected primarily by higher recoverable expenses (+$5 million and +$16 million, respectively) and increased capital investment (+$56 million and +$1013 million, respectively), as evidenced by a 10%an 11% increase in rate base used to calculate the revenue requirement, as well as higher recoverable expenses (+$9 million and +$13 million, respectively), and the absence in 2022 of the FERC’s March 2021 order (+$7 million) for the six months ended June 30, 2022. See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the March 2021 FERC order.requirement.
Ameren Missouri
Ameren Missouri’s electric margins increased $80decreased $17 million, or 14%3%, and $104$9 million, or 10%1%, for the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods. Revenues associated with “Cost recovery mechanisms – offset in fuel and purchased power” increased $4$28 million and $28$40 million respectively, forfor the three and six months ended June 30, 2022. The increased revenues are fully offset by an increase in fuel and purchased power costs, which increased primarily2023, respectively, due to 2022increased revenue related to the amortization of costs previously deferred under the FAC that were reflected in customer rates.rates, which also increased fuel expense. The changes to “Cost recovery mechanisms - offset in fuel and purchased power” are fully offset by “Cost recovery mechanisms - offset in electric revenue,” in the table above, and result in no impact to margins. Ameren Missouri’s 5% exposure to net energy cost variances under the FAC is reflected within “Off-system sales, capacity, and FAC revenues, net” and “Energy costs (excluding(excluding the estimated effect of weather)”, as discussed below.
The following items had an unfavorable effect on Ameren Missouri’s electric margins for the three and six months ended June 30, 2023, compared with the year-ago periods (except where a specific period is referenced):
•Summer temperatures were milder as cooling degree days decreased 15% for the three months ended June 30, 2023, and winter temperatures were warmer as heating degree days decreased 19% for the six months ended June 30, 2023. The aggregate effect of weather decreased margins an estimated $20 million and $46 million for the three and six months ended June 30, 2023, respectively. The change in margins due to weather is the sum of the “Effect of weather (estimate)”. on electric revenues (-$23 million and -$56 million, respectively) and the “Effect of weather (estimate)” on fuel and purchased power (+$3 million and +$10 million, respectively) in the table above.
•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues decreased an estimated $6 million and $13 million for the three and six months ended June 30, 2023, respectively. These decreases were primarily due to a decrease in retail sales volumes and a decrease in the average retail price per kilowatthour related to changes in customer usage patterns.
The following items had a favorable effect on Ameren Missouri’s electric margins for the three and six months ended June 30, 2022,2023, compared with the year-ago periods (except where a specific period is referenced):periods:
•The December 2021 MoPSC electric rate order effective February 28, 2022, that resulted in higherHigher electric base rates, excluding the change in base rates for the MEEIA customer energy efficiencyenergy-efficiency programs and the RESRAM, resulting from the December 2021 MoPSC electric rate order effective February 28, 2022, partially offset by higher net energy costs included in base rates, increased margins $56an estimated $37 million and $74 million, respectively.for the six months ended June 30, 2023. The change in electric base rates is the sum of the change in “Base rates (estimate)” (+$59 million and +$77 million, respectively)38 million) and the “Effect of higher net energy costs included in base rates” (-$3 million and -$3 million, respectively)1 million) in the table above.
•Summer temperatures were warmer as cooling degree days increased 12% for the three months ended June 30, 2022, and winter temperatures were colder as heating degree days increased 1% for the three months ended March 31, 2022. The aggregate effect of weather increased margins an estimated $17 million and $23 million, respectively. The change in margins due to weather is the sum of the “Effect of weather (estimate)” on electric revenues (+$21 million and +$28 million, respectively) and the “Effect of weather (estimate)” on fuel and purchased power (-$4 million and -$5 million, respectively) in the table above.
•Other cost recovery mechanisms increased margins $13 million and $6 million, respectively, due to increased RESRAM revenues (+$8 million and +$12 million, respectively) primarily resulting from higher off-system sales recoverable under the RESRAM, increased excise taxes (+$4 million and +$6 million, respectively), and a change in recoverable MEEIA program costs (+$1 million and -$12 million, respectively).
•Excluding the estimated effects of weather and the MEEIA customer energy-efficiency programs, electric revenues increased an estimated $4 million for the six months ended June 30, 2022. The increase was primarily due to an increase in retail sales volumes, partially offset by a decrease in the average retail price per kilowatthour due to changes in customer usage patterns.
Ameren Missouri’s electric margins decreased $6 million and $1 million due to Ameren Missouri’s 5% exposure to net energy cost variances under the FAC for the three and six months ended June 30, 2022, respectively. Net energy costs were higher than those reflected in base rates, primarily because of higher purchased power costs due to higher energy prices and the absence of electric revenues from insurance recoveries related to the Callaway Energy Center maintenance outage in 2021 in both periods, partially offset in the six months ended June 30, 2022, by an increase in off-system sales revenue due to higher energy prices and increased generation from the Callaway Energy Center. Inmargins $6 million for the three and six months ended June 30, 2022, higher capacity revenues were almost entirely offset by higher capacity costs included in “Purchased power” on Ameren’s and Ameren Missouri’s consolidated income statements, with the increase in both revenues and expenses caused by the capacity prices set in the April 2022 MISO capacity auction, which became effective in June 2022. See Outlook for additional information related to the April 2022 MISO capacity auction.2023. The change in net energy costs is the sum of “Off-system sales, capacity and FAC revenues, net” (+$228 million and +$54118 million, respectively) and “Energy costs (excluding the estimated effect of weather)” (-$822 million and -$55112 million, respectively) in the table above. In the three and six months ended June 30, 2023, these revenues and costs increased primarily due to higher capacity prices, partially offset by the effect of decreased generation volumes and lower market prices for power. Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. For the three and six months ended June 30, 2023, capacity revenues increased $54 million and $209 million, respectively, and capacity costs increased $52 million and $201 million, respectively. Capacity revenues and costs increased due to an increase in the price set by the annual MISO auction in April 2022, which became effective June 2022. These increases in capacity revenues and costs were partially offset by lower capacity prices set by the annual MISO auction in April 2023, which became effective June 2023, as well as the
effect of lower market prices for power, which resulted in a decrease in off-system sales and related fuel costs. See Outlook for additional information related to the April 2022 and April 2023 MISO auctions.
•Other cost recovery mechanisms increased margins $3 million for the six months ended June 30, 2023, primarily due to an increase in recoverable MEEIA program costs.
•Other decreases in fuel and purchased power expenses, which increased margins $3 million for the six months ended June 30, 2023, were largely due to a decrease in transmission network upgrade charges.
Ameren Missouri’s natural gas margins increased $2decreased $3 million, or 13%18%, and $4 million, or 9%, for the three months ended June 30, 2023, and were comparable for the six months ended June 30, 2022, respectively, compared with2023. Margins decreased for the year-ago periods, three months ended June 30, 2023, due primarily due to increased base rates as a result of the December 2021 MoPSC gas rate order effective February 28, 2022. lower sales volume from residential customers. Purchased gas costs increased $7 million and $22 million for the three and six months ended June 30, 2022, respectively, 2023, due to 2022 amortization of natural gas costs previously deferred under the PGA, driven by a significant increase in cost and customer demand as result of the extremely cold weather in mid-February 2021, partially offset by lower natural gas prices in 2022.2021. The increased purchased natural gas costs are fully offset by an increase in natural gas revenues under the PGA, rider, resulting in no impact to margin. The increase in purchased natural gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoverability from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above.
Ameren Illinois
Ameren Illinois’ electric margins increased $50$8 million, or 13%2%, and $92$19 million, or 12%2%, for the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods, driven by increased margins at Ameren Illinois Transmission, partially offset by decreased margins at Ameren Illinois Electric Distribution and Ameren Illinois Transmission.for the six months ended June 30, 2023. Ameren Illinois Natural Gas’ margins increased $8$3 million, or 7%, and $29 million, or 9%3%, for the three months ended June 30, 2023, and were comparable for the six months ended June 30, 2022, respectively, compared with the year-ago periods.2023.
Ameren Illinois Electric Distribution
Ameren Illinois Electric Distribution’s margins increased $33were comparable for the three months ended June 30, 2023, and decreased $5 million, or 11%, and $58 million, or 10%1%, for the three and six months ended June 30, 2022, respectively,2023, compared with the year-ago periods. Purchased power costs increased $83$36 million and $112$200 million for the three and six months ended June 30, 2022,2023, respectively, primarily resultingdue to increased energy prices (+$1 million and +$96 million, respectively) largely reflecting the results of IPA procurement events, and increased capacity prices (+$19 million and +$63 million, respectively). In the three and six months ended June 30, 2023, capacity revenues and costs increased due to an increase in the price set by the annual MISO auction in April 2022, which became effective June 2022. These increases in capacity revenues and costs were partially offset by lower capacity prices set by the annual MISO auction in April 2023, which became effective June 2023. See Outlook for additional information related to the April 2022 and April 2023 MISO auctions. In addition to increased energy and capacity prices, higher volumes increased purchased power costs (+$13 million and +$31 million, respectively), primarily due to residential and small commercial customer switching from higheralternative retail electric prices.suppliers to Ameren Illinois’ supplied power. The increased purchased power costs are fully offset by an increase in electric revenues under the cost recovery mechanisms for purchased power, resulting in no impact to margin. The increase in purchased power cost is reflected in “Cost recovery mechanisms – offset in electric revenue” and the associated recoverability from customers is reflected in “Cost recovery mechanisms – offset in fuel and purchased power” in the table above.
The following items had a favorable effect on Ameren Illinois Electric Distribution’sOther cost recovery mechanisms decreased margins by $6 million and $14 million for the three and six months ended June 30, 2022, 2023, respectively, compared with the year-ago periods:
•periods, Base rates increasedprimarily due to a lower amount of bad debt costs included in customer rates pursuant to the associated rider. The decreased margins were partially offset by an increase in revenues of $5 million and $9 million, respectively, due to the recovery of and return on increased energy-efficiency program investments under performance-based formula ratemaking. The impact from base rates was comparable (+$2 million and -$2 million, respectively) due to lower recoverable non-purchased power expenses (-$3 million and -$16 million, respectively), offset by a higher recognized ROE (+$62 million and +$8 million, respectively), as evidenced by an increase of 7974 basis points in the estimated annual average of the monthly yields of the 30-year United States Treasury bonds, and increased capital investment (+$23 million and +$46 million, respectively), as evidenced by a 6%7% increase in rate base used to calculate the revenue requirement, and higher recoverable non-purchased power expenses (+$20 million and +$39 million, respectively), partially offset by the absence in 2022 of revenue requirement reconciliation adjustment true-ups (-$4 million) recorded in the first quarter of 2021. The sum of these changes collectively increased margins $28 million and $47 million, respectively.
•Revenues increased $3 million and $6 million, respectively, due to the recovery of and return on increased energy-efficiency program investments under performance-based formula ratemaking.requirement.
Ameren Illinois Natural Gas
Ameren Illinois Natural Gas’ margins increased $8$3 million, or 7%, and $29 million, or 9%3%, for the three months ended June 30, 2023, and were comparable for the six months ended June 30, 2022, respectively, compared with the year-ago periods.2023. Purchased gas costs increased $8decreased $35 million and $121 million for the three and six months ended June 30, 2022,2023, respectively, primarily due to 2022lower amortization of natural gas costs that were previously deferred under the PGA driven by a significant increase in cost and customer demand as a result of the extremely cold weather in mid-February 2021, partially offset by lower natural gas prices in 2023. Those deferred natural gas costs inrelated to the mid-February 2021 weather event were fully recovered from customers by the end of 2022. The increaseddecreased purchased natural gas costs are fully offset by an increasea decrease in natural gas revenues under the PGA, rider, resulting in no impact to margin. The increasedecrease in purchased natural gas cost is reflected in “Cost recovery mechanisms – offset in natural gas revenue” and the associated recoverability from customers is reflected in “Cost recovery mechanisms – offset in natural gas purchased for resale” in the table above.
The following items had a favorable effect on Ameren Illinois Natural Gas’ margins for the three and six months ended June 30, 2022 (except where a specific period is referenced):
•Revenues increased $6$3 million and $15$6 million respectively, due to additional investment in natural gas infrastructure under the QIP.
•Other cost recovery mechanisms increased revenues $6 million, primarily due to increased revenuesQIP for excise taxes, for the three and six months ended June 30, 2022.
•Revenues increased $3 million in January 2022 due to higher base rates as a result of the January 2021 natural gas rate order.2023, respectively. Other cost recovery mechanisms decreased
Ameren Illinois Transmission
Ameren Illinois Transmission’s margins increased $17$8 million, or 19%8%, and $34$24 million, or 20%12%, for the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods. Base rate revenues were favorably affected primarily by increased capital investment (+$6 million and +$1113 million, respectively), as evidenced by a 16%17% increase in rate base used to calculate the revenue requirement, and the absence in 2022 of the FERC’s March 2021 order (+$7 million) for the six months ended June 30, 2022, and higherhigher recoverable expenses (+$113 million and +$1612 million, respectively). See Transmission Formula Rate Revisions in Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the March 2021 FERC order.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) by Segment | |
| | | Overall Ameren IncreaseDecrease of $79$41 Million (QTD YoY) | | Overall Ameren IncreaseDecrease of $120$54 Million (YTD YoY) | |
| Total by Segment(a) | | | |
(a)Includes $16$13 million and $14$16 million at Ameren Transmission in the three months ended June 30, 2023 and 2022, and 2021, respectively. Also includesIncludes other/intersegment eliminations of $4 million, $(2) million, $7$9 million and $(4)$4 million in the three months ended June 30, 2023 and 2022, respectively. Also includes other/intersegment eliminations of $14 million and 2021, and$7 million in the six months ended June 30, 20222023 and 2021,2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Ameren
Other operations and maintenance expenses increased $79decreased $41 million and $120$54 million in the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods. In addition to changes by segments discussed below, other operations and maintenance expenses increased $6$5 million and $11$7 million in the three and six months ended June 30, 20222023, respectively, for activity not reported as part of a segment, as reflected in “Other/Intersegment Eliminations” above, primarily because of an increase in the elimination of the non-service cost component of net periodic benefit income at Ameren Services. The non-service cost component of net periodic benefit cost or income at Ameren Services which is allocated to the segments and primarily included in the segments’ other operations and maintenance expenses.
Ameren Transmission
Other operations and maintenance expenses were comparable betweendecreased $3 million in both the three and six months ended June 30, 2023, compared with the year-ago periods, primarily because of increases in the cash surrender value of COLI due to favorable market returns in 2023, compared with unfavorable market returns in the year-ago periods.
Ameren Missouri
Other operations and maintenance expenses increased $42decreased $23 million and $49$16 million in the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods. The following items increaseddecreased other operations and maintenance expenses in the three and six months ended June 30, 2022,2023, compared with the year-ago periods (except where a specific period is referenced):
•The cash surrender value of company-owned life insurance decreased $12COLI increased $10 million and $18$19 million, respectively primarily because. In the three and six months ended June 30, 2023, the effect of unfavorable market returnschanges in 2022,the cash surrender value of COLI resulted in gains of $2 million and $5 million, respectively, compared with favorable market returnslosses of $8 million and $14 million, respectively, in 2021.the year-ago periods.
•The absencerecognition of regulatory assets for previously expensed costs approved for recovery pursuant to the June 2023 MoPSC rate order decreased other operations and maintenance expenses $15 million in 2022 ofboth periods.
•Renewable development costs decreased $6 million and $12$9 million, respectively, in service fees received under refined coal production agreements, as the resultMoPSC order approving CCNs for the Boomtown and Huck Finn solar projects in the first half of 2023 led to increased capitalization of renewable development costs pursuant to anticipated recovery from customers.
•Energy center operating and maintenance costs decreased $2 million and $5 million, respectively, related to the retirement of the expiration of refined coal tax credits atMeramec Energy Center.
The above decreases in the end of 2021, which impact was reflected in electric services rates pursuant tothree and six months ended June 30, 2023, compared with the December 2021 MoPSC rate order.year-ago periods, were partially offset by the below items (except where a specific period is referenced):
•Labor and benefit costs increased $7$5 million and $11 million, respectively, primarily because of increased pension service costs due tomedical and retirement benefits, including the effect of a higher base level of expensespension service costs reflected in electric service rates effective February 28, 2022, pursuant to the December 2021 MoPSC rate order.order for the six months ended June 30, 2023. Pursuant to the pension tracker, differences between actual costs incurred and base level expenses included in customer rates are deferred as a regulatory asset or liability for recovery from, or refund to, customers over a period of time as determined in a subsequent regulatory rate review.
•TransmissionCallaway Energy Center costs increased $2 million and distribution expenditures$5 million, respectively, primarily because of the amortization of increased $6 millioncosts related to the spring 2022 refueling and maintenance outage, which costs began amortizing in both periods, primarily due to disciplined project management and increased storm costs.June 2022.
•The absence of a $5MEEIA customer energy-efficiency program spend increased $4 million deferral to a regulatory asset of certain costs previously incurred related to the COVID-19 pandemic, pursuant to the March 2021 MoPSC orders, which decreased other operations and maintenance expenses in the six months ended June 30, 2021.2023, as approved by the MoPSC.
•Energy center operating costsCosts for injuries and damages increased $4 million in the six months ended June 30, 2023, primarily because of an increase in claims, compared with the year-ago period.
•Technology-related expenditures increased $3 million in the six months ended June 30, 2022, primarily because of costs related to new wind generation facilities, which are recovered under the RESRAM.
•Customer billing costs2023, resulting from increased $2 million in both periods, primarily because credit card fees charged to customers were discontinued in March 2022 pursuant to the December 2021 MoPSC rate order, which incorporated an amount of fees in electric service rates.software maintenance expenses.
The above increases in the six months ended June 30, 2022, compared with the year-ago period, were partially offset by a $12 million decrease in MEEIA customer energy-efficiency program spend as approved by the MoPSC.
Ameren Illinois
Other operations and maintenance expenses increased $32decreased $24 million and $61$45 million in the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods, as discussed below. Other operations and maintenance expenses increaseddecreased $4 million and $3 million at Ameren Illinois Transmission in the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods, primarily because of decreasesincreases in the cash surrender value of company-owned life insurance relatedCOLI due to favorable market returns in 2023, compared with unfavorable market returns in 2022, compared with favorable market returns in 2021.the year-ago periods.
Ameren Illinois Electric Distribution
Other operations and maintenance expenses increased $19decreased $15 million and $41$33 million in the three and six months ended June 30, 2022,2023, respectively, compared with the year-ago periods. The following items increaseddecreased other operations and maintenance expenses in the three and six months ended June 30, 2022,2023, compared with the year-ago periods (except where a specific period is referenced):
•Distribution system expenditures increased $5Bad debt costs decreased $10 million and $15$23 million, respectively, primarily because of projects deferreda lower amount of costs included in 2021 as a result of storm restoration efforts for whichcustomer rates pursuant to the associated costs were deferred as a regulatory asset in 2021.rider.
•The cash surrender value of company-owned life insurance decreased $6COLI increased $5 million and $9 million, respectively, primarily because of favorable market returns in 2023, compared with unfavorable market returns in 2022, compared with favorable market returns in 2021.the year-ago periods.
•Increased bad debt expense of $2 million and $7 million, respectively, primarily because of increased recovery of bad debt costs allowed by the ICC.
•InjuriesCosts for injuries and damages increaseddecreased $4 million in both periods, primarily because of an increasea decrease in claims compared with the year-ago periods.
•AmortizationThe above decreases in the three and six months ended June 30, 2023, compared with the year-ago periods, were partially offset by increases of $2 million and $4 million, respectively, in the amortization of regulatory assets associated with customer energy-efficiency program investments under formula ratemaking increased $2 million and $4 million, respectively.ratemaking.
Ameren Illinois Natural Gas
Other operations and maintenance expenses increased $10decreased $5 million and $17$9 million in the three and six months ended June 30, 2022,2023, compared with the year-ago periods, primarily because the cash surrender value of COLI increased distribution system expenditures of$3 million and $5 million, respectively. In the three and $9six months ended June 30, 2023, the effect of changes in the cash surrender value of COLI resulted in gains of $1 million in both periods, compared with losses of $2 million and $4 million, respectively, primarily because of a shift from capital to operations and maintenance activity, which is expected to largely reverse in the second half of the year.year-ago periods. Other operations and maintenance expenses also increased $3decreased $2 million and $5$4 million, respectively, because of decreases indecreased distribution system expenditures, primarily because of the cash surrender valuetiming of company-owned life insurance related to unfavorable market returns in 2022, compared with favorable market returns in 2021.
Depreciation and Amortization Expenses
| | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) by Segment | |
| | | Overall Ameren Increase of $31$19 Million (QTD YoY) | | Overall Ameren Increase of $49$40 Million (YTD YoY) | |
| Total by Segment(a) | | | |
(a)Includes other/intersegment eliminations of $1 million $2 million, $2 million, and $2$1 million in the three months ended June 30, 2023 and 2022, respectively. Also includes other/intersegment eliminations of $2 million and 2021, and$2 million in the six months ended June 30, 20222023 and 2021, respectively2022, respectively..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Depreciation and amortization expenses increased $31$19 million, $21$8 million, and $11$10 million in the three months ended June 30, 2022,2023, and $49$40 million, $29$20 million, and $20$19 million in the six months ended June 30, 2022,2023, compared with the year-ago periods, at Ameren, Ameren Missouri, and Ameren Illinois, respectively, primarily because of additional property, plant, and equipment investments across their respective segments. Ameren’s and Ameren Missouri’s depreciation and amortization expenses for the three and six months ended June 30, 2022,2023, compared with the year-ago periods, were affected by the following (except where a specific period is referenced), which include the effect of the additional investments:investments at Ameren Missouri:
•Depreciation and amortization rate changes effective February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which increased depreciation and amortization expenses by $17$11 million, and $23 million, respectively.in the six months ended June 30, 2023.
•Increased depreciation and amortization expenses of $17$11 million and $23 million, respectively, for amounts previously deferred under the PISA and RESRAM and subsequently reflected in base rates effective February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, largely due to investments in wind generation.generation, in the six months ended June 30, 2023.
•Fewer deferralsDepreciation and amortization expenses at Ameren and Ameren Missouri reflected a deferral to a regulatory asset of depreciation and amortization expenses of $15 million in both periods duepursuant to less property, plant, and equipment eligible for recovery under the PISA and RESRAM as a resultRESRAM. The amount of the December 2021 MoPSC electric rate order.
•The net deferral related to the Meramec Energy Center retirement, which decreased depreciation and amortization expenses by $15 millionincluded in base rates for PISA and $20 million, respectively,RESRAM deferrals was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order.
•order, which incorporated deferrals through September 30, 2021. The net under-recoveryeffect of RESRAM eligible expenses, which decreaseddeferrals and increased depreciation and amortization expenses, by $9 million and $14 million, respectively.primarily because of electric system capital additions, increased depreciation
$3 million and $11 million, respectively.
•The lower net under-recovery of RESRAM eligible expenses increased depreciation and amortization expenses by $2 million in the three months ended June 30, 2023, while the higher net under-recovery of RESRAM eligible expenses decreased depreciation and amortization expenses by $11 million in the six months ended June 30, 2023.
•The impact of the retirement of the Meramec Energy Center in December 2022 resulted in a $3 million increase to depreciation and amortization expenses in the three months ended June 30, 2023, and a $3 million decrease in the six months ended June 30, 2023, primarily due to the deferral in 2022 of the energy center’s depreciation and amortization expenses and resulting amortization of that deferral pursuant to the December 2021 MoPSC electric rate order, which established a five-year recovery period for certain Meramec Energy Center costs beginning February 28, 2022.
Taxes Other Than Income Taxes
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| | | Increase (Decrease) by Segment | |
| | | Overall Ameren IncreaseDecrease of $7$5 Million (QTD YoY) | | Overall Ameren IncreaseDecrease of $21$20 Million (YTD YoY) | |
| Total by Segment(a) | | | |
(a)Includes $2 million, $2 million, $4 million, and $4 million at Ameren Transmission in the three months ended June 30, 20222023 and 2021,2022, and in the six months ended June 30, 20222023 and 2021,2022, respectively. Also includes other/intersegment eliminations of $2$3 million, $2 million, $6$7 million, and $6 million in the three months ended June 30, 20222023 and 2021,2022, and in the six months ended June 30, 20222023 and 2021,2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Taxes other than income taxes increased $7decreased $5 million in the three months ended June 30, 2022,2023, compared with the year-ago period, primarily because of decreased sales at Ameren Illinois Natural Gas and deferral of taxes under the Ameren Missouri electric property tax tracker. Taxes other than income taxes decreased $20 million in the six months ended June 30, 2023, compared with the year-ago period, primarily because of a $4$9 million increasedecrease in excise taxes at Ameren Missouri,Illinois Natural Gas, primarily because of increasedresulting from decreased sales. Taxes other than income taxes increased $21also decreased $5 million in the six months ended June 30, 2022, compared with the year-ago period, primarily because of $7and $2 million increases in excise taxes at both Ameren Missouri and Ameren Illinois Natural Gas, primarilyElectric Distribution, respectively, because of increased sales. Taxes other than income taxes also increased $6 million inemployee retention tax credits received under the six months ended June 30, 2022, compared with the year-ago period, at Ameren Missouri because of increased property taxes, primarily resulting from higher assessed valuesCoronavirus Aid, Relief, and lower property tax refunds.Economic Security Act.
Other Income, Net
| | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) by Segment | |
| | | Overall Ameren Increase of $13$20 Million (QTD YoY) | | Overall Ameren Increase of $27$38 Million (YTD YoY) | |
| Total by Segment(a) | | | |
(a)Includes $4$8 million and $2$4 million at Ameren Transmission in the three months ended June 30, 20222023 and 2021,2022, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
Other income, net, increased $13$20 million in the three months ended June 30, 2022,2023, compared with the year-ago period, primarily because of increases in the non-service cost component of net periodic benefit income of $5$7 million, $5$6 million, and $2$3 million at Ameren Illinois Electric Distribution,for activity not reported as part of a segment, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. In the three months ended June 30, 2023, other income, net, also increased $4 million because of higher interest income on under-recovered balances associated with regulatory recovery mechanisms at Ameren Illinois Electric Distribution and $2 million because of higher allowance for equity funds used during construction at Ameren Transmission. Other Income,income, net, increased $27$38 million in the six months ended June 30, 2022,2023, compared with the year-ago period, primarily because of increases in the non-service cost component of net periodic benefit income of $10$15 million, $9$13 million, and $4$6 million for Ameren Illinois Electric Distribution, activity not reported as part of a segment, Ameren Illinois Electric Distribution, and Ameren Illinois Natural Gas, respectively. In the six months ended June 30, 2023, other income, net, also increased $7 million because of higher interest income on under-recovered balances associated with regulatory recovery mechanisms at Ameren Illinois Electric Distribution and $4 million because of higher allowance for equity funds used during construction at Ameren Transmission. The increases in other income, net, in the three and six months ended June 30, 2023, were partially offset by $6 million and $11 million decreases, respectively, in interest income on industrial development revenue bonds at Ameren Missouri, as these bonds were settled in December 2022 and January 2023. The increases in other income, net, associated with these bonds are offset by decreases in interest charges on a related financing obligation agreement, as discussed below.
See Note 5 – Other Income, Net, under Part I, Item 1, of this report for additional information. See Note 11 – Retirement Benefits under Part I, Item 1, of this report for more information on the non-service cost components of net periodic benefit income.
Interest Charges
| | | | | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) by Segment | |
| | | Overall Ameren Increase of $30$8 Million (QTD YoY) | | Overall Ameren Increase of $34$31 Million (YTD YoY) | |
| Total by Segment | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | | Ameren Illinois Natural Gas | | | Other/Intersegment Eliminations |
| | | | | | | | | |
| | Ameren Illinois Electric Distribution | | Ameren Transmission | | | | |
See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report and the Long-term Debt and Equity section below for additional information on short-term borrowings and long-term debt, respectively, discussed below. See Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information on the termination of the financing obligation agreement discussed below.
Ameren
Interest charges increased $30$8 million and $34$31 million in the three and six months ended June 30, 2022,2023, compared with the year-ago periods. In addition to changes by segments discussed below, interest charges increased $8 million and $14 million, respectively, at Ameren (parent) because of higher interest rates on increased levels of short-term borrowings.
Ameren Missouri
Interest charges decreased $8 million in the three months ended June 30, 2023, and increased $4 million in the six months ended June 30, 2023, compared with the year-ago periods. The following items increased interest charges in the three and six months ended June 30, 2022,2023, compared with the year-ago periods:periods (except where a specific period is referenced):
•Interest charges at Amerenincreased $3 million and Ameren Missouri$8 million, respectively, because of higher interest rates on increased levels of short-term borrowings.
•Issuances of long-term debt in April 2022 and March 2023 collectively increased interest charges by $7 million and $13 million, respectively.
•Interest charges reflected a deferral to a regulatory asset of interest charges pursuant to PISA and RESRAM. The amount of interest charges included in base rates for PISA and RESRAM deferrals was updated when new customer rates became effective on February 28, 2022, pursuant to the December 2021 MoPSC electric rate order, which incorporated deferrals through September 30, 2021. Lower deferrals, due to the inclusion in base rates of interest associated with certain property, plant, and equipment previously deferred under the PISA and RESRAM, increased interest charges by $15$2 million in the six months ended June 30, 2023.
The following items decreased interest charges in the three and $12six months ended June 30, 2023 (except where a specific period is referenced):
•Increased PISA and RESRAM deferrals reduced interest charges by $7 million respectively.in the three months ended June 30, 2023.
•Interest charges decreased $6 million and $11 million, respectively, primarily due to the termination of a financing obligation agreement related to the CT energy center in Audrain County.
•Interest charges decreased $4 million and $9 million, respectively, because of an increase in the borrowed funds capitalized as part of the allowance for funds used during construction, primarily due to increased eligible construction work in process balances and a higher applicable borrowing rate.
Ameren Illinois
Interest charges increased $9 million and $14 million in the three and six months ended June 30, 2023, compared with the year-ago periods, primarily due to the issuances of long-term debt in 2022. Issuances of long-term debt at Ameren MissouriIllinois in June 2021August and AprilNovember 2022 collectively increased interest charges by $4 million and $8 million, and $10 million, respectively.
•Issuances of long-term debtrespectively, at Ameren (parent) in MarchIllinois Electric Distribution, by $3 million and November 2021 collectively increased interest charges$6 million, respectively, at Ameren Illinois Transmission, and by $2 million and $6$4 million, respectively.respectively, at Ameren Illinois Natural Gas.
Income Taxes
The following table presents effective income tax rates for the three and six months ended June 30, 20222023 and 2021:2022:
| | | Three Months(a) | | Six Months(a) | | Three Months(a) | | Six Months(a) |
| | 2022 | | 2021 | | 2022 | | 2021 | | 2023 | | 2022 | | 2023 | | 2022 |
| Ameren | Ameren | | 15 | % | | 13 | % | | 13 | % | | 12 | % | Ameren | | 14 | % | | 15 | % | | 13 | % | | 13 | % |
| Ameren Missouri | Ameren Missouri | | (2) | % | | (3) | % | | (3) | % | | (3) | % | Ameren Missouri | | (1) | % | | (2) | % | | (1) | % | | (3) | % |
| Ameren Illinois | Ameren Illinois | | 25 | % | | 26 | % | | 26 | % | | 25 | % | Ameren Illinois | | 25 | % | | 25 | % | | 25 | % | | 26 | % |
| Ameren Illinois Electric Distribution | Ameren Illinois Electric Distribution | | 26 | % | | 25 | % | | 25 | % | | 24 | % | Ameren Illinois Electric Distribution | | 25 | % | | 26 | % | | 25 | % | | 25 | % |
| Ameren Illinois Natural Gas | Ameren Illinois Natural Gas | | 25 | % | | 29 | % | | 27 | % | | 27 | % | Ameren Illinois Natural Gas | | 27 | % | | 25 | % | | 26 | % | | 27 | % |
| Ameren Illinois Transmission | Ameren Illinois Transmission | | 25 | % | | 25 | % | | 26 | % | | 25 | % | Ameren Illinois Transmission | | 26 | % | | 25 | % | | 26 | % | | 26 | % |
| Ameren Transmission | Ameren Transmission | | 26 | % | | 26 | % | | 26 | % | | 26 | % | Ameren Transmission | | 26 | % | | 26 | % | | 26 | % | | 26 | % |
|
(a)Estimate of the annual effective income tax rate adjusted to reflect the tax effect of items discrete to the three and six months ended June 30, 20222023 and 2021.2022.
See Note 12 – Income Taxes under Part I, Item 1, of this report for a reconciliation of the federal statutory corporate income tax rate to the effective income tax rate for the Ameren Companies.
The effective income tax rate was lowerhigher at Ameren Illinois Natural Gas in the three months ended June 30, 2022,2023, compared with the year-ago period, primarily because of higher amortization of excess deferred taxes.depreciation differences on property-related items.
LIQUIDITY AND CAPITAL RESOURCES
Collections from our tariff-based revenues are our principal source of cash provided by operating activities. A diversified retail customer mix, primarily consisting of rate-regulated residential, commercial, and industrial customers, provides us with a reasonably predictable source of cash. In addition to using cash provided by operating activities, we use available cash, drawings under committed credit agreements, commercial paper issuances, and/or, in the case of Ameren Missouri and Ameren Illinois, short-term affiliate borrowings to support normal operations and temporary capital requirements. We may reduce our short-term borrowings with cash provided by operations or, at our discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with capital contributions from Ameren (parent). As of June 30, 2022,2023, there have been no material changes other than in the ordinary course of business related to cash requirements arising from these long-term commitments provided in Item 7 of the Form 10-K for the year ended December 31, 2021. In April and May 2022, Ameren Illinois conducted procurement events, administered by the IPA, to purchase energy products and acquire capacity through May 2025. As a result, Ameren and Ameren Illinois’ estimated minimum purchase obligations for purchased power increased by $0.5 billion in total over the period of June 2022 through May 2025.10-K.
We expect to make significant capital expenditures over the next five years, supported by a combination of long-term debt and equity, as we invest in our electric and natural gas utility infrastructure to support overall system reliability, grid modernization, renewable energy target requirements, environmental compliance, and other improvements. For additional information about our long-term debt outstanding, including maturities due within one year, and the applicable interest rates, see Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of the Form 10-K and Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2026.2027. Ameren expects these equity issuances to provide equity oftotal about $100 million annually. In addition, in 2021, Ameren establishedhas an ATM program under which Ameren may offer and sell from time to time up to $750 million of its common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. There were no shares issued under the ATM program for the three and six months ended June 30, 2022.2023. As of June 30, 2023, Ameren has entered into multiple forward sale agreements under the ATM program with various counterparties relating to 5.84.3 million shares of common stock. AsAmeren expects to settle approximately $300 million
of the forward sale agreements with physical delivery of 5.63.2 million shares of common stock by December 31, 2023. Also, Ameren plans to issue approximately $500 million of equity each year from 2024 to 2027, in addition to issuances under the respective counterparties in exchange for cash of $500 million.DRPlus and employee benefit plans. As of June 30, 2022,2023, Ameren had approximately $90$910 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of June 30, 2022. Ameren expects to settle approximately $300 million of the forward sale agreements by December 31, 2022. Ameren plans to issue approximately $300 million of equity each year from 2022 to 2026 in addition to issuances under the DRPlus and employee benefit plans.2023. Ameren expects its equity to total capitalization ratio to be approximatelyabout 45% throughby December 31, 2026,2027, with the long-term intent to support solid investment-grade credit ratings. See Long-term Debt and Equity below and Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information on the ATM program, including the forward sale agreements under the ATM program relating to common stock.program.
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 June 30, 2022,2023, for Ameren, Ameren Missouri, and Ameren Illinois. With the credit capacity available under the Credit Agreements, and cash and cash equivalents, Ameren (parent), Ameren Missouri, and Ameren Illinois, collectively, had net available liquidity of $1.3 billion at June 30, 2022.2023. Additionally, as of June 30, 2023, Ameren could have settled the forward sale agreements with physical delivery of 4.3 million shares of common stock to the respective counterparties in exchange for cash of $389 million. See Credit Facility Borrowings and Liquidity and Long-term Debt and Equity below for additional information.
The following table presents net cash provided by (used in) operating, investing, and financing activities for the six months ended June 30, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Cash Provided By
Operating Activities | | Net Cash Used In
Investing Activities | | Net Cash Provided By
Financing Activities |
| 2023 | | 2022 | | Variance | | 2023 | | 2022 | | Variance | | 2023 | | 2022 | | Variance |
| Ameren | $ | 1,111 | | (a) | $ | 872 | | (a) | $ | 239 | | | $ | (1,889) | | | $ | (1,552) | | | $ | (337) | | | $ | 808 | | | $ | 686 | | | $ | 122 | |
| | | | | | | | | | | | | | | | | |
| Ameren Missouri | 443 | | | 181 | | | 262 | | | (980) | | | (818) | | | (162) | | | 532 | | | 636 | | | (104) | |
| Ameren Illinois | 637 | | (a) | 675 | | (a) | (38) | | | (846) | | | (699) | | | (147) | | | 247 | | | 37 | | | 210 | |
(a)Both Ameren and Ameren Illinois’ cash provided by operating activities included cash outflows of $56 million and $37 million for the FEJA electric energy-efficiency rider and $5 million and $3 million for the customer generation rebate program for the six months ended June 30, 2023 and 2022, and 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Cash Provided By
Operating Activities | | Net Cash Used In
Investing Activities | | Net Cash Provided By
Financing Activities |
| 2022 | | 2021 | | Variance | | 2022 | | 2021 | | Variance | | 2022 | | 2021 | | Variance |
| Ameren | $ | 872 | | | $ | 436 | | | $ | 436 | | | $ | (1,552) | | | $ | (1,760) | | | $ | 208 | | | $ | 686 | | | $ | 1,290 | | | $ | (604) | |
| | | | | | | | | | | | | | | | | |
| Ameren Missouri | 181 | | | 224 | | | (43) | | | (818) | | | (1,053) | | | 235 | | | 636 | | | 701 | | | (65) | |
| Ameren Illinois | 675 | | | 286 | | | 389 | | | (699) | | | (668) | | | (31) | | | 37 | | | 477 | | | (440) | |
Cash Flows from Operating Activities
Our cash provided by operating activities is affected by fluctuations of trade accounts receivable, inventories, and accounts and wages
payable, among other things, as well as the unique regulatory environment for each of our businesses. Substantially all expenditures related to fuel, purchased power, and natural gas purchased for resale are recovered from customers through rate adjustment mechanisms, which may be adjusted without a traditional regulatory rate proceeding.review, subject to prudence reviews. Similar regulatory mechanisms exist for certain other operating expenses that can also affect the timing of cash provided by operating activities. The timing of cash payments for costs recoverable under our regulatory mechanisms differs from the recovery period of those costs. Additionally, the seasonality of our electric and natural gas businesses, primarily caused by seasonal customer rates and changes in customer demand due to weather, such as increased demand resulting from the extremely cold weather in mid-February 2021 discussed below, significantly affects the amount and timing of our cash provided by operating activities.
As a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, Ameren Missouri and Ameren Illinois had under-recovered costs for the month of February 2021 under their PGA clauses and, for Ameren Missouri, under the FAC (Ameren Missouri -– PGA $53 million, FAC $50 million; Ameren Illinois -– PGA $221 million). Ameren Missouri’s PGA under-recovery is being collected from customers over 36 months beginning November 2021, pursuant to an October 2021 MoPSC order, and the FAC under-recovery was collected over eight months beginning October 2021. Ameren Illinois is collectingcollected the PGA under-recovery over 18 months beginning April 2021.
Ameren
Ameren’s cash provided by operating activities increased $436$239 million in the first six months of 2022,2023, compared with the year-ago period. The following items contributed to the increase:
•A $574$237 million increase resulting from increased customer collections and decreased expenditures under the PGA and FAC, primarily as a result of the significant increase from customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, a net increase attributable to other regulatory recovery mechanisms, and higher customer collections resulting from base rate increases pursuant to Ameren Missouri’s December 2021 electric rate order.
•A $20 million decrease in coal inventory levels at Ameren Missouri, as less coal was purchased in 2022 due to service-related delivery disruptions.
•A $14 million decrease in major storm restoration costs at Ameren Illinois, primarily due to a January 2021 storm.
•An $11 million decrease in payments to settle ARO liabilities, primarily related to the closure of Ameren Missouri’s CCR storage facilities.
•An $8 million decrease in the cost of natural gas held in storage, primarily at Ameren Illinois, because of an increase in withdrawals between periods.
The following items partially offset the increase in Ameren’s cash from operating activities between periods:
•A $77 million increase in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.
•A $39$158 million increase resulting from increased customer collections, primarily from base rate increases effective February 28, 2022, pursuant to Ameren Missouri’s December 2021 electric rate order, electric transmission rate base growth, and an increase attributable to other regulatory mechanisms, partially offset by a decrease under Ameren Illinois’ PGA resulting from the recovery in 2022 of costs for the mid-February 2021 weather event discussed above.
•A $45 million decrease in the cost of natural gas held in storage, primarily at Ameren Illinois, because of lower commodity prices.
•A $40 million decrease in payments for nuclear refueling and maintenance outages at Ameren Missouri’s Callaway Energy Center. There was no scheduledCenter, primarily due to the spring 2022 outage. Ameren Missouri’s next refueling and maintenance outage at its Callaway Energy Center is scheduled for the fall of 2023.
The following items partially offset the increase in 2021.Ameren’s cash from operating activities between periods:
•A $58 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•A $30$54 million increase in purchasescoal inventory levels at Ameren Missouri, primarily due to fewer transportation delays and less coal burned in 2023 as a result of materialsdecreased generation volumes driven by lower market power prices and supplies inventories to support operations in 2022 as levels were increased to mitigate against any potential supply disruptions.decreased retail load because of both milder summer temperatures and warmer winter temperatures.
•A $23 million increase in payments for certain cloud computing arrangements.
•The absence in 2022 of $15 million in service fees received under refined coal production agreements at Ameren Missouri, as the result of the expiration of refined coal tax credits at the end of 2021.
•A $20$40 million increase in interest payments, primarily due to an increase in the average outstanding debt.debt and an increase in interest rates.
•A $13$23 million increase in purchases of materials and supplies inventories to support operations as levels were increased to mitigate against potential supply disruptions.
•A $12 million decrease resulting from income tax payments of $5 million in 2023, compared with income tax refunds of $7 million in 2022, primarily due to increased income tax extension payments, which are based on the preceding year’s taxable income and estimated payments.
•A $9 million increase in property tax payments at Ameren Missouri, primarily due to higher assessed property tax values.
Ameren Missouri
Ameren Missouri’s cash provided by operating activities decreased $43increased $262 million in the first six months of 2022,2023, compared with the year-ago period. The following items contributed to the decrease:increase:
•An $88A $199 million increasedecrease in net collateral posted with counterparties, primarily due to changes in the market prices of power, natural gas, and other fuels.
•A $67$142 million decrease in income tax refundsincrease resulting from Ameren (parent)increased customer collections, primarily from base rate increases effective February 28, 2022, pursuant to the tax allocation agreement, primarily dueDecember 2021 electric rate order and an increase attributable to higher taxable income in 2022.other regulatory mechanisms.
•A $39$40 million increasedecrease in payments for nuclear refueling and maintenance outages at the Callaway Energy Center. There was no scheduledCenter, primarily due to the spring 2022 outage. The next refueling and maintenance outage at the Callaway Energy Center is scheduled for the fall of 2023.
The following items partially offset the increase in 2021.Ameren Missouri’s cash from operating activities between periods:
•A $54 million increase in coal inventory levels, primarily due to fewer transportation delays and less coal burned in 2023 as a result of decreased generation volumes driven by lower market power prices and decreased retail load because of both milder summer temperatures and warmer winter temperatures.
•A $20$16 million increase in purchases of materials and supplies inventories to support operations in 2022 as levels were increased to mitigate against any potential supply disruptions.
•The absence in 2022 of $15 million in service fees received under refined coal production agreements, as the result of the expiration of refined coal tax credits at the end of 2021.
•A $13$9 million increase in property tax payments, primarily due to higher assessed property tax values.
•A $12$7 million increase indecrease due to the timing of payments for certain cloud computing arrangements.accounts payable and prepaid expenses.
Ameren Illinois
Ameren Illinois’ cash provided by operating activities decreased $38 million in the first six months of 2023, compared with the year-ago period. The following items contributed to the decrease:
•A $95 million decrease resulting from income tax payments to Ameren (parent) of $64 million in 2023, compared with income tax refunds from Ameren (parent) of $31 million in 2022, pursuant to the tax allocation agreement, primarily due to increased income tax extension payments, which are based on the preceding year’s taxable income and estimated payments.
•A $9$33 million decrease due to the timing of payments for accounts payable and prepaid expenses.
•A $17 million increase in interest payments, primarily due to an increase in the average outstanding debt.debt and an increase in interest rates.
The following items partially offset the decrease in Ameren Missouri’sIllinois’ cash from operating activities between periods:
•A $207$42 million increase from higher customer collections and decreased expenditures underdecrease in the FAC and PGA due to the significant increase from customer demand and prices forcost of natural gas and electricity experiencedheld in mid-February 2021 due to extremely cold weather and higher customer collections resulting from base rate increases pursuant to the December 2021 electric rate order.storage because of lower commodity prices.
•A $20$38 million decrease in coal inventory levels, as less coal was purchased in 2022 due to service-related delivery disruptions.
•An $11 million decrease in payments to settle ARO liabilities, primarily related to the closure of CCR storage facilities.
Ameren Illinois
Ameren Illinois’ cash provided by operating activities increased $389 million in the first six months of 2022, compared with the year-ago period. The following items contributed to the increase:
•A $368 million increase resulting from increased customer collections and decreased expenditures under the PGA, primarily as a result of the significant increase from customer demand and prices for natural gas experienced in mid-February due to extremely cold weather and a net increase attributable to other regulatory recovery mechanisms.
•A $14 million decrease in major storm restoration costs, primarily due to a January 2021 storm.
•An $11 million increase in net collateral received fromposted with counterparties, primarily due to changes in the market prices of power and natural gas.
•An $8$16 million decrease in the cost of natural gas held in storage because ofincrease resulting from increased customer collections, primarily from electric transmission rate base growth and an increase in withdrawals between periods.
The following itemsattributable to other regulatory mechanisms, partially offset by a decrease under the increase in Ameren Illinois’ cashPGA resulting from operating activities between periods:
•A $14 million increase in payments for certain cloud computing arrangements.
•A $10 million increase in purchases of materials and supplies inventories to support operationsthe recovery in 2022 as levels were increased to mitigate against any potential supply disruptions.of
costs for the mid-February 2021 weather event discussed above.
Cash Flows from Investing Activities
Ameren’s cash used in investing activities decreased $208increased $337 million during the first six months of 2022,2023, compared with the year-ago period, primarily as a result of a $225$284 million decreaseincrease in capital expenditures, largely resulting from a reduction in expenditures related to wind generation assets at Ameren Missouri, partially offset by increased expenditures for electric deliverytransmission upgrades at Ameren Missouri, Ameren Illinois, and ATXI and electric distribution infrastructure upgrades at Ameren Missouri and for transmission projects at Ameren Illinois. The decreaseATXI’s capital expenditures increased $25 million during the first six months of 2023, compared with the year-ago period. In addition, in Ameren’s cash used2022, Ameren Missouri received $17 million in investing activities was partially offset by an $18 million increase due toinsurance proceeds for the timing of nuclear fuel expenditures at Ameren Missouri.Callaway Energy Center’s generator.
Ameren Missouri’s cash used in investing activities decreased $235increased $162 million during the first six months of 2022,2023, compared with the year-ago period, primarily as a result of a $295$108 million decreaseincrease in capital expenditures, primarilylargely resulting from a reduction in expenditures related to wind generation assets partially offset by increased expenditures for electric deliverytransmission and distribution infrastructure upgrades. This decrease was partially offset by a $47In addition, in 2022, Ameren Missouri received $17 million return of net money pool advances in insurance proceeds for the first six months of 2021, and an $18 million increase due to the timing of nuclear fuel expenditures.
Callaway Energy Center’s generator. Ameren Illinois’ cash used in investing activities increased $31$147 million during the first six months of 2022,2023, compared with the year-ago period, primarily as a result of a $53$145 million increase in capital expenditures, largely related toresulting from increased expenditures for electric transmission projects. This increase was partially offset by a $20 million decrease in Ameren Illinois’ net money pool advances.and distribution infrastructure upgrades.
Cash Flows from Financing Activities
Cash provided by, or used in, financing activities is a result of our financing needs, which depend on the level of cash provided by operating activities, the level of cash used in investing activities, the level of dividends, and our long-term debt maturities, among other things. Due to extremely cold winter weather in mid-February 2021, Ameren Missouri and Ameren Illinois experienced higher than anticipated commodity costs for natural gas purchased for resale and purchased power, which contributed to the acceleration of the timing of certain planned 2021 debt issuances.
Ameren’s cash provided by consolidated financing activities decreased $604increased $122 million during the first six months of 2022,2023, compared with the year-ago period. During the first six months of 2023, Ameren utilized proceeds from the issuance of long-term debt of $997 million for capital expenditures, to repay then-outstanding short-term debt, and to repay $100 million of long-term debt maturities. In addition, during the first six months of 2023, Ameren utilized proceeds from net commercial paper issuances of $260 million along with cash provided by operating activities to fund, in part, capital expenditures. In comparison, during the first six months of 2022, Ameren utilized proceeds of $524 million of long-term debt to repay then-outstanding short-term debt and for near-term capital expenditures. In addition, during the first six months of 2022, Ameren utilized proceeds from net commercial paper issuances of $475 million along withand cash provided by operating activities to fund, in part, investing activities. In comparison, during the first six months of 2021, Ameren utilized proceeds from the issuance of $1,423 million of long-term debt for general corporate purposes, including to repay then-outstanding short-term debt, including short-term debt in connection with the increased purchases for natural gas for resale and purchased power costs as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, and to fund, in part, investing activities.capital expenditures. During the first six months of 2021, Ameren repaid net short-term debt of $59 million. In addition, Ameren received aggregate cash proceeds of $258 million from the issuance of common stock under the ATM program, the DRPlus, and the 401(k) plan and the settlement of the remaining portion of the 2019 forward sale agreement. These proceeds were used to fund a portion of Ameren Missouri’s wind generation investments and to fund, in part, other investing activities. During the first six months of 2022,2023, Ameren paid common stock dividends of $305$330 million, compared with $282$305 million in the year-ago period, as a result of an increase in both the dividend rate and the number of common shares outstanding.
Ameren Missouri’s cash provided by financing activities decreased $65$104 million during the first six months of 2022,2023, compared with the year-ago period. During the first six months of 2023, Ameren Missouri utilized proceeds from the issuance of long-term debt of $499 million for capital expenditures and to repay then-outstanding short-term debt. During the first six months of 2023, Ameren Missouri utilized proceeds from net commercial paper issuances of $44 million and cash provided by operating activities to fund, in part, capital expenditures. In comparison, during the first six months of 2022, Ameren Missouri utilized proceeds from the issuance of $524 million to repay then-outstanding short-term debt and for near-term capital expenditures. In addition, during the first six months of 2022, Ameren Missouri utilized proceeds from net commercial paper issuances of $120 million along withand cash provided by operating activities to fund, in part, investing activities. In comparison,capital expenditures.
Ameren Illinois’ cash provided by financing activities increased $210 million during the first six months of 2021,2023, compared with the year-ago period. During the first six months of 2023, Ameren MissouriIllinois utilized net proceeds from the issuance of long-term debt of $524$498 million to repay then-outstanding short-term debt including short-term debt incurred in connection with the increased purchases for natural gas for resale and purchased power costs as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather. Additionally, proceeds from the issuance$100 million of long-term debt and capital contributions of $183 million from Ameren (parent) were used to fund a portion of wind generation investments and to fund, in part, investing activitiesmaturities. In addition, during the first six months of 2021.
2023, Ameren Illinois’ cash provided by financing activities decreased $440 millionIllinois repaid net commercial paper borrowings totaling $147 million. In comparison, during the first six months of 2022, compared with the year-ago period. During the first six months of 2022, Ameren Illinois utilized proceeds from net commercial paper issuances of $38 million and cash provided by operating activities to fund, in part, investing activities. In comparison, during the first six months of 2021, Ameren Illinois utilized net proceeds from the issuance of long-term debt of $449 million to repay then-outstanding short-term debt, including short-term debt incurred in connection with the increased purchases for natural gas for resale and purchased power costs as a result of the significant increase in customer demand and prices for natural gas and electricity experienced in mid-February 2021 due to extremely cold weather, and to fund, in part, investing activities. Ameren Illinois also received a $70 million capital contribution from Ameren (parent) during the first six months of 2021. In addition, Ameren repaid $19 million of money pool borrowings and redeemed $13 million of preferred stock during the first six months of 2021.expenditures.
See Long-term Debt and Equity in this section for additional information on maturities and issuances of long-term debt, issuances of common stock, and redemptionsnoncash settlement of preferred stock.a financing obligation.
Credit Facility Borrowings and Liquidity
The following table presents Ameren’s consolidated liquidity as of June 30, 2022:2023:
| | | | | | | | | |
| | | | | Available at June 30, 20222023 |
Ameren (parent) and Ameren Missouri: | | | | | |
Missouri Credit Agreement – borrowing capacity | | | | | $ | 1,2001,400 | |
| | | | | |
| Less: Ameren (parent) commercial paper outstanding | | | | | 382494 | |
| Less: Ameren Missouri commercial paper outstanding | | | | | 285373 | |
| | | | | |
| Less: Ameren Missouri letters of credit | | | | | 21 | |
| Missouri Credit Agreement – subtotal | | | | | 531532 | |
| Ameren (parent) and Ameren Illinois: | | | | | |
Illinois Credit Agreement – borrowing capacity | | | | | 1,1001,200 | |
| | | | | |
| Less: Ameren (parent) commercial paper outstanding | | | | | 213345 | |
| Less: Ameren Illinois commercial paper outstanding | | | | | 141117 | |
| | | | | |
| | | | | |
Illinois Credit Agreement – subtotal | | | | | 746738 | |
| Subtotal | | | | | $ | 1,2771,270 | |
| Add: Cash and cash equivalents | | | | | 7 | |
Net Available Liquidity(a) | | | | | $ | 1,2841,277 | |
(a)Does not include Ameren’s forward equity sale agreements. See Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information.
The Credit Agreements, among other things, provide $2.3$2.6 billion of credit until maturity in December 2025.2027. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on the Credit Agreements. During the six months ended June 30, 2022,2023, Ameren (parent), Ameren Missouri, and Ameren Illinois each issued commercial paper. Borrowings under the Credit Agreements and commercial paper issuances are based upon available interest rates at thatthe time of the borrowing or issuance.
Ameren has a money pool agreement with and among its utility subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. As short-term capital needs arise, and based on availability of funding sources, Ameren Missouri and Ameren Illinois will access funds from the utility money pool, the Credit Agreements, or the commercial paper programs depending on which option has the lowest interest rates.
See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information on credit agreements, commercial paper issuances, Ameren’s money pool arrangements and related borrowings, and relevant interest rates.
The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to FERC approval under the Federal Power Act. In March 2022,January 2023, the FERC issued an orderorders authorizing Ameren Missouri, Ameren Illinois, and ATXI to issue up to $1 billion, $1 billion, and $300 million, respectively, of short-term debt securities through March 2024. In 2020, the FERC issued an order authorizing Ameren Illinois to issue up to $1 billion of short-term debt securities through September 2022. In 2021, the FERC issued an order authorizing ATXI to issue up to $300 million of short-term debt securities, which expires in July 2023.January 2025.
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 borrowing arrangements, or other arrangements may be made.
Long-term Debt and Equity
The following table presents issuances (net of any issuance premiums or discounts) of long-term debt and equity, and redemptionsas well as maturities of preferred stocklong-term debt for the six months ended June 30, 20222023 and 2021:2022:
| | | | | | | | | | | | | | | | | | | | |
| Month Issued, Redeemed, or Matured | | 2022 | | 2021 | |
| Issuances of Long-term Debt | | | | | | |
| Ameren: | | | | | | |
| 1.75% Senior unsecured notes due 2028 | March | | $ | — | | | $ | 450 | | |
| | | | | | |
| Ameren Missouri: | | | | | | |
| 3.90% First mortgage bonds due 2052 (green bonds) | April | | 524 | | | — | | |
| 2.15% First mortgage bonds due 2032 (green bonds) | June | | — | | | 524 | | |
| Ameren Illinois: | | | | | | |
| 2.90% First mortgage bonds due 2051 (green bonds) | June | | — | | | 349 | | |
| 0.375% First mortgage bonds due 2023 | June | | — | | | 100 | | |
| Total Ameren long-term debt issuances | | | $ | 524 | | | $ | 1,423 | | |
| Issuances of Common Stock | | | | | | |
| Ameren: | | | | | | |
DRPlus and 401(k) (a) | Various | | $ | 17 | | (b) | $ | 24 | | |
August 2019 forward sale agreement (c) | February | | — | | | 113 | | |
ATM program (d) | Various | | — | | | 121 | | |
Total Ameren common stock issuances (e) | | | $ | 17 | | | $ | 258 | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Redemptions of Preferred Stock | | | | | | |
| Ameren Illinois: | | | | | | |
| 6.625% Series | March | | $ | — | | | $ | 12 | | |
| 7.75% Series | March | | — | | | 1 | | |
| Total Ameren Illinois preferred stock redemptions | | | $ | — | | | $ | 13 | | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| Month Issued, Redeemed, or Matured | | 2023 | | 2022 | |
| Issuances of Long-term Debt | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Ameren Missouri: | | | | | | |
| 5.45% First mortgage bonds due 2053 | March | | 499 | | | — | | |
3.90% First mortgage bonds due 2052(a) | April | | — | | | 524 | | |
| Ameren Illinois: | | | | | | |
| 4.95% First mortgage bonds due 2033 | May | | 498 | | | — | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Total Ameren long-term debt issuances | | | $ | 997 | | | $ | 524 | | |
| Issuances of Common Stock | | | | | | |
| Ameren: | | | | | | |
DRPlus and 401(k)(b)(c) | Various | | $ | 16 | | | $ | 17 | | |
| | | | | | |
| | | | | | |
Total Ameren common stock issuances(d) | | | $ | 16 | | | $ | 17 | | |
| | | | | | |
| Maturities of Long-term Debt | | | | | | |
| Ameren Missouri: | | | | | | |
| Audrain County agreement (Audrain County CT) due 2023 | January | | $ | 240 | | (e) | $ | — | | |
| | | | | | |
| | | | | | |
| Ameren Illinois: | | | | | | |
| 0.375% First mortgage bonds due 2023 | June | | 100 | | | | |
| Total Ameren long-term debt maturities | | | $ | 340 | | | $ | — | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
(a)Ameren Missouri intends to allocate an amount equal to the net proceeds to sustainability projects meeting certain eligible criteria.
(b)Ameren issued a total of 0.30.2 million and 0.3 million shares of common stock under its DRPlus and 401(k) plan infor the six months ended June 30, 20222023 and 2021,2022, respectively.
(b)(c)Excludes ana $7 million and $8 million receivable at June 30, 2023 and 2022, respectively.
(c)Ameren issued 1.6 million shares of common stock to settle the remainder of the August 2019 forward sale agreement.
(d)Ameren issued 1.4 million shares of common stock under the ATM program.
(e)Excludes 0.40.5 million and 0.50.4 million shares of common stock valued at $31$37 million and $33$31 million issued for no cash consideration in connection with stock-based compensation for the six months ended June 30, 2023 and 2022, respectively.
(e)In January 2023, Ameren Missouri and 2021, respectively.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.
See Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for additional information, including proceeds from issuances of long-term debt, including Ameren Missouri’s April 2022March 2023 issuance of first mortgage bonds, the use of those proceeds, Ameren’s forward equity sale agreements, and the ATM program.
Indebtedness Provisions and Other Covenants
At June 30, 2022,2023, the Ameren Companies were in compliance with the provisions and covenants contained in their credit agreements, indentures, and articles of incorporation, as applicable, and ATXI was in compliance with the provisions and covenants contained in its note purchase agreements. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report and Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for a discussion of provisions, applicable cross-default provisions, and covenants contained in our credit agreements, in ATXI’s note purchase agreements, and in certain of the Ameren Companies’ indentures and articles of incorporation.
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. Inability to raise capital on reasonable terms, particularly during times of uncertainty in the capital and credit markets, could negatively affect our ability to maintain and expand our businesses. After assessing itstheir respective current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri, and Ameren Illinois each believes that it will continue to have access to the capital and credit markets on reasonable terms. However, events beyond Ameren’s, Ameren Missouri’s, and Ameren Illinois’ control may create uncertainty in the capital and credit markets or make access to the capital and credit markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital and credit markets.
Dividends
The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. Ameren’s board of directors has not set specific targets or payout parameters when declaring common stock dividends, but it considers various factors, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow
requirements, historical earnings and cash flow, projected earnings, impacts of regulatory orders or legislation, and other key business considerations. Ameren expects its dividend payout ratio to be between 55% and 70% of annual earnings over the next few years.
See Note 4 – Short-term Debt and Liquidity and Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of the Form 10-K for additional discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At June 30, 2022,2023, none of these circumstances existed at Ameren, Ameren Missouri, or Ameren Illinois and, as a result, these companies were not restricted from paying dividends.
The following table presents common stock dividends declared and paid by Ameren Corporation to its common shareholders and by Ameren subsidiaries to their parent, Ameren Corporation, for the six months ended June 30, 20222023 and 2021:2022:
| | | Six Months | | Six Months |
| | 2022 | | 2021 | | 2023 | | 2022 |
| Ameren | Ameren | $ | 305 | | | $ | 282 | | Ameren | $ | 330 | | | $ | 305 | |
| | ATXI | ATXI | — | | | 32 | | ATXI | 75 | | | — | |
Credit Ratings
Our credit ratings affect our liquidity, our access to the capital markets and credit markets, our cost of borrowing under our credit facilities and our commercial paper programs, and our collateral posting requirements under commodity contracts.
The following table presents the principal credit ratings by Moody’s and S&P, as applicable, effective on the date of this report:
| | | | | | | | | | | | | | |
| | Moody’s | | S&P |
| Ameren: | | | | |
| Issuer/corporate credit rating | | Baa1 | | BBB+ |
| Senior unsecured debt | | Baa1 | | BBB |
| Commercial paper | | P-2 | | A-2 |
| Ameren Missouri: | | | | |
| Issuer/corporate credit rating | | Baa1 | | BBB+ |
| Secured debt | | A2 | | A |
| Senior unsecured debt | | Baa1 | | Not Rated |
| Commercial paper | | P-2 | | A-2 |
| Ameren Illinois: | | | | |
| Issuer/corporate credit rating | | A3 | | BBB+ |
| Secured debt | | A1 | | A |
| Senior unsecured debt | | A3 | | BBB+ |
| Commercial paper | | P-2 | | A-2 |
| ATXI: | | | | |
| Issuer credit rating | | A2 | | Not Rated |
| Senior unsecured debt | | A2 | | Not Rated |
A credit rating is not a recommendation to buy, sell, or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.
Collateral Postings
Any weakening of our credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing, resulting in an adverse effect on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts were $222 million, $199 million, and $23 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively,immaterial and cash collateral posted by external parties were $75 million, $15 million, and $60$46 million for Ameren Ameren Missouri, and Ameren Illinois respectively, at June 30, 2022.2023. A sub-investment-grade issuer or senior unsecured debt rating (below “Baa3” from Moody’s or below “BBB-” from S&P) at June 30, 2022,2023, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois being required to post additional collateral or other assurances for certain trade and contractual obligations amounting to $166$587 million, $89$526 million, and $77$61 million, respectively.
Changes in commodity prices could trigger additional collateral postings and prepayments. Based on credit ratings at June 30, 2022,2023, if market prices were 15% higher or lower than June 30, 20222023 levels in the next 12 months and 20% higher or lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, and Ameren Illinois could be required to post an immaterial amount, compared to each company’s liquidity, of collateral or provide other assurances for certain trade and contractual obligations.
OUTLOOK
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 20222023 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 I, Item 1, of this report and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.
Operations
•InWe are observing inflationary pressures on the first halfprices of 2022, our sales volumes, which have been,certain commodities, labor, services, materials, and continue to be, affected by the COVID-19 pandemic, among other things, increased compared to the same period in 2021, excluding the estimated effects of weather and customer energy-efficiency programs. While total sales volume levels at Ameren Missouri were comparable to pre-pandemic levels for the first six months of 2022, Ameren Illinois’ sales remain below pre-pandemic levels. However, revenues from Ameren Illinois’ electric distribution business, residential and small nonresidential customers of Ameren Illinois’ natural gas distribution business, and Ameren Illinois’ and ATXI’s electric transmission businesses are decoupled from changes in sales volumes. There has also been a shift in sales volumes by customer class at bothsupplies, as well as increasing interest rates. Ameren Missouri and Ameren Illinois which beganare 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 increasing interest rates could impact our ability to control costs and/or make substantial investments in 2020, with an increase in residential sales,our businesses, including our ability to recover costs and a decrease in commercialinvestments, and industrial sales. The continued effectto earn our allowed ROEs within frameworks established by our regulators, while maintaining rates that are affordable to our customers. In addition, these inflationary pressures and increasing interest rates could adversely affect our customers’ usage of, the COVID-19 pandemic onor payment for, our results of operations, financial position, and liquidity in subsequent periods will depend on its severity and longevity, future regulatory or legislative actions with respect thereto, and the resulting impact on business, economic, and capital market conditions.services.
•The PISA permits Ameren Missouri to defer and recover 85% of the depreciation expense and earn a return at the applicable WACC onfor investments in certainqualifying property, plant, and equipment placed in service and not included in base rates. Investments not eligible for recovery under the PISA include amounts related to new nuclear and natural gas generating units and service to new customer premises. Additionally, the PISA permits Ameren Missouri to earn a return at the applicable WACC on rate base that incorporates those qualifying investments, as well as changes in total accumulated depreciation excluding retirements and plant-related deferred income taxes since the previous regulatory rate review. The regulatory asset for accumulated PISA deferrals also earns a return at the applicable WACC with all approved PISA deferralsuntil added to rate base prospectivelyprospectively. Ameren Missouri recognizes an offset to interest charges for its cost of debt relating to each return allowed under the PISA, with the difference between the applicable WACC and its cost of debt recognized in revenues when recovery of PISA deferrals is reflected in customer rates. Approved PISA deferrals are recovered over a period of 20 years following a regulatory rate review. Additionally, under the RESRAM, Ameren Missouri is permitted to recover the 15% of depreciation expense not recovered under the PISA, and earn a return at the applicable WACC for investments in renewable generation plant placed in service to comply with Missouri’s renewable energy standard. Accumulated RESRAM deferrals earn carrying costs at short-term interest rates. The PISA and the RESRAM mitigate the effects of regulatory lag between regulatory rate reviews. Those investments not eligible for recovery under the PISA and the remaining 15% of certain property, plant, and equipment placed in service, unless eligible for recovery under the RESRAM, remain subject to regulatory lag. Ameren Missouri defers its cost of debt relating to PISA eligible investments as an offset to interest charges with the difference between the applicable WACC and its cost of debt recognized in revenues when recovery of such deferrals is reflected in customer rates. As a result of the PISA election, additional provisions of the law apply to Ameren Missouri, including limitations on electric customer rate increases. Ameren Missouri does not expect to exceed theseThe rate increase limitations in 2022. Inapproved by the June 2022,2023 MoPSC electric rate order did not exceed the rate increase limitation applicable through 2023. Missouri Senate Bill 745 was enacted and will becomebecame effective on August 28, 2022. The law extended Ameren Missouri’s PISA election through December 2028 and allows for an additional five-year extension through December 2033 if requested by Ameren Missouri and approved by the MoPSC, among other things. The law also established a 2.5% annual limit on increases to the electric service revenue requirement used to set customer rates due to the inclusion of incremental PISA deferrals in the revenue requirement. The limitation will be effective for revenue requirements approved by the MoPSC after January 1, 2024, and will be based on the revenue requirement established in the immediately preceding rate order.
•In June 2023, the MoPSC issued an order that resulted in an increase of $140 million to Ameren Missouri’s annual revenue requirement for electric retail service. The current rate limitation, which is effective through 2023, is a 2.85% cap onorder increased the compound annual growth rateannualized base level of net energy costs pursuant to the FAC by approximately $40 million from the base level established in the average overall customerMoPSC’s December 2021 electric rate per kilowatthour, basedorder. 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 the electricAmeren’s and Ameren Missouri’s consolidated statements of income. The new rates that became effective on July 9, 2023. As a result of this order, Ameren Missouri expects a year-over-year increase to 2023 earnings, compared to 2022, of approximately $44 million ($11 million in April 2017, less half of the annual savings fromsecond quarter, $23 million in the TCJA that was passed on to customers as approvedthird quarter, and $10 million in a July 2018 MoPSC order.the fourth quarter).
•In 2018, the MoPSC issued an order approving Ameren Missouri’s MEEIA 2019 plan. The plan includes a portfolio of customer energy-efficiency and demand response programs through December 2023 and low-income customer energy-efficiency programs through December 2024, along with a rider.2023. Ameren Missouri intends to invest approximately $360$350 million over the life of the plan, including $80 million in 2022 and $75 million in 2023. The plan includes the continued use of the MEEIA rider, which allows Ameren Missouri to collect from, or refund to, customers any difference in actual MEEIA program costs and related lost electric margins and the amounts collected from customers. In addition, the plan includes a performance incentive that provides Ameren Missouri an opportunity to earn additional revenues by achieving certain customer energy-efficiency goals. If the target goals were achieved for 2021 and are achieved for 2022, additional revenues of $24 million would be recognized in 2022, and, if targetspending goals are achieved for 2023, additionalthe performance incentive would result in revenues of $13$12 million would be recognized in 2023.
•In August 2022,2023, Ameren Missouri, the MoPSC staff, and the MoOPC filed a requestnonunanimous stipulation and agreement with the MoPSC seekingto extend Ameren Missouri’s MEEIA 2019 program through 2024. The stipulation and agreement, which is subject to MoPSC approval, includes the establishment of a portfolio of customer energy-efficiency programs for 2024 and performance incentives that would provide Ameren Missouri an opportunity to increase its annualearn revenues, for electric service by $316 million.including $12 million if Ameren Missouri achieves certain energy-efficiency goals in 2024. If approved, Ameren Missouri expects to invest $76 million in energy-efficiency programs in 2024. The MoPSC proceeding relatingis under no deadline 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 June 2023 and new rates effective by July 2023. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, whether the requested regulatory recovery mechanisms will be approved, or whether any rate change that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.
•In December 2021, the MoPSC issuedissue an order in Ameren Missouri’s 2021 electric service regulatory rate review, resulting in an increase of $220 million to Ameren Missouri’s annual revenue requirement for electric retail service. As a result of this order, Ameren Missouri expects a year-over-year increase to 2022 earnings, compared to 2021, primarily in the third quarter of 2022 due to seasonal electric customer rates and higher demand during the summer. Ameren Missouri expects earnings to increase approximately $23 million in the third quarter of 2022, compared to the same period in 2021.proceeding.
•Ameren Illinois and ATXI use a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. Based on expected rate base and the currently allowed 10.52% ROE, which includes a 50 basis point50-basis-point incentive adder for participation in an RTO, the revenue requirements included in 20222023 rates for Ameren Illinois’ and ATXI’s electric transmission businesses are $422$476 million and $195$194 million, respectively. These revenue requirements represent an increase in Ameren Illinois’ revenue requirement of $42$54 million and a decrease in ATXI’s revenue requirement of $5$1 million from the revenue requirements reflected in 20212022 rates, primarily due to higher expected rate base at Ameren Illinois and a lower expected rate base at ATXI. These rates will affect Ameren Illinois’ and ATXI’s cash receipts during 2022,2023, but will not determine their respective electric transmission service operating revenues, which will instead be based on 20222023 actual recoverable costs, rate base, and a return on rate base at the applicable WACC as calculated under the FERC formula ratemaking framework.
•The allowed base ROE for FERC-regulated transmission rates previously charged under the MISO tariff is the subject of an appeal filed with the United States Court of Appeals for the District of Columbia Circuit.pending proceedings. Depending on the outcome of the appeal,proceedings, the transmission rates charged during previous periods and the currently effective rates may be subject to change. Additionally, in March 2019, the FERC issued a Notice of Inquiry regarding its transmission incentives policy.change and refund. In March 2020, the FERC issued a Notice of Proposed Rulemaking on its transmission incentives policy, which addressed many ofincreased the issues in the Notice of Inquiry on transmission incentives. The Notice of Proposed Rulemaking included an increased 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 proposes to modify the Notice of Proposed Rulemaking’s incentive for participation in an RTO by limiting this incentive for utilities that join an RTO to 50 basis points and only allowing them to earn the incentive for three years, among other things. If this proposal is included in a final rule, Ameren Illinois and ATXI would no longer be eligible for the 50 basis point RTO incentive adder, prospectively. The FERC is under no deadline to issue a final rule on this matter. Ameren is unable to predict the ultimate impact of any changes to the FERC’s incentives policy, or any further order on base ROE. A 50 basis point50-basis-point change in the FERC-allowed ROE would affect Ameren’s and Ameren Illinois’ annual net income by an estimated $12$14 million and $8$10 million, respectively, based on each company’s 20222023 projected rate base.
•Ameren Illinois’ electric distribution service performance-based formula ratemaking framework under the IEIMA allows Ameren Illinois to reconcile electric distribution service rates to its actual revenue requirement on an annual basis to reflect actual recoverable costs incurred and a return at the applicable WACC on year-end rate base.base through 2023. If a given year’s revenue requirement varies from the amount collected from customers, an adjustment is made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance is then collected from, or refunded to, customers within two years from the end of the year. Pursuant to an order issued by the ICC inDecember 2022 and March 2021 ICC orders, Ameren Illinois expects to useused the current IEIMA formula framework to establish annual customer rates effective through 2023, and will reconcile the related revenue requirement for customer rates established for 2022 and 2023. As such, Ameren Illinois’ 2022 and 2023 revenues wouldwill reflect each year’s 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. For more information on the March 2021 ICC order, see Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. By law, the decoupling
provisions extend beyond the end of existing performance-based formula ratemaking, which ensures that Ameren Illinois’ electric distribution revenues authorized in a regulatory rate review are not affected by changes in sales volumes. In April 2023, Ameren Illinois filed for a reconciliation adjustment to its 2022 electric distribution service revenue requirement with the ICC. In July 2023, Ameren Illinois filed a revised reconciliation adjustment, requesting recovery of $125 million. An ICC decision in this proceeding is required by December 2023, and any approved adjustment would be collected from customers in 2024.
•Pursuant to the IETL, which was enacted in September 2021, Ameren Illinois may file an MYRP with the ICC to establish base rates for electric distribution service to be charged to customers for each calendar year of a four-year period. The base rates for a particular calendar year are based on forecasted recoverable costs and an ICC-determined ROE applied to Ameren Illinois’ forecasted average annual rate base using a forecasted capital structure, with a common equity ratio of up to 50% being deemed prudent and reasonable by law and a higher equity ratio requiring specific ICC approval. The ROE determined by the ICC for each calendar year of the four-year period is subject to annual adjustments based on certain performance incentives and penalties. An MYRP would allowallows 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 ICC-determined ROE for performance incentives and penalties.ROE. If a given year’s revenue amount collected from customers varies from the approved revenue requirement, an adjustment would be made to electric operating revenues with an offset to a regulatory asset or liability to reflect that year’s actual revenue requirement, independent of actual sales volumes. The regulatory balance would then be collected from, or refunded to, customers within two years from the end of the applicable annual period. Ameren Illinois’ existing riders will remain effective under the MYRP discussed below, and will continue to remain effective beyond 2027 whether it elects to file an MYRP or a traditional regulatory rate review. Additionally, electric distribution service revenues would continue to be decoupled from sales volumes under either election. Subject
•In January 2023, Ameren Illinois filed an MYRP with the ICC. In July 2023, Ameren Illinois filed a revised MYRP requesting approval of forecasted revenue requirements for electric distribution service for 2024, 2025, 2026, and 2027 of $1,291 million, $1,387 million, $1,484 million, and $1,560 million, respectively. Pursuant to a constructive outcome regardingprovision under the ICC’s determination of performance metrics, Ameren Illinois anticipates filing an MYRP by mid-January 2023, with rates effective beginning in 2024. If Ameren Illinois does not file an MYRP for rates effective beginning in 2024, its next opportunity to file an MYRP would be for rates effective beginning in 2028. For additional information regarding ratemakingIETL that permits initial rate increases under an MYRP including detailsto be phased in, Ameren Illinois’ filing proposes to defer 50% of the requested 2024 rate increase of $179 million as a regulatory asset to be collected from customers in 2026. That regulatory asset would earn a return at the applicable WACC. An ICC decision in this proceeding is required by December 2023, with new rates effective starting in January 2024. Ameren Illinois cannot predict the level of any electric distribution service rate change the ICC may approve, or whether any rate change that may eventually be approved will be sufficient for Ameren Illinois to recover its costs to the extent those costs are subject to and exceed the MYRP reconciliation cap see Note 2 – Rate and Regulatory Matters under Part II, Item 8, ofearn a reasonable return on its investments when the Form 10-K.rate change goes into effect. If the rates approved by the ICC are materially different from its forecasted spend, Ameren Illinois may adjust its overall spending, both operating and capital.
•In 2021,December 2022, the ICC issued an order in Ameren Illinois’ annual update filing that approved a $58$61 million increase in Ameren Illinois’ electric distribution service rates beginning in January 2022.2023. Ameren Illinois’ 20222023 electric distribution service revenues will be based on its 20222023 actual recoverable costs, 20222023 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. As of June 30, 2022,2023, Ameren Illinois expects its 20222023 electric distribution year-end rate base to be $3.9$4.2 billion. The 20222023 revenue requirement reconciliation adjustment will be collected from, or refunded to, customers in 2024.2025. A 50 basis point50-basis-point change in the annual average of the monthly yields of the 30-year United States Treasury bonds would result in an estimated $11$12 million change in Ameren’s and Ameren Illinois’ annual net income, based on Ameren Illinois’ 20222023 projected year-end rate base, including electric energy-efficiency investments. Ameren Illinois’ recognized ROE for the first six monthshalf of 20222023 was based on an estimated annual average of the monthly yields of the 30-year United States Treasury bonds of 3.10%3.84%.
•In April 2022,January 2023, Ameren Illinois filed its annual electric distribution service performance-based formula rate updatea request with the ICC seeking approval to be usedincrease its annual revenues for 2023 rates.natural gas delivery service. In July 2022,2023, Ameren Illinois filed a revised request seeking to increase its annual revenues for electric distribution service by $84 million.$148 million, which includes an estimated $77 million of annual revenues that would otherwise be recovered under the QIP and other riders. In June 2022,an attempt to reduce regulatory lag, Ameren Illinois used a 2024 future test year in this proceeding. A decision by the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing, recommending a $60 million increase in Ameren Illinois’ electric distribution service rates. An ICC decision in this proceeding is required by December 2022,late November 2023, with new rates expected to be effective in Januaryearly December 2023. These rates will affect Ameren Illinois’ cash receipts during 2023, but will not affect electric distributionIllinois cannot predict the level of any delivery service revenues, whichrate change the ICC may approve, nor whether any rate change that may eventually be approved will be basedsufficient to enable Ameren Illinois to recover its costs and to earn a reasonable return on 2023 actual recoverable costs, 2023 year-endinvestments when the rate base, and a return atchanges go into effect. Without legislative action, the applicable WACC as calculated under the Illinois performance-based formula ratemaking framework.QIP will expire after December 2023.
•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. The allowed ROE on electric energy-efficiency investments can be increased or decreased by up to 200 basis points, depending on the achievement of annual energy savings goals. 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 plan program years if there are insufficient cost-effective programs available, which could reduce the investments in electric energy-efficiency programs. The electric energy-efficiency program investments and the return on those investments are collected from customers through a rider and are not recovered through the electric distribution service performance-based formula ratemaking framework.
•In May 2023, the MISO released the results of its April 2023 capacity auction, which included capacity price decreases in the central region of the MISO footprint, where Ameren Missouri’s and Ameren Illinois’ service territories are located. Capacity prices decreased from $237 per MW-day for June 2022 through May 2023 pursuant to the April 2022 capacity auction to seasonal prices ranging from $2 to $15 per MW-day for June 2023 through May 2024. Based on estimated power prices and customer demand as of June 30, 2023, the capacity prices set by the April 2023 MISO auction, and the amounts of energy and capacity hedged through IPA procurement events, Ameren Illinois estimates a decrease to purchased power costs for calendar year 2023, compared to 2022, of approximately $100 million. The actual decrease to purchased power costs will vary due to differences between estimated and realized power prices as well as customer demand satisfied by Ameren Illinois, which will be affected by changes in customers’ elections to use Ameren Illinois or an alternative retail electric supplier for their energy needs. Because of the power procurement riders, the difference between actual purchased power costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. These pass-through costs do not affect Ameren Illinois’ net income, as any change in costs are offset by a corresponding change in revenues. Also, largely due to the capacity price set by the April 2023 MISO auction, Ameren Missouri estimates decreases to capacity revenues and purchased power costs for the calendar year 2023, compared to 2022, of approximately $100 million. Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. Capacity revenues and purchased power costs are a part of the net energy costs recoverable under the FAC, with 95% of the variance between net energy costs and the amount set in base rates recovered or refunded through the FAC.
•Ameren Missouri’s next refueling and maintenance outage at its Callaway energy centerEnergy Center is scheduled for the fall of 2023. During a scheduled refueling, which occurs every 18 months, maintenance expenses are deferred as a regulatory asset and amortized until the completion of the next refueling and maintenance outage. Ameren Missouri expects to incur approximately $40 million in maintenance expenses related to the fall 2023 outage. During an outage, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri’s purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, which results in limited impacts to earnings. In addition, Ameren Missouri may incur increased non-nuclear energy center maintenance costs in non-outage years.
•Ameren Missouri continues to experience coal transportation disruptions in 2022, resulting in coal inventory levels below targeted levels at the Labadie, Rush Island, and Sioux energy centers as of the end of July 2022. Prolonged disruptions in the delivery of coal could have adverse effects on Ameren Missouri's electric generation operations and could result in increased purchased power expense. Under the FAC, 95% of the variance in net energy costs, which includes purchased power expense, from the amount set in base rates is expected to be recovered. Further, the timing of payments for purchased power costs compared to the recovery through customer rates under the FAC could have adverse effects on Ameren and Ameren Missouri's liquidity.
•In December 2021, Ameren Missouri filed a motion with the United States District Court for the Eastern District of Missouri to modify a September 2019 remedy order issued by the district court to allow the retirement of the Rush Island Energy Center in advance of its previously expected useful life in lieu of installing a flue gas desulfurization system. In June 2022, Ameren Missouri supplemented its filing with the district court by proposing reduced operations, mostly operating during peak demand times and emergencies until the energy center is retired. The March 31,30, 2024 compliance date contained in the district court’s September 2019 remedy order remains in effect unless extended by the district court. In July 2022, in response to an Ameren Missouri request for a final, binding reliability assessment, the MISO designated the Rush Island Energy Center as a system support resource and concluded that certain mitigation measures, including transmission upgrades, should occur before the energy center is retired. The Rush Island Energy Center began operating as a system support resource on September 1, 2022. In 2023, the MISO extended the system support resource designation for the Rush Island Energy Center through August 2024, and in July 2023, an agreement between Ameren Missouri and the MISO was filed with the FERC for approval that details the manner of continued operation for the Rush Island Energy Center that results in operating during peak demand times and emergencies. The system support resource designation and the related agreement are subject to annual renewal and revision. The FERC is under no deadline to issue an order. The transmission upgrade projects have been approved by the MISO, and Ameren Missouri has started design and procurementconstruction activities necessary to complete the upgrades andare underway. Ameren Missouri expects to complete the last of the upgrades by late 2025. The FERC will needmid-2025. In August 2023, Ameren Missouri requested the district court to approve a system support resource agreement detailingextend the manner of continued operation ofMarch 30, 2024 compliance date to October 15, 2024, at which point Ameren Missouri proposes to retire the Rush Island Energy Center, as well as aCenter. In addition, in October 2022, the FERC established hearing and settlement procedures in response to an August 2022 request from Ameren Missouri for recovery of non-energy costs under the related MISO tariff. In May 2023, a settlement agreement between Ameren Missouri and certain intervenors in the non-energy costs proceeding at the FERC, which provides for recovery of substantially all of Ameren Missouri’s requested non-energy costs through August 2023, was filed with the FERC for approval. The agreement, if approved, would have a term of 12 months. The system support resource designation and the related agreement are subjectFERC is under no deadline to renewal and revision. Any difference between revenuesissue an order. Revenues and costs under the MISO tariff is expected to beare included in the FAC. The district court has the authority to determine the retirement date and operating parameters for the Rush Island Energy Center and is not bound by the MISO determination of the Rush Island Energy Center as a system support resource or the FERC’s approval. While theThe district court is under no deadline to issue a ruling modifying the remedy order, a decision is expected in the near term.order. For additional information on the NSR and Clean Air Act litigation, see Note 9 – Commitments and Contingencies under Part I, Item 1, of this report. Ameren Missouri filed a 2022 Change to the 2020 IRP with the MoPSC in June 2022 to reflect, among other things, the planned acceleration of the retirement of the Rush Island Energy Center from 2039, the retirement year for the facility as reflected in the 2020 IRP. In February 2022, the MoPSC issued an order directing the MoPSC staff to review Ameren Missouri’s planned accelerated retirement of the Rush Island Energy Center, including potential impacts on the reliability and cost of Ameren Missouri’s service to its customers; Ameren Missouri’s plans to mitigate the customer impacts of the accelerated retirement; and the prudence of Ameren Missouri’s actions and decisions with regard to the Rush Island Energy Center, which is expected to be addressed in the current electric service regulatory rate review, among other things. In April 2022, the MoPSC staff filed an initial report with the MoPSC in which the staff concluded early retirement of the Rush Island Energy Center may cause reliability concerns. The MoPSC staff is under no deadline to complete this review. As of December 31, 2021, and June 30, 2022,In Ameren and Ameren Missouri classifiedMissouri’s last electric service regulatory rate review, the remaining net book value ofMoPSC staff recommended a lower rate base for the Rush Island Energy Center as plantclaiming imprudent actions by Ameren Missouri. While the nonunanimous stipulation and agreement approved in that regulatory rate review by the June 2023 MoPSC electric rate order did not specify any rate base disallowance, it did not preclude parties to be abandoned, net, within “Property, Plant, and Equipment, Net” on Ameren’s andthe agreement from raising issues regarding the prudence of Ameren Missouri’s balance sheets.actions and decisions with regard to the energy center in future proceedings. As part of the assessment of any potential future abandonment loss, consideration will be given to rate and securitization orders issued by the MoPSC to Ameren Missouri and to orders issued to other Missouri utilities with similar facts.
•The IETL established emission standards that became effective in September 2021.Pursuant to Illinois state law, Ameren Missouri’s natural gas-fired energy centers in Illinois are subject to limits on emissions, including CO2 and NOx,NOx, equal to their unit-specific average annual emissions from 2018 through 2020, for any rolling twelve-month period beginning October 1, 2021, through 2029. Further reductions to emissions limits will become effective between 2030 and 2040, resulting in the closure of the Venice Energy Center by 2029. The reductions could also limit the operations of Ameren Missouri’s other four natural gas-fired energy centers located in the state of Illinois, and will result in their closure by 2040. These energy centers are utilized to support peak loads. Subject to certain conditions, in the IETL, these energy centers may be allowed to exceed the emissions limits in order to maintain reliability of electric utility service as necessary. Ameren Missouri filed a 2022 Change to the 2020 IRP with the MoPSC in June 2022 to reflect, among other things, the updated scheduled retirement dates of the natural gas-fired energy centers located in the state of Illinois.service.
•In April 2022, the MISO released the results of its 2022 capacity auction, which projected a capacity shortage in the central region of the MISO footprint, which includes Ameren Missouri’s and Ameren Illinois’ service territories. The projected shortage resulted in higher capacity prices for June 2022 through May 2023, and the MISO indicated that the shortage may lead to temporary, controlled interruptions of service during the summer of 2022 to maintain system reliability.
•We are observing inflationary pressures on the prices of commodities, labor, services, materials, and supplies, as well as increasing interest rates. Ameren Missouri and Ameren Illinois are generally allowed to pass on to customers prudently incurred costs for fuel, purchased power, and natural gas supply. Additionally, for certain non-commodity cost changes, the use of trackers, riders, and formula ratemaking, as applicable, mitigates our exposure. The inflationary pressures and increasing interest rates could impact our ability to control costs and/or make substantial investments in our businesses, including our ability to recover costs and investments, and to earn our allowed ROEs within frameworks established by our regulators, while maintaining rates that are affordable to our customers. Based on estimated power prices and customer demand, the capacity price set by the April 2022 MISO auction, and the amounts of energy and capacity hedged through IPA procurement events, Ameren Illinois estimates an increase to purchased power costs for calendar year 2022, compared to 2021, of approximately $400 million. The actual increase to purchased power costs will vary due to differences between estimated and realized power prices as well as customer demand satisfied by Ameren Illinois, which will be affected by changes in customers’ elections to use Ameren Illinois or an alternative retail electric supplier for their energy needs. An increase to purchased power costs for calendar year 2023, compared to 2021, is also likely but Ameren Illinois cannot reasonably estimate the amount of the increase as additional energy and capacity contracts for 2023 will be entered into as a part of IPA procurement events
later in 2022 and the first half of 2023, as well as pricing determined by the April 2023 MISO capacity auction. Because of the power procurement riders, the difference between actual purchased power costs and costs billed to customers in a given period is deferred as a regulatory asset or liability. These pass-through costs do not affect Ameren Illinois’ net income, as any change in costs are offset by a corresponding change in revenues. Also, based on the capacity price set by the April 2022 MISO auction, Ameren Missouri estimates increases to capacity revenues and purchased power costs for the calendar year 2022, compared to 2021, of approximately $375 million. Ameren Missouri sells nearly all of its capacity to the MISO and purchases the capacity it needs to supply its native load sales from the MISO. An increase to capacity revenues and purchased power costs for calendar year 2023, compared to 2021, is also likely but Ameren Missouri cannot reasonably estimate the amount of the increases as capacity pricing for June 2023 through December 2023 will be determined by the April 2023 MISO capacity auction. Capacity revenues and purchased power costs are a part of the net energy costs recoverable under the FAC, with 95% of the variance between net energy costs and the amount set in base rates recovered or refunded through the FAC.
•Ameren Missouri and Ameren Illinois continue to make infrastructure investments and expect to seek increases to electric and natural gas rates to recover the cost of investments and earn an adequate return. Ameren Missouri and Ameren Illinois will also seek new, or to maintain existing, legislative solutions to address regulatory lag and to support investment in their utility infrastructure for the benefit of their customers. Ameren Missouri and Ameren Illinois continue to face cost recovery pressures, including limited economic growth in their service territories, increasing inflation, higher cost of debt, economic impacts of the COVID-19 pandemic, customer conservation efforts, the impacts of additional customer energy-efficiency programs, and increased customer use of increasingly cost-effective advancements in innovative energy technologies, including private generation and energy storage. However, over the long-term, we expect the decreased demand to be partially offset by
increased demand resulting from increased electrification of the economy and as a means to address economy-wide CO2 emission concerns. We expect that increased investments, including expected future investments for environmental compliance, system reliability improvements, and new generation sources, will result in rate base and revenue growth but also higher depreciation and financing costs.
Liquidity and Capital Resources
•In February 2022, 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 2022. The plan is designed to upgrade Ameren Missouri’s electric infrastructure and includes investments that will upgrade the grid and accommodate more renewable energy. Investments under the plan are expected to total approximately $8.4 billion over the five-year period from 2022 through 2026, with expenditures largely recoverable under the PISA and the RESRAM.
•In June 2022, Ameren Missouri filed a notice of change in preferred resource plan with the MoPSC. The filing includes ais included in its 2022 Change to the 2020 IRP, which the MoPSC may review at its election.IRP. In connection with the change, Ameren revised its goals for reduction of carbon emissions.this plan, Ameren is targeting net-zero carbon emissions by 2045, as well as a 60% reduction by 2030 and an 85% reduction by 2040 based on 2005 levels. Ameren’s goals include both direct emissions from operations (scope 1), as well as electricity usage at Ameren buildings (scope 2), including other greenhouse gas emissions of methane, nitrous oxide, and sulfur hexafluoride. Achieving these goals will be dependent on a variety of factors, including cost-effective advancements in innovative clean energy technologies and constructive federal and state energy and economic policies. The 2022 Change to the 2020 IRP includes, among other things, the following:
•the continued implementation of customer energy-efficiency programs;
•expanding renewable sources by adding 2,800 MWs of renewable generation by 2030, 400 MWs of battery storage by 2035, and a total of 4,700 MWs of renewable generation and 800 MWs of battery storage by 2040. These amounts include 350 MWs ofthe solar generation projects discussed below. The change also includes below;
•adding 1,200 MWs of natural gas-fired combined cycle generation by 2031, with plans to switch to hydrogen fuel and/or blend hydrogen fuel with natural gas and install carbon capture technology if these technologies become commercially available at a reasonable cost, cost;
•adding 1,200 MWs of additional clean dispatchable generation by 2043, the continued implementation of customer energy-efficiency programs, and 2043;
•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. Additionally, the change includes date;
•extending the retirement date of the coal-fired Sioux Energy Center from 2028 to 2030 in order to ensure reliability during the transition to clean energy generation, which is subject to the approval of a change in the asset’s depreciable life by the MoPSC in Ameren Missouri’s current electric service regulatory rate review, generation;
•accelerating the retirement date of the Rush Island coal-fired energy center to 2025, 2025;
•retiring the Meramec coal-fired energy center at the end of its useful life, which was completed in 2022, December 2022;
•retiring the generating units at the Labadie coal-fired energy center at the end of their useful lives (two generating units by 2036 and the other two by 2042), ;
•accelerating the retirement date of the Venice natural gas-fired energy center to 2029,2029; and
•retiring Ameren Missouri’s other natural gas-fired energy centers in Illinois by 2040.
Ameren Missouri’s plan could be affected by, among other factors: Ameren Missouri’s ability to obtain certificates of convenience and necessityCCNs from the MoPSC, and any other required approvals for the addition of renewable resources or natural gas-fired combined cycle generation, retirement of energy centers, and new or continued customer energy-efficiency programs; the ability to enter into build-transfer agreements for renewable or natural gas-fired combined cycle 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, including those that are affected by the disruptions in the global supply chain caused by the COVID-19 pandemicgeopolitical conflict, or government actions, among other things; changes in the scope and timing of projects; the availability ofability to qualify for, and use or transfer, federal production andor investment tax credits related to renewable energy and Ameren
Missouri’s ability to use such credits; the cost of wind, solar, and other renewable generation and battery storage technologies; the cost of natural gas or hydrogen CT technologies; the ability to maintain system reliability during and after the transition to clean energy generation; new and/or changes in environmental regulations, including those related to CO2 and other greenhouse gas emissions; energy prices and demand; and Ameren Missouri’s ability to obtain necessary rights-of-way, easements, and transmission interconnection agreements at an acceptable cost and in a timely fashion.fashion, the inability to earn an adequate return on invested capital; and the ability to raise capital on reasonable terms. The next integrated resource plan is expected towill be filed in September 2023.
•Missouri law allows Missouri electric utility companies to petition the MoPSC for a financing order to authorize the issuance of securitized utility tariff bonds to finance the cost of retiring electric generation facilities before the end of their useful lives, including the repayment of existing debt.lives. In connection with the planned accelerated retirement of the Rush Island Energy Center due to the NSR and Clean Air Act Litigation discussed above, Ameren Missouri expects to seek approval from the MoPSC as early as the fourth quarter of 2023, to finance the costs associated with the retirement, including the remaining unrecovered net plant balance associated with the facility, through the issuance of securitized utility tariff bonds. As such, Ameren Missouri did not request a change in the depreciation rates related to the Rush Island Energy Center in the electric regulatory rate review filed in August 2022.
•In FebruaryDuring 2022 and 2023, Ameren Missouri, through a subsidiary,and certain subsidiaries of Ameren Missouri, entered into a build-transfer agreementagreements to acquire after construction, a 150-MWand/or construct various solar generation facility, which is expected to be located in southeastern Illinois and, if approved byfacilities, with various regulatory approvals pending. All of the MoPSC, serve customers under Ameren Missouri’s Renewable Solutions Program. In June 2022, Ameren Missouri, through a subsidiary, entered into a build-transfer agreement to acquire, after construction, a 200-MW solar generation facility, which is expected to be located in central Missouri and support Ameren Missouri’s compliancefacilities are aligned with the state of Missouri’s requirement of achieving 15% of retail sales from renewable energy sources, of which 2% must be derived from solar energy sources. The acquisitions are subject2022 Change to certain conditions, including the issuance of certificates of convenience2020 IRP discussed above, and necessity by the MoPSC, obtaining MISO transmission interconnection agreements, and approval by the FERC. In July 2022, Ameren Missouri filed for certificates of convenience and necessity with the MoPSC for both facilities and expects decisions by March 2023 and April 2023 for the 200-MW facility and the 150-MW facility, respectively. Depending on the timing of regulatory approvals and the impact of potential sourcing issues discussed below, the projects could be completed as early as the fourth quarter of 2024. Capitalcapital expenditures related to these facilities are not included in Ameren’s and Ameren Missouri’s expected capital investments discussed below.
•Ameren Missouri'sMissouri’s 2022 Change to the 2020 IRP targets cleaner and more diverse sources of energy generation, including solar
generation. While rights to acquire and/or construct the solar facilities discussed above were secured through build-transfer 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 solar panelspanel components to the United States was significantly disrupted as a result of an investigation initiated by the United States Department of Commerce in late March 2022, which could result in punitivesignificant tariffs on solar panelspanel components imported from four Southeast Asian countries. The investigation is in response to complaints ofa petition, which alleged that Chinese solar manufacturers shiftingshifted solar cellspanel component manufacturing to these countries to avoid tariffs requiredimposed on imports from China. In December 2022, the United States Department of Commerce issued a preliminary determination, finding that all exporters and producers of solar panel components from the four Southeast Asian countries, with a few exceptions, have been circumventing tariffs imposed on imports from China. As a result of the preliminary determination, importers and exporters may avoid the imposition of increased tariffs by certifying to the United States Department of Commerce that the entry of solar panel components into the United States are not subject to the investigation or that they fall within the scope of the 24-month waiver of tariffs discussed below. Failure to submit the applicable certifications, or denial of the submitted certifications by the United States Department of Commerce, could result in increased tariffs on solar panel components that are subject to the investigation and entered the United States on or after April 1, 2022. The United States Department of Commerce is requiredexpected to issue a preliminary determination within 150 days of its initiation of an investigation, with final determination taking 300 days or more.by mid-August 2023. Additionally, certain solar panelspanel 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 was passedbecame effective in December 2021. InJune 2022. Also, in June 2022, President Biden authorized the United States Department of Energy to use the Defense Production Act to rapidly expand American manufacturing of five critical clean energy technologies, including solar panel components. President Biden also took executive action to temporarily lift certain tariffs on solar panelspanel components imported from the four Southeast Asian countries under investigation by the United States Department of Commerce for 24 months in order to allow the United States access to a sufficient supply of solar panelspanel components to meet electricity generation needs while domestic manufacturing scales up. Any future tariffs or other outcomes resulting from the investigation by the United States Department of Commerce or actions by the United States Customs and Border Protection Agency could affect the cost and the availability of solar panelspanel components and the timing and amount of Ameren Missouri'sMissouri’s estimated capital expenditures associated with solar generation investments.
•Through 2026,2027, we expect to make significant capital expenditures to improve our electric and natural gas utility infrastructure, with a major portion directed to our transmission and distribution systems. We estimate that we will invest up to $18.0$20.5 billion (Ameren Missouri – up to $9.2$10.8 billion; Ameren Illinois – up to $8.6$9.5 billion; ATXI – up to $0.2 billion) of capital expenditures during the period from 20222023 through 2026.2027. These planned investments are based on the assumption of continued constructive regulatory frameworks. Ameren’s and Ameren Missouri’s estimates excludeinclude $2.5 billion of renewable generation investment opportunities of 800 MWs by 2026, which are includedinvestments through 2027 consistent with investments outlined in Ameren Missouri’s 2022 Change to the 2020 IRP,IRP. Ameren’s estimate also includes $0.8 billion of capital expenditures through 2027 related to projects assigned to Ameren pursuant to the first tranche of projects under the MISO’s long-range transmission planning roadmap discussed below.
•As a result of major storms experienced throughout our service territories in late June and investment opportunities that may be approved by the MISOJuly 2023, Ameren Missouri and Ameren Illinois expect capital expenditures related to address reliability concerns in connection with the planned accelerated retirementrestoration costs of the Rush Island Energy Center. These investment opportunities may be incrementalapproximately $65 million to or partially replace other expenditures included in the 2022 through 2026 estimates above.$80 million and $60 million to $75 million, respectively.
•In 2021, the MISO issued a report outlining a preliminary long-range transmission planning roadmap of projects through 2039, which considers the rapidly changing generation mix within MISO resulting from significant additions of renewable generation, actual and expected generation plant closures, and state mandates or goals for clean energy or carbon emissions reductions. In July 2022, the MISO approved the first tranche of projects under the first phase of the roadmap. A portion of these projects were assigned to various utilities, of which Ameren was awarded projects that are estimated to cost approximately $1.8 billion, based on the MISO’s cost estimate.
The MISO Construction on the Ameren projects is expected to initiatebegin in 2025, with completion dates expected near the end of this decade. The MISO initiated requests for proposals for the remaining projects included in theadditional first tranche whichcompetitive bid projects in December 2022, June 2023, and July 2023, with proposals due in May 2023, November 2023, and October 2023, respectively. These competitive-bid projects are estimated by the MISO to cost approximately $0.7 billion and are expected to be awarded between mid-2023late-2023 and mid-2024. These investment opportunities mayIn 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 incremental to or partially replace other expenditures includedapproved in the 2022 through 2026 estimates discussed above.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.order in this proceeding.
•In July 2022, an Illinois law prohibiting the state’s oversight of certain electric utilities’ choice of RTO membership ceased to be effective. Given the change in law and the high prices resulting from MISO’s April 2022 capacity auction, the ICC issued an order requiring
Ameren Illinois to perform a cost benefitcost-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 benefitcost-benefit study will examineexamined 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 ICC order requires Ameren Illinois to filestudy concluded that continued participation in the study by July 2023. A 30-day comment period will follow.MISO was prudent and more cost-beneficial than participation in PJM Interconnection LLC. The ICC is under no obligation to issue an order in this matter.related to the cost-benefit study.
•Environmental regulations, including those related to CO2emissions, or other actions taken by the EPA or state regulators, or requirements that may result from the NSR and Clean Air Act Litigation, discussed in Note 9 – Commitments and Contingencies under Part I, Item 1, of this report, could result in significant increases in capital expenditures and operating costs. Regulations enacted by a prior federal administration can be reviewed and repealed, and replacement or alternative regulations can be proposed or adopted by the current federal administration, including the EPA. See Note 9 – Commitments and Contingencies under Part I, Item 1, of this report, for additional information on environmental matters, including the NSR and Clean Air Act litigation. The ultimate implementation of any of these new regulations, as well as the timing of any such implementation, is uncertain. However, the individual or combined effects of existing and new environmental regulations could result in significant capital expenditures, increased operating costs, or the closure or alteration of some of Ameren Missouri’s coal and natural gas-fired energy centers. Ameren Missouri’s capital expenditures are subject to MoPSC prudence reviews, which could result in cost disallowances, as well as regulatory lag. The cost of Ameren Illinois’ purchased power and natural gas purchased for resale could increase. However, Ameren Illinois expects that these costs would be recovered from customers with no material adverse effect on its results of operations, financial position, or liquidity. Ameren’s and Ameren Missouri’s earnings could benefit from increased investment to comply with environmental regulations if those investments are reflected and recovered on a timely basis in customer rates.
•The Ameren Companies have multiyear credit agreements that cumulatively provide $2.3$2.6 billion of credit through December 2025,2027, 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 $2.7$3.2 billion. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report and Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for additional information regarding the Credit Agreements. BySee Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, in the end of 2022, $55 million, $400 million, and $50 million ofForm 10-K for long-term debt obligations are duematurities from 2023 to mature2027 and beyond at Ameren (parent), Ameren Missouri, Ameren Illinois, and ATXI respectively.and see Note 4 – Long-term Debt and Equity Financings under Part I, Item 1, of this report for principal payments made on long-term debt during 2023 through the date of this report. 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. To date,plans, and expect to continue to have access to the Ameren Companies have been able to access the capital and credit markets on reasonable terms when needed. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
•Ameren expects its cash used for currently planned capital expenditures and dividends to exceed cash provided by operating activities over the next several years. As part of its funding plan for capital expenditures, Ameren is using newly issued shares of common stock rather than market-purchased shares, to satisfy requirements under the DRPlus and employee benefit plans and expects to continue to do so through at least 2026.2027. Ameren expects these equity issuances to provide equity oftotal about $100 million annually. In addition, in 2021, Ameren establishedhas an ATM program under which Ameren may offer and sell from time to time up to $750 million of its common stock, which includes the ability to enter into forward sales agreements, subject to market conditions and other factors. As of June 30, 2023, Ameren has entered intohad multiple forward sale agreements that could be settled under the ATM program with various counterparties relating to 5.84.3 million shares of common stock. AsAmeren expects to settle approximately $300 million of June 30, 2022, Ameren could have settled the forward sale agreements with physical delivery of 5.63.2 million shares of common stock by December 31, 2023. Also, Ameren plans to issue approximately $500 million of equity each year from 2024 to 2027, in addition to issuances under the respective counterparties in exchange for cash of $500 million.DRPlus and employee benefit plans. As of June 30, 2022,2023, Ameren had approximately $90$910 million of common stock available for sale under the ATM program, which takes into account the forward sale agreements in effect as of June 30, 2022. For additional information regarding outstanding forward sale agreements, including settlement dates, see Note 4 – Long-Term Debt and Liquidity under Part I, Item 1, of this report. Ameren expects to settle approximately $300 million of the forward sale agreements by December 31, 2022. Ameren plans to issue approximately $300 million of equity each year from 2022 to 2026 in addition to issuances under the DRPlus and employee benefit plans.2023. Ameren expects its equity to total capitalization ratio to be approximatelyabout 45% throughby December 31, 2026,2027, with the long-term intent 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 IRA was enacted in August 2022, and includes various income tax provisions, among other things. The law extends federal production and investment tax credits for projects beginning construction through 2024 and allows for a 10% adder to the production and investment tax credits for siting projects at existing energy communities as defined in the law, which includes sites previously used for coal-fired generation. The law also creates clean energy tax credits for projects placed in service after 2024. The clean energy tax credits will apply to renewable energy production and investments, along with certain nuclear energy production, and will be phased out beginning in 2033, at the earliest. The phase-out is triggered when greenhouse gas emissions from the electric generation industry are reduced by at least 75% from the annual 2022 emission rate or at the beginning of 2033, whichever is later. The law allows for transferability to an unrelated party for cash of up to 100% of certain tax credits generated after 2022. In addition, the new law imposes a 15% minimum tax on adjusted financial statement income, as defined in the law, for corporations whose average annual adjusted financial statement income exceeds $1 billion for three consecutive preceding tax years effective for tax years beginning after
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 are expected to be issued by the IRS or United States Department of Treasury, which may impact the timing of when the 15% minimum tax becomes applicable for Ameren as discussed below.
•As of June 30, 2022,2023, Ameren had $146$198 million in tax benefits from federal and state income tax credit carryforwards and $38$48 million in tax benefits from federal and state net operating loss carryforwards, which will be utilized in future periods. Future expected income tax payments are based on expected taxable income, available income tax credit and net operating loss carryforwards, and current tax law. Expected taxable income is affected by expected capital expenditures, when property, plant, and equipment is placed in-service or retired, and the timing of regulatory reviews, among other things. Ameren expects federal income tax payments at the required minimum levels from 20222023 to 20262027 resulting from the anticipated use of existing production tax credits generated by Ameren Missouri’s High Prairie Renewable and Atchison Renewable energy centers, existing income tax credit and net operating losses, tax creditloss carryforwards, tax overpayments, and outstanding refunds. Based on its preliminary calculations, Ameren does not expect to be subject to the 15% minimum tax on adjusted financial statement income imposed by the IRA in 2023 and 2024. Ameren expects annual federal income tax payments, including payments related to the 15% minimum tax pursuant to the IRA, to be immaterial through 2027.
The above items could have a material impact on our results of operations, financial position, and liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
There have been no material changes to the quantitative and qualitative disclosures about interest rate risk, credit risk, commodity price risk, investment price risk, and commodity supplier risk included in the Form 10-K, except as discussed below. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risk.
Ameren Missouri has an immaterial amountreceived a planned delivery of enriched uranium intended to be utilized later this decade that is sourced from a Russian supplier and could become subject toin the spring of 2023. The planned delivery concluded the nuclear fuel supply agreement with this Russian supplier with no future sanctions. Ameren Missouri is reviewing options to reduce its exposure to Russian-sourced supplies.deliveries planned with any Russian suppliers. Ameren Missouri has inventoriessufficient inventory and supply contracts fromwith non-Russian suppliers sufficient tothat adequately meet all of its uranium (concentrate and hexafluoride), conversion, and enrichment requirements at leastthe nuclear fuel needs of the Callaway Energy Center through the 2026 refueling of the Callaway Energy Center.reload.
ITEM 4. CONTROLS AND PROCEDURES.
(a)Evaluation of Disclosure Controls and Procedures
As of June 30, 2022,2023, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and the principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of June 30, 2022,2023, the principal executive officer and the principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive officer and its principal financial officer, to allow timely decisions regarding required disclosure.
(b)Changes in Internal Controls over Financial Reporting
There has been no change in any of the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, each of their internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings,
except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses. For additional information on material legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 9 – Commitments and Contingencies, and Note 10 – Callaway Energy Center, under Part I, Item 1, of this report. Pursuant to Item 103(c)(3)(iii) of Regulation S-K, our policy is to disclose environmental proceedings to which a governmental entity is a party if we reasonably believe such proceedings will result in monetary sanctions of $1 million or more. ITEM 1A. RISK FACTORS.
There have been no material changes to the risk factors disclosed in Part I, Item 1A, Risk Factors in the Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
Ameren Corporation, Ameren Missouri, and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from April 1, 2022,2023, to June 30, 2022.2023.
ITEM 5. OTHER INFORMATION.
Insider Adoption or Termination of Trading Arrangements
During the fiscal quarter ended June 30, 2023, none of our directors or officers informed us of the adoption or termination of a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Regulation S-K, Item 408.
ITEM 6. EXHIBITS.
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
| | | | | | | | | | | | | | | | | | | | |
Exhibit
Designation | | Registrant(s) | | Nature of Exhibit | | Previously Filed as Exhibit to: |
|
| | | | | | |
| Instruments Defining Rights of Security Holders, Including Indentures |
| 4.1 | | Ameren
Ameren Illinois | | | | May 31, 2023 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| Material Contracts |
| 10.1 | | Ameren CompaniesAmeren Missouri | | | | |
Exhibit 99.1, File No. 333-26487610.2 | | Ameren Ameren Illinois | | | | |
| Rule 13a-14(a) / 15d-14(a) Certifications |
| 31.1 | | Ameren | | | | |
| 31.2 | | Ameren | | | | |
| 31.3 | | Ameren Missouri | | | | |
| 31.4 | | Ameren Missouri | | | | |
| 31.5 | | Ameren Illinois | | | | |
| 31.6 | | Ameren Illinois | | | | |
| Section 1350 Certifications |
| 32.1 | | Ameren | | | | |
| 32.2 | | Ameren Missouri | | | | |
| 32.3 | | Ameren Illinois | | | | |
| Interactive Data Files |
| 101.INS | | Ameren Companies | | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | | |
| 101.SCH | | Ameren Companies | | Inline XBRL Taxonomy Extension Schema Document | | |
| 101.CAL | | Ameren Companies | | Inline XBRL Taxonomy Extension Calculation Linkbase Document | | |
| 101.LAB | | Ameren Companies | | Inline XBRL Taxonomy Extension Label Linkbase Document | | |
| 101.PRE | | Ameren Companies | | Inline XBRL Taxonomy Extension Presentation Linkbase Document | | |
| 101.DEF | | Ameren Companies | | Inline XBRL Taxonomy Extension Definition Document | | |
| 104 | | Ameren Companies | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | | |
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; Ameren Missouri, 1-2967; and Ameren Illinois, 1-3672.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
SIGNATURES
Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
| | |
|
AMEREN CORPORATION
(Registrant) |
|
| /s/ Michael L. Moehn |
Michael L. Moehn
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
|
|
UNION ELECTRIC COMPANY
(Registrant) |
|
| /s/ Michael L. Moehn |
Michael L. Moehn
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
|
|
AMEREN ILLINOIS COMPANY
(Registrant) |
|
| /s/ Michael L. Moehn |
Michael L. Moehn
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|
Date: August 5, 20223, 2023
