10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549 

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2023

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-8644

IPALCO ENTERPRISES, INC.

(Exact name of registrant as specified in its charter)

Indiana	35-1575582
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
One Monument Circle
Indianapolis, Indiana	46204
(Address of principal executive offices)	(Zip code)
Registrant's telephone number, including area code:	(317) 261-8261

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
N/A	N/A	N/A
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☒ No ☐

Indicate by check mark whether the registrant (1) has 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) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒

(The registrant is a voluntary filer. The registrant has filed all applicable reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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:

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. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐   No ☒

At February 26, 2024, 108,907,318 shares of IPALCO Enterprises, Inc. common stock, no par value, were outstanding, of which 89,685,177 shares were owned by AES U.S. Investments, Inc. and 19,222,141 shares were owned by CDP Infrastructures Fund L.P., a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec. 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of registrant’s Proxy Statement for its annual meeting of stockholders are incorporated by reference in Part III hereof.

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IPALCO ENTERPRISES, INC.
Annual Report on Form 10-K
For Fiscal Year Ended December 31, 2023
Table of Contents
Item No.		Page No.
	GLOSSARY OF TERMS	5
	PART I
ITEM 1.	BUSINESS	8
ITEM 1A.	RISK FACTORS	23
ITEM 1B.	UNRESOLVED STAFF COMMENTS	36
ITEM 1C.	CYBERSECURITY	36
ITEM 2.	PROPERTIES	38
ITEM 3.	LEGAL PROCEEDINGS	38
ITEM 4.	MINE SAFETY DISCLOSURES	38
PART II
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	38
ITEM 6.	[RESERVED]	39
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39
	EXECUTIVE SUMMARY	40
	RESULTS OF OPERATIONS	41
	KEY TRENDS AND UNCERTAINTIES	47
	CAPITAL RESOURCES AND LIQUIDITY	49
	CRITICAL ACCOUNTING POLICIES AND ESTIMATES	55
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	56
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	59
	IPALCO ENTERPRISES, INC. AND SUBSIDIARIES
	Report of Independent Registered Public Accounting Firm	60
	Consolidated Statements of Operations	63
	Consolidated Statements of Comprehensive Income	64
	Consolidated Balance Sheets	65
	Consolidated Statements of Cash Flows	66
	Consolidated Statements of Changes in Equity	67
	Notes to Consolidated Financial Statements	68
	Note 1 - Overview and Summary of Significant Accounting Policies	68
	Note 2 - Regulatory Matters	76
	Note 3 - Property, Plant and Equipment	86
	Note 4 - Fair Value	87
	Note 5 - Derivative Instruments and Hedging Activities	90
	Note 6 - Debt	92
	Note 7 - Income Taxes	95
	Note 8 - Benefit Plans	97
	Note 9 - Equity and Cumulative Preferred Stock	103
	Note 10 - Commitments and Contingencies	105
	Note 11 - Related Party Transactions	106

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	Note 12 - Business Segments	107
	Note 13 - Revenue	108
	Note 14 - Leases	110
	AES INDIANA AND SUBSIDIARIES
	Report of Independent Registered Public Accounting Firm	112
	Consolidated Statements of Operations	115
	Consolidated Balance Sheets	116
	Consolidated Statements of Cash Flows	117
	Consolidated Statements of Changes in Equity	118
	Notes to Consolidated Financial Statements	119
	Note 1 - Overview and Summary of Significant Accounting Policies	119
	Note 2 - Regulatory Matters	127
	Note 3 - Property, Plant and Equipment	137
	Note 4 - Fair Value	138
	Note 5 - Derivative Instruments and Hedging Activities	140
	Note 6 - Debt	141
	Note 7 - Income Taxes	144
	Note 8 - Benefit Plans	146
	Note 9 - Equity and Cumulative Preferred Stock	152
	Note 10 - Commitments and Contingencies	153
	Note 11 - Related Party Transactions	155
	Note 12 - Business Segments	156
	Note 13 - Revenue	156
	Note 14 - Leases	158
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	160
ITEM 9A.	CONTROLS AND PROCEDURES	160
ITEM 9B.	OTHER INFORMATION	161
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	161
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	161
ITEM 11.	EXECUTIVE COMPENSATION	161
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	161
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	162
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	162
PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES	163
ITEM 16.	FORM 10-K SUMMARY	175
SIGNATURES		176

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GLOSSARY OF TERMS
The following is a list of frequently used terms, abbreviations or acronyms that are found in this Form 10-K:
2016 Base Rate Order	The order issued in March 2016 by the IURC authorizing AES Indiana to, among other things, increase its basic rates and charges by $30.8 million annually
2018 Base Rate Order	The order issued in October 2018 by the IURC authorizing AES Indiana to, among other things, increase its basic rates and charges by $43.9 million annually
2024 IPALCO Notes	$405 million of 3.70% IPALCO Enterprises, Inc. Senior Secured Notes due September 1, 2024
2030 IPALCO Notes	$475 million of 4.25% IPALCO Enterprises, Inc. Senior Secured Notes due May 1, 2030
$200 million Term Loan Agreement	$200 million AES Indiana Term Loan Agreement, dated as of June 23, 2022
$300 million Term Loan Agreement	$300 million AES Indiana Term Loan Agreement, dated as of November 21, 2023
ACE	Affordable Clean Energy
AES	The AES Corporation
AES Indiana	Indianapolis Power & Light Company and its consolidated subsidiaries, which does business as AES Indiana
AES U.S. Investments	AES U.S. Investments, Inc.
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BESS	Battery Energy Storage System
BIL	Bipartisan Infrastructure Law, also known as the Infrastructure Investment and Jobs Act
BTA	Best Technology Available
CAA	U.S. Clean Air Act
CCGT	Combined Cycle Gas Turbine
CCR	Coal Combustion Residuals
CDPQ	CDP Infrastructures Fund L.P., a wholly-owned subsidiary of La Caisse de dépôt et placement du Québec
CO2	Carbon Dioxide
COVID-19	The disease caused by the novel coronavirus that resulted in a global pandemic beginning in 2020.
CPCN	Certificate of Public Convenience and Necessity
CPP	Clean Power Plan
Credit Agreement	$350 million AES Indiana Revolving Credit Facilities Second Amended and Restated Credit Agreement, dated as of December 22, 2022
CSAPR	Cross-State Air Pollution Rule
Cumulative Deficiencies	Cumulative Net Operating Income Deficiencies. The Cumulative Deficiencies calculation provides that only five years' worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.
CWA	U.S. Clean Water Act
D.C. Circuit	U.S. Court of Appeals for the District of Columbia Circuit
Defined Benefit Pension Plan	Employees’ Retirement Plan of AES Indiana
DOJ	U.S. Department of Justice
DSM	Demand Side Management
ECCRA	Environmental Compliance Cost Recovery Adjustment
EDG	Excess Distributed Generation
EGUs	Electrical Generating Units
ELG	Effluent Limitation Guidelines
EPA	U.S. Environmental Protection Agency
EPAct	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act of 1974
EV	Electric Vehicle
FAC	Fuel Adjustment Clause

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FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
Financial Statements	Audited Consolidated Financial Statements of IPALCO in “Item 8. Financial Statements and Supplementary Data” included in Part II of this Form 10-K
FIP	Federal Implementation Plan
FTRs	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States
GHG	Greenhouse Gas
Hardy Hills JV	Hardy Hills JV, LLC
HLBV	Hypothetical Liquidation Book Value
IBEW	International Brotherhood of Electrical Workers
IDEM	Indiana Department of Environmental Management
IOSHA	Indiana Occupational Safety and Health Administration
IPALCO	IPALCO Enterprises, Inc. and its consolidated subsidiaries
IPL	Indianapolis Power & Light Company and its consolidated subsidiaries, which does business as AES Indiana
IRA	Inflation Reduction Act of 2022
IRP	Integrated Resource Plan
ITC	Investment Tax Credit
IURC	Indiana Utility Regulatory Commission
kWh	Kilowatt hours
MATS	Mercury and Air Toxics Standards
Mid-America	Mid-America Capital Resources, Inc.
MISO	Midcontinent Independent System Operator, Inc.
MW	Megawatts
MWh	Megawatt hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standards
NSR	New Source Review
OUCC	Indiana Office of Utility Consumer Counselor
Pension Plans	Employees’ Retirement Plan of AES Indiana and Supplemental Retirement Plan of AES Indiana
PTC	Production Tax Credit
PM2.5	Fine particulate matter or particulate matter with an aerodynamic diameter less than or equal to a nominal 2.5 micrometers
PSD	Prevention of Significant Deterioration
RF	ReliabilityFirst
RFP	Request for Proposal
RSP	AES Retirement Savings Plan
RTO	Regional Transmission Organization
SEC	United States Securities and Exchange Commission
Securities Act	Securities Act of 1933, as Amended
Service Company	AES US Services, LLC
SIP	State Implementation Plan
SO2	Sulfur Dioxide
SOFR	Secured Overnight Financing Rate
Supplemental Retirement Plan	Supplemental Retirement Plan of AES Indiana

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TCJA	Tax Cuts and Jobs Act
TDSIC	Transmission, Distribution, and Storage System Improvement Charge
Third Amended and Restated Articles of Incorporation	Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc.
Thrift Plan	Employees’ Thrift Plan of AES Indiana
URT	Utility Receipts Tax
U.S.	United States of America
USD	United States Dollars
VEBA	Voluntary Employees' Beneficiary Association
VIE	Variable Interest Entity
WOTUS	Waters of the U.S.

PART I

Throughout this document, the terms “the Company,” “we,” “us,” and “our” refer to IPALCO and its consolidated subsidiaries. 

We encourage investors, the media, our customers and others interested in the Company to review the information we post at https://www.aesindiana.com. None of the information on our website is incorporated into, or deemed to be a part of, this Annual Report on Form 10-K or in any other report or document we file with the SEC, and any reference to our website is intended to be an inactive textual reference only.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 including, in particular, the statements about our plans, strategies and prospects under the headings “Item 1. Business,” “Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Forward-looking statements express an expectation or belief and contain a projection, plan or assumption with regard to, among other things, our future revenue, income, expenses or capital structure. Such statements of future events or performance are not guarantees of future performance and involve estimates, assumptions and uncertainties. The words “could,” “may,” “predict,” “anticipate,” “would,” “believe,” “estimate,” “expect,” “forecast,” “project,” “objective,” “intend,” “continue,” “should,” “plan,” and similar expressions, or the negatives thereof, are intended to identify forward-looking statements unless the context requires otherwise.

Some important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward-looking statements include, but are not limited to:

▪impacts of weather on retail sales;

▪growth in our service territory and changes in retail demand and demographic patterns;

▪weather-related damage to our electrical system;

▪commodity and other input costs;

▪performance of our suppliers;

▪transmission, distribution and generation system reliability and capacity, including natural gas pipeline system and supply constraints;

▪regulatory actions and outcomes, including, but not limited to, the review and approval of our rates and charges by the IURC;

▪federal and state legislation and regulations; 

▪changes in our credit ratings or the credit ratings of AES;  

▪fluctuations in the value of pension plan assets, fluctuations in pension plan expenses and our ability to fund defined benefit pension plans;

▪changes in financial or regulatory accounting policies;

▪environmental and climate change matters, including costs of compliance with, and liabilities related to, current and future environmental and climate change laws and requirements;

▪interest rates and the use of interest rate hedges, inflation rates and other costs of capital;

▪the availability of capital;

▪the ability of subsidiaries to pay dividends or distributions to IPALCO;

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▪level of creditworthiness of counterparties to contracts and transactions;

▪labor strikes or other workforce factors, including the ability to attract and retain key personnel;

▪facility or equipment maintenance, repairs and capital expenditures;

▪significant delays or unanticipated cost increases associated with construction or other projects;

▪the availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material;

▪local economic conditions;

▪costs and effects of legal and administrative proceedings, audits, settlements, investigations and claims and the ultimate disposition of litigation, cyber-attacks, information security breaches or information system failures;

▪industry restructuring, deregulation and competition;

▪issues related to our participation in MISO, including the cost associated with membership, our continued ability to recover costs incurred, and the risk of default of other MISO participants;

▪changes in tax laws and the effects of our tax strategies;

▪the use of derivative contracts;

▪product development, technology changes, and changes in prices of products and technologies;

▪catastrophic events such as fires, explosions, terrorist acts, acts of war, pandemics, or the future outbreak of any other highly infectious or contagious disease, including COVID-19, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts, or other similar occurrences, including as a result of climate change; and

▪the risks and other factors discussed in this report and other IPALCO filings with the SEC.

Forward-looking statements speak only as of the date of the document in which they are made. We disclaim any obligation or undertaking to provide any updates or revisions to any forward-looking statement to reflect any change in our expectations or any change in events, conditions or circumstances on which the forward-looking statement is based. If we do update one or more forward-looking statements, no inference should be made that we will make additional updates with respect to those or other forward-looking statements.

All of the above factors are difficult to predict, contain uncertainties that may materially affect actual results, and many are beyond our control. See "Item 1A - Risk Factors" to Part I in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023 and the “Management's Discussion and Analysis of Financial Condition and Results of Operations” section in this Annual Report on Form 10-K for a more detailed discussion of the foregoing and certain other factors that could cause actual results to differ materially from those reflected in such forward-looking statements and that should be considered in evaluating our outlook. These risks may also be specifically described in our Quarterly Reports on Form 10-Q in Part II - Item 1A, Current Reports on Form 8-K and other documents that we may file from time to time with the SEC.

ITEM 1. BUSINESS

OVERVIEW

IPALCO is a holding company incorporated under the laws of the state of Indiana whose principal subsidiary is AES Indiana. AES Indiana is a regulated electric utility operating in the state of Indiana. Substantially all of our business consists of the generation, transmission, distribution and sale of electric energy conducted through AES Indiana. Our business segments are “utility” and “all other.” All of our operations are conducted within the U.S. and principally within the state of Indiana. Please see Note 12, “Business Segments” to the Financial Statements of this Annual Report on Form 10-K.

AES INDIANA

IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana is engaged primarily in generating, transmitting, distributing and selling electric energy to approximately 523,000 retail customers in the city of Indianapolis and neighboring areas within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers. AES Indiana's service area covers about 528 square miles with an estimated population of approximately 969,000. AES Indiana’s generation, transmission and distribution facilities, and changes to our sources of electric generation, are further described below under “Properties.” There have been no significant changes in the services rendered by AES Indiana during 2023. 

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AES Indiana is a transmission company member of RF. RF is one of eight Regional Reliability Councils under the NERC, which has been designated as the Electric Reliability Organization under the EPAct. RF seeks to preserve and enhance electric service reliability and security for the interconnected electric systems within the RF geographic area by setting and enforcing electric reliability standards. RF members cooperate under agreements to augment the reliability of its members’ electricity supply systems in the RF region through coordination of the planning and operation of the members’ generation and transmission facilities. Smaller electric utility systems, independent power producers and power marketers can participate as full members of RF.

HUMAN CAPITAL MANAGEMENT

AES Indiana's employees are essential to delivering and maintaining reliable service to our customers. As of December 31, 2023, AES Indiana had 1,138 employees, of whom 1,074 were full time. Of the total employees, 774 were represented by the IBEW in two bargaining units: a physical unit and a clerical-technical unit. In December 2021, the IBEW physical unit ratified a three-year agreement with AES Indiana that expires on December 4, 2024. In February 2023, the membership of the IBEW clerical-technical unit ratified a three-year labor agreement with AES Indiana that expires on February 12, 2026. Both collective bargaining agreements continue in full force and effect from year-to-year unless either party provides prior written notice at least sixty (60) days prior to the expiration, or anniversary thereof, of its desire to amend or terminate the agreement. As of December 31, 2023, neither IPALCO nor any of its majority-owned subsidiaries, other than AES Indiana, had any employees.

Safety

As part of AES, safety is one of our core values. Conducting safe operations at our facilities, so that each person can return home safely, is the cornerstone of our daily activities and decisions. Safety efforts are led globally by the AES Chief Operating Officer and supported by safety committees that operate at the local site level. Hazards in the workplace are actively identified, and management tracks incidents so remedial actions can be taken to improve workplace safety.

We work with the Safety Management System (“SMS”), a Global Safety Standard that applies to all AES employees and employees of AES subsidiaries, as well as contractors working in AES facilities and construction projects. The SMS requires continuous safety performance monitoring, risk assessment and performance of periodic integrated environmental, health, and safety audits. The SMS provides a consistent framework for all AES operational businesses and construction projects to set expectations for risk identification and reduction, measure performance, and drive continuous improvements. The SMS standard is consistent with the OHSAS 18001/ISO 45001 standard.

Our safety performance is also measured by both leading and lagging metrics. Our leading safety metrics track safety observations, safety meeting engagement and the reporting of lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards. Our lagging safety metrics track lost workday cases, severity rate, and recordable incidents. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices.

Talent

We believe our success depends on our ability to attract, develop and retain key personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance. We have a comprehensive approach to managing our talent and developing our leaders in order to ensure our people have the right skills for today and tomorrow, whether that requires us to build new business models or leverage leading technologies.

We emphasize employee development and training. To empower employees, we provide a range of development programs and opportunities, skills, and resources they need to be successful by focusing on experience and exposure, as well as formal programs including the AES' ACE Academy for Talent Development, and our Trainee Program.

We believe that our individual differences make us stronger. Our Global Diversity and Inclusion Program is led by the AES Diversity and Inclusion Officer. Governance and standards are guided by the AES Chief Human Resources Officer, with input from members of AES' Executive Leadership Team.

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Compensation

Our compensation philosophy emphasizes pay-for-performance. Our incentive plans are designed to reward strong performance, with greater compensation paid when performance exceeds expectations and less compensation paid when performance falls below expectations. We invest significant time and resources to ensure our compensation programs are competitive and reward the performance of our people. Every year, our people who are not part of a collective bargaining agreement are eligible for an annual merit-based salary increase. In addition, individuals are eligible for a salary increase if they receive a significant promotion. For non-collectively bargained employees at certain levels in the organization, we offer annual incentives (bonus) and long-term compensation to reinforce the alignment between employees and AES.

SERVICE COMPANY

The Service Company provides services including operations, accounting, legal, human resources, information technology and other corporate services on behalf of certain AES U.S. companies, including among other companies, IPALCO and AES Indiana. The Service Company allocates the costs for these services based on cost drivers designed to result in fair and equitable allocations. This includes ensuring that the regulated utilities served, including AES Indiana, are not subsidizing costs incurred for the benefit of other businesses. Please see Note 11, “Related Party Transactions – Service Company” to the Financial Statements and “Item 13. Certain Relationships and Related Transactions, and Director Independence” of this Annual Report on Form 10-K for additional details.

PROPERTIES

Our executive offices are located at One Monument Circle, Indianapolis, Indiana. This facility and the remainder of our material properties in our business and operations are owned directly by AES Indiana. The following is a description of these material properties.

We own two distribution service centers in Indianapolis. We also own the building in Indianapolis that houses our customer service center. 

We own and operate four generating stations, all within the state of Indiana. The first station, Petersburg, is coal-fired. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. For electric generation, the net winter design capacity is 3,070 MW and net summer design capacity is 2,925 MW. Our highest summer peak level of 3,139 MW was recorded in August 2007 and the highest winter peak level of 2,971 MW was recorded in January 2009.

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Our sources of electric generation are as follows:

Fuel	Name	Number of Units	Winter Capacity (MW)	Summer Capacity (MW)	Location
Gas	Harding Street	6	1,026	963	Marion County, Indiana
	Eagle Valley	1	719	689	Morgan County, Indiana
	Georgetown	2	200	158	Marion County, Indiana
	Total	9	1,945	1,810
Coal	Petersburg(1)	2	1,064	1,064	Pike County, Indiana
	Total	2	1,064	1,064
Oil	Petersburg	3	8	8	Pike County, Indiana
	Harding Street	3	53	43	Marion County, Indiana
	Total	6	61	51
Grand Total		17	3,070	2,925

(1) AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP”).

Net electrical generation during 2023 at our Eagle Valley, Petersburg, Harding Street and Georgetown plants accounted for approximately 41.9%, 32.5%, 24.8% and 0.8%, respectively, of our total net generation. Even though the capacity of our Harding Street plant far exceeds that of the Eagle Valley CCGT plant, we expect the generation at Eagle Valley to continue to far exceed that of Harding Street due to the relatively lower cost to produce electricity at Eagle Valley.

The following table summarizes projects that have not yet been fully placed into service (see further discussion in Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K):

Type	Project Name	Solar Capacity (MW)	Storage Capacity (MWh)	Date filed with IURC	Date of IURC approval	Estimated Completion	Location
Solar	Hardy Hills Solar Project	195	—	2/12/2021	6/16/2021	2024(1)	Clinton County, Indiana
Solar & Storage	Petersburg Energy Center Project	250	180	7/30/2021	11/24/2021	2025	Pike County, Indiana
Storage	Pike County BESS Project	—	800	7/19/2023	1/17/2024	2024	Pike County, Indiana
(1)In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.

Our electric system is directly interconnected with the electric systems of Indiana Michigan Power Company, CenterPoint Indiana (formerly Vectren Corporation), Hoosier Energy Rural Electric Cooperative, Inc., and the electric system jointly owned by Duke Energy Indiana, Indiana Municipal Power Agency and Wabash Valley Power Association, Inc. Our transmission system includes 458 circuit miles of 345,000 volt lines and 408 circuit miles of 138,000 volt lines. The distribution system consists of 5,314 circuit miles of underground primary and secondary cables and 6,081 circuit miles of overhead primary and secondary wire. Underground street lighting facilities include 790 circuit miles of underground cable. Also included in the system are 132 substations. Depending on the voltage levels at the substation, some substations may be considered both a bulk power substation and a distribution substation. There are 73 bulk power substations and 103 distribution substations; 52 substations are considered both bulk power and distribution substations.

All critical facilities we own are well maintained, in good condition and meet our present needs. Our plants generally have enough capacity to meet the daily needs of our retail customers when all of our units are available. During periods when our generating capacity is not sufficient to meet our retail demand, or when MISO provides a lower cost alternative to some of our available generation, we purchase power on the MISO wholesale market.

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SEASONALITY

The electric utility business is affected by seasonal weather patterns throughout the year and, therefore, the operating revenue and associated operating expenses are not generated evenly by month during the year. AES Indiana’s business is not dependent on any single customer or group of customers. Additionally, retail kWh sales, after adjustments for weather variations, are impacted by changes in service territory economic activity and the number of retail customers we have, as well as DSM energy efficiency programs implemented by AES Indiana. For the ten years ending in 2023, AES Indiana’s retail kWh sales have decreased at a compound annual rate of 1.2%. Conversely, the number of our retail customers grew at a compound annual rate of 0.9% during that same period. Going forward, we expect modest retail kWh sales growth annually, which will continue to be offset by our DSM programs. Please see Note 2, “Regulatory Matters – DSM” to the Financial Statements of this Annual Report on Form 10-K for more details. AES Indiana’s electricity sales for 2019 through 2023 are set forth in the table of statistical information included at the end of this section.

Weather and Weather-Related Damage in our Service Area

Extreme high and low temperatures in our service area have a significant impact on revenue as many of our retail customers use electricity to power air conditioners, electric furnaces and heat pumps. The impact on customers is partially mitigated by our declining block rate structure, which generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. The effect is generally more significant with high temperatures than with low temperatures as many of our customers use gas heat. In addition, because extreme temperatures have the effect of increasing demand for electricity, the wholesale price for electricity generally increases during periods of extreme hot or cold weather, however 100% of annual wholesale margins AES Indiana earns above (or below) the benchmark of $16.3 million are passed back (or charged) to customer rates through a rider.

Storm activity can also have an adverse effect on our operating performance. Severe storms often damage transmission and distribution equipment, thereby causing power outages, which reduce revenue and increase repair costs. Partially mitigating this impact is AES Indiana’s ability to timely recover certain operation and maintenance repair costs related to severe storms. In our 2016 and 2018 Base Rate Orders, we received approval for a storm damage restoration reserve account that allows us to defer major storm costs over a benchmark that meet certain criteria considered to be severe, for recovery in a future basic rate proceeding. Because AES Indiana's basic rates and charges include an annual amount for recovery for such severe storm costs, if actual severe storm costs are below that level, AES Indiana will record a regulatory liability for the shortfall to be passed to customers in a future basic rate proceeding. Conversely, if AES Indiana's major storm costs are above the level in basic rates, AES Indiana will defer the excess for future recovery.

MISO OPERATIONS 

AES Indiana is one of many transmission system owner members in MISO. MISO is a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy and ancillary services markets in the U.S. MISO policies are developed, in part, through a stakeholder process in which we are an active participant. We focus our participation in this process primarily on items that could impact our customers, shared cost of transmission expansion, resource adequacy, results of operations, financial condition and cash flows. Additionally, we participate in the process to impact MISO and FERC policy by filing comments with MISO, the FERC, or the IURC.

MISO has functional control of our transmission facilities and our transmission operations are integrated with those of MISO. Our participation and authority to sell wholesale power at market-based rates are subject to the FERC jurisdiction. Transmission service over our facilities is provided through MISO’s tariff.

As a member of MISO, we offer our available electricity production of each of our generation assets into the MISO day-ahead and real-time markets. MISO dispatches generation assets in economic order considering transmission constraints and other reliability issues to meet the total demand in the MISO region. MISO settles hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations, generation and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids optimizing for energy and ancillary services products to economically and reliably dispatch the entire MISO system. The IURC has authorized AES Indiana to

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recover its ongoing costs from MISO and such costs are being recovered per specific rate orders. The unamortized balance of total MISO costs deferred as regulatory assets was $30.6 million and $44.6 million as of December 31, 2023 and 2022, respectively.

We have preserved our right to withdraw from MISO by tendering our Notice of Withdrawal (subject to the FERC and the IURC approval). We have made no decision to seek withdrawal from MISO at this time. We will continue to assess the relative costs and benefits of being a MISO member, as well as actively advocate for our positions through the existing MISO stakeholder process and in filings with the FERC or IURC. 

See also Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K for additional details on the regulatory oversight of the FERC and the IURC.

REGULATION

General 

AES Indiana is a regulated public utility principally engaged in providing electric service to the Indianapolis metropolitan area. An inherent business risk facing any regulated public utility is that of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana, as it is elsewhere. We attempt to work cooperatively with regulators and those who participate in the regulatory process, while remaining vigilant in protecting or asserting our legal rights in the regulatory process. We take an active role in addressing regulatory policy issues in the current regulatory environment. Additionally, there is increased activity by environmental regulators, in particular under a President Biden administration, which has had and will continue to have a significant impact on our operations and financial statements for the foreseeable future. We maintain our books and records consistent with GAAP reflecting the impact of regulation. See Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K.

Retail Ratemaking

AES Indiana’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, AES Indiana’s rates include various adjustment mechanisms including, but not limited to:

•a rider to reflect changes in fuel and purchased power costs to meet AES Indiana’s retail load requirements, referred to as the FAC;

•a rider for the timely recovery of costs (including a return) incurred to comply with environmental laws and regulations, referred to as the ECCRA;

•a rider to reflect changes in ongoing MISO costs, referred to as the RTO Adjustment;

•a rider to reflect changes in net capacity sales above and below an established annual benchmark of $11.3 million, referred to as the Capacity Adjustment;

•a rider for passing through to customers wholesale sales margins above and below an established annual benchmark of $16.3 million, referred to as the Off-System Sales Margin Adjustment;

•a rider for the timely recovery of costs (including a return) incurred on investments for eligible TDSIC improvements; and

•cost recovery, lost margin recoveries and performance incentives from our DSM programs.

Each of these tariff rate components may be set and approved by the IURC in separate proceedings at different points in time (currently the FAC proceedings occur on a quarterly basis and AES Indiana's other rider proceedings all occur on an annual basis). These components function somewhat independently of one another, but the overall structure of our rates and charges would be subject to review at the time of any review of our basic rates and charges.

For additional discussion of the regulatory environment related to our business, see the discussion in Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K, which is incorporated by reference herein.

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ENVIRONMENTAL MATTERS

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, suspension or revocation of permits and/or facility shutdowns. There can be no assurance that we have been or will be at all times in full compliance with such laws, regulations and permits.

Where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to us and could require us to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2023.

From time to time, we are subject to enforcement actions for claims of noncompliance with environmental laws and regulations. AES Indiana cannot assure that it will be successful in defending against any claim of noncompliance. However, we do not believe any currently open environmental investigations will result in fines material to our results of operations, financial condition and cash flows.

Under certain environmental laws, we could be held responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held liable for human exposure to hazardous substances or for other environmental damage. Our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, hazardous substances may adversely affect our business, results of operations, financial condition and cash flows. A discussion of the legislative and regulatory initiatives most likely to affect us follows.

MATS

In April 2012, the EPA’s rule to establish maximum achievable control technology standards for hazardous air pollutants regulated under the CAA emitted from coal and oil-fired electric utilities, known as “MATS”, became effective. AES Indiana management developed and implemented a plan, which was approved by the IURC, to comply with this rule and all Petersburg units subject to the rule have been and remain in material compliance with the MATS rule since applicable deadlines.

In June 2015, the U.S. Supreme Court remanded MATS to the D.C. Circuit due to the EPA’s failure to consider costs before deciding to regulate power plants under Section 112 of the CAA and subsequently remanded MATS to the EPA without vacatur. On March 6, 2023, the EPA published a final rule reaffirming its 2016 finding that it is appropriate and necessary to regulate emissions under MATS. On April 24, 2023, EPA published the proposed MATS Risk and Technology Review (RTR) Rule to lower certain emissions limits and revise certain other aspects of MATS. It is too early to predict the outcome of this proposed rule and any potential impact. However, the existing requirements of MATS and the proposed requirements of MATS RTR Rule would not apply to AES Indiana upon conversion of the remaining two coal-fired units at Petersburg to natural gas.

Further rulemakings and/or proceedings are possible; however, in the meantime, MATS remains in effect. We currently cannot predict the outcome of the regulatory or judicial process, or its impact, if any, on our MATS compliance planning or ultimate costs.

Waste Management and CCR

In the course of operations, our facilities generate solid and liquid waste materials requiring eventual disposal or

processing. Waste materials generated at our electric power and distribution facilities include asbestos, CCR, oil,

scrap metal, rubbish, small quantities of industrial hazardous wastes such as spent solvents, tree-and-land-clearing

wastes and polychlorinated biphenyl contaminated liquids and solids. We endeavor to ensure that all our solid and

liquid wastes are disposed of in accordance with applicable national, regional, state and local regulations. With the

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exception of CCR, we have not usually physically disposed of waste materials on our property. Instead, they are usually shipped off-site for final disposal, treatment or recycling. Some of our CCRs have been and/or are currently beneficially used on-site and offsite, including as a raw material for production of wallboard, and concrete or cement, and some are disposed off-site in permitted disposal facilities. A small amount of CCR, which consists of bottom ash, fly ash and air pollution control wastes, is disposed of at our Petersburg coal-fired power generation plant in an engineered, permitted landfill.

The EPA's final CCR rule became effective in October 2015 (the "CCR Rule"). Generally, the rule regulates CCR as

nonhazardous solid waste and establishes national minimum criteria for existing and new CCR landfills and existing and new CCR ash ponds, including location restrictions, design and operating criteria, groundwater monitoring,

corrective action and closure requirements and post-closure care. The 2016 Water Infrastructure Improvements for

the Nation Act ("WIIN Act") includes provisions to implement the CCR rule through a state permitting program, or if the state chooses not to participate, a federal permit program. On February 20, 2020, the EPA published a proposed rule to establish a federal CCR permit program that would operate in states without approved CCR permit programs. If this rule is finalized before Indiana establishes a final state-level CCR permit program, AES Indiana

could eventually be required to apply for a federal CCR permit from the EPA. On December 21, 2022, IDEM

published in the Indiana Register a Second Notice of Comment Period for its proposed CCR rulemaking which would include regulation of CCR through a state permitting program. In 2023, the Indiana legislature passed a law prohibiting IDEM from promulgating a CCR state permitting program that was more stringent than the federal CCR rule or imposed requirements not imposed by the federal CCR rule.

The EPA has indicated that they will implement a phased approach to amending the CCR Rule, which is ongoing. On January 11, 2022, EPA released its first in a series of proposed and final determinations regarding CCR Part A Rule demonstrations and compliance-related letters notifying certain other facilities of their compliance obligations under the federal CCR regulations. On April 8, 2022, petitions for review were filed challenging these EPA actions. The petitions are consolidated in Electric Energy, Inc. v. EPA. While AES Indiana has not received a proposed determination nor a letter, the determinations and letters include interpretations regarding implementation of the CCR Rule. It is too early to determine the impact of these letters or any determinations that may be made.

On May 18, 2023, EPA published a proposed rule that would expand the scope of CCR units regulated by the CCR Rule to include inactive surface impoundments at inactive generating facilities as well as additional inactive and closed landfills and certain other accumulations of CCR. It is too early to predict the outcome of this proposed rule and any potential impact.

The CCR Rule, current or proposed amendments to, or EPA interpretations of, the CCR Rule, Indiana CCR regulations, the results of groundwater monitoring data or the outcome of CCR-related litigation could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting expenditures; however, there is no guarantee we would be successful in this regard. See Note 3, "Property, Plant and Equipment - ARO" and Note 10, "Commitments and Contingencies - Contingencies - Legal Matters - Coal Ash Insurance Litigation" to the Financial Statements of this Annual Report on Form 10-K for further discussion.

Regional Haze Rule

EPA’s 1999 Regional Haze Rule established timelines for states to improve visibility in national parks and wilderness areas throughout the United States by establishing reasonable progress goals toward meeting a national goal of natural visibility conditions in Class I areas by the year 2064 through submittal of a series of state implementation plans (SIPs). Indiana’s SIP for the first planning period (through 2018) did not require any additional controls to be installed or operated on AES Indiana generating facilities. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions. On December 22, 2021, IDEM submitted Indiana's Regional Haze SIP for the Second Implementation Period to EPA for review and approval. The SIP does not include additional requirements for AES Indiana EGUs or for other EGUs in Indiana. However, we cannot predict the possible outcome or potential impacts of this matter at this time. We would seek recovery of capital expenditures; however, there is no guarantee we would be successful.

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Climate Change Legislation and Regulation

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. We face certain risks related to existing and potential international, federal, state, regional and local GHG legislation and regulations,

including risks related to increased capital expenditures or other compliance costs, as well as increased climate change disclosure obligations, which could have a material adverse effect on our results of operations, financial condition and cash flows.

The possible impact of any existing or future international, federal, regional or state GHG legislation, regulations or proposals will depend on various factors, including but not limited to: 

▪The geographic scope of legislation and/or regulation (e.g., international, federal, regional, state), which entities are subject to the legislation and/or regulation (e.g., electricity generators, load-serving entities, electricity deliverers, etc.), the enactment date of the legislation and/or regulation and the compliance deadlines set forth therein;

▪The level of reductions of GHGs being sought by the regulation and/or legislation (e.g., 10%, 20%, 50%, etc.) and the year selected as a baseline for determining the amount or percentage of mandated GHG reduction (e.g., 10% reduction from 1990 emission levels, 20% reduction from 2000 emission levels, etc.);

▪The legislative and/or regulatory structure (e.g., a GHG cap-and-trade program, a carbon tax, GHG emission limits, etc.);

▪In any cap-and-trade program, the mechanism used to determine the price of emission allowances or offsets to be auctioned by designated governmental authorities or representatives;

▪If a cap-and-trade or similar market-based program is enacted, the price of offsets and emission allowances in the secondary market, including any price floors or price caps on the costs of offsets and emission allowances;

▪The operation of and emissions from regulated units;

▪The permissibility of using offsets to meet reduction requirements and the requirements of such offsets (e.g., type of offset projects allowed, the amount of offsets that can be used for compliance purposes, any geographic limitations regarding the origin or location of creditable offset projects), as well as the methods required to determine whether the offsets have resulted in reductions in GHG emissions and that those reductions are permanent (i.e., the verification method);

▪Whether the use of proceeds of any auction conducted by responsible governmental authorities is reinvested in developing new energy technologies, is used to offset any cost impact on certain energy consumers or is used to address issues unrelated to power;

▪How the price of electricity is determined, including whether the price includes any costs resulting from any new climate change legislation and the potential to transfer compliance costs pursuant to legislation, market or contract, to other parties;

▪Any impact on fuel demand and volatility that may affect the market clearing price for power;

▪The effects of any legislation or regulation on the operation of power generation facilities that may in turn affect reliability;

▪The availability and cost of carbon control technology;

▪The impact of any laws and regulations, supply or cost of fuels used by our generation facilities, including coal, natural gas or oil;

▪Whether any federal legislation regulating GHG emissions will preclude the EPA from regulating GHG emissions under the CAA or preempt private nuisance suits or other litigation by third parties;

▪Any opportunities to change the use of fuel at the generation facilities or opportunities to increase efficiency;

▪The extent of any required GHG emissions disclosure requirements in the forthcoming final version of the SEC's proposed 2022 climate change disclosure rule, including potential disclosure of Scope 1-3 GHG emissions; and

▪Our ability to recover any resulting costs from our customers and the timing of such recovery.

Except as noted in the discussion below, at this time, we cannot estimate the costs of compliance with existing,

proposed or potential international, federal, state or regional GHG emissions reductions legislation or initiatives due

in part to the fact that many of these proposals are in earlier stages of development and any final laws or

regulations, if adopted, could vary drastically from current proposals. Any international, federal, state or regional

legislation adopted in the U.S. that would require the reduction of GHG emissions could have a material adverse effect on our business and/or results of operations, financial condition and cash flows.

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In the past, the U.S. Congress has considered several different draft bills pertaining to GHG legislation, including comprehensive GHG legislation that would impact many industries and more limited legislation focusing only on the

utility and electric generation industry. Although no legislation pertaining to GHG emissions has been passed to date

by the U.S. Congress, similar legislation may be considered or passed by the U.S. Congress in the future. In

addition, in the past Midwestern state governors (including the Governor of Indiana) and the premier of Manitoba,

Canada committed to reduce GHG emissions through the implementation of a cap-and-trade program pursuant to

the Midwestern Greenhouse Gas Reduction Accord. Though the participating states and province are no longer

pursuing this commitment, similar applicable state or regional initiatives may be pursued in the future.

The final NSPS for CO2 emissions from new, modified and reconstructed fossil-fuel-fired power plants were published in the Federal Register on October 23, 2015. Several states and industry groups challenged the NSPS for CO2 in the D.C. Circuit Court. On December 20, 2018, the EPA published proposed revisions to the final NSPS for new, modified and reconstructed coal-fired electric utility steam generating units. The EPA proposed that the Best System of Emissions Reduction (BSER) for these units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and sub-critical steam conditions for smaller units, and not partial carbon capture and sequestration (CCS), which had been the BSER for these units in the 2015 final NSPS. The EPA did not include revisions for natural-gas combined cycle or simple cycle units in the December 20, 2018 proposal. Challenges to the GHG NSPS remain held in abeyance at this time. On May 23, 2023, EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023.

On July 8, 2019, the EPA published the final ACE Rule which would have established CO2 emission rules for existing coal-fired power plants under CAA Section 111(d) and would have replaced the EPA's 2015 CPP, which among other things, had called on states to mandate that power companies shift electricity generation to lower or zero carbon fuel sources. However, on January 19, 2021, the D.C. Circuit vacated and remanded to EPA the ACE Rule. Subsequently, on June 30, 2022, the U.S. Supreme Court reversed the judgment of the D.C. Circuit Court and

remanded for further proceedings consistent with its opinion, holding that the “generation shifting” approach in the CPP exceeded the authority granted to EPA by Congress under Section 111(d) of the CAA. As a result of the June 30, 2022 U.S. Supreme Court decision, on October 27, 2022, the D.C. Circuit issued a partial mandate holding pending challenges to the ACE Rule in abeyance while EPA developed a replacement rule.

On May 23, 2023, EPA published a proposed rule that would vacate the ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing EGUs and would require states to develop State Plans that establish standards of performance for such EGUs that are at least as stringent as EPA’s emissions guidelines. Depending on various EGU-specific factors, the bases of proposed emissions guidelines range from routine methods of operations to carbon capture and sequestration or co-firing low-GHG hydrogen starting in the 2030s.

Due to the uncertainty of these regulations, and existing and potential associated litigation, it is too early to determine the potential impact, but any rule could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard.

On the international level, on December 12, 2015, 195 nations, including the U.S., finalized the text of an

international climate change accord in Paris, France (the “Paris Agreement”), which agreement was signed and

officially entered into on April 22, 2016. The Paris Agreement calls for countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG emissions targets. A long-term goal of the

Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the

pre-industrial era. The U.S. withdrawal from the Paris Agreement became effective on November 4, 2020. However,

on January 20, 2021, President Biden signed and submitted an instrument for the U.S. to rejoin the Paris Agreement, which became effective on February 19, 2021. In November 2023, the international community

gathered for the 28th Conference to the Parties on the UN Framework Convention on Climate Change (“COP28”). The Parties agreed to non-binding language calling on countries to transition away from fossil fuels in energy systems to achieve net zero emissions by 2050.

Based on the above, there is some uncertainty with respect to the impact of GHG rules on AES Indiana. The EPA, states and other utilities are still evaluating potential impacts of the GHG regulations in our industry. In light of these uncertainties, we cannot predict the impact of the EPA’s current and future GHG regulations on our consolidated results of operations, cash flows, and financial condition, but it could be material.

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Unit Retirements and Replacement Generation

In December 2019, AES Indiana filed its 2019 IRP, which included plans to retire approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023. AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. For further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K.

NSR and Other CAA NOVs

See Note 10, “Commitments and Contingencies - Contingencies - Environmental Matters - NSR and other CAA NOVs” to the Financial Statements of this Annual Report on Form 10-K for additional details.

NAAQS

Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO2, which result from fossil-fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS, which may include imposing operating limits on individual plants. The EPA is required to review NAAQS at five-year intervals.

Ozone.  In October 2015, the EPA published a final rule lowering the NAAQS for ozone to 70 parts per billion from 75 parts per billion. The EPA published its final designations for the areas in which our operations are located on November 16, 2017. None of our operations are located in areas designated as nonattainment.

In March 2018, the state of New York submitted a petition to the EPA pursuant to Section 126 of the CAA requesting new limitations on NOx emissions from dozens of upwind generating stations, including AES Indiana's Petersburg, Harding Street, and Eagle Valley stations on the basis that they are contributing significantly to New York’s ability to meet the 2008 ozone NAAQS. On July 14, 2020, the D.C. Circuit Court vacated and remanded EPA’s denial of the petition. EPA must now issue a new decision based on the Court’s decision. If the Section 126 petition is ultimately granted, our units could be subject to additional requirements, which could be material. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful.

Fine Particulate Matter.  In 2013, the EPA published the 2012 annual PM2.5 standard of 12 micrograms per cubic meter of air and the 24-hour PM2.5 standard of 35 micrograms per cubic meter of air. In 2015, the EPA published its final attainment designations for the 2012 PM2.5 standard. In addition to the PM2.5 standard, there is also a 24-hour PM10 standard of 150 micrograms per cubic meter of air. No AES Indiana operations are currently located in nonattainment areas. On January 27, 2023, the EPA published a proposed rule to lower the primary annual PM2.5 NAAQS from 12 micrograms per cubic meter to a level between 9 and 10 micrograms per cubic meter and to maintain other PM NAAQS at current levels. On February 7, 2024, EPA released a final rule lowering the primary annual PM2.5 NAAQS from 12 micrograms per cubic meter to 9 micrograms per cubic meter.

SO2. In 2010, a new one-hour SO2 primary NAAQS became effective. In 2015, IDEM published its final rule establishing reduced SO2 limits for AES Indiana facilities in accordance with the 2010 one-hour standard with compliance required by January 1, 2017. Improvements to the existing FGD systems at Petersburg station were required to meet the emission limits imposed by the rule. All areas in which AES Indiana operates have been subsequently redesignated and are no longer designated as nonattainment.

Based on these current and potential national ambient air quality standards, the state of Indiana is required to determine whether certain areas within the state meet the NAAQS. With respect to Marion, Morgan and Pike Counties, as well as any other areas determined to be in "nonattainment," the state of Indiana will be required to modify its SIP to detail how the state will regain its attainment status. As part of this process, it is possible that the

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IDEM or the EPA may require reductions of emissions from our generating stations to reach attainment status for ozone, fine particulate matter or SO2. At this time, we cannot predict what the impact will be to AES Indiana with respect to new ambient standards, but it could be material.

CSAPR and 2015 Ozone NAAQS FIP

CSAPR, which became effective in January 2015, addresses the "good neighbor" provision of the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment, or interference with maintenance of, any NAAQS. CSAPR is implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of emissions allowances created by the EPA. In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS (“CSAPR Update Rule”). Following legal challenges related to the CSAPR Update Rule, on April 30, 2021, EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected EGUs within certain states (including Indiana) to participate in a new trading program, the CSAPR NOx Ozone Season Group 3 trading program. These affected EGUs received fewer NOx Ozone Season allowances beginning in 2021.

On June 5, 2023, the EPA published a final Federal Implementation Plan ("FIP") to address air quality impacts with respect to the 2015 Ozone NAAQS. The rule established a revised CSAPR NOx Ozone Season Group 3 trading program for 22 states, including Indiana and became effective during 2023. The FIP also includes enhancements in the revised Group 3 trading program which include a dynamic budget setting process beginning in 2026, annual recalibration of the allowance bank to reflect changes to affected sources, a daily backstop emissions rate limit for certain coal-fired electric generating units beginning in 2024, and a secondary emissions limit prohibiting certain emissions associated with state assurance levels.

At this time we cannot predict the impact of these rule revisions or potential future legal outcomes, but any such impact could include the need to purchase additional allowances or make operational adjustments or could otherwise be material to our business, financial condition or results of operation.

CWA – Facility Response Plan

On March 28, 2022, the EPA published a proposed rule to establish Facility Response Plan (“FRP”) requirements for non-transportation onshore facilities that store CWA hazardous substances and meet certain criteria and thresholds. It is too early to determine whether this proposed rule may have a material impact on our business, financial condition or results of operation.

CWA - Environmental Wastewater Requirements and Regulation of Water Discharge

In November 2015, the EPA published its final Steam ELG rule to reduce toxic pollutants discharged into waterways by steam-electric power plants through technology applications. In 2020, EPA issued a final rule, known as the 2020 Reconsideration Rule, revising certain aspects of the 2015 ELG rule. Wastewater treatment technologies already installed and operated at Petersburg met the requirements of these rules. Following the 2019 U.S. Court of Appeals vacatur and remand of portions of the 2015 ELG rule related to leachate and legacy water, on March 29, 2023, EPA published a proposed rule revising the 2020 Reconsideration Rule. The proposed rule would establish new best available technology economically achievable effluent limits for flue gas desulfurization wastewater, bottom ash treatment water, and combustion residual leachate. It is too early to determine whether any outcome of this proposed rule, litigation or current or future revisions to the ELG rule might have a material impact on our business, financial condition and results of operations.

On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of "functional equivalent" are ongoing in various jurisdictions. On November 27, 2023, EPA issued a draft guidance addressing how the Supreme Court decision would be applied to the NPDES permit program as it relates to functional equivalent discharge. It is too early to determine whether the U.S. Supreme Court decision,

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implementation thereof, or the result of litigation related to "functional equivalent" determination may have a material impact on our business, financial condition or results of operations.

The concept of WOTUS defines the geographic reach and authority of the U.S. Army Corps of Engineers and EPA (together, the "Agencies") to regulate streams, wetlands, and other water bodies under the CWA. There have been multiple Supreme Court decisions and dueling regulatory definitions over the past several years concerning the appropriate standard for how to properly determine whether a wetland or stream that is not navigable is considered a WOTUS. On May 25, 2023, the U.S. Supreme Court rendered a decision (Decision) in the case of Sackett v. Environmental Protection Agency, addressing the definition of WOTUS with regards to the CWA. This decision provides a standard that substantially restricts the Agencies' ability to regulate certain types of wetlands and streams. Specifically, under this decision, wetlands that do not have a continuous surface connection with traditional interstate navigable water are not considered a WOTUS and therefore are not federally jurisdictional.

On September 8, 2023, the Agencies published final amendments to the “Revised Definition of ‘Waters of the United States’” rule. These final rule amendments conform the definition of WOTUS to the definition adopted in the Decision. The Agencies have amended key aspects of the regulatory text to conform the rule to the Decision.

It is too early to determine whether any outcome of litigation or current or future revisions to rules interpreting federal jurisdiction over WOTUS might have a material adverse effect on our results of operations, financial condition and cash flows.

CWA - Cooling Water Intake Regulations

We use water as a coolant at our generating stations. Under the CWA, cooling water intake structures are required to reflect the BTA for minimizing adverse environmental impact. In 2014, the EPA's final standards became effective to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other facilities. These standards, based on Section 316(b) of the CWA, require affected facilities to choose amongst seven BTA options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers) or other technology. Finally, the standards require that new units added to an existing facility must reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards. AES Indiana’s NPDES permits as described below will be updated with the requirements of this rule, including any source-specific requirements arising from the evaluation process described above. At this time it is not yet possible to predict the total impacts of this final rule, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material. We would seek recovery of these capital expenditures; however, there is no guarantee we would be successful.

CWA – NPDES Permits

National Pollutant Discharge Elimination System (NPDES) permits regulate specific industrial wastewater and storm water discharges to the waters of Indiana under Section 402 of the Federal Water Pollution Control Act. A number of CWA regulations described above are implemented through NPDES permits.

In 2017, IDEM issued to Eagle Valley a NPDES permit regulating water discharges associated with operation of its CCGT. As part of the normal course of business, AES Indiana submitted a timely application for renewal for the Eagle Valley NPDES permit, and on March 31, 2023, IDEM issued the renewed NPDES permit. On April 17, 2023, a third party filed an appeal of Eagle Valley’s renewed NPDES permit. AES Indiana contends that the renewed permit was validly issued, and the permit remains in effect. AES Indiana is unable to predict the outcome of the appeal, but depending on the results, it could have an adverse effect on the Company.

In 2017, IDEM also issued to Harding Street and Petersburg NPDES permits regulating water discharges associated with operation of their power plant operations. As part of the normal course of business, AES Indiana submitted timely applications for renewal for both Harding Street and Petersburg NPDES permits in March 2022. On November 29, 2023, IDEM issued the final NPDES permit renewal for Harding Street with an effective date of January 1, 2024. The permit includes a 316(b) determination requiring the installation of modified traveling screens and fish handling return system and an entrainment study. The permit also includes other new requirements,

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including new thermal limitations, that could result in the need for AES Indiana to take additional actions to ensure compliance with the final permit. On December 14, 2023, AES Indiana filed a petition for appeal of certain new requirements, including the new thermal limitations, in the final Harding Street NPDES permit. A stay of the appealed requirements was granted on January 4, 2024, and is in effect until April 15, 2024, which could be further extended. It is too early to determine the potential impact, but final or future permits could have a material impact on our business, financial condition and results of operations. We would seek recovery of any resulting capital expenditures; however, there is no guarantee we would be successful in this regard. The renewal application for the Petersburg NPDES permit remains pending.

ENERGY SUPPLY

Total electricity sold to our retail customers in 2023 came from the following sources: 58.3% from AES Indiana-owned natural gas-fired units, 30.6% from AES Indiana-owned coal-fired steam generation, and 11.1% from power purchased under power purchase agreements (primarily wind and solar) and from the wholesale power market.

Natural gas accounted for approximately 64% of the total kWh we generated in 2023, as compared to 42% in 2022 and 28% in 2021. Natural gas is used in our steam boiler units at Harding Street Station, our CCGT at Eagle Valley and combustion turbines at Georgetown. AES Indiana sources natural gas from the wholesale market delivered to our plants by interstate pipeline and local distribution companies. AES Indiana holds firm pipeline transportation commitments on Texas Gas Transmission, Rockies Express Pipeline, LLC, Trunkline Gas Company, LLC, Panhandle Eastern Pipeline Company, and has firm redelivery contracts with the local distribution companies that serve AES Indiana plants. AES Indiana has established physical natural gas hedges for firm supply over a two year period in accordance with a hedge program approved by the IURC. Hedge percentages vary by season with winter the highest percentage of coverage. Eagle Valley returned from an extended outage in March of 2022 and the hedge program was initiated after the return date. We have natural gas inventory related to a storage agreement with Citizens Energy Group which provides natural gas supply to Harding Street Station.

Coal and fuel oil provided the remaining kWh generation in 2023. Approximately 36% of the total kWh we generated in 2023 was from coal as compared to approximately 58% and 72% in 2022 and 2021, respectively. In 2021 and early in 2022, coal was a higher percentage of kWh generated due to an extended outage at the Eagle Valley CCGT plant, and we expect this percentage to be lower going forward. Additionally, AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP” to the Financial Statements of this Annual Report on Form 10-K). Our existing coal contracts provide for approximately 100% of our current projected requirements in 2024 and approximately 83% in total for the two-year period ending December 31, 2025. We have long-term coal contracts with one supplier. Pricing provisions in some of our long-term coal contracts allow for price changes under certain circumstances. Substantially all of our coal is currently mined in the state of Indiana, and all of our coal supply is mined by unaffiliated suppliers or third parties. Our goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. Our present inventory is above our target range. Fuel oil accounted for less than 1% of the total kWh we generated in 2023, 2022, and 2021, and is used for start-up and flame stabilization in coal-fired generating units, as primary fuel in two older combustion turbines, and as an alternate fuel in two other combustion turbines.

As a result of the completion of the CCGT at the Eagle Valley Station in 2018, the Harding Street Station refueling projects in 2015 and 2016, the retirement of coal-fired units at Eagle Valley in 2016, and the 2021, 2023 and future retirement of coal-fired units at Petersburg, we generally have experienced and expect to continue to experience an increase in the percentage of generation from natural gas and renewable projects. Due to outages at the Eagle Valley CCGT this was not the case in 2021 and early 2022, however we expect to continue experiencing an increase in the percentage of generation from natural gas and renewable projects going forward. The generation fuel mix from coal and natural gas will continue to change as the relative prices of the commodities change and as our generation portfolio changes.

See Note 2 “Regulatory Matters - IRP Filings and Replacement Generation” to the Financial Statements of this Annual Report on Form 10-K for further discussion of AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years, including the acquisition and development of the Hardy Hills Solar Project and Petersburg Energy Center Project, the development of the Pike County BESS Project, acquisition of the Hoosier Wind Project, and the conversion of the remaining two coal units at Petersburg to natural gas.

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Additionally, we meet the electricity demands of our retail customers with energy purchased under power purchase agreements and by power purchases in MISO. We are currently committed under long-term power purchase agreements to purchase all energy from two wind projects that have a combined maximum output capacity of 300 MW, including the Hoosier Wind Project. AES Indiana received IURC approval for the acquisition of the Hoosier Wind Project in January 2024 (see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation - Hoosier Wind Project” to the Financial Statements of this Annual Report on Form 10-K). We have 94.5 MW of solar-generated electricity in our service territory under long-term contracts, of which 94.0 MW was in operation as of December 31, 2023. We also purchase up to 8 MW of energy from a combined heat and power facility located in Indianapolis, Indiana.

AES Indiana retired Petersburg Unit 1 in May 2021 and Petersburg Unit 2 in June 2023. In addition, AES Indiana’s most recent 2022 IRP short-term action plan includes the conversion of Petersburg Units 3 and 4 from coal to gas as part of AES Indiana’s preferred portfolio. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024.

After the conversion of Petersburg Units 3 and 4 from coal to natural gas, we will no longer have any coal fired generation in our generation portfolio. Upon the completion of our various renewable projects (e.g., Hardy Hills Solar Project, Petersburg Energy Center Project, Pike County BESS Project, Hoosier Wind Project, etc.) and the Petersburg unit conversions, we expect our installed capacity to be approximately 74% from AES Indiana-owned natural gas-fired units, 16% from AES Indiana-owned renewable projects, and 10% from wind and solar power purchase agreements.

STATISTICAL INFORMATION ON OPERATIONS

The following table of statistical information presents additional data on our operations:

	Years Ended December 31,
	2023		2022		2021		2020		2019
Revenue (In Thousands):
Residential	$	668,209	$	698,648	$	607,260	$	575,329	$	597,809
Small commercial and industrial	238,595		247,884		212,169		194,904		215,878
Large commercial and industrial	635,221		644,181		541,471		500,208		564,216
Public lighting	10,013		9,784		8,994		9,257		7,335
Other(1)	24,615		17,845		16,785		14,402		14,136
Retail electric revenue	1,576,653		1,618,342		1,386,679		1,294,100		1,399,374
Wholesale	56,557		148,517		25,059		46,482		68,474
Miscellaneous	16,707		24,852		14,394		12,403		13,795
Total revenue	$	1,649,917	$	1,791,711	$	1,426,132	$	1,352,985	$	1,481,643
kWh Sales (In Millions):
Residential	4,800		5,305		5,172		5,115		5,200
Small commercial and industrial	1,722		1,823		1,774		1,709		1,840
Large commercial and industrial	5,929		6,091		6,006		5,839		6,283
Public lighting	19		18		21		30		42
Sales – retail customers	12,470		13,237		12,973		12,693		13,365
Wholesale	1,657		2,148		908		1,866		2,718
Total kWh sold	14,127		15,385		13,881		14,559		16,083
Retail Customers at End of Year:
Residential	462,848		458,585		455,756		451,735		448,210
Small commercial and industrial	54,998		55,210		55,078		54,253		53,751
Large commercial and industrial	4,456		4,517		4,506		4,567		4,635
Public lighting	1,093		1,007		983		986		980
Total retail customers	523,395		519,319		516,323		511,541		507,576
(1) Other retail revenue includes miscellaneous charges to customers.

HOW TO CONTACT IPALCO AND SOURCES OF OTHER INFORMATION

Our principal executive offices are located at One Monument Circle, Indianapolis, Indiana 46204, and our telephone number is (317) 261-8261. Our website address is www.aesindiana.com. The information on our website is not

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incorporated by reference into this report. The SEC maintains an internet website that contains this report and other information that we file electronically with the SEC at www.sec.gov.

ITEM 1A. RISK FACTORS

Investors should consider carefully the following risk factors that could cause our business, operating results and financial condition to be materially adversely affected. We routinely encounter and address risks, some of which may cause our future results to be materially different than we presently anticipate. New risks may emerge at any time, and we cannot predict those risks or estimate the extent to which they may affect our business or financial performance. The categories of risk we have identified in "Item 1A. Risk Factors" include risks associated with our operations, governmental regulation and laws, our indebtedness and financial condition. These risk factors should be read in conjunction with the other detailed information concerning IPALCO and AES Indiana set forth in the Notes to the Financial Statements and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K herein. The risks and uncertainties described below are not the only ones we face.

RISKS ASSOCIATED WITH OUR OPERATIONS

Our electric generating facilities are subject to operational risks that at times result in unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased fuel or purchased power costs and other liabilities, and these liabilities could become significant for which we may not have adequate insurance coverage.

We operate generating facilities, including those using coal, oil, natural gas, and renewable energy, which involve certain risks that can adversely affect energy costs, output and efficiency levels. These risks include:

•unit or facility shutdowns due to a breakdown or failure of equipment or processes;

•increased prices for fuel and fuel transportation as existing contracts expire or as such contracts are adjusted through price re-opener provisions or automatic adjustments;  

•disruptions in the availability or delivery of fuel and lack of adequate inventories;

•shortages of or delays in obtaining equipment;

•loss of cost-effective disposal options for solid waste generated by the facilities;

•accidents and injuries;

•reliability of our suppliers;

•inability to comply with regulatory or permit requirements;

•operational restrictions resulting from environmental or permit limitations or governmental interventions;

•construction delays and cost overruns;

•disruptions in the delivery of electricity;

•labor disputes or work stoppages by employees;

•the availability of qualified personnel;

•events occurring on third party systems that interconnect to and affect our system;

•operator error; and

•catastrophic events.

We experience unscheduled plant outages, unanticipated operation and/or maintenance expenses, increased capital expenditures and/or increased fuel and purchased power costs from time to time, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. These risks are partially mitigated by our ability to generally pass fuel and purchased power costs through to customers through the FAC. If unexpected plant outages occur frequently and/or for extended periods of time, this could result in adverse regulatory action that may have a significant impact on our results of operations, financial condition and cash flows.

Additionally, as a result of the above risks and other potential hazards associated with the power generation industry, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. The control and management of these risks depend upon adequate development and training of personnel and on the existence of operational procedures, preventative maintenance plans and specific programs supported by quality control systems which reduce, but do not eliminate, the possibility of the occurrence and impact of these risks.

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The hazardous activities described above can also cause personal injury or loss of life, damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events results in us from time to time being named as a defendant in lawsuits asserting claims for damages, environmental cleanup costs, personal injury and fines and/or penalties. We maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. A successful claim that is significant for which we are not fully insured could adversely and materially affect our results of operations, financial condition and cash flows. In addition, except for our large substations, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of property insurance. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide assurance that insurance coverage will continue to be available on terms similar to those presently available to us or at all. Any such losses not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

We may be negatively affected by a lack of growth or a decline in the number of customers or in customer usage.

Customer growth and customer usage are affected by a number of factors outside our control, such as energy efficiency and DSM measures, population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. A significant lack of growth, or a decline, in the number of customers in our service territory or in customer demand for electricity could have a material adverse effect on our results of operations, financial condition and cash flows and may cause us to fail to fully realize anticipated benefits from investments and expenditures.

The cost of fuel and other commodities have experienced and could continue to experience volatility and we may not be able to hedge the entire exposure of our operations from availability and price volatility. In addition, until our coal units are converted or retired, a portion of our electricity is generated by coal.

Our business is sensitive to changes in the price of natural gas, coal, purchased power and emissions allowances. In addition, changes in the prices of steel, copper and other raw materials can have a significant impact on our costs. We also are dependent on purchased power, in part, to meet our seasonal planning reserve margins. Any changes in fuel prices could affect the prices we charge, our operating costs and our competitive position with respect to our products and services. The cost of fuel and other commodities has been volatile in recent years and we expect that volatility to continue.

Our exposure to fluctuations in the price of fuel is limited because, pursuant to Indiana law, we apply to the IURC for a change in our FAC every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates and charges. In addition, we apply to recover the energy portion of our purchased power costs in these quarterly FAC proceedings subject to a benchmark (please see Note 2, “Regulatory Matters – FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements of this Annual Report on Form 10-K for additional details regarding the benchmark and the process to recover fuel costs). As part of this cost-recovery process, we must present evidence in each proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible. If we are unable to timely or fully recover our fuel and purchased power costs, it could have a material adverse effect on our results of operations, financial condition and cash flows.  

Approximately 36% of the energy we produced in 2023 was generated by coal as compared to approximately 58% and 72% in 2022 and 2021, respectively. While we have approximately 83% in total of our current coal requirements for the two-year period ending December 31, 2025 under long-term contracts as of the date of this report, the balance is yet to be purchased and will be purchased under a combination of long-term contracts, short-term contracts and on the spot market. Prices can be highly volatile in both the short-term market and on the spot market. The coal market has experienced price volatility in the last several years. We are now in a global market for coal in which our domestic price is increasingly affected by international supply disruptions and demand balance. Coal exports from the U.S. have increased significantly at times in recent years. In addition, domestic developments such as government-imposed direct costs and permitting issues that affect mining costs and supply availability, and the variable demand of retail customer load and the performance of our generation fleet have an impact on our fuel procurement operations. In addition, pricing provisions in some of our coal contracts with terms of one year or more allow for price changes under certain circumstances.

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Because of our dependence on coal to meet customer demand for electricity, our business and operations could be materially adversely affected by unexpected price volatility in the coal market, price increases pursuant to the provisions of certain of our long-term coal contracts, and the continued regulatory and political scrutiny of coal. As discussed below, regulators, politicians and non-governmental organizations have expressed concern about GHG emissions and are taking actions which, in addition to the potential physical risk associated with climate change, could have a material adverse impact on our results of operations, financial condition and cash flows. Our dependence on coal also means that the output of our coal-fired generation units can be greatly affected by the costs of other fuels combusted by generation facilities that compete with our coal-fired generation units. Until 2021, natural gas prices over the last several years have been relatively low and some gas-fired generators that previously were primarily used during periods of peak and intermediate electric demand have run even during periods of relatively low demand. This can cause many coal-fired generators, including ours, to run fewer hours during these periods of base-load demand. The cyclical nature of commodity markets makes this a possibility in the future, however, we would expect any retirement of our coal-fired generators to reduce the potential impact of these events due to lower volumes of coal in our generation fleet.

In addition, substantially all of our coal supply is currently mined in the state of Indiana, and all of our coal supply is currently mined by unaffiliated suppliers or third parties. Our current goal is to carry a 25-50 day system supply of coal to offset unforeseen occurrences such as equipment breakdowns and transportation or mine delays. AES Indiana typically has long-term contracts with a small number of suppliers of coal. In recent years, the coal industry has undergone significant restructuring as a result of debt restructurings, bankruptcy proceedings and other factors. Further restructuring may result in a failure of our suppliers to fulfill their contractual obligations or fewer suppliers and, consequently, increased dependency on any one supplier. Any significant disruption in the ability of our suppliers, particularly our most significant suppliers, to mine or deliver coal or other fuel, or any failure on the part of our suppliers to fulfill their contractual obligations could have a material adverse effect on our business. In the event of disruptions or failures, there can be no assurance that we would be able to find another supplier of fuel on similarly favorable terms, which could also limit our ability to recover fuel costs through the FAC proceedings.

Catastrophic events could adversely affect our facilities, systems and operations.

Catastrophic events such as fires, explosions, cyber-attacks, terrorist acts, acts of war, acts of sabotage or vandalism, pandemic events, or natural disasters such as floods, earthquakes, tornadoes, severe winds, ice or snow storms, droughts or other similar occurrences could adversely affect our generation facilities, transmission and distribution systems, results of operations, financial condition and cash flows. Our Petersburg Plant, which is our largest source of generating capacity, is located in the Wabash Valley seismic zone, adjacent to the New Madrid seismic zone, which are both areas of significant seismic activity in the central U.S.

Our business is sensitive to weather and seasonal variations.

Weather conditions significantly affect the demand for electric power, and accordingly, our business is affected by variations in general weather conditions and unusually severe weather. As a result of these factors, our operating revenue and associated operating expenses are not generated evenly by month during the year. We forecast electric sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather (such as warmer winters and cooler summers) could have a material impact on our revenue, operating income and net income and cash flows. In addition, severe or unusual weather, such as floods, tornadoes and ice or snow storms, may cause outages and property damage that may require us to incur additional costs that may not be insured or recoverable from customers. While we are permitted to seek recovery of certain severe storm damage costs, if we are unable to fully recover such costs in a timely manner, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Our membership in a RTO presents risks that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are a member of MISO, a FERC-regulated RTO. MISO serves the electrical transmission needs of a 15-state area including much of the Mid-U.S. and Canada and maintains functional operational control over our electric transmission facilities, as well as that of the other utility members of MISO. We retain control over our distribution facilities. As a result of membership in MISO and its operational control, our continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. We offer our generation and bid our load into this market on a day-ahead basis and settle differences in real time. Given the

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nature of MISO’s policies regarding use of transmission facilities, and its administration of the energy and ancillary services markets, it is difficult to predict near-term operational impacts. We cannot assure MISO’s reliable operation of the regional transmission system, or the impact of its operation of the energy and ancillary services markets.

The rules governing the various regional power markets may also change from time to time which could affect our costs and revenue and have a material adverse effect on our results of operations, financial condition and cash flows. We may expand or otherwise change our transmission system according to decisions made by MISO in addition to our internal planning process. In addition, various proposals and proceedings before the FERC relating to MISO or otherwise may cause transmission rates to change from time to time. We also incur fees and costs to participate in MISO.

To the extent that we rely, at least in part, on the performance of MISO to maintain the reliability of our transmission system, it puts us at some risk for the performance of MISO. In addition, actions taken by MISO to secure the reliable operation of the entire transmission system operated by MISO could result in voltage reductions, rolling blackouts, or sustained system-wide blackouts on AES Indiana’s transmission and distribution system, any of which could have a material adverse effect on our results of operations, financial condition and cash flows. See also “Item 1. Business - MISO Operations" and “Item 1. Business - Regulation – Retail Ratemaking.”

Our transmission and distribution system is subject to operational, reliability and capacity risks.

The ongoing reliable performance of our transmission and distribution system is subject to risks due to, among other things, weather damage, intentional or unintentional damage, equipment or process failure, catastrophic events, such as fires and/or explosions, facility outages, labor disputes, accidents or injuries, operator error, or inoperability of key infrastructure internal or external to us and events occurring on third party systems that interconnect to and affect our system. The failure of our transmission and distribution system to fully operate and deliver the energy demanded by customers could have a material adverse effect on our results of operations, financial condition and cash flows, and if such failures occur frequently and/or for extended periods of time, could result in adverse regulatory action. In addition, the advent and quick adaptation of new products and services that require increased levels of electrical energy cannot be predicted and could result in insufficient transmission and distribution system capacity. As with all utilities, potential concern with the adequacy of transmission capacity on AES Indiana’s system or the regional systems operated by MISO could result in MISO, the NERC, the FERC or the IURC requiring us to upgrade or expand our transmission system through additional capital expenditures or share in the costs of regional expansion. Also, as a result of the above risks and other potential risks and hazards associated with transmission and distribution operations, we may from time to time become exposed to significant liabilities for which we may not have adequate insurance coverage. Except for AES Indiana’s large substations, transmission and distribution assets are not covered by insurance and are considered to be outside the scope of property insurance. Otherwise, we maintain an amount of insurance protection that we believe is adequate, but there can be no assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Further, any increased costs or adverse changes in the insurance markets may cause delays or inability in maintaining insurance coverage on terms similar to those presently available to us or at all. A successful claim for which we are not fully insured could have an adverse impact on our results of operations, financial condition and cash flows.

Current and future conditions in the economy may adversely affect our customers, suppliers and other counterparties in a way which could materially and adversely affect our results of operations, financial condition and cash flows.

Our business, results of operations, financial condition and cash flows have been and will continue to be affected by general economic conditions. Slowing economic growth, credit market conditions, fluctuating consumer and business confidence, fluctuating commodity prices, and other challenges affecting the general economy, have caused and may continue to cause some of our customers to experience deterioration of their businesses, cash flow shortages, and difficulty obtaining financing. As a result, existing customers may reduce their electricity consumption and may not be able to fulfill their payment obligations to us in the normal, timely fashion. In addition, some existing commercial and industrial customers may discontinue their operations. Sustained downturns, recessions or a sluggish economy generally affect the markets in which we operate and negatively influence our energy operations. A contracting, slow or sluggish economy could reduce the demand for energy in areas in which we are doing business. For example, during economic downturns, our commercial and industrial customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of energy they require. Furthermore, projects which may result in potential new customers may be delayed until economic

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conditions improve. Some of our suppliers, customers and other counterparties, and others with whom we transact business experience financial difficulties, which may impact their ability to fulfill their obligations to us. For example, our counterparties on forward purchase contracts and financial institutions involved in our credit facility may become unable to fulfill their contractual obligations to us or result in their declaring bankruptcy or similar insolvency-like proceedings. We may not be able to enter into replacement agreements on terms as favorable as our existing agreements. Reduced demand for our electric services, failure by our customers to timely remit full payment owed to us and supply delays or unavailability could have a material adverse effect on our results of operations, financial condition and cash flows. In particular, the projected economic growth and total employment in Indianapolis are important to the realization of our forecasts for annual energy sales.

Economic conditions relating to the asset performance and interest rates of the Pension Plans could materially and adversely impact our results of operations, financial condition and cash flows.

Pension costs are based upon a number of actuarial assumptions, including an expected long-term rate of return on pension plan assets, level of employer contributions, the expected life span of pension plan beneficiaries and the discount rate used to determine the present value of future pension obligations. Any of these assumptions could prove to be wrong, resulting in a shortfall of our Pension Plans’ assets compared to pension obligations under the Pension Plans. Further, the performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations under the Pension Plans. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the Pension Plans’ assets will increase the funding requirements under the Pension Plans if the actual asset returns do not recover these declines in value in the foreseeable future. Future pension funding requirements, and the timing of funding payments, may also be subject to changes in legislation. We are responsible for funding any shortfall of our Pension Plans’ assets compared to obligations under the Pension Plans, and a significant increase in our pension liabilities could materially and adversely impact our results of operations, financial condition, and cash flows. We are subject to the Pension Protection Act of 2006, which requires underfunded pension plans to improve their funding ratios within prescribed intervals based on the level of their underfunding. As a result, our required contributions to these plans, at times, have increased and may increase in the future. In addition, our pension and postemployment benefit plan liabilities are sensitive to changes in interest rates. If interest rates decrease, the discounted liabilities increase benefit expense and funding requirements. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements for the obligations related to the pension and other postemployment benefit plans. Declines in market values and increased funding requirements could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 8, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for further discussion.

Counterparties providing materials or services may fail to perform their obligations, which could materially and adversely impact our results of operations, financial condition and cash flows.

We enter into transactions with and rely on many counterparties in connection with our business, including for the purchase and delivery of inventory, including fuel and equipment components, for our capital improvements and additions and to provide professional services, such as actuarial calculations, payroll processing and various consulting services. If any of these counterparties fails to perform its obligations to us or becomes unavailable, our business plans may be materially disrupted, we may be forced to discontinue or delay certain operations if a cost-effective alternative is not readily available or we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and cause delays. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than the relief provided by these mitigation provisions. Any of the foregoing could result in regulatory actions, cost overruns, delays or other losses, any of which (or a combination of which) could have a material adverse effect on our results of operations, financial condition and cash flows.

Further, our construction program calls for extensive expenditures for capital improvements and additions, including the installation of environmental upgrades, improvements to and replacements of generation, transmission and distribution facilities, as well as other initiatives. As a result, we have engaged, and will continue to engage, numerous contractors and have entered into a number of agreements to acquire the necessary materials and/or obtain the required construction related services. In addition, some contracts provide for us to assume the risk of price escalation and availability of certain metals and key components. This could force us to enter into alternative arrangements at then-current market prices that may exceed our contractual prices or cause construction delays in a significant manner. It could also subject us to enforcement action by regulatory authorities to the extent that such

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a contractor failure resulted in a failure by AES Indiana to comply with requirements or expectations, particularly with regard to the cost of the project. As a result of these events, we might incur losses or delays in completing construction.

The COVID-19 pandemic, or the future outbreak of any other highly infectious or contagious diseases, could impact our business and operations.

The COVID-19 pandemic has impacted global economic activity, caused significant volatility and negative pressure in financial markets and reduced the demand for energy in our service territory in recent years. In addition to reduced revenue and lower margins resulting from decreased energy demand within our service territory, we also have incurred expenses relating to COVID-19, including expenses relating to events outside of our control. In addition to contributing to economic slowdown or a recession, COVID-19 or another pandemic could have material and adverse effects on our results of operations, financial condition and cash flows due to, among other factors:

•further decline in customer demand as a result of general decline in business activity;

•further destabilization of the markets and decline in business activity negatively impacting our customer growth or the number of customers in our service territory as well as our customers’ ability to pay for our services when due (or at all);

•delay or inability in obtaining regulatory actions and outcomes that could be material to our business, including for recovery of COVID-19 related expenses and losses, such as uncollectible customer amounts, and the review and approval of our applications, rates and charges by the IURC;

•difficulty accessing the capital and credit markets on favorable terms, or at all, a disruption and instability in the global financial markets, or deteriorations in credit and financing conditions which could affect our access to capital necessary to fund business operations or address maturing liabilities on a timely basis;

•negative impacts on the health of our essential personnel, especially if a significant number of them are affected, and on our operations as a result of implementing stay-at-home, quarantine and other social distancing measures;

•a deterioration in our ability to ensure business continuity during a disruption, including increased cybersecurity attacks related to the work-from-home environment;

•delays or inability to access, transport and deliver fuel or other materials to our facilities due to restrictions on business operations or other factors affecting us and our third-party suppliers;

•the inability to hedge sufficient exposure of our operations from availability and cost of fuel and other commodities that experience significant volatility;

•delays or inability to access equipment or the availability of personnel to perform planned and unplanned maintenance, which can, in turn, lead to disruption in operations;

•delays or inability in achieving our financial goals, growth strategy and digital transformation; and

•delays in the implementation of expected rules and regulations.

The impact of the COVID-19 pandemic also depends on factors, including the effectiveness and timing of updated vaccines to address new variants, the development of more virulent COVID-19 variants as well as third-party actions taken to contain its spread and mitigate its public health effects. A resurgence or material worsening of the COVID-19 pandemic could present material uncertainty which could materially and adversely affect our generation facilities, transmission and distribution systems, results of operations, financial condition and cash flows. To the extent COVID-19 adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in this “Risk Factors” section, such as those relating to our level of indebtedness, our need to generate sufficient cash flows to service our indebtedness and our ability to comply with the covenants contained in the agreements that govern our indebtedness.

Failure to maintain an effective system of internal controls over financial reporting could result in material misstatements in our financial statements, the disallowance of cost recovery, or incorrect payment processing.

Our internal controls, accounting policies and practices and internal information systems are designed to enable us to capture and process transactions and information in a timely and accurate manner in compliance with GAAP, laws and regulations, taxation requirements and federal securities laws and regulations in order to, among other things, disclose and report financial and other information in connection with the recovery of our costs and with our reporting requirements under federal securities, tax and other laws and regulations and to properly process payments. We have also implemented corporate governance, internal control and accounting policies and procedures in connection with the Sarbanes-Oxley Act of 2002. Our internal controls and policies have been and

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continue to be closely monitored by management and our Board of Directors. While we believe these controls, policies, practices and systems are adequate to verify data integrity, the identification of significant deficiencies or material weaknesses in our internal controls that we cannot remediate in a timely manner could lead to undetected errors that could result in material misstatements in our financial statements, the disallowance of cost recovery, or incorrect payment processing. The consequences of these events could have a material adverse effect on our results of operations, financial condition and cash flows.

As more fully disclosed in "Item 9A. Controls and Procedures”, we have identified a material weakness in our internal control over financial reporting that resulted from the design and operation of information technology general controls. While we believe that this material weakness did not result in a material misstatement of our financial statements, this control deficiency was not remediated as of December 31, 2023. Since there is a reasonable possibility that the control deficiency could result in a material misstatement in our financial statements that would not be detected, we determined that this control deficiency constituted a material weakness. While we have taken steps to implement a remediation plan, the material weakness will not be considered remediated until the enhanced controls operate for a sufficient period of time and management has concluded, through testing, that the related controls are effective. Furthermore, we can give no assurance that the measures we take will remediate the material weakness. We can give no assurance that additional material weaknesses will not arise in the future. Any failure to remediate the material weakness, or the development of new material weaknesses in our internal control over financial reporting, could result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations.

If we are unable to maintain a qualified and properly motivated workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows.

One of the challenges we face is to retain a skilled, efficient and cost-effective workforce while recruiting new talent to replace losses in knowledge and skills due to resignations, terminations or retirements. This undertaking could require us to make additional financial commitments and incur increased costs. If we are unable to successfully attract and retain an appropriately qualified workforce, it could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we have employee compensation plans that reward the performance of our employees. We seek to ensure that our compensation plans encourage acceptable levels for risk and high performance through pay mix, performance metrics and timing. We also have policies and procedures in place to mitigate potential excessive risk-taking by employees to achieve performance targets which could result in events that could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements that could adversely affect our business, results of operations, financial condition and cash flows.

We are subject to collective bargaining agreements with employees who are members of a union. Approximately 68% of our employees are represented by a union in two bargaining units: a physical unit and a clerical-technical unit. While we believe that we maintain a satisfactory relationship with our employees, it is possible that labor disruptions affecting some or all of our operations could occur during the period of the collective bargaining agreements or at the expiration of the collective bargaining agreements before new agreements are negotiated. We may not be able to successfully train new personnel as current workers with significant knowledge and expertise retire. We also may be unable to staff our business with qualified personnel in the event of significant absenteeism related to a pandemic illness. Work stoppages by, or poor relations or ineffective negotiations with, our employees or other workforce issues could have a material adverse effect on our results of operations, financial condition and cash flows.

The use of non-derivative and derivative instruments in the normal course of business could result in losses that could materially and adversely impact our results of operations, financial position and cash flows.

We sometimes use non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial risks. We may at times enter into forward contracts to hedge the risk of volatility in earnings from wholesale marketing activities. These trades are affected by a range of factors, including variations in power demand, fluctuations in market prices, market prices for alternative commodities and optimization opportunities. We have attempted to manage our commodities price risk exposure by establishing and enforcing risk limits and risk management policies. Despite our efforts, however, these risk limits and management policies may not work as planned and fluctuating prices and other events could adversely affect our results of operations,

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financial condition and cash flows. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these instruments can involve management’s judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. We could also recognize financial losses as a result of volatility in the market values of these contracts, a counterparty failing to perform, or the underlying transactions which the instruments are intended to hedge failing to materialize, which could result in a material adverse effect on our results of operations, financial condition and cash flows.

Potential security breaches (including cybersecurity breaches) and terrorism risks could materially and adversely affect our businesses.

We operate in a highly regulated industry that requires the continued operation of sophisticated systems and network infrastructure at our generation stations, fuel storage facilities and transmission and distribution facilities. We also use various financial, accounting and other systems in our businesses. These systems and facilities are vulnerable to unauthorized access due to hacking, viruses, other cybersecurity attacks and other causes and also may be subject to acts of sabotage and vandalism. In particular, given the importance of energy and the electric grid, there is the possibility that our systems and facilities could be targets of terrorism or acts of war and there has been an increased focus on the U.S. energy grid that is believed to be related to the Russia/Ukraine conflict. We have implemented measures to help prevent unauthorized access to our systems and facilities, including network and system monitoring, identification and deployment of secure technologies, and certain other measures to comply with mandatory regulatory reliability standards. Pursuant to NERC requirements, we have a robust cybersecurity plan in place and are subject to regular audits by an independent auditor approved by NERC. We routinely test our systems and facilities against these regulatory requirements in order to measure compliance, assess potential security risks, and identify areas for improvement. In addition, we provide cybersecurity training for our employees and perform exercises designed to raise employee awareness of cyber risks on a regular basis. To date, cyber-attacks on our business and operations have not had a material impact on our operations or financial results. Despite our efforts, if our systems or facilities were to be breached or disabled, we may be unable to recover them in a timely manner to fulfill critical business functions, including the supply of electric services to our customers, and we could experience decreases in revenue and increases in costs that could materially and adversely affect our results of operations, cash flows and financial condition.

In the course of our business, we also store and use customer, employee, and other personal information and other confidential and sensitive information, including personally identifiable information and personal financial information. If our or our third-party vendors’ systems were to be breached or disabled, sensitive and confidential information and other data could be compromised, which could result in liability or penalties under privacy laws, negative publicity, remediation costs and potential litigation, damages, consent orders, injunctions, fines and other relief.

To help mitigate these risks, we maintain insurance coverage against some, but not all, potential losses, including coverage for illegal acts against us. However, insurance may not be adequate to protect us against all costs and liabilities associated with these risks.

Failure or disruption in our information systems or those of businesses we rely on, or implementation of new processes and information systems could, if significant, interrupt our operations and adversely affect our business, results of operations, financial condition and cash flows in a material manner.

Our business depends on numerous information systems to manage our operations and business processes, financial information, and customer billings. From time to time, we have experienced, and may in the future experience, damage or disruptions in our information technology and computer systems from various risks including, but not limited to, power outages, facility damage, computer and telecommunications failures, computer viruses, security breaches, vandalism, theft, natural disasters, catastrophic events, human error and potential cyber threats. Our disaster recovery planning cannot account for all eventualities.

In addition, we are currently making, and expect to continue to make, investments in our information technology systems and infrastructure, some of which are significant. In 2023, we implemented certain replacement information systems, including our customer information and billing system. Failure to successfully manage the post-implementation phase of this initiative, including with respect to our systems for billing and collecting from our customers, could, if significant, result in a material adverse effect on our business, operating results and financial

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condition. In addition, the effectiveness of our information technology general controls and internal controls over financial reporting could continue to be negatively affected.

RISKS ASSOCIATED WITH GOVERNMENTAL REGULATION AND LAWS

We may not always be able to recover our costs to deliver electricity to our retail customers. The costs we can recover and the return on capital we are permitted to earn for certain aspects of our business are regulated and governed by the laws of Indiana and the rules, policies and procedures of the IURC.

We are currently obligated to supply electric energy to retail customers in our service territory. Even though rate regulation is premised on full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the IURC will agree that all of our costs have been prudently incurred or are recoverable. There also is no assurance that the regulatory process in which rates are determined will always result in rates that will produce a full or timely recovery of our costs and authorized return. From time to time, the demand for electric energy required to meet our service obligations could exceed our available electric generating capacity. When our retail customer demand exceeds our generating capacity for units operating under MISO economic dispatch, recovery of our cost to purchase electric energy in the MISO market to meet that demand is subject to a stipulation and settlement agreement. The agreement includes a benchmark which compares hourly purchased power costs to daily natural gas prices. Purchased power costs above the benchmark must meet certain criteria in order for us to fully recover them from our retail customers, such as consideration of the capacity of units available but not selected by the MISO economic dispatch. We may not always have the ability to pass all of the purchased power costs on to our customers, and even if we are able to do so, there may be a significant delay between the time the costs are incurred and the time the costs are recovered. Since these situations most often occur during periods of peak demand, the market price for electric energy at the time we purchase it could be very high, and we may not be allowed to recover all of such costs through our FAC (please see Note 2, "Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income" to the Financial Statements of this Annual Report on Form 10-K for additional details regarding the benchmark and the process to recover purchased power costs). Even if a supply shortage were brief, we could suffer substantial losses that could adversely affect our results of operations, financial condition and cash flows.

Changes in, or reinterpretations of, the laws, rules, policies and procedures that set electric rates, permitted rates of return, changes in AES Indiana’s rate structure, regulations regarding ownership of generation assets and electric service, the supply or generation, reliability initiatives, fuel and purchased power (which account for a substantial portion of our operating costs), capital expenditures and investments and the recovery of these and other costs on a full or timely basis through rates, power market prices and changes to the frequency and timing of rate increases could have a material adverse effect on our results of operations, financial condition and cash flows.

Concerns about GHG emissions and the potential risks associated with climate change have led to increased regulation and other actions that could impact our business.

One byproduct of burning coal and other fossil fuels is the emission of GHGs, including CO2. At the federal, state and regional levels, policies are under development or have been developed to regulate GHG emissions. In 2023, AES Indiana emitted approximately 9 million tons of CO2 from our power plants. AES Indiana uses CO2 emission estimation methodologies supported by “The Greenhouse Gas Protocol” reporting standard on GHG emissions. Our CO2 emissions are determined from emissions monitoring data and calculations using actual fuel heat inputs and fuel type CO2 emission factors.

There currently is no U.S. federal legislation imposing mandatory GHG emission reductions (including for CO2) that affects our electric power generation facilities. However, in 2015, the EPA promulgated a rule establishing NSPS for CO2 emissions for newly constructed and modified/reconstructed fossil-fueled EUSGUs larger than 25 MW, and the EPA proposed revisions to this rule in December 2018. On May 23, 2023, EPA published a proposed rule that would establish CO2 emissions limits for certain new fossil-fuel fired stationary combustion turbines that commence construction or are modified after May 23, 2023. Also on May 23, 2023, following prior rulemaking activity under CAA Section 111(d) and associated legal challenges, EPA published a proposed rule that would vacate its prior ACE Rule, establish emissions guidelines in the form of CO2 emissions limitations for certain existing electric generating units (EGUs) and would require states to develop State Plans that establish standards of performance for such EGUs that are that least as stringent as EPA's emissions guidelines. In addition, it is likely that there will be increased focus on climate change from a President Biden administration and any future Democrat-controlled U.S. Congress, both of which may result in additional legislation and regulations regarding GHG emissions. For example,

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in March 2022, the SEC proposed a rule that would require extensive climate-related disclosures, including climate-related risks, GHG emissions and climate-related financial metrics; while this rule has not yet been finalized, once final it could require significant efforts and costs to comply.

In December 2015, the parties to the United Nations Framework Convention on Climate Change convened for the 21st Conference of the parties and the resulting Paris Agreement established a long-term goal of keeping the increase in global average temperature well below 2°C above pre-industrial levels. We anticipate that the Paris Agreement will continue the trend toward efforts to de-carbonize the global economy. Although the U.S. was officially able to withdraw from the Paris Agreement on November 4, 2020, on January 20, 2021, President Biden began the 30-day process of rejoining the Paris Agreement, which became effective for the U.S. on February 19, 2021. In November 2023, the international community gathered for COP28. The Parties agreed to non-binding language calling on countries to transition away from fossil fuels in energy systems to achieve net zero emissions by 2050.

Any existing or future international, federal, state or regional legislation or regulation of GHG emissions could have a material adverse impact on our financial performance. The actual impact on our financial performance will depend on a number of factors, including among others, the degree and timing of GHG emissions reductions required under any such legislation or regulations, of offsets, the extent to which market-based compliance options are available, if such options were available, the extent to which we would be entitled to receive GHG emissions allowances without having to purchase them in an auction or on the open market as well as the cost or availability of such allowances and the impact of such legislation or regulation on our ability to recover costs incurred through rate increases or otherwise. Our cost of compliance could be substantial. Although we would seek recovery of costs associated with new climate change or GHG regulations, our inability to fully or timely recover such costs could have a material adverse effect on our results of operations, financial condition and cash flows. Additionally, concerns over GHG emissions and their effect on the environment have led, and could lead further, to reduced demand for coal-fired power, which could have a material adverse effect on our results of operations, financial condition and cash flows.

Furthermore, according to the Intergovernmental Panel on Climate Change, physical risks from climate change could include, but are not limited to, increased runoff and earlier spring peak discharge in many glacier and snow-fed rivers, warming of lakes and rivers, an increase in sea level, changes and variability in precipitation and in the intensity and frequency of extreme weather events. Physical impacts may have the potential to significantly affect our business and operations. For example, extreme weather events could result in increased downtime and operation and maintenance costs at our electric power generation facilities and our support facilities. Variations in weather conditions, primarily temperature and humidity, would also be expected to affect the energy needs of customers. A decrease in energy consumption could decrease our revenue. In addition, while revenue would be expected to increase if the energy consumption of customers increased, such increase could prompt the need for additional investment in generation capacity. Changes in the temperature of lakes and rivers and changes in precipitation that result in drought could adversely affect the operations of our fossil-fuel fired electric power generation facilities.

If any of the foregoing risks materialize, we expect our costs to increase or revenue to decrease and there could be a material adverse effect on our business and on our consolidated results of operations, financial condition, cash flows and reputation if such changes are significant. Please see “Item 1. Business - Environmental Matters” for additional information of environmental matters impacting us, including those relating to regulation of GHG emissions.

We are subject to numerous environmental laws, rules and regulations that require capital expenditures, increase our cost of operations, may expose us to environmental liabilities or make continued operation of certain generating units unprofitable.

We are subject to various federal, state, regional and local environmental protection and health and safety laws, rules and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including CCR; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials into the environment; and the health and safety of our employees. Such laws, rules and regulations can become stricter over time, and we could also become subject to additional environmental laws, rules and regulations and other requirements in the future. Environmental laws, rules and regulations also generally require us to comply with inspections and obtain and comply with a wide variety of environmental licenses, permits, and other governmental authorizations. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits and other

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governmental authorizations from federal, state and local agencies. If we are not able to timely comply with inspections and obtain, maintain or comply with all environmental laws, rules and regulations, and all licenses, permits, and other government authorizations required to operate our business, then our operations could be prevented, delayed or subject to additional costs. A violation of environmental laws, rules, regulations, permits or other requirements can result in substantial fines, penalties, other sanctions, permit revocation, facility shutdowns, the imposition of stricter environmental standards and controls or other injunctive measures affecting operating assets. Compliance with these laws, regulations and other requirements requires us to expend significant funds and resources and could at some point become prohibitively expensive or result in our shutting down (temporarily or permanently) or altering the operation of our facilities. Under certain environmental laws, we could also be held responsible for costs relating to contamination at our past or present facilities and at third-party waste disposal sites. We could also be held strictly, jointly and severally liable for investigation or remediation of such contamination, human exposure to hazardous substances or for other environmental damage. From time to time we are subject to enforcement and litigation actions for claims of noncompliance with environmental laws, rules and regulations or other environmental requirements. We cannot assure that we will be successful in defending against any claim of noncompliance. Any actual or alleged violation of environmental laws, rules, regulations and other requirements also may require us to expend significant resources to defend against any such alleged violations and expose us to unexpected costs. Our costs and liabilities relating to environmental matters could have a material adverse effect on our results of operations, financial condition and cash flows.

In addition, we are subject to potentially significant remediation expenses, enforcement initiatives, private party lawsuits and reputational risk associated with CCR, which consists of bottom ash, fly ash, and air pollution control wastes generated at our current and former coal-fired generation plant sites. We expect to incur substantial costs to comply with CCR rules and requirements and any changes to existing CCR rules or requirements or other new rules or requirements addressing CCR may require us to incur additional costs. Also, we may become subject to CCR-related lawsuits or involved in other CCR-related litigation from time to time that may require us to incur other costs or expose us to unexpected liabilities, which could be significant. In addition, CCR and its production at our facilities have been the subject of interest from environmental non-governmental organizations and the media. Any of the foregoing could have a material adverse effect on our results of operations, financial condition and cash flows. While we maintain insurance for certain of these costs and liabilities, there can be no assurance that our insurance will be available, sufficient or effective under all circumstances and against all of our claimed liabilities.

Please see “Item 1. Business - Environmental Matters” for additional information of environmental matters impacting us, including our current CCR-related insurance coverage litigation.

If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

As an owner and operator of a bulk power transmission system, AES Indiana is subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is guided by reliability and market interface principles. Compliance with reliability standards may subject us to higher operating costs or increased capital expenditures. Although we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the IURC will approve full recovery in a timely manner. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates and could have a material adverse effect on our results of operations, financial condition and cash flows.

We are subject to extensive laws and local, state and federal regulation, as well as litigation and other proceedings that affect our operations and costs.

We are subject to extensive regulation at the federal, state and local levels. For example, at the federal level, AES Indiana, as an electric utility, is regulated by the FERC and the NERC and, at the state level, we are regulated by the IURC. The regulatory power of the IURC over AES Indiana is both comprehensive and typical of the traditional form of regulation generally imposed by state public utility commissions. We face the risk of unexpected or adverse regulatory action. Regulatory discretion is reasonably broad in Indiana. AES Indiana is subject to regulation by the IURC as to our services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, the increase or decrease in retail rates and

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charges, the issuance of securities and long-term debt, the acquisition and sale of some public utility properties or securities and certain other matters.

AES Indiana’s tariff rates for electric service to retail customers consist of basic rates and charges which are set and approved by the IURC after public hearings. In addition, AES Indiana’s rates typically include various adjustment mechanisms and we must seek approval from the IURC through such public proceedings of our rate adjustment mechanism factors to reflect changes in certain costs. There can be no assurance that we will be granted approval of rate adjustment mechanism factors that we request from the IURC. The failure to obtain IURC approval of requested relief, or any other adverse rate determination by the IURC could have a material adverse effect on our results of operations, financial condition and cash flows.

As a result of the EPAct and subsequent legislation affecting the electric utility industry, we have been required to comply with rules and regulations in areas including mandatory reliability standards, cybersecurity, transmission expansion and energy efficiency. We are currently unable to predict the long-term impact, if any, to our results of operations, financial condition and cash flows as a result of these rules and regulations. Complying with the regulatory environment to which we are subject requires us to expend a significant amount of funds and resources. The failure to comply with this regulatory environment could subject us to substantial financial costs and penalties and changes, either forced or voluntary, in the way we operate our business.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. Additionally, the fuel charge applied for can be reduced if a utility’s rolling twelve-month operating income, determined at quarterly measurement dates, exceeds a utility’s authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies against which the excess rolling twelve-month jurisdictional net operating income can be offset.

Future events, including the advent of retail competition within AES Indiana’s service territory, could result in the deregulation of part of AES Indiana’s existing regulated business. In addition to effects on our business that could result from any deregulation, such as a loss of customers and increased costs to retain or attract customers upon deregulation, adjustments to AES Indiana’s accounting records may be required to eliminate the historical impact of regulatory accounting. Such adjustments, as required by FASB ASC 980 “Regulated Operations,” could eliminate the effects of any actions of regulators that have been recognized as assets and liabilities. Required adjustments could include the expensing of any unamortized net regulatory assets, the elimination of certain tax liabilities, and a write down of any impaired utility plant balances. We expect AES Indiana to meet the criteria for the application of ASC 980 for the foreseeable future.

We are subject to litigation, regulatory proceedings, administrative proceedings, audits, settlements, investigations and claims from time to time that require us to expend significant funds to address. There can be no assurance that the outcome of these matters will not have a material adverse effect on our business, results of operations, financial condition and cash flows. Asbestos and other regulated substances are, and may continue to be, present at our facilities, and we have been named as a defendant in asbestos litigation. The continued presence of asbestos and other regulated substances at these facilities could result in additional litigation being brought against us, which could have a material adverse effect on our results of operations, financial condition and cash flows. Please see Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for a summary of significant regulatory matters and legal proceedings involving us.

Tax legislation initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.

We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. In addition, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations.

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RISKS RELATED TO OUR INDEBTEDNESS AND FINANCIAL CONDITION

We rely on access to the financial markets. General economic conditions and disruptions in the financial markets could adversely affect our ability to raise capital on favorable terms or at all, and cause increases in our interest expense.

From time to time we rely on access to the capital and credit markets as a source of liquidity for capital requirements not satisfied by operating cash flows. These capital and credit markets experience volatility and disruption from time to time and the ability of corporations to raise capital can be negatively impacted. Disruptions in the capital and credit markets make it harder and more expensive to raise capital. Our ability to raise capital on favorable terms or at all can be adversely affected by unfavorable market conditions or declines in our creditworthiness, and we may be unable to access adequate funding to refinance our debt as it becomes due or finance capital expenditures. The extent of any impact will depend on several factors, including our operating cash flows, financial condition and prospects, the overall supply and demand in the credit markets, our credit ratings, credit capacity, the cost of financing, the financial condition, performance and prospects of other companies in our industry or with similar financial circumstances and other general economic and business conditions. It may also depend on the performance of credit counterparties and financial institutions with which we do business. Access to funds under our existing financing arrangements is also dependent on the ability of our counterparties to meet their financing commitments and our satisfying conditions to borrowing. Our inability to obtain financing on reasonable terms, or at all, with creditworthy counterparties could adversely affect our results of operations, financial condition and cash flows. If our available funding is limited or we are forced to fund our operations at a higher cost, these conditions may require us to curtail our business activities and increase our cost of funding, both of which would adversely impact our profitability.

See Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. See also “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for information related to market risks.

The level of our indebtedness, and the security provided for this indebtedness, could adversely affect our financial flexibility.

As of December 31, 2023, we had on a consolidated basis $3,476.0 million of indebtedness, including finance lease obligations, and total shareholders’ equity of $1,076.5 million. AES Indiana had $2,153.8 million of first mortgage bonds outstanding as of December 31, 2023, which are secured by the pledge of substantially all of the assets of AES Indiana under the terms of AES Indiana’s mortgage and deed of trust. This level of indebtedness and related security has important consequences, including the following:

•increasing our vulnerability to general adverse economic and industry conditions;

•requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund other corporate purposes;

•limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

•limiting, along with the financial and other restrictive covenants in our indebtedness, our ability to borrow additional funds, as needed.

We expect to incur additional debt in the future, subject to the terms of our debt agreements and regulatory approvals for any AES Indiana debt. To the extent we become more leveraged, the risks described above would increase. Further, actual cash requirements in the future may be greater than expected. Accordingly, our cash flow from operations may not be sufficient to repay at maturity all of the outstanding debt as it becomes due and, in that event, we may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms or at all to refinance our debt as it becomes due. For a further discussion of outstanding debt, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” and Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K.

We have variable rate debt that bears interest based on a prevailing rate that is reset based on a market index that can be affected by market demand, supply, market interest rates and other market conditions. We also maintain both cash on deposit and investments in cash equivalents from time to time that could be impacted by interest rate fluctuations. As such, any event which impacts market interest rates could have a material effect on our results of operations, financial condition and cash flows. In addition, ratings agencies issue credit ratings on us and our debt

35

that affect our borrowing costs under our financial arrangements and affect our potential pool of investors and funding sources. Our credit ratings also govern the collateral provisions of certain of our contracts. If rating agencies downgrade our credit ratings, our borrowing costs would likely further increase, our potential pool of investors and funding resources could be reduced, and we could be required to post additional cash collateral under selected contracts. These events would likely reduce our liquidity and profitability and could have a material adverse effect on our results of operations, financial condition and cash flows.

IPALCO is a holding company and parent of AES Indiana and other subsidiaries. IPALCO’s cash flow is dependent on operating cash flows of AES Indiana and its ability to pay cash to IPALCO.

IPALCO is a holding company with no material assets other than the common stock of its subsidiaries, and accordingly all cash is generated by the operating activities of our subsidiaries, principally AES Indiana. As such, IPALCO’s cash flow is largely dependent on the operating cash flows of AES Indiana and its ability to pay cash to IPALCO. AES Indiana’s mortgage and deed of trust, its amended articles of incorporation, its Credit Agreement and its $300 million Term Loan Agreement contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends to IPALCO. For example, there are restrictions that require maintenance of a leverage ratio which could limit the ability of AES Indiana to pay dividends. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity” for a discussion of these restrictions. See Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K for information regarding indebtedness. In addition, AES Indiana is regulated by the IURC, which possesses broad oversight powers to ensure that the needs of utility customers are being met. The IURC could impose additional restrictions on the ability of AES Indiana to distribute, loan or advance cash to IPALCO pursuant to these broad powers. While we do not expect any of the foregoing restrictions to significantly affect AES Indiana’s ability to pay funds to IPALCO in the future, a significant limitation on AES Indiana’s ability to pay dividends or loan or advance funds to IPALCO would have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows.

Our ownership by AES subjects us to potential risks that are beyond our control.

All of AES Indiana’s common stock is owned by IPALCO, all of whose common stock is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). Due to our relationship with AES, any adverse developments and announcements concerning AES may impair our ability to access the capital markets and to otherwise conduct business. In particular, downgrades in AES’s credit ratings could result in AES Indiana’s or IPALCO’s credit ratings being downgraded.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

We recognize the importance of maintaining the safety and security of our people, systems, and data and have a holistic process, supported by our management and Board of Directors, for overseeing and managing cybersecurity and related risks. As part of AES, we are also supported by AES’ cyber risk management program.

AES’ Chief Information Security Officer (“CISO”) reports to AES’ General Counsel and is the head of the Company’s cybersecurity team. The CISO is responsible for assessing and managing AES’ cyber risk management program globally, including IPALCO and its subsidiaries. In this role, the CISO informs senior management regarding the prevention, detection, mitigation, and remediation of cybersecurity incidents and supervises such efforts. AES’ CISO has extensive experience assessing and managing cybersecurity programs and cybersecurity risk and has served in that position since 2020.

The CISO manages a global team of cybersecurity professionals with broad experience and expertise, including in cybersecurity threat assessments and detection, cloud security, mitigation technologies, cybersecurity training, incident response, cyber forensics, insider threats and regulatory compliance. We rely on threat intelligence as well as other information obtained from governmental, public, or private sources, including contracted external consultants. The global team includes local cyber security professionals that manage the operational technology (OT) network security of IPALCO to demonstrate compliance with the NERC-Critical Infrastructure Protection (CIP) standards and IURC regulation.

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The Board of Directors oversees our cybersecurity risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. The CISO briefs the Board of Directors on the effectiveness of our cyber risk management program periodically and as needed.

We consider cybersecurity as part of the enterprise risk process, including organized and structured reporting protocols. The prioritization of cybersecurity risk is aligned with overall risk management processes.

In addition, the Company’s management team considers risks relating to cybersecurity, among other significant risks, and applicable mitigation plans to address such risks, at monthly performance review meetings. The Company's CEO, CFO and other members of senior management participate in such meetings.

We have also established an Incident Response Team and associated protocol led by AES’ CISO that governs our assessment, response, and notifications internally and externally upon the occurrence of a cybersecurity incident. Depending on the nature and severity of an incident, this protocol provides for escalating notification to our CEO and the Board. We regularly practice our incident response through executive tabletop exercises.

Our policies, standards, processes, and practices for assessing, identifying, and managing material risks from cybersecurity threats are integrated into our overall risk management program and are informed by frameworks established by the National Institute of Standards and Technology (“NIST”) and other applicable industry standards. Our cybersecurity program addresses threats in a prioritized manner and, in particular, focuses on the following key areas:

•gap analysis to identify programmatic opportunities for improvement that can be incorporated into the cyber strategy;

•policies and standards that are annually reviewed and communicated;

•exceptions management and internal audits that support cybersecurity requirements through assessing control implementation risks; and

•monitoring and regular reporting of cyber resilience and posture at operational and strategic levels.

We engage assessors, consultants, auditors, or other third parties in connection with any such processes, including:

•external vulnerability assessments, including penetration tests;

•internal audit reviews;

•threat intelligence;

•incident management;

•audits of NERC-Critical Infrastructure Protection regulated environments by the NERC Registered Regional Entity; and

•program development support, as needed.

Our risk management program for third-party service providers includes risk-based assessments of their interactions with our data and systems. We implement monitoring and response processes for key third-party service providers.

We provide awareness training to our employees to help identify, avoid, and mitigate cybersecurity threats. Our employees participate in training, including phishing exercises, monthly safety meetings, and an annual cybersecurity awareness update. We also periodically host tabletop exercises with management and other employees to practice rapid cyber incident response.

We face cybersecurity risks in connection with our business. Although such risks have not materially affected us to date, we have, from time to time, experienced threats to and breaches of our data and systems. For more information about the cybersecurity risks we face, see the risk factor entitled Potential security breaches (including cybersecurity breaches) and terrorism risks could materially and adversely affect our business in Item 1A—Risk Factors of this Annual Report on Form 10-K.

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ITEM 2. PROPERTIES

Information relating to our properties is contained in “Item 1. Business – Properties” and Note 3, “Property, Plant and Equipment” to the Financial Statements of this Annual Report on Form 10-K.

AES Indiana’s mortgage and deed of trust secures first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage and deed of trust, substantially all property owned by AES Indiana is subject to a direct first mortgage lien securing indebtedness of $2,153.8 million at December 31, 2023. In addition, IPALCO has outstanding $880.0 million of debt obligations which are secured by its pledge of all of the outstanding common stock of AES Indiana.

ITEM 3. LEGAL PROCEEDINGS 

In the normal course of business, we are subject to various lawsuits, actions, claims, and other proceedings. We are also from time to time involved in other reviews, investigations and proceedings by governmental and regulatory agencies regarding our business, certain of which may result in adverse judgments, settlements, fines, penalties, injunctions or other relief. We have accrued in our Financial Statements of this Annual Report on Form 10-K for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We believe the amounts provided in our Financial Statements of this Annual Report on Form 10-K, as prescribed by GAAP, for these matters are adequate in light of the probable and estimable contingencies. However, there can be no assurances that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters (including those matters noted below), and to comply with applicable laws and regulations will not exceed the amounts reflected in our Financial Statements of this Annual Report on Form 10-K. As such, costs, if any, that may be incurred in excess of those amounts provided for in our Financial Statements of this Annual Report on Form 10-K, cannot be reasonably determined, but could be material. Please see Note 2, “Regulatory Matters” and Note 10, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for summaries of significant legal proceedings involving us, which are incorporated by reference herein.

The following additional information is incorporated by reference into this Item: information about the legal proceedings contained in "Regulation" and “Environmental Matters” in “Item 1. Business” of this Annual Report on Form 10-K.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of February 26, 2024, all of the outstanding common stock of IPALCO is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). As a result, our stock is not listed for trading on any stock exchange.

Dividends

During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to our shareholders totaling $104.3 million, $102.0 million and $131.5 million, respectively. Future distributions to our shareholders will be determined at the discretion of our Board of Directors and will depend primarily on dividends received from AES Indiana and such other factors as our Board of Directors deems relevant. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” of this Form 10-K for a discussion of limitations on dividends from AES Indiana. In order for us to make any dividend payments to our shareholders, we must, at the time and as a result of such dividends, either maintain certain credit ratings on our senior long-term debt or be in compliance with leverage and interest coverage ratios contained in IPALCO’s Third Amended and Restated Articles of Incorporation. We do not believe this requirement will be a limiting factor in paying dividends in the ordinary course of prudent business operations.

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Dividends and Capital Structure Restrictions

AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million (for further discussion, see Note 9, "Equity and Cumulative Preferred Stock - Cumulative Preferred Stock" to the Financial Statements of this Annual Report on Form 10-K). As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions.

AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.

IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed 0.67 to 1 and IPALCO’s interest coverage ratio is not less than 2.50 to 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.

ITEM 6. [RESERVED]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our Financial Statements of this Annual Report on Form 10-K and the notes thereto. The following discussion contains forward-looking statements. Our actual results may differ materially from the results suggested by these forward-looking statements. Please see “Forward-Looking Statements” and “Item 1A. Risk Factors.” For a list of certain terms, abbreviations or acronyms in this discussion, see “Glossary of Terms” at the beginning of this Form 10-K.

OVERVIEW OF 2023 RESULTS AND STRATEGIC PERFORMANCE

The most important matters on which we focus in evaluating our financial condition and operating performance and allocating our resources include: (i) recurring factors which have significant impacts on operating performance such as: regulatory action, environmental matters, weather and weather-related damage in our service area, customer growth and the local economy; (ii) our progress on performance improvement and growth strategies designed to maintain high standards in several operating areas (including safety, reliability, customer satisfaction, operations, financial and enterprise-wide performance, talent management/people, capital allocation/sustainability and corporate social responsibility) simultaneously; and (iii) our short-term and long-term financial and operating strategies. For a discussion of how we are impacted by regulation and environmental matters, please see Note 2, “Regulatory Matters” to the Financial Statements and “Environmental Matters” in “Item 1. Business” of this Annual Report on Form 10-K.

Operational Excellence

Our objective is to optimize AES Indiana’s performance in the U.S. utility industry by focusing on the following areas: safety, operations (reliability and customer satisfaction), financial and enterprise-wide performance (efficiency and cost savings, talent management/people, capital allocation/sustainability and corporate social responsibility). We set

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and measure these objectives carefully, balancing them in a way and to a degree necessary to ensure a sustainable high level of performance in these areas simultaneously as compared to our peers. We monitor our performance in these areas, and where practical and meaningful, compare performance in some areas to peer utilities. Because some of our financial and enterprise-wide performance measures are company-specific performance goals, they are not benchmarked.

Our safety performance is measured by both leading and lagging metrics. Our leading safety metrics track safety observations, safety meeting engagement and the reporting of lost time incident (“LTI”) rates for our employees and contractors based on OSHA standards. Our lagging safety metrics track lost workday cases, severity rate, and recordable incidents. We are committed to excellence in safety and have implemented various programs to increase safety awareness and improve work practices.

AES Indiana measures delivery reliability by Customer Average Interruption Duration Index ("CAIDI"), System Average Interruption Duration Index ("SAIDI") and System Average Interruption Frequency Index ("SAIFI") and benchmarks the reliability metrics against other utilities at both the state and national levels. AES Indiana also measures customer centricity on more of an individual basis by the industry metric of Customers that Experience Multiple Interruption of five or more times ("CEMI-5"). AES Indiana measures generation reliability by Commercial Availability (“CA”), Equivalent Forced Outage Factor (“EFOF”) and Equivalent Availability Factor (“EAF”) metrics and benchmarks both EFOF and EAF results nationally. We measure Customer Satisfaction using J.D. Power in their Electric Utility Residential Customer Satisfaction Study and Research America Market Research - Consumer Insight. Monitoring performance in the areas such as competitive rates, operational reliability and customer service supports our ongoing work to deliver reliable service to our customers.

EXECUTIVE SUMMARY

Compared with the prior year, the results for the year ended December 31, 2023 reflect lower income from operations before income tax of $46.7 million, or 39%, primarily due to factors including, but not limited to:

$ in millions	2023 vs. 2022
Decrease in retail margin due to lower volumes driven by weather and lower demand	$	(52.4)
Decrease due to higher depreciation expense from additional assets placed in service and higher amortization of regulatory assets	(21.4)
Decrease due to higher defined benefit plan costs driven by increase in interest cost	(17.3)
Increase due to a charge to power purchased costs recorded in the prior period resulting from settlement of the FAC sub-docket on the Eagle Valley CCGT extended outage	27.8
Increase in TDSIC rider revenue	24.3
Other	(7.7)
Net change in income from operations before income tax	$	(46.7)

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RESULTS OF OPERATIONS 

The following review of results of operations and "Capital Resources and Liquidity" sections compare the results for the year ended December 31, 2023 to the results for the year ended December 31, 2022. For discussion comparing the results for the year ended December 31, 2022 to the results for the year ended December 31, 2021, see Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Annual Report on Form 10-K, filed with the SEC on March 1, 2023. In addition to the discussion on operations below, please see the “Statistical Information on Operations” table included in “Item 1. Business” of this report for additional data such as kWh sales and number of customers by customer class.

IPALCO’s results of operations include the results of its subsidiaries, including the consolidated results of its principal subsidiary AES Indiana. All material intercompany accounts and transactions have been eliminated in consolidation.

Statements of Operations Highlights

	Years Ended December 31,						Change 2023 vs. 2022				Change 2022 vs. 2021
(In Thousands)	2023		2022		2021		$		%		$		%
REVENUE	$	1,649,917	$	1,791,711	$	1,426,132	$	(141,794)	(7.9)	%	$	365,579	25.6	%
OPERATING COSTS AND EXPENSES:
Fuel	494,000		568,676		255,817		(74,676)		(13.1)	%	312,859		122.3	%
Power purchased	159,908		199,860		175,025		(39,952)		(20.0)	%	24,835		14.2	%
Operation and maintenance	477,880		493,674		449,746		(15,794)		(3.2)	%	43,928		9.8	%
Depreciation and amortization	287,863		266,504		256,085		21,359		8.0	%	10,419		4.1	%
Taxes other than income taxes	24,864		33,048		44,419		(8,184)		(24.8)	%	(11,371)		(25.6)	%
Other, net	(361)		(3,201)		(5,630)		2,840		(88.7)	%	2,429		(43.1)	%
Total operating costs and expenses	1,444,154		1,558,561		1,175,462		(114,407)		(7.3)	%	383,099		32.6	%
OPERATING INCOME	205,763		233,150		250,670		(27,387)		(11.7)	%	(17,520)		(7.0)	%
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction	9,315		4,784		5,412		4,531		94.7	%	(628)		(11.6)	%
Interest expense	(142,926)		(131,232)		(125,626)		(11,694)		8.9	%	(5,606)		4.5	%
Other (expense) / income, net	(410)		11,783		17,667		(12,193)		(103.5)	%	(5,884)		(33.3)	%
Total other expense, net	(134,021)		(114,665)		(102,547)		(19,356)		16.9	%	(12,118)		11.8	%
INCOME BEFORE INCOME TAX	71,742		118,485		148,123		(46,743)		(39.5)	%	(29,638)		(20.0)	%
Income tax expense	14,715		21,859		28,941		(7,144)		(32.7)	%	(7,082)		(24.5)	%
NET INCOME	57,027		96,626		119,182		(39,599)		(41.0)	%	(22,556)		(18.9)	%
Dividends on and redemption of preferred stock	—		3,509		3,213		(3,509)		(100.0)	%	296		9.2	%
Net loss attributable to noncontrolling interests	(26,093)		—		—		(26,093)		(100.0)	%	—		—	%
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	83,120	$	93,117	$	115,969	$	(9,997)	(10.7)	%	$	(22,852)	(19.7)	%

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Revenue

Revenue decreased in 2023 from the prior year by $141.8 million, which resulted from the following changes (dollars in thousands):

	2023		2022		Change		% Change
Revenue:
Retail Revenue	$	1,576,653	$	1,618,342	$	(41,689)	(2.6)	%
Wholesale Revenue	56,557		148,517		(91,960)		(61.9)	%
Miscellaneous Revenue	16,707		24,852		(8,145)		(32.8)	%
Total Revenue	$	1,649,917	$	1,791,711	$	(141,794)	(7.9)	%
Heating Degree Days(1):
Actual	4,350		5,281		(931)		(17.6)	%
30-year Average	5,198		5,244
Cooling Degree Days(1):
Actual	1,139		1,295		(156)		(12.0)	%
30-year Average	1,177		1,171

(1) Heating and cooling degree-days are a measure of the relative heating or cooling required for a home or business. The heating degrees in a day are calculated as the degrees that the average actual daily temperature is below 65 degrees Fahrenheit. For example, if the average temperature on March 20th was 40 degrees Fahrenheit, the heating degree days for that day would be the 25-degree difference between 65 degrees and 40 degrees. Similarly, cooling degree days in a day are calculated as the degrees that the average actual daily temperature is above 65 degrees Fahrenheit.

The following table presents additional data on kWh sold:

	2023	2022	kWh Change	% Change
kWh Sales (In Millions):
Residential	4,800	5,305	(505)	(9.5)	%
Small commercial and industrial	1,722	1,823	(101)	(5.5)	%
Large commercial and industrial	5,929	6,091	(162)	(2.7)	%
Public lighting	19	18	1	5.6	%
Sales – retail customers	12,470	13,237	(767)	(5.8)	%
Wholesale	1,657	2,148	(491)	(22.9)	%
Total kWh sold	14,127	15,385	(1,258)	(8.2)	%

The following graph shows the percentage changes in weather-normalized and actual retail electric sales volumes by customer class for the year ended December 31, 2023 as compared to the prior year:

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The decrease in revenue of $141.8 million was primarily due to the following:

$ in millions		2023 vs. 2022
Retail revenue:
	Volume:
	Net decrease in the volume of kWh sold primarily due to weather and demand in our service territory versus the comparable period.	$	(95.2)
	Price:
	Net increase in the weighted average price of retail kWh sold primarily due to higher fuel revenue, as well as higher TDSIC and Off System Sales Margin rider revenue.	55.9
	Other:	(2.4)
	Net change in retail revenue	(41.7)
Wholesale revenue:
	Volume:
	Net decrease in the volume of wholesale kWh sold. The amount of electricity available for wholesale sales is impacted by our retail load requirements, generation capacity and unit availability.	(34.0)
	Price:
	Net decrease in the weighted average price of wholesale kWh sold. Our ability to be dispatched in the MISO market is primarily driven by the locational marginal price of electricity and variable generation costs.	(58.0)
	Net change in wholesale revenue	(92.0)
Miscellaneous revenue:
	Primarily due to decrease in capacity revenue due to recent MISO auction results (lower clearing prices in the 2023-2024 MISO auction).	(8.1)
Net change in revenue		$	(141.8)

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Operating Costs and Expenses

The following table illustrates changes in Operating costs and expenses from 2022 to 2023 (in thousands):

	Years Ended
	December 31,
	2023		2022		$ Change		% Change
Operating costs and expenses:
Fuel	$	494,000	$	568,676	$	(74,676)	(13.1)	%
Power purchased	159,908		199,860		(39,952)		(20.0)	%
Operation and maintenance	477,880		493,674		(15,794)		(3.2)	%
Depreciation and amortization	287,863		266,504		21,359		8.0	%
Taxes other than income taxes	24,864		33,048		(8,184)		(24.8)	%
Other, net	(361)		(3,201)		2,840		(88.7)	%
Total operating costs and expenses	$	1,444,154	$	1,558,561	$	(114,407)	(7.3)	%

Fuel

The decrease in fuel costs of $74.7 million was primarily due to the following:

$ in millions		2023 vs. 2022
Volume:
	Coal	$	(92.1)
	Natural gas	160.9
	Oil	(0.9)
	Net change in volume	67.9
Price:
	Coal	34.4
	Natural gas	(244.9)
	Deferred fuel	67.9
	Net change in price	(142.6)
Net change in fuel expense		$	(74.7)

The decrease in volume of coal is primarily attributable to the retirement of Petersburg Unit 2 in June 2023. As the company exits coal, we expect that overall volumes of coal decrease over time and volumes of other fuel sources to increase. The increase in natural gas is primarily attributable to the timing of outages versus the comparable period (including the extended outage at the Eagle Valley CCGT that began in April 2021 until March 2022). The changes in the price of fuel are reflective of market prices for coal and natural gas. We are generally permitted to recover underestimated fuel and purchased power costs to serve our retail customers in future rates through quarterly FAC proceedings. These variances are deferred when incurred and amortized into expense in the same period that our rates are adjusted to reflect these variances. Additionally, fuel and purchased power costs incurred for wholesale energy sales are considered in the Off System Sales Margin rider.

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Power Purchased

The decrease in purchased power costs of $40.0 million was primarily due to the following:

$ in millions		2023 vs. 2022
Volume:
	Net change in the volume of power purchased primarily due to AES Indiana's generation units running more frequently, as well as the timing and duration of outages, during these respective periods	$	(25.4)
Price:
	Market prices	(60.5)
	Deferred purchased power	31.4
	Net change in price	(29.1)
Other, net (mostly due to changes in capacity purchases)		14.5
Net change in power purchased costs		$	(40.0)

The volume of power purchased each period is primarily influenced by retail demand, generating unit capacity and outages, and the relative cost of producing power versus purchasing power in the market. The market price of purchased power is influenced primarily by changes in the market price of delivered fuel (primarily natural gas), the supply of and demand for electricity, and the time of day during which power is purchased.

The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. The IURC initiated a sub-docket in FAC-133 (IURC Cause No. 38703-FAC-133 S1) to examine the impact of the Eagle Valley extended outage, which was settled in October 2022. A $27.8 million charge was recorded in the third quarter of 2022 resulting from the settlement of the FAC sub-docket of the Eagle Valley CCGT unplanned outage. For further discussion, please see Note 2, "Regulatory Matters - Regulatory Assets and Liabilities - Deferred Fuel" to the Financial Statements of this Annual Report on Form 10-K.

Operation and Maintenance

The decrease in Operation and maintenance expense of $15.8 million was primarily due to the following:

$ in millions	2023 vs. 2022
Decrease in compensation and benefits expense, primarily health and other insurance benefits and lower pension service costs	$	(11.4)
Decrease in DSM program costs (these program costs are recoverable through customer rates and are offset by a decrease in DSM revenue)	(8.2)
Decrease in contracted services expenses primarily due to lower generation maintenance and outage costs	(5.0)
Decrease in MISO non-purchased power costs (primarily transmission related expenses)	(3.2)
Increase in charges from the Service Company	13.3
Other, net	(1.3)
Net change in operation and maintenance costs	$	(15.8)

Depreciation and Amortization

The increase in Depreciation and amortization expense of $21.4 million was mostly attributed to the impact of additional assets placed in service and higher amortization of regulatory assets.

Taxes Other Than Income Taxes

The decrease in Taxes other than income taxes of $8.2 million was mostly attributed to (i) a decrease in taxes of $11.4 million related to the repeal of the URT in June 2022 (for further discussion, please see Note 2, "Regulatory Matters - House Bill 1002" to the Financial Statements of this Annual Report on Form 10-K), partially offset by (ii) an increase in property tax expense of $4.3 million primarily as a result of higher assessed values.

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Other, Net

The change in Other, net of $2.8 million was primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition of $3.2 million resulting in higher one-time expenses in 2022. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - Hardy Hills Solar Project " to the Financial Statements of this Annual Report on Form 10-K for more information.

Other (Expense) / Income, Net

The following table illustrates changes in Other (expense) / income, net from 2022 to 2023 (in thousands):

	Years Ended
	December 31,
	2023		2022		$ Change		% Change
Other (expense) / income, net:
Allowance for equity funds used during construction	$	9,315	$	4,784	$	4,531	94.7	%
Interest expense	(142,926)		(131,232)		(11,694)		8.9	%
Other (expense) / income, net	(410)		11,783		(12,193)		(103.5)	%
Total other expense, net	$	(134,021)	$	(114,665)	$	(19,356)	16.9	%

Allowance for Equity Funds Used During Construction

The increase in Allowance for equity funds used during construction of $4.5 million was primarily due to increased construction activity.

Interest Expense

The increase in Interest expense of $11.7 million was primarily due to (i) higher interest expense on debt of $17.1 million mostly due to new debt issuances (including $350 million AES Indiana first mortgage bonds in November 2022 and $300 million Term Loan in November 2023) and higher line of credit balances, partially offset by (ii) an increase in the allowance for borrowed funds used during construction of $5.5 million.

Other (Expense) / Income, Net

The decrease in Other (expense) / income, net of $12.2 million was primarily due to (i) an increase in defined benefit plan costs of $17.3 million (mostly as a result of higher interest cost), partially offset by (ii) an increase in investment income of $5.1 million.

Income Tax Expense

The following table illustrates changes in income tax expense from 2022 to 2023 (in thousands):

	Years Ended
	December 31,
	2023		2022		$ Change		% Change
Income tax expense	$	14,715	$	21,859	$	(7,144)	(32.7)	%

The decrease in income tax expense of $7.1 million was primarily driven by lower pretax income versus the comparable period, partially offset by tax effects associated with HLBV in the current period.

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Dividends On and Redemption of Preferred Stock

The decrease in Dividends on and redemption of preferred stock was due to AES Indiana's redemption of its cumulative preferred stock on December 30, 2022. See Note 9, "Equity And Cumulative Preferred Stock - Cumulative Preferred Stock" to the Financial Statements of this Annual Report on Form 10-K for more information.

Net Loss Attributable to Noncontrolling Interests

The following table illustrates changes in Net loss attributable to noncontrolling interests from 2022 to 2023 (in thousands):

	Years Ended
	December 31,
	2023		2022		$ Change		% Change
Net loss attributable to noncontrolling interests	$	(26,093)	$	—	$	(26,093)	(100.0)	%

The Net loss attributable to noncontrolling interests of $26.1 million for the year ended December 31, 2023 was related to the initial allocation of earnings from tax attributes using the HLBV method upon the first stage of the Hardy Hills Solar Project being placed in service in December 2023. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - Hardy Hills Solar Project " to the Financial Statements of this Annual Report on Form 10-K for more information.

KEY TRENDS AND UNCERTAINTIES

During 2024 and beyond, we expect that our financial results will be driven primarily by retail demand, weather, and maintenance costs. In addition, our financial results will likely be driven by many other factors including, but not limited to:

▪regulatory outcomes and impacts;

▪the passage of new legislation, implementation of regulations or other changes in regulation; and

▪timely recovery of capital expenditures and operation and maintenance costs.

If favorable outcomes related to these factors do not occur, or if the challenges described below and elsewhere in this report impact us more significantly than we currently anticipate, then these factors, or other factors unknown to us, may impact our operating margin, net income and cash flows. We continue to monitor our operations and address challenges as they arise. For a discussion of the risks related to our business, see “Item 1. Business” and “Item 1A. Risk Factors” of this Annual Report on Form 10-K.

Operational

Trade Restrictions and Supply Chain

On March 29, 2022, the U.S. Department of Commerce (“Commerce”) announced the initiation of an investigation into whether imports into the U.S. of solar cells and panels imported from Cambodia, Malaysia, Thailand and Vietnam ("Southeast Asia") are circumventing antidumping and countervailing duty ("AD/CVD") orders on solar cells and panels from China. This investigation resulted in disruptions to the import of solar panels from Southeast Asia. On June 6, 2022, President Biden issued a Proclamation waiving any circumvention duties on imported solar cells and panels from Southeast Asia that result from this investigation for a 24-month period ending June 6, 2024. Suppliers resumed importing cells and panels from Southeast Asia into the U.S. pursuant to a Commerce certification regime implementing the Proclamation.

On December 2, 2022, Commerce issued country-wide affirmative preliminary determinations that circumvention had occurred in each of the four Southeast Asian countries. Commerce also evaluated numerous individual companies and issued preliminary determinations that circumvention had occurred with respect to many but not all of these companies. Additionally, Commerce issued a preliminary determination that circumvention would not be deemed to occur for any solar cells and panels imported from the four countries if the wafers were manufactured outside of China or if no more than two out of six specifically identified components were produced in China. On August 18, 2023, Commerce issued its final determinations on the matter and affirmed its preliminary findings in

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most respects. Additionally, Commerce found that three of the specific companies it investigated were not circumventing.

On December 29, 2023, Auxin Solar and Concept Clean Energy filed a lawsuit with the U.S. Court of International Trade, challenging certain aspects of the final rule promulgated by Commerce to implement the Proclamation. The lawsuit specifically challenges Commerce’s decisions not to suspend the final disposition of certain entries of imported solar cells and panels from Southeast Asia made prior to June 6, 2024, and not to collect AD/CVD deposits with respect to those entries. The Department of Justice has responded by filing a motion to dismiss the lawsuit.

While we have executed agreements for AES Indiana's existing solar projects, further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements with respect to these projects on terms that we deem satisfactory and these and future disruptions may impact the availability or costs of future projects. The impact of any adverse Commerce determination, the impact of the UFLPA, future disruptions to the solar panel supply chain and their effect on AES Indiana's solar project development and construction activities is uncertain. AES Indiana will continue to monitor developments and take prudent steps towards managing our renewables projects.

Capital Projects

Our construction projects have experienced some indications of delays and price increases due to supply chain disruptions; however, they are currently proceeding without material delays. For further discussion of our capital requirements, see "Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity" of this Annual Report on Form 10-K.

Macroeconomic and Political

IRA and U.S. Renewable Energy Tax Credits

The IRA was signed into law in the United States. The IRA includes provisions that are expected to benefit the Company's planned clean energy projects, including increases, extensions, and/or new tax credits for wind, solar, and storage. We expect that the extension of the current solar ITCs for projects that satisfy wage and apprenticeship requirements, as well as the "technology neutral" clean electricity PTC and ITC will provide incremental benefits for our current and future planned renewable projects. For further discussion of our renewable projects, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation" to the Financial Statements of this Annual Report on Form 10-K.

We account for renewable projects according to GAAP, which, when partnering with tax-equity investors to monetize tax benefits, utilizes the HLBV method. This method recognizes the tax-credit value that is transferred to tax equity investors at the time of its creation, which for projects utilizing the ITC, begins in the quarter the project is placed in service. For projects utilizing the PTC, this value is recognized over 10 years as the facility produces energy. In 2023, we recognized $26.1 million of earnings from tax attributes using the HLBV method upon the first stage of the Hardy Hills Solar Project being placed in service. As we progress in our plan of integrating additional renewable energy projects under our 2022 IRP, as discussed further below, we anticipate additional earnings associated with the tax attributes of these projects.

The implementation of the IRA requires substantial guidance from the U.S. Department of Treasury and other government agencies. While some of that guidance remains pending, there will be uncertainty with respect to the implementation of certain provisions of the IRA.

U.S. Income Tax

The macroeconomic and political environments in the U.S. have changed during 2022 and 2023. This could result in significant impacts to tax law.

Inflation

In the markets in which we operate, there have been higher rates of inflation recently. If inflation continues to increase in our markets, it may increase our expenses that we may not be able to pass through to customers. It may

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also increase the costs of some of our construction projects. AES Indiana may have the ability to recover operations and maintenance costs through the regulatory process, however, timing impacts on recovery may vary. In addition, we expect the cost of fuel, specifically coal and natural gas, to continue to be volatile during 2024. Our exposure to fluctuations in the price of fuel is limited because of our FAC. If we are unable to timely or fully recover our fuel and purchased power costs, however, it could have a material adverse effect on our results of operations, financial condition and cash flows.

Interest Rates

In the U.S. there has been a rise in interest rates during 2021 through 2023. Looking ahead, we anticipate a landscape marked by volatility in interest rates in the near term. Although all of our existing IPALCO and AES Indiana long-term debt is at fixed rates, an increase in interest rates can have several impacts on our business. For our existing short-term debt under floating rate structures and any future debt refinancings or future new money financings, rising interest rates will increase future financing costs. Our floating rate debt is currently limited to short-term borrowings under our Credit Agreement and $300 million Term Loan Agreement. For future IPALCO debt financings, IPALCO manages a hedging program to reduce uncertainty and exposure to future interest rates.

Bipartisan Infrastructure Law (Infrastructure Investment and Jobs Act)

In November 2021, President Biden signed into law the Infrastructure Investment and Jobs Act, which provides for approximately $1.2 trillion of federal spending over the next five years across the United States. The BIL’s energy-related provisions include new federal funding for power grid infrastructure and resiliency investments, new and existing energy efficiency and weatherization programs, electric vehicle infrastructure for public chargers and additional Low Income Home Energy Assistance Program funding. AES Indiana is participating as a sub-recipient for a Department of Energy Office of Energy Efficiency and Renewable Energy Topic 2 award and has identified other potential opportunities associated with the BIL and is submitting concept papers and grants for those that align with its strategy going forward.

Regulatory

Regulatory Rate Review

On June 28, 2023, AES Indiana filed a petition with the IURC for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

2022 IRP

AES Indiana filed its 2022 IRP with the IURC in December 2022. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. For further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K.

Please see “Item 1. Business – Regulation” and Note 2, “Regulatory Matters” to the Financial Statements of this Annual Report on Form 10-K for further discussion of these and other regulatory matters.

CAPITAL RESOURCES AND LIQUIDITY

Overview

As of December 31, 2023, we had unrestricted cash and cash equivalents of $28.6 million and available borrowing capacity of $195 million under our unsecured revolving Credit Agreement. All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from the FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order

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from the IURC granting authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available under the order as of December 31, 2023. This order also grants authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt, AES Indiana has authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. We also have restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. We do not believe such restrictions will be a limiting factor in our ability to issue debt in the ordinary course of prudent business operations.

We depend on timely and continued access to capital markets to manage our liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty or otherwise could have material adverse effects on our financial condition and results of operations. In addition, changes in the timing of tariff increases or delays in the regulatory determinations as well as unfavorable regulatory outcomes could have a material adverse effect on our results of operations, financial condition and cash flows. See "Risks related to our indebtedness and financial condition" in "Item 1A. Risk Factors" and "Regulation" in "Item 1 - Business" of this Annual Report on Form 10-K for more information. From time to time, we may elect to repurchase our outstanding debt through cash purchases, privately negotiated transactions or otherwise when management believes such repurchases are favorable to make. The amounts involved in any such repurchases may be material.

Cash Flows

The following table summarizes the changes in operating, investing, and financing cash flows for the comparative periods:

	Years ended December 31,						$ Change
	2023		2022		2021		2023 vs. 2022
	(in thousands)
Net cash provided by operating activities	$	391,933	$	346,346	$	225,217	$	45,587
Net cash used in investing activities	(992,873)		(525,087)		(368,715)		(467,786)
Net cash provided by financing activities	427,971		373,377		123,793		54,594
Net change in cash, cash equivalents and restricted cash	(172,969)		194,636		(19,705)		(367,605)
Cash, cash equivalents and restricted cash at beginning of year	201,553		6,917		26,622		194,636
Cash, cash equivalents and restricted cash at end of year	$	28,584	$	201,553	$	6,917	$	(172,969)

The following cash flow discussion compares the cash flows for the year ended December 31, 2023 to the cash flows for the year ended December 31, 2022. For discussion comparing the cash flows for the year ended December 31, 2022 to the cash flows for the year ended December 31, 2021, see Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2022 Annual Report on Form 10-K, filed with the SEC on March 1, 2023.

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2023 versus 2022

Operating Activities

The following table summarizes the key components of our consolidated operating cash flows:

	Years ended December 31,						$ Change
	2023		2022		2021		2023 vs. 2022
	(in thousands)
Net income	$	57,027	$	96,626	$	119,182	$	(39,599)
Depreciation and amortization	287,863		266,504		256,085		21,359
Amortization of deferred financing costs and debt discounts	3,880		3,914		3,915		(34)
Deferred income taxes and investment tax credit adjustments - net	32,653		(6,706)		(7,378)		39,359
Allowance for equity funds used during construction	(9,315)		(4,784)		(5,412)		(4,531)
Gain on acquisition	—		—		(5,630)		—
Net income, adjusted for non-cash items	372,108		355,554		360,762		16,554
Net change in operating assets and liabilities	19,825		(9,208)		(135,545)		29,033
Net cash provided by operating activities	$	391,933	$	346,346	$	225,217	$	45,587

The net change in operating assets and liabilities for the year ended December 31, 2023 compared to the year ended December 31, 2022 was driven by the following (in thousands):

Increase in accounts receivable driven primarily by the timing of collections	$	19,989
Increase in accounts payable due to the timing of invoices and payments	14,955
Increase in inventories due to the timing of coal purchases and higher coal prices in the current year	17,318
Decrease from prepaids mainly due to higher advanced capacity purchases and collateral deposits in 2023	(25,532)
Other	2,303
Net change in operating assets and liabilities	$	29,033

Investing Activities

Net cash used in investing activities increased $467.8 million for the year ended December 31, 2023 compared to the year ended December 31, 2022, which was primarily driven by (in thousands):

Higher cash outflows for capital expenditures related with renewable energy projects, higher T&D maintenance related capital expenditures and growth related capital expenditures primarily from TDSIC Plan	$	(406,195)
Higher cash outflows from purchase of intangibles in 2023	(44,650)
Higher cash outflows on cost of removal due to the timing of payments	(21,647)
Other	4,706
Net change in investing activities	$	(467,786)

Financing Activities

Net cash provided by financing activities increased $54.6 million for the year ended December 31, 2023 compared to the year ended December 31, 2022, which was primarily driven by (in thousands):

Increase due to higher net revolver draws on AES Indiana's revolving credit facility	$	215,000
Increase due to sales to noncontrolling interests	77,921
Increase due to redemption of preferred stock in the prior year	60,080
Decrease due to lower equity contributions from shareholders	(253,000)
Decrease due to lower debt issuances	(50,000)
Other	4,593
Net change in financing activities	$	54,594

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Capital Requirements

Capital Expenditures

Our capital expenditure program, including development and permitting costs, for the three-year period from 2024 through 2026 is currently estimated to cost approximately $3.2 billion (excluding environmental compliance), and includes estimates as follows (amounts in millions):

							For the three-year period
	2024		2025		2026		from 2024 through 2026
Power generation related projects	$	786.8	$	654.9	$	430.2	$	1,871.9	(1)
Transmission and distribution related additions, improvements and extensions	202.8		298.8		210.2		711.8		(2)
TDSIC Plan investments	177.6		194.9		156.6		529.1		(3)
Other miscellaneous equipment	37.1		28.5		27.2		92.8
Total estimated costs of capital expenditure program	$	1,204.3	$	1,177.1	$	824.2	$	3,205.6
(1) Includes spending for AES Indiana's power generation and renewable energy projects.
(2) Additions, improvements and extensions to AES Indiana's transmission and distribution lines, substations, power factor and voltage regulating equipment, distribution transformers and street lighting facilities.
(3) Includes spending under AES Indiana's TDSIC plan approved by the IURC on March 4, 2020 for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Total TDSIC costs expended from project inception through December 31, 2023 were $678.8 million.

The amounts described in the capital expenditure program above include estimated spending under AES Indiana's 2022 IRP filed with the IURC in December 2022. See Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP" to the Financial Statements of this Annual Report on Form 10-K for further discussion. Additionally, estimated capital expenditure spending on environmental compliance costs for the three-year period from 2024 through 2026 is approximately $90 million. Please see “Item 1. Business - Environmental Matters" for additional details.

Capital Resources

As IPALCO is a holding company, substantially all of its cash is generated by the operating activities of its subsidiaries, principally AES Indiana. None of its subsidiaries, including AES Indiana, are obligated under or have guaranteed to make payments with respect to the 2024 IPALCO Notes or the 2030 IPALCO Notes; however, all of AES Indiana’s common stock is pledged to secure these debt obligations. Accordingly, IPALCO’s ability to make payments on the 2024 IPALCO Notes and the 2030 IPALCO Notes depends on the ability of AES Indiana to generate cash and distribute it to IPALCO.  

Liquidity

We expect our existing cash balances, cash generated from operating activities and borrowing capacity on our existing Credit Agreement will be adequate to meet our anticipated operating needs, including interest expense on our debt and dividends to our equity owners. Our business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and carrying costs, potential margin requirements related to interest rate and commodity hedges, taxes and dividend payments. For 2024 and subsequent years, we expect to satisfy these requirements with a combination of cash from operations, funds from debt financing, funds from tax equity contributions, and parent capital contributions as our internal liquidity needs and market conditions warrant. We also expect that the borrowing capacity under our existing Credit Agreement will continue to be available to manage working capital requirements during those periods. The absence of adequate liquidity could adversely affect our ability to operate our business and have a material adverse effect on our results of operations, financial condition and cash flows.

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Indebtedness

Significant Debt Transactions

For further discussion of our significant debt transactions, please see Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K.

Line of Credit

AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders, as discussed in Note 6, “Debt - Line of Credit” to the Financial Statements of this Annual Report on Form 10-K.

We had the following amounts available under the revolving Credit Agreement:

$ in millions	Type	Maturity	Commitment		Amounts available at December 31, 2023
AES Indiana	Revolving	December 2027	$	350.0	$	195.0

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement (as well as the amount of certain other fees in the Credit Agreement) are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded. Any reduction in our debt or credit ratings may adversely affect the trading price of our outstanding debt securities.

The following table presents the debt ratings and credit ratings (issuer/corporate rating) and outlook for IPALCO and AES Indiana.

Debt ratings	IPALCO	AES Indiana	Outlook
Fitch Ratings	BBB (a)	A (b)	Stable
Moody’s Investors Service	Baa3 (a)	A2 (b)	Stable
S&P Global Ratings	BBB- (a)	A- (b)	Stable
Credit ratings	IPALCO	AES Indiana	Outlook
Fitch Ratings	BBB-	BBB+	Stable
Moody’s Investors Service	—	Baa1	Stable
S&P Global Ratings	BBB	BBB	Stable
(a) Ratings relate to IPALCO's Senior Secured Notes
(b) Ratings relate to AES Indiana's first mortgage bonds

We cannot predict whether our current debt and credit ratings or the debt and credit ratings of AES Indiana will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. A security rating is not a recommendation to buy, sell or hold securities. Such ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

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Contractual Obligations

Our non-contingent contractual obligations as of December 31, 2023 are set forth below:

	Payments due in:
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(In Millions)
Short-term and long-term debt	$	3,488.8	$	900.0	$	130.0	$	—	$	2,458.8
Interest obligations	1,788.4		159.6		241.0		239.8		1,148.0
Finance lease obligations	44.6		0.9		1.8		1.9		40.0
Purchase obligations:
Coal, gas, purchased power and
related transportation	933.5		249.7		267.3		225.7		190.8
Other	409.1		355.0		32.8		20.2		1.1
Total	$	6,664.4	$	1,665.2	$	672.9	$	487.6	$	3,838.7

Short-term and long-term debt:

Our short-term and long-term debt at December 31, 2023 consists of outstanding borrowings on the Credit Agreement, $300 million Term Loan Agreement, AES Indiana first mortgage bonds and IPALCO long-term debt. These long-term debt amounts include current maturities but exclude unamortized debt discounts and deferred financing costs. See Note 6, "Debt" to the Financial Statements of this Annual Report on Form 10-K.

Interest payments:

Interest payments are associated with the short-term and long-term debt described above. The interest payments relating to variable-rate debt are projected using the interest rates in effect at December 31, 2023.

Finance lease obligations:

Finance lease obligations are primarily related to land. For additional information, see Note 14, "Leases - Lessee" to the Financial Statements of this Annual Report on Form 10-K.

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.

Purchase orders and other contractual obligations:

At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements of this Annual Report on Form 10-K for additional information on the items excluded.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We prepare our consolidated financial statements in accordance with GAAP. As such, we are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period presented. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. Significant accounting policies used in the preparation of the consolidated financial statements are described in Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K. This section addresses only those accounting policies involving amounts material to our financial statements that require the most estimation, judgment or assumptions and should be read in conjunction with Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K.

Revenue Recognition

For information regarding the nature of our revenue streams and our critical accounting policies affecting revenue recognition, please see Note 1, “Overview and Summary of Significant Accounting Policies - Revenue Recognition” and Note 13, "Revenue" to the Financial Statements of this Annual Report on Form 10-K.

Income Taxes

We are subject to federal and state income taxes. Our income tax provision requires significant judgment and is based on calculations and assumptions that are subject to examination by the U.S. Internal Revenue Service and other tax authorities. We regularly assess the potential outcome of tax examinations when determining the adequacy of our income tax provisions by considering the technical merits of the filing position, case law, and results of previous tax examinations. Accounting guidance for uncertainty in income taxes prescribes a more-likely-than-not recognition threshold and measurement requirements for financial statement reporting of our income tax positions. If tax positions do not meet the more-likely-than-not threshold, reserves will be established. These reserves are adjusted only when there is more information available or when an event occurs necessitating a change to the reserves. While we have reasonably determined that a tax reserve is not required as of December 31, 2023, it is possible that the ultimate outcome of future examinations may be materially different than our current assessment of uncertain tax positions. Please see Note 1, “Overview and Summary of Significant Accounting Policies - Income Taxes” and Note 7, "Income Taxes" to the Financial Statements of this Annual Report on Form 10-K for more information.

Regulatory Assets and Liabilities

As a regulated utility, we apply the provisions of ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of the IURC and the FERC. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds or future rate reductions to customers for previous overcollections or the deferral of revenue collected for costs that AES Indiana expects to incur in the future. Specific regulatory assets and liabilities are disclosed in Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” to the Financial Statements of this Annual Report on Form 10-K.  

The deferral of costs (as regulatory assets) is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the IURC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period income. Our regulatory assets and liabilities have been created pursuant to specific orders of the IURC or established regulatory practices, such as other utilities under the jurisdiction of the IURC being granted recovery of similar costs. It is probable, but not certain, that these regulatory assets will be recoverable, subject to IURC approval.

AROs

In accordance with the provisions of GAAP relating to the accounting for AROs, legal obligations associated with the retirement of long-lived assets are required to be recognized at their fair value at the time those obligations are

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incurred. Upon initial recognition of a legal liability, costs are capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. These GAAP provisions also require that components of previously recorded depreciation related to the cost of removal of assets upon future retirement, whether legal AROs or not, must be removed from a company’s accumulated depreciation reserve and be reclassified as a regulatory liability. We make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to AROs. These assumptions and estimates are based on historical experience and assumptions that we believe to be reasonable at the time. See Note 3, "Property, Plant and Equipment - ARO" to the Financial Statements of this Annual Report on Form 10-K for more information.

Pension Plans

The valuation of our benefit obligation, fair value of plan assets, and net periodic benefit costs requires various estimates and assumptions, the most significant of which include the discount rate and expected return on plan assets. We review these and other assumptions, such as mortality, on an annual basis. Please see Note 1, “Overview and Summary of Significant Accounting Policies - Pension and Postretirement Benefits” and Note 8, "Benefit Plans" to the Financial Statements of this Annual Report on Form 10-K for more information.

Contingent and Other Obligations

During the conduct of our business, we are subject to a number of federal and state laws and regulations, as well as other factors and conditions that potentially subject us to environmental, litigation, insurance and other risks. We periodically evaluate our exposure to such risks and record estimated liabilities for those matters where a loss is considered probable and reasonably estimable in accordance with GAAP. In recording such estimated liabilities, we may make assumptions, estimates and judgments that affect the reported amounts of assets, liabilities and expenses as they relate to contingent and other obligations. These assumptions and estimates are based on historical experience and assumptions and may be subject to change. We believe such estimates and assumptions are reasonable.

Please see Note 1, “Overview and Summary of Significant Accounting Policies - Contingencies” and Note 10, “Commitments and Contingencies” to the Financial Statements of this Annual Report on Form 10-K for information about significant contingencies involving us.

NEW ACCOUNTING STANDARDS

Please see Note 1, “Overview and Summary of Significant Accounting Policies” to the Financial Statements of this Annual Report on Form 10-K for a discussion of new accounting pronouncements and the potential impact to our results of operations, financial condition and cash flows.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Overview

The primary market risks to which we are exposed are those associated with environmental regulation, debt and equity investments, fluctuations in interest rates and the prices of SO2 and NOx allowances and certain raw materials. We sometimes use financial instruments and other contracts to hedge against such fluctuations, including, on a limited basis, financial and commodity derivatives. We generally do not enter into derivative instruments for trading or speculative purposes. Our U.S. Risk Management Committee (U.S. RMC), comprised of members of senior management, is responsible for establishing risk management policies and the monitoring and reporting of risk exposures related to our operations. The U.S. RMC meets on a regular basis with the objective of identifying, assessing and quantifying material risk issues and developing strategies to manage these risks.

The disclosures presented in this section are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this section. For further information regarding market risk, see "Item 1A.—Risk Factors." Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the electricity markets, which could have a material adverse effect on our financial performance; and we may not be adequately hedged against our exposure to changes in interest rates.

56

Wholesale Sales

We engage in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO day-ahead and real-time markets. Our ability to compete effectively in the wholesale market is dependent on a variety of factors, including our generating availability, the supply of wholesale power, the demand by load-serving entities, and the formation of AES Indiana’s offers into the market. Our wholesale revenue is generated primarily from sales directly to the MISO energy market. The average price per MWh we sold in the wholesale market was $34.13, $69.14 and $27.60 in 2023, 2022 and 2021, respectively. For the periods presented in the Financial Statements of this Annual Report on Form 10-K, a decline in wholesale prices could have had a negative impact on wholesale margins, because most of our non-fuel costs are fixed in the short term and lower wholesale prices can result in lower wholesale volumes sold. However, the impact is limited as the 2018 Base Rate Order provides that annual wholesale margins earned above (or below) a benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Our wholesale revenue represented 4.5% of our total electric revenue over the past five years. As a result, we anticipate that a 10% change in the market price for wholesale electricity would not have a material impact on our results of operations.

Fuel

We have limited exposure to commodity price risk for the purchase of coal and natural gas, the primary fuels used by us for the production of electricity. We manage this risk for coal by providing for a significant portion of our current projected burn through 2024 and approximately 83% of our current projected burn for the two-year period ending December 31, 2025, under long-term contracts. In addition, AES Indiana has established physical natural gas hedges for firm supply over a two year period in accordance with a hedge program approved by the IURC. Pricing provisions in some of our long-term contracts allow for price changes under certain circumstances. Our exposure to fluctuations in the price of fuel is limited because pursuant to Indiana law, we apply to the IURC for a change in our fuel charge every three months to recover our estimated fuel costs, which may be above or below the levels included in our basic rates. We must present evidence in each FAC proceeding that we have made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to our retail customers at the lowest fuel cost reasonably possible.

Power Purchased

We depend on purchased power, in part, to meet our retail load obligations. As a result, we also have limited exposure to commodity price risk for the purchase of electric energy for our retail customers. Purchased power costs can be highly volatile. We are committed under long-term power purchase agreements to purchase all the electricity generated from a project located in Indiana ("Hoosier Wind Project") and a second project located in Minnesota, that have a combined maximum output capacity of 300 MW and have 94.5 MW of solar-generated electricity in our service territory under long-term contracts. AES Indiana is currently in the process of acquiring the Hoosier Wind Project and the existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We also purchase up to 8 MW of energy from a combined heat and power facility. We are generally allowed to recover, through our FAC, the energy portion of purchased power costs incurred to meet jurisdictional retail load. In certain circumstances, we may not be allowed to recover a portion of purchased power costs incurred to meet our jurisdictional retail load. See Note 2, “Regulatory Matters - FAC and Authorized Annual Jurisdictional Net Operating Income” to the Financial Statements of this Annual Report on Form 10-K.

Equity Price Risk

Our Pension Plans are impacted significantly by the economy as a result of the Pension Plans being invested in common equity securities. The performance of the Pension Plans’ investments in such common equity securities and other instruments impacts our earnings as well as our funding liability. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $8.3 million reduction in fair value as of December 31, 2023 and approximately a $5.7 million increase to the 2024 pension expense. Please see Note 8, “Benefit Plans” to the Financial Statements of this Annual Report on Form 10-K for additional Pension Plan information.

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Interest Rate Risk

We use long-term debt as a significant source of capital in our business, which exposes us to interest rate risk. We do not enter into market risk sensitive instruments for trading purposes. We manage our exposure to interest rate risk through the use of fixed-rate debt and by refinancing existing long-term debt at times when it is deemed economic and prudent. In addition, AES Indiana’s Credit Agreement and $300 million Term Loan Agreement bears interest at a variable rate based either on the Prime interest rate or on the SOFR. Fair values relating to financial instruments are dependent upon prevalent market rates of interest. At December 31, 2023, we had approximately $3,033.8 million principal amount of fixed rate debt and $455.0 million variable rate debt outstanding. In regard to our fixed rate debt, the interest rate risk with respect to long-term debt primarily relates to the potential impact a decrease in interest rates has on the fair value of our fixed-rate debt and not on our financial condition or results of operations. Our interest rate risk on our fixed-rate debt is associated with refinancing activity.

The following table shows our consolidated indebtedness (in millions) by maturity as of December 31, 2023:

	2024		2025		2026		2027		2028		Thereafter		Total		Fair Value
Fixed-rate	$	445.0	$	40.0	$	90.0	$	—	$	—	$	2,458.8	$	3,033.8	$	2,860.5
Variable-rate	455.0		—		—		—		—		—		455.0		455.0
Total Indebtedness	$	900.0	$	40.0	$	90.0	$	—	$	—	$	2,458.8	$	3,488.8	$	3,315.5
Weighted Average Interest Rates by Maturity	5.087%		0.650%		0.883%		N/A		N/A		4.877%		4.780%

For further discussion of our fair value of our indebtedness and book value of our indebtedness please see Note 4, “Fair Value” and Note 6, “Debt” to the Financial Statements of this Annual Report on Form 10-K.

Retail Energy Market

The legislatures of several states have enacted laws that allow various forms of competition or that experiment with allowing some form of customer choice of electricity suppliers for retail sales of electric energy. Indiana has not done so. In Indiana, competition among electric energy providers for sales has focused primarily on the sale of bulk power to other public and municipal utilities. Indiana law provides for electricity suppliers to have exclusive retail service areas. In order to increase sales, we work to attract new customers into our service territory. Although the retail sales of electric energy are regulated, we face competition from other energy sources. For example, customers have a choice of installing electric or natural gas home and hot water heating systems or installing qualified generation facilities on their premises.

Counterparty Credit Risk

At times, we may utilize forward purchase contracts to manage the risk associated with power purchases and could be exposed to counterparty credit risk in these contracts. We manage this exposure to counterparty credit risk by entering into contracts with companies that are expected to fully perform under the terms of the contract. Individual credit limits are generally implemented for each counterparty to further mitigate credit risk. We may also require a counterparty to provide collateral in the event certain financial benchmarks are not maintained, or certain credit ratings are not maintained. 

We are also exposed to counterparty credit risk related to our ability to collect electricity sales from our customers, which may be impacted by volatility in the financial markets and the economy. Historically, our write-offs of customer accounts have been immaterial, which is common for the electric utility industry. 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

	Page No.
IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2023, 2022 and 2021 (PCAOB ID: 42)	60
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	63
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022 and 2021	64
Consolidated Balance Sheets as of December 31, 2023 and 2022	65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	66
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021	67
Notes to Consolidated Financial Statements	68
AES Indiana and Subsidiaries – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2023, 2022 and 2021 (PCAOB ID: 42)	112
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	115
Consolidated Balance Sheets as of December 31, 2023 and 2022	116
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	117
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021	118
Notes to Consolidated Financial Statements	119

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of IPALCO Enterprises, Inc.                                

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of IPALCO Enterprises, Inc. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedules listed in the Index at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Board of Directors and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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	Regulatory Accounting
	Regulatory Accounting
Description of the Matter	As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASB Accounting Standards Codification 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory liabilities generally represent obligations to provide refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that the Company expects to incur in the future. Accounting for the economics of rate regulation affects multiple consolidated financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; revenues; and depreciation expense, and related disclosures in the Company’s consolidated financial statements
	Auditing the Company’s regulatory accounting was complex due to significant judgments made by management to support its assertions about the impact of future regulatory orders on the consolidated financial statements. In particular, there is subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred through December 31, 2023, judgment required to evaluate the relevance and reliability of audit evidence to support impacted account balances and disclosures, and judgments involved in assessing the probability of recovery in future rates of incurred costs or refunds to customers. These assumptions have a significant effect on the consolidated financial statements and related disclosures.
How We Addressed the Matter in Our Audit	To evaluate the Company’s significant judgments in accounting for regulatory assets and liabilities, our audit procedures included, among others, reviewing relevant regulatory orders, statutes and interpretations; filings made by intervening parties; and other publicly available information, to assess the likelihood of recovery of regulatory assets in future rates or of a refund or future reduction in rates for regulatory liabilities based on precedents for the treatment of similar costs under similar circumstances. We evaluated the Company’s assertions regarding the probability of recovery of regulatory assets or refund or future reduction in rates for regulatory liabilities, to assess the Company’s assertion that amounts are probable of recovery or of a refund or future reduction in rates.

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	Asset Retirement Obligations
	Regulatory Accounting
Description of the Matter	At December 31, 2023, the Company’s asset retirement obligations (“ARO”) totaled $249.9 million. As described in Note 3 to the consolidated financial statements, the Company’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The Company recorded adjustments to its ARO liabilities of $30.0 million during 2023. ARO liabilities incurred in 2023 primarily related to FGD residual water disposal. ARO liabilities were revised in 2023 primarily to reflect revisions to cash flow estimates due to increases to estimated ash pond closure costs.
	Auditing the Company’s ARO liabilities was complex and highly judgmental due to the significant estimation required by management to determine the estimated cost estimates of the legal obligations associated with the Company’s generating plants, transmission system and distribution system. In particular, the estimate was sensitive to significant assumptions including the scope and method of decommissioning and timing of related cash flows.
How We Addressed the Matter in Our Audit	To test the Company’s ARO liability estimates, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing significant assumptions and inputs including the timing of activities, projected closure dates and the method of decommissioning. We involved our specialists in our assessment of the Company’s ARO liabilities including reviewing the Company’s methodology, evaluating the reasonableness of the cost estimates and assumptions, and assessing completeness of the estimates with respect to regulatory requirements.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2008.

Indianapolis, Indiana

February 26, 2024

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2023, 2022 and 2021
	2023		2022		2021
	(In Thousands)
REVENUE	$	1,649,917	$	1,791,711	$	1,426,132
OPERATING COSTS AND EXPENSES:
Fuel	494,000		568,676		255,817
Power purchased	159,908		199,860		175,025
Operation and maintenance	477,880		493,674		449,746
Depreciation and amortization	287,863		266,504		256,085
Taxes other than income taxes	24,864		33,048		44,419
Other, net	(361)		(3,201)		(5,630)
Total operating costs and expenses	1,444,154		1,558,561		1,175,462
OPERATING INCOME	205,763		233,150		250,670
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction	9,315		4,784		5,412
Interest expense	(142,926)		(131,232)		(125,626)
Other (expense) / income, net	(410)		11,783		17,667
Total other expense, net	(134,021)		(114,665)		(102,547)
INCOME BEFORE INCOME TAX	71,742		118,485		148,123
Income tax expense	14,715		21,859		28,941
NET INCOME	57,027		96,626		119,182
Dividends on and redemption of preferred stock	—		3,509		3,213
Net loss attributable to noncontrolling interests	(26,093)		—		—
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	83,120	$	93,117	$	115,969

See Notes to Consolidated Financial Statements.

63

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2023, 2022 and 2021
	2023		2022		2021
	(In Thousands)
NET INCOME	$	57,027	$	96,626	$	119,182
Derivative activity:
Change in derivative fair value, net of income tax effect of $(528), $(15,309) and $(3,441), for each respective period	1,594		46,245		10,393
Reclassification to earnings, net of income tax effect of $(1,798), $(1,798) and $(1,199), for each respective period	5,431		5,431		3,620
Net change in fair value of derivatives	7,025		51,676		14,013
Other comprehensive income	7,025		51,676		14,013
Comprehensive income	64,052		148,302		133,195
Less: dividends on and redemption of preferred stock of subsidiary	—		3,509		3,213
Less: comprehensive loss attributable to noncontrolling interests	(26,093)		—		—
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	90,145	$	144,793	$	129,982

See Notes to Consolidated Financial Statements.

64

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Balance Sheets
	December 31, 2023		December 31, 2022
	(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	28,579	$	201,548
Accounts receivable, net of allowance for credit losses of $2,283 and $1,117, respectively	233,921		216,523
Inventories	143,590		123,608
Regulatory assets, current	89,419		119,723
Taxes receivable	36,481		18,000
Derivative assets, current	15,682		7,545
Prepayments and other current assets	26,358		19,882
Total current assets	574,030		706,829
NON-CURRENT ASSETS:
Property, plant and equipment	7,082,443		6,982,314
Less: Accumulated depreciation	2,954,555		3,243,968
	4,127,888		3,738,346
Construction work in progress	359,014		294,985
Total net property, plant and equipment	4,486,902		4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net	235,656		138,978
Regulatory assets, non-current	541,784		593,939
Pension plan assets	41,172		33,611
Derivative assets, non-current	—		12,172
Other non-current assets	301,979		70,354
Total other non-current assets	1,120,591		849,054
TOTAL ASSETS	$	6,181,523	$	5,589,214
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Note 6)	$	899,159	$	—
Accounts payable	292,851		189,845
Accrued taxes	22,580		22,474
Accrued interest	33,639		33,447
Customer deposits	29,308		35,097
Regulatory liabilities, current	23,371		23,348
Accrued and other current liabilities	27,547		19,014
Total current liabilities	1,328,455		323,225
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 6 and 14)	2,576,798		3,016,810
Deferred income tax liabilities	361,488		312,641
Regulatory liabilities, non-current	527,224		612,585
Accrued other postretirement benefits	2,776		3,085
Asset retirement obligations	249,930		218,729
Other non-current liabilities	5,130		11,621
Total non-current liabilities	3,723,346		4,175,471
Total liabilities	5,051,801		4,498,696
COMMITMENTS AND CONTINGENCIES (see Note 10)
EQUITY:
Common shareholders' equity
Common stock (no par value, 290,000,000 shares authorized; 108,907,318 shares issued and outstanding at December 31, 2023 and 2022)	—		—
Paid in capital	1,021,992		1,068,357
Accumulated other comprehensive income	29,294		22,269
Retained earnings / (accumulated deficit)	25,182		(108)
Total common shareholders' equity	1,076,468		1,090,518
Noncontrolling interests	53,254		—
Total equity	1,129,722		1,090,518
TOTAL LIABILITIES AND EQUITY	$	6,181,523	$	5,589,214

See Notes to Consolidated Financial Statements.

65

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2023, 2022 and 2021
	2023		2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES:	(In Thousands)
Net income	$	57,027	$	96,626	$	119,182
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	287,863		266,504		256,085
Amortization of deferred financing costs and debt discounts	3,880		3,914		3,915
Deferred income taxes and investment tax credit adjustments - net	32,653		(6,706)		(7,378)
Allowance for equity funds used during construction	(9,315)		(4,784)		(5,412)
Gain on acquisition	—		—		(5,630)
Change in certain assets and liabilities:
Accounts receivable	(17,398)		(37,387)		(13,943)
Inventories	(30,171)		(47,489)		(12,017)
Prepayments and other current assets	(6,476)		19,056		(4,593)
Accounts payable	46,993		32,038		21,417
Accrued and other current liabilities	2,790		6,532		(13,017)
Accrued taxes payable/receivable	(18,375)		(5,858)		638
Accrued interest	192		2,813		(1,099)
Pension and other postretirement benefit assets and liabilities	1,625		(8,727)		(16,592)
Current and non-current regulatory assets and liabilities	54,358		38,863		(104,759)
Other non-current liabilities	(9,445)		(14,384)		10,446
Other - net	(4,268)		5,335		(2,026)
Net cash provided by operating activities	391,933		346,346		225,217
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(902,705)		(496,510)		(291,510)
Project development costs	(4,462)		(3,910)		(1,304)
Cost of removal payments	(45,595)		(23,948)		(35,260)
Insurance proceeds	4,900		—		—
Purchase of intangibles	(44,650)		—		(26,261)
Other	(361)		(719)		(14,380)
Net cash used in investing activities	(992,873)		(525,087)		(368,715)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities	435,000		300,000		320,000
Repayments from revolving credit facilities	(280,000)		(360,000)		(335,000)
Short-term borrowings	300,000		200,000		—
Repayments of short-term borrowings	—		(200,000)		—
Long-term borrowings	—		350,000		95,000
Retirement of long-term borrowings, including early payment premium	—		—		(95,000)
Distributions to shareholders	(104,287)		(101,986)		(131,476)
Equity contributions from shareholders	—		253,000		275,000
Sales to noncontrolling interests	77,921		—		—
Redemption of preferred stock	—		(60,080)		—
Preferred dividends of subsidiary	—		(3,213)		(3,213)
Payments of deferred financing costs and discounts	(350)		(4,309)		(1,387)
Other	(313)		(35)		(131)
Net cash provided by financing activities	427,971		373,377		123,793
Net change in cash, cash equivalents and restricted cash	(172,969)		194,636		(19,705)
Cash, cash equivalents and restricted cash at beginning of year	201,553		6,917		26,622
Cash, cash equivalents and restricted cash at end of year	$	28,584	$	201,553	$	6,917
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized)	$	129,113	$	115,277	$	118,052
Income taxes	$	—	$	31,000	$	27,500
Non-cash investing activities:
Accruals for capital expenditures	$	124,626	$	66,949	$	81,325
Recognition and changes to right-of-use assets - finance leases	$	983	$	(3,402)	19,763
Non-cash financing activities:
Recognition and changes to financing lease liabilities	$	(1,408)	$	(3,402)	$	19,763

See Notes to Consolidated Financial Statements.

66

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended December 31, 2023, 2022 and 2021
	Common Shareholders' Equity
	Common Stock
(in Thousands)	Outstanding Shares	Amount		Paid in Capital		Accumulated Other Comprehensive Income (Loss)		Retained Earnings (Accumulated Deficit)		Total Common Shareholders' Equity		Cumulative Preferred Stock of Subsidiary		Noncontrolling Interests
Balance at January 1, 2021	108,907	$	—	$	588,966	$	(43,420)	$	(24,558)	$	520,988	$	59,784	$	—
Net income				—		—		119,182		119,182		3,213		—
Other comprehensive income				—		14,013		—		14,013
Preferred stock dividends				—		—		(3,213)		(3,213)		(3,213)		—
Distributions to shareholders(1)				(15,507)		—		(115,969)		(131,476)		—		—
Contributions from shareholders				275,000		—		—		275,000		—		—
Other				106		—		—		106		—		—
Balance at December 31, 2021	108,907	—		848,565		(29,407)		(24,558)		794,600		59,784		—
Net income				—		—		96,626		96,626		3,213		—
Other comprehensive income				—		51,676		—		51,676
Preferred stock dividends				—		—		(3,213)		(3,213)		(3,213)		—
Redemption of preferred stock				—		—		(296)		(296)		(59,784)		—
Distributions to shareholders(1)				(33,319)		—		(68,667)		(101,986)		—		—
Contributions from shareholders				253,000		—		—		253,000		—		—
Other				111		—		—		111		—		—
Balance at December 31, 2022	108,907	—		1,068,357		22,269		(108)		1,090,518		—		—
Net income / (loss)				—		—		83,120		83,120		—		(26,093)
Other comprehensive income				—		7,025		—		7,025		—		—
Distributions to shareholders(1)				(46,457)		—		(57,830)		(104,287)		—		—
Sales to noncontrolling interests						—		—		—		—		79,347
Other				92		—		—		92		—		—
Balance at December 31, 2023	108,907	$	—	$	1,021,992	$	29,294	$	25,182	$	1,076,468	$	—	$	53,254
(1) IPALCO made return of capital payments of $46.5 million, $33.3 million and $15.5 million in 2023, 2022 and 2021, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.

See Notes to Consolidated Financial Statements.

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IPALCO ENTERPRISES, INC. and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2023, 2022 and 2021

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL, which does business as AES Indiana. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana has approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.

AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.

In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.

In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.

For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."

IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through AES Indiana. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of AES Indiana and everything else is included in the nonutility segment.

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on

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allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. IPALCO uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by IPALCO. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

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Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	28,579	$	201,548
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	28,584	$	201,553

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,178		239
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,921	$	216,523

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk

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characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

Inventories

We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Regulatory Accounting

The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
AFUDC equity	$	9,315	$	4,784	$	5,412
AFUDC debt	$	13,739	$	8,215	$	4,815

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Impairment of Long-lived Assets

GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:

			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	8		$	261,872	$	205,910
Project development intangible assets	28		84,097		39,455
Other	Various		797		797
Less: Accumulated amortization			(111,110)		(107,184)
Intangible assets - net			$	235,656	$	138,978
	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	14,570	$	10,122	$	11,241
Estimated future amortization
Years ending December 31,
2024					$	20,764
2025					20,764
2026					22,550
2027					22,550
2028					22,550
Total					$	109,178

Implementation Costs Related to Software as a Service

IPALCO has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.

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Contingencies

IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If IPALCO’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Additionally, we use interest rate hedges to manage the interest rate risk associated with refinancing our long-term debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in the fair value being recorded within accumulated other comprehensive income, a component of shareholders' equity. We have elected not to offset net derivative positions in the Financial Statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 5, “Derivative Instruments and Hedging Activities” for additional information.

Leases

The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.

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Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):

Details about AOCI / (AOCL) components	Affected line item in the Consolidated Statements of Operations	For the Years Ended December 31,
		2023		2022		2021
Net losses on cash flow hedges (Note 5):	Interest expense	$	7,229	$	7,229	$	4,819
	Income tax effect	(1,798)		(1,798)		(1,199)
Total reclassifications for the period, net of income taxes		$	5,431	$	5,431	$	3,620

See Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCL.

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Operating Expenses – Other, Net

Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition.

Pension and Postretirement Benefits

We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at

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fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities, which are included in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

IPALCO and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.

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New Accounting Pronouncements

We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on the Company's Financial Statements.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements.

ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative	In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.	The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.	We will provide the required disclosures on a prospective basis on the date each amendment becomes effective. We do not expect ASU 2023-06 will have any impact to our consolidated financial statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures	The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.	The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures	The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.	The amendments in this Update are effective for fiscal years beginning after December 15, 2024.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

2. REGULATORY MATTERS

General

AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

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In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.  

Basic Rates and Charges

Our basic rates and charges represent the largest component of our annual revenue. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.

Regulatory Rate Review and Base Rate Orders

AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.

FAC and Authorized Annual Jurisdictional Net Operating Income

AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each

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FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.

In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.

ECCRA 

AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million.

DSM

Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively.

On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one-year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

We are currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We are also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, we have 94.5 MW of solar-generated electricity in our service territory under long-term contracts (these long-term contracts have

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expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.

TDSIC

In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue.

On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million.

IRP Filings and Replacement Generation

Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.

2022 IRP

AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.

In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

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2019 IRP

In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.

AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. Our modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023.

AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.

Hardy Hills Solar Project

In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.

On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.

On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of

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$79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.

Petersburg Energy Center Project

In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).

Pike County BESS Project

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.

Hoosier Wind Project

On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.

Incentives for Clean Energy Projects

Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.

IURC COVID-19 Orders

Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and

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2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.

EDG Rates

On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.

EV Portfolio Program

On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.

House Bill 1002

In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on the Company's net income.

Regulatory Assets and Liabilities

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

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The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:

	2023		2022		Recovery Period
	(In Thousands)
Regulatory assets, current:
Undercollections of rate riders	$	75,416	$	26,047	Approximately 1 year(1)
Fuel costs	—		79,861		Approximately 1 year(1)
Unamortized reacquisition premium on debt	188		—		Approximately 1 year
Costs being recovered through basic rates and charges	13,815		13,815		Approximately 1 year(1)
Total regulatory assets, current	89,419		119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs	115,847		131,907		Various(2)
Deferred MISO costs	21,091		34,483		Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	2,812		3,866		Through 2026(1)(3)
Unamortized reacquisition premium on debt	13,379		14,429		Over remaining life of debt
Environmental costs	66,837		68,947		Through 2046(1)(3)
COVID-19 costs	5,426		5,426		4 years(4)
Major storm damage	1,493		—		To be determined
TDSIC costs	35,979		18,547		36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs	259,892		287,463		Through 2034(1)(3)
Hardy Hills Solar Project development costs	6,774		5,744		30 years(3)
Petersburg Energy Center Project development costs	2,469		1,582		30 years(3)
Pike County BESS Project development costs	2,623		—		20 years(3)
Fuel costs	4,275		20,518		Through 2025(1)
Other miscellaneous	2,887		1,027		Various(5)
Total regulatory assets, non-current	541,784		593,939
Total regulatory assets	$	631,203	$	713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders	$	19,649	$	15,803	Approximately 1 year(1)
FTRs	3,722		7,545		Approximately 1 year(1)
Total regulatory liabilities, current	23,371		23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs	451,886		518,797		Not applicable
Deferred income taxes payable to customers through rates	74,796		88,662		Various
Hardy Hills sponsor investment tax credit	542		—		To be determined(6)
Major storm damage	—		5,126		To be determined
Total regulatory liabilities, non-current	527,224		612,585
Total regulatory liabilities	$	550,595	$	635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

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Current Regulatory Assets and Liabilities

Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.

Deferred Fuel

Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs. 

The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.  

Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs

These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.

Unamortized Reacquisition Premium on Debt

This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.

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Environmental Costs

These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years.

COVID-19 Costs

These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.

TDSIC Costs

These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from 1 to 36 years. See "TDSIC" above for additional discussion.

Petersburg Unit 1 and 2 Retirement Costs

These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.

Hardy Hills Solar Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Petersburg Energy Center Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Pike County BESS Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.

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ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana and IPALCO remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, we have a net regulatory deferred income tax liability of $74.8 million and $88.7 million as of December 31, 2023 and 2022, respectively.

3.  PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:

	As of December 31,
	2023		2022
	(In Thousands)
Production	$	3,942,052	$	4,164,416
Transmission	487,527		461,245
Distribution	2,304,526		2,045,579
General plant	348,338		311,074
Total property, plant and equipment	$	7,082,443	$	6,982,314

As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).

Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information.

ARO

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel. 

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AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances:

	2023		2022
	(In Thousands)
Balance as of January 1	$	218,729	$	189,509
Liabilities incurred	17,080		1,159
Liabilities settled	(11,902)		(24,699)
Revisions to cash flow and timing estimates	12,921		44,679
Accretion expense	13,102		8,081
Balance as of December 31	$	249,930	$	218,729

ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.

4. FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

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Financial Assets

VEBA Assets

IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Consolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other (expense) / income, net" on the accompanying Consolidated Statements of Operations and were not material to the consolidated financial statements in the periods covered by this report.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations.

Forward Power Contracts

As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.

Interest Rate Hedges

IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.

Recurring Fair Value Measurements

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	127	$	—	$	—	$	127	$	5	$	—	$	—	$	5
Mutual funds	3,425		—		—		3,425		3,223		—		—		3,223
Total VEBA investments	3,552		—		—		3,552		3,228		—		—		3,228
FTRs	—		—		1,388		1,388		—		—		7,545		7,545
Interest rate hedges	—		14,294		—		14,294		—		12,172		—		12,172
Total financial assets measured at fair value	$	3,552	$	14,294	$	1,388	$	19,234	$	3,228	$	12,172	$	7,545	$	22,945

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The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	1,235
Issuances	15,338
Settlements	(9,028)
Balance at December 31, 2022	7,545
Issuances	3,624
Settlements	(9,781)
Balance at December 31, 2023	$	1,388

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	3,033,800	$	2,860,467	$	3,033,800	$	2,775,644
Variable-rate	455,000		455,000		—		—
Total indebtedness	$	3,488,800	$	3,315,467	$	3,033,800	$	2,775,644

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $24.8 million and $26.3 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $6.8 million and $7.1 million at December 31, 2023 and 2022, respectively.

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5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt and the risk of price changes for purchased power. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)		Sales (in thousands)		Net Notional (in thousands)
Interest rate hedges	Designated	USD	$	400,000	$	—	$	400,000
FTRs	Not Designated	MWh	3,919		—		3,919

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.

In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment is being amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.

The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:

	Interest Rate Hedges for the Years Ended December 31,
$ in thousands (net of tax)	2023		2022		2021
Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)	$	22,269	$	(29,407)	$	(43,420)
Net gains associated with current period hedging transactions	1,594		46,245		10,393
Net losses reclassified to interest expense	5,431		5,431		3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)	$	29,294	$	22,269	$	(29,407)
Loss expected to be reclassified to earnings in the next twelve months	$	(5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9

Derivatives Not Designated as Hedge

AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when

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acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.

When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments (in thousands):

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
FTRs	Not a Cash Flow Hedge	Derivative assets, current	$	1,388	$	7,545
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	14,294	$	—
Interest rate hedges	Cash Flow Hedge	Derivative assets, non-current	$	—	$	12,172

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6.  DEBT

The following table presents our long-term debt:

		December 31,
Series	Due	2023		2022
		(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)	December 2024	$	40,000	$	40,000
0.65% (1)	August 2025	40,000		40,000
0.75% (2)	April 2026	30,000		30,000
0.95% (2)	April 2026	60,000		60,000
1.40% (1)	August 2029	55,000		55,000
5.65%	December 2032	350,000		350,000
6.60%	January 2034	100,000		100,000
6.05%	October 2036	158,800		158,800
6.60%	June 2037	165,000		165,000
4.875%	November 2041	140,000		140,000
4.65%	June 2043	170,000		170,000
4.50%	June 2044	130,000		130,000
4.70%	September 2045	260,000		260,000
4.05%	May 2046	350,000		350,000
4.875%	November 2048	105,000		105,000
Unamortized discount – net		(6,449)		(6,651)
Deferred financing costs		(19,058)		(20,362)
Total AES Indiana first mortgage bonds		2,128,293		2,126,787
Total long-term debt – AES Indiana		2,128,293		2,126,787
Long-term debt – IPALCO:
3.70% Senior Secured Notes	September 2024	405,000		405,000
4.25% Senior Secured Notes	May 2030	475,000		475,000
Unamortized discount – net		(319)		(425)
Deferred financing costs		(4,554)		(5,912)
Total long-term debt – IPALCO		875,127		873,663
Total consolidated IPALCO long-term debt		3,003,420		3,000,450
Less: current portion of long-term debt		445,000		—
Net consolidated IPALCO long-term debt		$	2,558,420	$	3,000,450

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

Line of Credit

AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31,

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2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:

Year	Amount
	(In Thousands)
2024	$	445,000
2025	40,000
2026	90,000
2027	—
2028	—
Thereafter	2,458,800
	3,033,800
Unamortized discounts	(6,768)
Deferred financing costs, net	(23,612)
Total long-term debt	$	3,003,420

Significant Transactions

AES Indiana Term Loans

In November 2023, AES Indiana entered into an unsecured $300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt.

In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.

AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes.

In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par.

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IPALCO’s Senior Secured Notes and Term Loan

The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.

Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

Restrictions on Issuance of Debt 

All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.

The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded.

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7. INCOME TAXES

IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $0.0 million, $31.0 million and $27.5 million in 2023, 2022 and 2021, respectively.

Income Tax Provision

Federal and state income taxes charged to income are as follows: 

	2023		2022		2021
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	(14,222)	$	22,539	$	28,100
State	(3,716)		6,026		8,218
Total current income taxes	(17,938)		28,565		36,318
Deferred income taxes:
Federal	24,885		(6,920)		(7,286)
State	7,768		214		(91)
Total deferred income taxes	32,653		(6,706)		(7,377)
Total income tax expense	$	14,715	$	21,859	$	28,941

Effective and Statutory Rate Reconciliation

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows: 

	2023		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
State income tax, net of federal tax benefit	3.9	%	3.9	%	4.0	%
Depreciation flow through and amortization	(12.9)	%	(7.8)	%	(6.3)	%
AFUDC - equity	(0.3)	%	0.9	%	0.4	%
Noncontrolling interests in subsidiaries	9.0	%	—	%	—	%
Other – net	(0.2)	%	0.4	%	0.4	%
Effective tax rate	20.5	%	18.4	%	19.5	%

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Deferred Income Taxes

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:

	2023		2022
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	409,675	$	341,473
Regulatory assets recoverable through future rates	108,823		123,669
Other	17,694		17,953
Total deferred tax liabilities	536,192		483,095
Deferred tax assets:
Investment tax credit	5		6
Regulatory liabilities including ARO	168,619		167,725
Investments in tax partnerships	2,501		—
Other	3,579		2,723
Total deferred tax assets	174,704		170,454
Deferred income tax liability – net	$	361,488	$	312,641

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	—	$	—	$	7,368
Gross decreases – prior period tax positions	—		—		(7,368)
Unrecognized tax benefits at December 31	$	—	$	—	$	—

The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, IPALCO reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.

Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed our provision for current unrecognized tax benefits.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

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8. BENEFIT PLANS

Defined Contribution Plans

All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:

The Thrift Plan

Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively.

The RSP

Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively.

Defined Benefit Plans

Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants.

AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.

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The following table presents information relating to the Pension Plans: 

	Pension benefits as of December 31,
	2023		2022
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	577,530	$	772,040
Service cost	5,189		8,949
Interest cost	29,818		18,099
Actuarial loss (gain)	9,681		(182,590)
Amendments (primarily increases in pension bands)	653		—
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Projected benefit obligation at December 31	549,546		577,529
Change in plan assets:
Fair value of plan assets at January 1	611,125		820,684
Actual return/(loss) on plan assets	52,905		(171,002)
Employer contributions	114		412
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Fair value of plan assets at December 31	590,819		611,125
Funded status	$	41,273	$	33,596
Amounts recognized in the statement of financial position:
Non-current assets	$	41,273	$	33,611
Non-current liabilities	—		(15)
Net amount recognized at end of year	$	41,273	$	33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	653	$	—
Net (gain)/loss arising during period	(10,117)		24,069
Amortization of prior service cost	(2,172)		(2,589)
Amortization of loss	(6,145)		(2,622)
Total recognized in regulatory assets	$	(17,781)	$	18,858
Amounts included in regulatory assets:
Net loss	$	115,297	$	131,559
Prior service cost	10,136		11,655
Total amounts included in regulatory assets	$	125,433	$	143,214

(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period

As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.

Pension Benefits and Expense

Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are

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impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.

The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023.

	Pension benefits for years ended December 31,
	2023			2022			2021
	(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost	$	5,189		$	8,949		$	9,339
Interest cost	29,818			18,099			15,660
Expected return on plan assets	(33,107)			(35,656)			(41,815)
Amortization of prior service cost	2,172			2,589			2,944
Amortization of actuarial loss	6,145			2,424			5,529
Amortization of settlement loss	—			199			—
Net periodic benefit cost / (credit)	10,217			(3,396)			(8,343)
Less: amounts capitalized	1,689			(316)			(771)
Amount charged to expense	$	8,528		$	(3,080)		$	(7,572)
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	5.41		%	2.83		%	2.46		%
Discount rate – supplemental retirement plan	5.32		%	2.62		%	2.31		%
Expected return on defined benefit pension plan assets	5.60		%	4.45		%	5.05		%
Expected return on supplemental retirement plan assets	6.45		%	5.50		%	3.60		%

Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively.

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In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.

The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data. 

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.

The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own

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judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, we have the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes the Company’s target pension plan allocation for 2023:

Asset Category:	Target Allocations
Equity Securities	13.5%
Debt Securities	86.5%

	Fair Value Measurements at
	December 31, 2023
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	82,652	$	2,267	$	80,385	14	%
Debt securities (b)	387,979		1,168		386,811		66	%
Government debt securities (c)	117,397		178		117,219		20	%
Total common collective trusts	588,028		3,613		584,415		100	%
Cash and cash equivalents (d)	2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

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	Fair Value Measurements at
	December 31, 2022
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	85,341	$	2,017	$	83,324	14	%
Debt securities (b)	400,291		1,254		399,037		66	%
Government debt securities (c)	122,704		420		122,284		20	%
Total common collective trusts	608,336		3,691		604,645		100	%
Cash and cash equivalents (d)	2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

Pension Funding

We contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans’ underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. 

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Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:

Year	Pension Benefits
	(In Thousands)
2024	$	37,997
2025	38,794
2026	39,665
2027	40,085
2028	41,477
2029 through 2033	200,574

9. EQUITY AND CUMULATIVE PREFERRED STOCK

Cumulative Preferred Stock

On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.

Prior to the redemption, AES Indiana had five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $0.0 million, $3.2 million, and $3.2 million, respectively. Holders of preferred stock were entitled to two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities.

Paid In Capital

On December 12, 2022, AES U.S. Investments received equity capital contributions totaling $208.3 million, of which $177.0 million was contributed by AES U.S. Holdings, LLC and $31.3 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $253.0 million, of which $208.3 million was contributed by AES U.S. Investments and $44.7 million was contributed by CDPQ.

On December 13, 2021, AES U.S. Investments received equity capital contributions totaling $226.5 million, of which $192.5 million was contributed by AES U.S. Holdings, LLC and $34.0 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $275.0 million, of which $226.5 million was contributed by AES U.S. Investments and $48.5 million was contributed by CDPQ.

IPALCO then made the same investments in AES Indiana in 2021 and 2022. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects. The capital contributions were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO or AES U.S. Investments.

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Dividend Restrictions

AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions. Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).

AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.

IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed 0.67 to 1 and IPALCO’s interest coverage ratio is not less than 2.50 to 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.

During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to its shareholders totaling $104.3 million, $102.0 million and $131.5 million, respectively.

Equity Transactions with Noncontrolling Interests

The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.

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10. COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:

	Payments due in:
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation	$	933.5	$	249.7	$	267.3	$	225.7	$	190.8
Other	$	409.1	$	355.0	$	32.8	$	20.2	$	1.1

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.

Purchase orders and other contractual obligations:

At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.

Contingencies

Legal Matters

IPALCO and AES Indiana are involved in litigation arising in the normal course of business. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.

Coal Ash Insurance Litigation

In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.

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Environmental Matters

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

NSR and other CAA NOVs

In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.  

11.  RELATED PARTY TRANSACTIONS

AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPALCO, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, we had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets. 

AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and

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is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable balance under this agreement of $36.5 million and $18.0 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.

Long-term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

See also Note 8, “Benefit Plans” to the Financial Statements for a description of benefits awarded to AES Indiana employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of IPALCO were $73.8 million, $60.3 million and $58.4 million during 2023, 2022 and 2021, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. IPALCO had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.

Other

In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

12. BUSINESS SEGMENTS

IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of IPALCO and is the most relevant measure considered in IPALCO's internal evaluation of the financial performance of its segment. The Utility segment is comprised of AES Indiana, a vertically integrated electric utility, with all other nonutility business activities aggregated separately. See Note 1, "Overview and Summary of Significant Accounting Policies" for further information on AES Indiana. The “Other” nonutility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balance associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.

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The following table provides information about IPALCO’s business segments (in thousands):

	2023						2022						2021
	Utility		Other		Total		Utility		Other		Total		Utility		Other		Total
Revenue	$	1,649,917	$	—	$	1,649,917	$	1,791,711	$	—	$	1,791,711	$	1,426,132	$	—	$	1,426,132
Depreciation and amortization	$	287,863	$	—	$	287,863	$	266,504	$	—	$	266,504	$	256,085	$	—	$	256,085
Interest expense	$	99,051	$	43,875	$	142,926	$	87,428	$	43,804	$	131,232	$	84,256	$	41,370	$	125,626
Income/(loss) before income tax	$	115,763	$	(44,021)	$	71,742	$	162,862	$	(44,377)	$	118,485	$	189,548	$	(41,425)	$	148,123
Capital expenditures(1)	$	902,705	$	—	$	902,705	$	496,510	$	—	$	496,510	$	291,546	$	—	$	291,546
(1) Capital expenditures includes $0 thousand, $0 thousand and $36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively.
	As of December 31, 2023						As of December 31, 2022						As of December 31, 2021
Total assets	$	6,129,581	$	51,942	$	6,181,523	$	5,559,977	$	29,237	$	5,589,214	$	5,222,987	$	16,780	$	5,239,767

13. REVENUE

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

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Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.

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14. LEASES

LESSEE

The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	December 31, 2023		December 31, 2022
Assets
Right-of-use assets — finance leases	Other non-current assets	$	16,357	$	15,819
Liabilities
Finance lease liabilities (noncurrent)	Long-term debt	$	17,769	$	16,361
Total finance lease liabilities		$	17,769	$	16,361

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate	December 31, 2023		December 31, 2022
Weighted-average remaining lease term — finance leases	35 years		36 years
Weighted-average discount rate — finance leases	5.30	%	5.650	%

The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):

	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021
Finance lease cost:
Amortization of right-of-use assets	$	445	$	542	$	—
Interest on lease liabilities	933		782		—
Total lease cost	$	1,378	$	1,324	$	—

Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):

	Finance Leases
2024	$	891
2025	909
2026	927
2027	945
2028	965
Thereafter	39,958
Total	$	44,595
Less: Imputed interest	(26,826)
Present value of lease payments	$	17,769

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LESSOR

The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.

The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):

	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	1,537	$	1,134	$	1,439

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):

Property, Plant and Equipment, Net	December 31, 2023		December 31, 2022
Gross assets	$	4,341	$	4,334
Less: Accumulated depreciation	(1,222)		(1,060)
Net assets	$	3,119	$	3,274

The option to extend or terminate a lease is based on customary early termination provisions in the contract.

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Indianapolis Power & Light Company                                

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Indianapolis Power & Light Company and subsidiaries, d/b/a AES Indiana, (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedule listed in the Index at Item 15 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Board of Directors and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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	Regulatory Accounting
	Regulatory Accounting
Description of the Matter	As described in Note 2 to the consolidated financial statements, the Company applies the provisions of FASB Accounting Standards Codification 980 “Regulated Operations”, which gives recognition to the ratemaking and accounting practices of the Indiana Utility Regulatory Commission and the Federal Energy Regulatory Commission. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory assets can also represent performance incentives permitted by the regulator. Regulatory liabilities generally represent obligations to provide refunds or future rate reductions to customers for previous overcollections or the deferral of revenues collected for costs that the Company expects to incur in the future. Accounting for the economics of rate regulation affects multiple consolidated financial statement line items, including property, plant, and equipment; regulatory assets and liabilities; revenues; and depreciation expense, and related disclosures in the Company’s consolidated financial statements.
	Auditing the Company’s regulatory accounting was complex due to significant judgments made by management to support its assertions about the impact of future regulatory orders on the consolidated financial statements. In particular, there is subjectivity involved in assessing the impact of current and future regulatory orders on events that have occurred through December 31, 2023, judgment required to evaluate the relevance and reliability of audit evidence to support impacted account balances and disclosures, and judgments involved in assessing the probability of recovery in future rates of incurred costs or refunds to customers. These assumptions have a significant effect on the consolidated financial statements and related disclosures.
How We Addressed the Matter in Our Audit	To evaluate the Company’s significant judgments in accounting for regulatory assets and liabilities, our audit procedures included, among others, reviewing relevant regulatory orders, statutes and interpretations; filings made by intervening parties; and other publicly available information, to assess the likelihood of recovery of regulatory assets in future rates or of a refund or future reduction in rates for regulatory liabilities based on precedents for the treatment of similar costs under similar circumstances. We evaluated the Company’s assertions regarding the probability of recovery of regulatory assets or refund or future reduction in rates for regulatory liabilities, to assess the Company’s assertion that amounts are probable of recovery or of a refund or future reduction in rates.

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	Asset Retirement Obligations
	Regulatory Accounting
Description of the Matter	At December 31, 2023, the Company’s asset retirement obligations (“ARO”) totaled $249.9 million. As described in Note 3 to the consolidated financial statements, the Company’s ARO liabilities relate primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The Company recorded adjustments to its ARO liabilities of $30.0 million during 2023. ARO liabilities incurred in 2023 primarily related to FGD residual water disposal. ARO liabilities were revised in 2023 primarily to reflect revisions to cash flow estimates due to increases to estimated ash pond closure costs.
	Auditing the Company’s ARO liabilities was complex and highly judgmental due to the significant estimation required by management to determine the estimated cost estimates of the legal obligations associated with the Company’s generating plants, transmission system and distribution system. In particular, the estimate was sensitive to significant assumptions including the scope and method of decommissioning and timing of related cash flows.
How We Addressed the Matter in Our Audit	To test the Company’s ARO liability estimates, our audit procedures included evaluating the appropriateness of the Company’s methodology, interviewing members of the Company’s environmental staff and testing significant assumptions and inputs including the timing of activities, projected closure dates and the method of decommissioning. We involved our specialists in our assessment of the Company’s ARO liabilities including reviewing the Company’s methodology, evaluating the reasonableness of the cost estimates and assumptions, and assessing completeness of the estimates with respect to regulatory requirements.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2008.

Indianapolis, Indiana

February 26, 2024

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AES INDIANA and SUBSIDIARIES
Consolidated Statements of Operations
For the Years Ended December 31, 2023, 2022 and 2021
	2023		2022		2021
	(In Thousands)
REVENUE	$	1,649,917	$	1,791,711	$	1,426,132
OPERATING COSTS AND EXPENSES:
Fuel	494,000		568,676		255,817
Power purchased	159,908		199,860		175,025
Operation and maintenance	477,497		493,454		449,317
Depreciation and amortization	287,863		266,504		256,085
Taxes other than income taxes	24,865		33,048		44,419
Other, net	(361)		(3,201)		(5,630)
Total operating costs and expenses	1,443,772		1,558,341		1,175,033
OPERATING INCOME	206,145		233,370		251,099
OTHER INCOME / (EXPENSE), NET:
Allowance for equity funds used during construction	9,315		4,784		5,412
Interest expense	(99,051)		(87,428)		(84,257)
Other income, net	(646)		12,136		17,294
Total other expense, net	(90,382)		(70,508)		(61,551)
INCOME BEFORE INCOME TAX	115,763		162,862		189,548
Income tax expense	25,666		32,887		39,305
NET INCOME	90,097		129,975		150,243
Dividends on and redemption of preferred stock	—		3,509		3,213
Net loss attributable to noncontrolling interests	(26,093)		—		—
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	116,190	$	126,466	$	147,030

See Notes to Consolidated Financial Statements.

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AES INDIANA and SUBSIDIARIES
Consolidated Balance Sheets
	December 31, 2023		December 31, 2022
	(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,767	$	199,103
Accounts receivable, net of allowance for credit losses of $2,283 and $1,117, respectively	233,970		216,572
Inventories	143,590		123,608
Regulatory assets, current	89,419		119,723
Taxes receivable	5,140		6,682
Prepayments and other current assets	27,741		27,422
Total current assets	525,627		693,110
NON-CURRENT ASSETS:
Property, plant and equipment	7,082,443		6,982,314
Less: Accumulated depreciation	2,954,555		3,243,968
	4,127,888		3,738,346
Construction work in progress	359,014		294,985
Total net property, plant and equipment	4,486,902		4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net	235,656		138,978
Regulatory assets, non-current	541,784		593,939
Pension plan assets	41,172		33,611
Other non-current assets	298,439		67,008
Total other non-current assets	1,117,051		833,536
TOTAL ASSETS	$	6,129,580	$	5,559,977
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Short-term debt and current portion of long-term debt (see Note 6)	$	494,685	$	—
Accounts payable	292,835		189,806
Accrued taxes	22,580		22,474
Accrued interest	25,245		25,054
Customer deposits	29,308		35,097
Regulatory liabilities, current	23,371		23,348
Accrued and other current liabilities	34,748		26,214
Total current liabilities	922,772		321,993
NON-CURRENT LIABILITIES:
Long-term debt (see Notes 6 and 14)	2,106,146		2,143,147
Deferred income tax liabilities	342,557		305,107
Regulatory liabilities, non-current	527,224		612,585
Accrued other postretirement benefits	2,776		3,085
Asset retirement obligations	249,930		218,729
Other non-current liabilities	5,129		11,621
Total non-current liabilities	3,233,762		3,294,274
Total liabilities	4,156,534		3,616,267
COMMITMENTS AND CONTINGENCIES (see Note 10)
EQUITY:
Common shareholder's equity
Common stock (no par value, 20,000,000 shares authorized; 17,206,630 shares issued and outstanding at December 31, 2023 and 2022)	324,537		324,537
Paid in capital	1,193,199		1,193,107
Retained earnings	402,056		426,066
Total common shareholder's equity	1,919,792		1,943,710
Noncontrolling interests	53,254		—
Total equity	1,973,046		1,943,710
TOTAL LIABILITIES AND EQUITY	$	6,129,580	$	5,559,977

See Notes to Consolidated Financial Statements.

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AES INDIANA and SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2023, 2022 and 2021
	2023		2022		2021
	(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	90,097	$	129,975	$	150,243
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	287,863		266,504		256,085
Amortization of deferred financing costs and debt discounts	2,406		2,511		2,536
Deferred income taxes and investment tax credit adjustments - net	23,582		(6,584)		(7,373)
Allowance for equity funds used during construction	(9,315)		(4,784)		(5,412)
Gain on acquisition	—		—		(5,630)
Change in certain assets and liabilities:
Accounts receivable	(17,398)		(37,391)		(13,746)
Inventories	(30,171)		(47,489)		(12,017)
Prepayments and other current assets	(6,476)		19,016		(4,556)
Accounts payable	47,016		32,232		21,502
Accrued and other current liabilities	2,790		6,532		(13,017)
Accrued taxes payable/receivable	1,647		(3,452)		(2,302)
Accrued interest	192		2,813		(1,099)
Pension and other postretirement benefit assets and liabilities	1,625		(8,727)		(16,592)
Current and non-current regulatory assets and liabilities	54,358		38,863		(104,759)
Other non-current liabilities	(16,663)		(21,717)		5,566
Other - net	(4,074)		4,967		(1,645)
Net cash provided by operating activities	427,479		373,269		247,784
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(902,705)		(496,510)		(291,510)
Project development costs	(4,462)		(3,910)		(1,304)
Cost of removal payments	(45,595)		(23,948)		(35,260)
Insurance proceeds	4,900		—		—
Loan repayments from parent	—		—		6,110
Purchase of intangibles	(44,650)		—		(26,261)
Other	(361)		(719)		(14,380)
Net cash used in investing activities	(992,873)		(525,087)		(362,605)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities	435,000		300,000		320,000
Repayments from revolving credit facilities	(280,000)		(360,000)		(335,000)
Short-term borrowings	300,000		200,000		—
Repayment of short-term borrowings	—		(200,000)		—
Long-term borrowings	—		350,000		95,000
Retirement of long-term debt	—		—		(95,000)
Dividends on common stock	(140,200)		(127,200)		(155,700)
Dividends on preferred stock	—		(3,213)		(3,213)
Payments of deferred financings costs and discounts	(350)		(4,309)		(1,325)
Purchase of preferred stock	—		(60,080)		—
Equity contributions from IPALCO	—		253,000		275,000
Sales to noncontrolling interests	77,921		—		—
Other	(313)		(33)		(131)
Net cash provided by financing activities	392,058		348,165		99,631
Net change in cash, cash equivalents and restricted cash	(173,336)		196,347		(15,190)
Cash, cash equivalents and restricted cash at beginning of year	199,108		2,761		17,951
Cash, cash equivalents and restricted cash at end of year	$	25,772	$	199,108	$	2,761
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized)	$	93,544	$	80,104	$	82,880
Income taxes	$	—	$	39,500	$	40,800
Non-cash investing activities:
Accruals for capital expenditures	$	124,626	$	66,949	$	81,325
Recognition and changes to right-of-use assets - finance leases	$	983	$	(3,402)	$	19,763
Non-cash financing activities:
Recognition and changes to financing lease liabilities	$	(1,408)	$	(3,402)	$	19,763

See Notes to Consolidated Financial Statements.

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AES INDIANA and SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended December 31, 2023, 2022 and 2021
	Common Shareholder's Equity
	Common Stock
(in Thousands)	Outstanding Shares	Amount		Paid in Capital		Retained Earnings		Total Common Shareholder's Equity		Cumulative Preferred Stock		Noncontrolling Interests
Balance at January 1, 2021	17,207	$	324,537	$	664,886	$	435,470	$	1,424,893	$	59,784	$	—
Net income		—		—		150,243		150,243		3,213		—
Preferred stock dividends		—		—		(3,213)		(3,213)		(3,213)		—
Cash dividends declared on common stock		—		—		(155,700)		(155,700)		—		—
Contributions from IPALCO		—		275,000		—		275,000		—		—
Other		—		107		—		107		—		—
Balance at December 31, 2021	17,207	324,537		939,993		426,800		1,691,330		59,784		—
Net income		—		—		129,975		129,975		3,213		—
Preferred stock dividends		—		—		(3,213)		(3,213)		(3,213)		—
Redemption of preferred stock		—		—		(296)		(296)		(59,784)		—
Cash dividends declared on common stock		—		—		(127,200)		(127,200)		—		—
Contributions from IPALCO		—		253,000		—		253,000		—		—
Other		—		114		—		114		—		—
Balance at December 31, 2022	17,207	324,537		1,193,107		426,066		1,943,710		—		—
Net income / (loss)		—		—		116,190		116,190		—		(26,093)
Cash dividends declared on common stock		—		—		(140,200)		(140,200)		—		—
Sales to noncontrolling interests		—		—		—		—		—		79,347
Other		—		92		—		92		—		—
Balance at December 31, 2023	17,207	$	324,537	$	1,193,199	$	402,056	$	1,919,792	$	—	$	53,254

See Notes to Consolidated Financial Statements.

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AES INDIANA and SUBSIDIARIES

Notes to Consolidated Financial Statements

For the Years Ended December 31, 2023, 2022 and 2021

1. OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPL, which does business as AES Indiana, was incorporated under the laws of the state of Indiana in 1926. All of the outstanding common stock of AES Indiana is owned by IPALCO. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments and CDPQ. AES U.S. Investments is owned by AES (85%) and CDPQ (15%). AES Indiana is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.

AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.

In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.

In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.

For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."

Principles of Consolidation

AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which

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consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

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The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	25,767	$	199,103
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	25,772	$	199,108

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,227		288
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,970	$	216,572

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

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Inventories

AES Indiana maintains coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Regulatory Accounting

The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
AFUDC equity	$	9,315	$	4,784	$	5,412
AFUDC debt	$	13,739	$	8,215	$	4,815

Impairment of Long-lived Assets

GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to

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current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:

			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	8		$	261,872	$	205,910
Project development intangible assets	28		84,097		39,455
Other	Various		797		797
Less: Accumulated amortization			(111,110)		(107,184)
Intangible assets - net			$	235,656	$	138,978
	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	14,570	$	10,122	$	11,241
Estimated future amortization
Years ending December 31,
2024					$	20,764
2025					20,764
2026					22,550
2027					22,550
2028					22,550
Total					$	109,178

Implementation Costs Related to Software as a Service

AES Indiana has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.

Contingencies

AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been

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the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Leases

The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. AES Indiana’s provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated

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Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, AES Indiana is one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Operating Expenses – Other, Net

Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition.

Pension and Postretirement Benefits

AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. AES Indiana establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. AES Indiana’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. AES Indiana’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities which are included in allowable costs for ratemaking purposes in future years are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

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AES Indiana files U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.

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New Accounting Pronouncements

We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on AES Indiana's Financial Statements.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the AES Indiana's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on AES Indiana's Financial Statements.

ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative	In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.	The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.	AES Indiana will provide the required disclosures on a prospective basis on the date each amendment becomes effective. AES Indiana does not expect ASU 2023-06 will have any impact to its Financial Statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures	The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.	The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted.	AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures	The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.	The amendments in this Update are effective for fiscal years beginning after December 15, 2024.	AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.

2. REGULATORY MATTERS

General

AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

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In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.

Basic Rates and Charges

AES Indiana’s basic rates and charges represent the largest component of its annual revenue. AES Indiana’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.

Regulatory Rate Review and Base Rate Orders

AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.

FAC and Authorized Annual Jurisdictional Net Operating Income

AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each

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FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.

In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.

ECCRA 

AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million.

DSM

Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively.

On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

AES Indiana is currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). AES Indiana is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, AES Indiana has 94.5 MW of solar-generated electricity in its service territory under long-term contracts

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(these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. AES Indiana has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.

TDSIC

In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue.

On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million, The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million.

IRP Filings and Replacement Generation

Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.

2022 IRP

AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.

In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

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2019 IRP

In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.

AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. AES Indiana's modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023.

AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.

Hardy Hills Solar Project

In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.

On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.

On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of

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$79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.

Petersburg Energy Center Project

In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).

Pike County BESS Project

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.

Hoosier Wind Project

On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.

Incentives for Clean Energy Projects

Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.

IURC COVID-19 Orders

Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and

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2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.

EDG Rates

On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.

EV Portfolio Program

On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.

House Bill 1002

In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on AES Indiana's net income.

Regulatory Assets and Liabilities

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

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The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:

	2023		2022		Recovery Period
	(In Thousands)
Regulatory assets, current:
Undercollections of rate riders	$	75,416	$	26,047	Approximately 1 year(1)
Fuel costs	—		79,861		Approximately 1 year(1)
Unamortized reacquisition premium on debt	188		—		Approximately 1 year
Costs being recovered through basic rates and charges	13,815		13,815		Approximately 1 year(1)
Total regulatory assets, current	89,419		119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs	115,847		131,907		Various(2)
Deferred MISO costs	21,091		34,483		Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	2,812		3,866		Through 2026(1)(3)
Unamortized reacquisition premium on debt	13,379		14,429		Over remaining life of debt
Environmental costs	66,837		68,947		Through 2046(1)(3)
COVID-19 costs	5,426		5,426		4 years(4)
Major storm damage	1,493		—		To be determined
TDSIC costs	35,979		18,547		36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs	259,892		287,463		Through 2034(1)(3)
Hardy Hills Solar Project development costs	6,774		5,744		30 years(3)
Petersburg Energy Center Project development costs	2,469		1,582		30 years(3)
Pike County BESS Project development costs	2,623		—		20 years(3)
Fuel costs	4,275		20,518		Through 2025(1)
Other miscellaneous	2,887		1,027		Various(5)
Total regulatory assets, non-current	541,784		593,939
Total regulatory assets	$	631,203	$	713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders	$	19,649	$	15,803	Approximately 1 year(1)
FTRs	3,722		7,545		Approximately 1 year(1)
Total regulatory liabilities, current	23,371		23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs	451,886		518,797		Not applicable
Deferred income taxes payable to customers through rates	74,796		88,662		Various
Hardy Hills sponsor investment tax credit	542		—		To be determined(6)
Major storm damage	—		5,126		To be determined
Total regulatory liabilities, non-current	527,224		612,585
Total regulatory liabilities	$	550,595	$	635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

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Current Regulatory Assets and Liabilities

Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.

Deferred Fuel

Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs. 

The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.

Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs

These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.

Unamortized Reacquisition Premium on Debt

This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.

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Environmental Costs

These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years.

COVID-19 Costs

These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.

TDSIC Costs

These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from 1 to 36 years. See "TDSIC" above for additional discussion.

Petersburg Unit 1 and 2 Retirement Costs

These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.

Hardy Hills Solar Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Petersburg Energy Center Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Pike County BESS Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.

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ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, AES Indiana has a net regulatory deferred income tax liability of $74.8 million and $88.7 million as of December 31, 2023 and 2022, respectively.

3. PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:

	As of December 31,
	2023		2022
	(In Thousands)
Production	$	3,942,052	$	4,164,416
Transmission	487,527		461,245
Distribution	2,304,526		2,045,579
General plant	348,338		311,074
Total property, plant and equipment	$	7,082,443	$	6,982,314

As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).

Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information.

ARO

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel.

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AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances:

	2023		2022
	(In Thousands)
Balance as of January 1	$	218,729	$	189,509
Liabilities incurred	17,080		1,159
Liabilities settled	(11,902)		(24,699)
Revisions to cash flow and timing estimates	12,921		44,679
Accretion expense	13,102		8,081
Balance as of December 31	$	249,930	$	218,729

ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.    

4. FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of AES Indiana’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, AES Indiana has categorized its financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of AES Indiana’s financial instruments. AES Indiana’s financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that AES Indiana could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

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Financial Assets

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations.

Forward Power Contracts

As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.

Recurring Fair Value Measurements

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
FTRs	$	—	$	—	$	1,388	$	1,388	$	—	$	—	$	7,545	$	7,545
Total financial assets measured at fair value	$	—	$	—	$	1,388	$	1,388	$	—	$	—	$	7,545	$	7,545

The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	1,235
Issuances	15,338
Settlements	(9,028)
Balance at December 31, 2022	7,545
Issuances	3,624
Settlements	(9,781)
Balance at December 31, 2023	$	1,388

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Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of AES Indiana’s outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: 

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	2,153,800	$	2,020,997	$	2,153,800	$	1,959,233
Variable-rate	455,000		455,000		—		—
Total indebtedness	$	2,608,800	$	2,475,997	$	2,153,800	$	1,959,233

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $20.2 million and $20.4 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $6.4 million and $6.7 million at December 31, 2023 and 2022, respectively.

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

AES Indiana uses derivatives principally to manage the risk of price changes for purchased power. The derivatives that AES Indiana uses to economically hedge this risk is governed by our risk management policies for forward and futures contracts. AES Indiana's net positions are continually assessed within its structured hedging programs to determine whether new or offsetting transactions are required. AES Indiana monitors and values derivative positions monthly as part of its risk management processes. AES Indiana uses published sources for pricing, when possible, to mark positions to market. All of AES Indiana's derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)	Sales (in thousands)	Net Notional (in thousands)
FTRs	Not Designated	MWh	3,919	—	3,919

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Derivatives Not Designated as Hedge

AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.

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Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.

When applicable, AES Indiana has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, AES Indiana did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of AES Indiana's derivative instruments (in thousands):

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
FTRs	Not a Cash Flow Hedge	Prepayments and other current assets	$	1,388	$	7,545

6. DEBT

The following table presents AES Indiana’s long-term debt:

		December 31,
Series	Due	2023		2022
		(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)	December 2024	$	40,000	$	40,000
0.65% (1)	August 2025	40,000		40,000
0.75% (2)	April 2026	30,000		30,000
0.95% (2)	April 2026	60,000		60,000
1.40% (1)	August 2029	55,000		55,000
5.650%	December 2032	350,000		350,000
6.60%	January 2034	100,000		100,000
6.05%	October 2036	158,800		158,800
6.60%	June 2037	165,000		165,000
4.875%	November 2041	140,000		140,000
4.65%	June 2043	170,000		170,000
4.50%	June 2044	130,000		130,000
4.70%	September 2045	260,000		260,000
4.05%	May 2046	350,000		350,000
4.875%	November 2048	105,000		105,000
Unamortized discount – net		(6,449)		(6,651)
Deferred financing costs		(19,058)		(20,362)
Total AES Indiana first mortgage bonds		2,128,293		2,126,787
Total consolidated AES Indiana long-term debt		2,128,293		2,126,787
Less: current portion of long-term debt		40,000		—
Net consolidated AES Indiana long-term debt		$	2,088,293	$	2,126,787

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

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Line of Credit

AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31, 2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:

Year	Amount
	(In Thousands)
2024	$	40,000
2025	40,000
2026	90,000
2027	—
2028	—
Thereafter	1,983,800
	2,153,800
Unamortized discounts	(6,449)
Deferred financing costs, net	(19,058)
Total long-term debt	$	2,128,293

Significant Transactions

AES Indiana Term Loans

In November 2023, AES Indiana entered into an unsecured$300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt.

In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.

AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes.

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In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par.

Restrictions on Issuance of Debt

All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.

The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.

Credit Ratings

AES Indiana’s ability to borrow money or to refinance existing indebtedness and the interest rates at which AES Indiana can borrow money or refinance existing indebtedness are affected by AES Indiana’s credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES and/or IPALCO could result in AES Indiana’s credit ratings being downgraded.

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7. INCOME TAXES

AES Indiana follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if AES Indiana filed separate income tax returns. AES Indiana is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $0.0 million, $39.5 million and $40.8 million in 2023, 2022 and 2021, respectively.

Income Tax Provision

Federal and state income taxes charged to income are as follows:

	2023		2022		2021
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	1,816	$	31,286	$	36,353
State	268		8,185		10,325
Total current income taxes	2,084		39,471		46,678
Deferred income taxes:
Federal	17,631		(6,822)		(7,283)
State	5,951		238		(90)
Total deferred income taxes	23,582		(6,584)		(7,373)
Total income tax expense	$	25,666	$	32,887	$	39,305

Effective and Statutory Rate Reconciliation

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows:

	2023		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
State income tax, net of federal tax benefit	3.9	%	3.9	%	4.0	%
Depreciation flow through and amortization	(8.0)	%	(5.7)	%	(4.9)	%
AFUDC - equity	(0.2)	%	0.7	%	0.3	%
Noncontrolling interests in subsidiaries	5.6	%	—	%	—	%
Other – net	(0.1)	%	0.3	%	0.3	%
Effective tax rate	22.2	%	20.2	%	20.7	%

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Deferred Income Taxes

The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 

	2023		2022
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	409,675	$	341,473
Regulatory assets recoverable through future rates	108,823		123,669
Other	7,975		22,717
Total deferred tax liabilities	526,473		487,859
Deferred tax assets:
Investment tax credit	5		6
Regulatory liabilities including ARO	168,619		167,726
Investments in tax partnerships	2,483		—
Operating loss carryforwards	9,230		—
Other	3,579		15,020
Total deferred tax assets	183,916		182,752
Deferred income tax liability – net	$	342,557	$	305,107

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:

	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	—	$	—	$	7,368
Gross decreases – prior period tax positions	—		—		(7,368)
Unrecognized tax benefits at December 31	$	—	$	—	$	—

The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, AES Indiana reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.

Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult

to predict the final outcome or the timing of resolution of any particular uncertain tax position, AES Indiana believes

unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact AES Indiana's previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed AES Indiana's provision for current unrecognized tax benefits.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

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8. BENEFIT PLANS

Defined Contribution Plans

All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:

The Thrift Plan

Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively. 

The RSP

Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively.

Defined Benefit Plans

Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants.

AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.

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The following table presents information relating to the Pension Plans:

	Pension benefits as of December 31,
	2023		2022
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	577,530	$	772,040
Service cost	5,189		8,949
Interest cost	29,818		18,099
Actuarial loss (gain)	9,681		(182,590)
Amendments (primarily increases in pension bands)	653		—
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Projected benefit obligation at December 31	549,546		577,529
Change in plan assets:
Fair value of plan assets at January 1	611,125		820,684
Actual return/(loss) on plan assets	52,905		(171,002)
Employer contributions	114		412
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Fair value of plan assets at December 31	590,819		611,125
Funded status	$	41,273	$	33,596
Amounts recognized in the statement of financial position:
Non-current assets	$	41,273	$	33,611
Non-current liabilities	—		(15)
Net amount recognized at end of year	$	41,273	$	33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	653	$	—
Net (gain)/loss arising during period	(10,117)		24,069
Amortization of prior service cost	(2,172)		(2,589)
Amortization of loss	(6,145)		(2,622)
Total recognized in regulatory assets	$	(17,781)	$	18,858
Amounts included in regulatory assets:
Net loss	$	115,297	$	131,559
Prior service cost	10,136		11,655
Total amounts included in regulatory assets	$	125,433	$	143,214

(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period

As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.

Pension Benefits and Expense

Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are

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impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.

The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023.

	Pension benefits for years ended December 31,
	2023			2022			2021
	(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost	$	5,189		$	8,949		$	9,339
Interest cost	29,818			18,099			15,660
Expected return on plan assets	(33,107)			(35,656)			(41,815)
Amortization of prior service cost	2,172			2,589			2,944
Amortization of actuarial loss	6,145			2,424			5,529
Amortization of settlement loss	—			199			—
Net periodic benefit cost / (credit)	10,217			(3,396)			(8,343)
Less: amounts capitalized	1,689			(316)			(771)
Amount charged to expense	$	8,528		$	(3,080)		$	(7,572)
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	5.41		%	2.83		%	2.46		%
Discount rate – supplemental retirement plan	5.32		%	2.62		%	2.31		%
Expected return on defined benefit pension plan assets	5.60		%	4.45		%	5.05		%
Expected return on supplemental retirement plan assets	6.45		%	5.50		%	3.60		%

Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively.

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In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.

The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing AES Indiana’s expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data. 

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations. 

The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a

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combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. AES Indiana then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, AES Indiana has the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. AES Indiana uses an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes AES Indiana’s target pension plan allocation for 2023: 

Asset Category:	Target Allocations
Equity Securities	13.5%
Debt Securities	86.5%

	Fair Value Measurements at
	December 31, 2023
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	82,652	$	2,267	$	80,385	14	%
Debt securities (b)	387,979		1,168		386,811		66	%
Government debt securities (c)	117,397		178		117,219		20	%
Total common collective trusts	588,028		3,613		584,415		100	%
Cash and cash equivalents (d)	2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

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	Fair Value Measurements at
	December 31, 2022
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	85,341	$	2,017	$	83,324	14	%
Debt securities (b)	400,291		1,254		399,037		66	%
Government debt securities (c)	122,704		420		122,284		20	%
Total common collective trusts	608,336		3,691		604,645		100	%
Cash and cash equivalents (d)	2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

Pension Funding

AES Indiana contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans' underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. 

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Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows: 

Year	Pension Benefits
	(In Thousands)
2024	$	37,997
2025	38,794
2026	39,665
2027	40,085
2028	41,477
2029 through 2033	200,574

9. EQUITY AND CUMULATIVE PREFERRED STOCK

Cumulative Preferred Stock

On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million. On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.

Prior to the redemption, AES Indiana had five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $0.0 million, $3.2 million, and $3.2 million, respectively. Holders of preferred stock were entitled to two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities.

Paid in Capital and Capital Stock

On December 12, 2022 and December 13, 2021, respectively, AES Indiana received equity capital contributions of $253.0 million and $275.0 million from IPALCO. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects.

All of the outstanding common stock of AES Indiana is owned by IPALCO. AES Indiana’s common stock is pledged under the 2024 IPALCO Notes and 2030 IPALCO Notes. There have been no changes in the capital stock of AES Indiana during the three years ended December 31, 2023.

Dividend Restrictions

AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or

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accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions.

Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).

AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.

During the years ended December 31, 2023, 2022 and 2021, AES Indiana declared dividends to its shareholder totaling $140.2 million, $127.2 million, and $155.7 million, respectively.

Equity Transactions with Noncontrolling Interests

The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.

10. COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:

	Payments due in:
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation	$	933.5	$	249.7	$	267.3	$	225.7	$	190.8
Other	$	409.1	$	355.0	$	32.8	$	20.2	$	1.1

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.

Purchase orders and other contractual obligations:

At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies

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(see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.

Contingencies

Legal Matters

AES Indiana is involved in litigation arising in the normal course of business. AES Indiana accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on AES Indiana’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.

Coal Ash Insurance Litigation

In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.

Environmental Matters

AES Indiana is subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of AES Indiana's employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. AES Indiana cannot assure that it has been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

NSR and other CAA NOVs

In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.  

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11. RELATED PARTY TRANSACTIONS

AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including AES Indiana, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, AES Indiana had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets. 

AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. AES Indiana had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively. 

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. AES Indiana had a receivable balance under this agreement of $5.1 million and $6.7 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.

Long-term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

See also Note 8, “Benefit Plans” to the audited consolidated financial statements of AES Indiana for a description of benefits awarded to AES Indiana employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of AES Indiana were $73.6 million, $60.1 million and $58.2 million during 2023, 2022 and 2021, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses -

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Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. AES Indiana had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.

Other

During the year ended December 31, 2021, AES Indiana received loan repayments of $6.1 million from IPALCO.

In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Additionally, transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

12. BUSINESS SEGMENTS

Operating segments are components of an enterprise that engage in business activities from which it may earn revenue and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana had only one reportable segment.

13. REVENUE

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

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Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

AES Indiana has elected to apply the optional disclosure exemptions under ASC 606. Therefore, AES Indiana has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration

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relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.

14. LEASES

LESSEE

The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	December 31, 2023		December 31, 2022
Assets
Right-of-use assets — finance leases	Other non-current assets	$	16,357	$	15,819
Liabilities
Finance lease liabilities (noncurrent)	Long-term debt	$	17,769	$	16,361
Total finance lease liabilities		$	17,769	$	16,361

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate	December 31, 2023	December 31, 2022
Weighted-average remaining lease term — finance leases	35 years	36 years
Weighted-average discount rate — finance leases	5.30%	5.650%

The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):

	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021
Finance lease cost:
Amortization of right- of-use assets	$	445	$	542	$	—
Interest on lease liabilities	933		782		—
Total lease cost	$	1,378	$	1,324	$	—

Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):

	Finance Leases
2024	$	891
2025	909
2026	927
2027	945
2028	965
Thereafter	39,958
Total	$	44,595
Less: Imputed interest	(26,826)
Present value of lease payments	$	17,769

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LESSOR

The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.

The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):

	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	1,537	$	1,134	$	1,439

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):

Property, Plant and Equipment, Net	December 31, 2023		December 31, 2022
Gross assets	$	4,341	$	4,334
Less: Accumulated depreciation	(1,222)		(1,060)
Net assets	$	3,119	$	3,274

The option to extend or terminate a lease is based on customary early termination provisions in the contract.

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that the Company files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosures.

The Company carried out the evaluation required by Rules 13a-15(b) and 15d-15(b), under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of our “disclosure controls and procedures” (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon this evaluation, the CEO and CFO concluded that as of December 31, 2023, our disclosure controls and procedures were not effective due to a material weakness in our internal control over financial reporting described below.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that:

•pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

•provide reasonable assurance that unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements are prevented or detected timely.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.

The Company conducted an assessment of the effectiveness of its internal control over financial reporting as of December 31, 2023 based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). As of December 31, 2023, we have identified material weaknesses in internal controls related to the fourth quarter implementation of SAP IS-U, a software solution that SAP developed for businesses operating in the utility industries. We identified control deficiencies that aggregated to a material weakness in the design and operation of information technology general controls (“ITGCs”) which support the Company’s internal control processes for revenue recognition and related accounts and disclosures impacted by revenue recognition. The design deficiencies relate to user access and program change-management controls. Business process controls (automated and manual) and management review controls reliant on SAP IS-U were deemed ineffective as they were adversely impacted by the ineffective information technology general controls.

Management has implemented and continues to implement measures designed to ensure that control deficiencies contributing to the material weakness are remediated. The remediation actions include: (i) changes to our ITGC attributes in the areas of user access and program change-management for systems supporting the Company’s

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revenue internal control processes to ensure that internal controls are designed and operating effectively; and (ii) training and educating the control owners on ITGC policies concerning the requirements of each control, with a focus on those related to user access and change-management over IT systems impacting our revenue process. Management has performed a lookback analysis to determine if any unauthorized activity occurred related to the control deficiencies; none was identified.

We believe that these actions will remediate the foregoing material weakness. The material weakness will not be considered remediated, however, until the applicable controls operate for a sufficient period of time, and management has concluded, through testing, that these controls are operating effectively.

Management, including our CEO and CFO, does not expect that our internal controls will prevent or detect all misstatements and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Changes in Internal Control Over Financial Reporting

Except for the implementation of the SAP IS-U system discussed above, there has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2023, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Notwithstanding the existence of the material weaknesses as described above, we believe that the consolidated financial statements in this Annual Report present fairly, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods presented, in conformity with U.S. GAAP.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required to be furnished pursuant to this item with respect to Directors and Executive Officers of IPALCO will be set forth under the captions “Directors” and “Executive Officers” in IPALCO’s Proxy Statement to be furnished to shareholders in connection with the solicitation of proxies by our Board of Directors, which information is incorporated herein by reference.

The information required to be furnished pursuant to this item for IPALCO with respect to the identification of the Audit Committee, the Audit Committee financial expert and the registrant’s code of ethics will be set forth under the caption “Corporate Governance” in the Proxy Statement, which information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Executive Compensation” in the Proxy Statement, which information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” in the Proxy Statement, which information is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required to be furnished pursuant to this item for IPALCO will be set forth under the caption “Certain Relationships and Related Transactions, and Director Independence” in the Proxy Statement, which information is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Financial Audit Committee of AES pre-approves the audit and non-audit services provided by the independent auditors for itself and its subsidiaries, including IPALCO and its subsidiaries. The AES Financial Audit Committee maintained its policy established in 2002 within which to judge if the independent auditor may be eligible to provide certain services outside of its main role as outside auditor. Services within the established framework include audit and related services and certain tax services. Services outside of the framework require AES Financial Audit Committee approval prior to the performance of the service. The Sarbanes-Oxley Act of 2002 addresses auditor independence and this framework is consistent with the provisions of the Act. No services performed by the independent auditor with respect to IPALCO and its subsidiaries were approved after the fact by the AES Financial Audit Committee other than those that were considered to be de minimis and approved in accordance with Regulation 2-01(c)(7)(i)(C) to Regulation S-X of the Exchange Act.

In addition to the pre-approval policies of the AES Financial Audit Committee, the IPALCO Board of Directors has established a pre-approval policy for audit, audit related, and certain tax and other non-audit services. The Board of Directors will specifically approve the annual audit services engagement letter, including terms and fees, with the independent auditor. Other audit, audit related and tax consultation services are specifically identified in the pre-approval policy and the policy is subject to review at least annually. This pre-approval allows management to request the specified services on an as-needed basis during the year. Any such services are reviewed with the Board of Directors on a timely basis. Any audit or non-audit services that involve a service not listed on the pre-approval list must be specifically approved by the Board of Directors prior to commencement of such work. No services were approved after the fact by the IPALCO Board of Directors other than those that were considered to be de minimis and approved in accordance with Regulation 2-01 (c)(7)(i)(c) to Regulation S-X of the Exchange Act. 

Audit fees are fees billed or expected to be billed by our principal accountant for professional services for the audit of the Financial Statements, included in this Annual Report on Form 10-K and review of financial statements included in IPALCO’s quarterly reports on Form 10-Q, services that are normally provided by our principal accountants in connection with statutory, regulatory or other filings or engagements or any other service performed to comply with generally accepted auditing standards and include comfort and consent letters in connection with SEC filings and financing transactions.

The following table lists fees billed to IPALCO for products and services provided by our principal accountants:

	Years Ended December 31,
	2023		2022
Audit Fees	$	1,442,837	$	945,033
Audit Related Fees:
Fees for the audit of AES Indiana’s employee benefit plans	70,000		68,096
Other	10,000		8,500
Total Principal Accountant Fees and Services	$	1,522,837	$	1,021,629

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

(a) Index to the financial statements, supplementary data and financial statement schedules

IPALCO Enterprises, Inc. and Subsidiaries – Consolidated Financial Statements	Page
Report of Independent Registered Public Accounting Firm – 2023, 2022 and 2021 (PCAOB ID: 42)	60
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	63
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2023, 2022, and 2021	64
Consolidated Balance Sheets as of December 31, 2023 and 2022	65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	66
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021	67
Notes to Consolidated Financial Statements	68
Schedule I – Condensed Financial Information of Registrant	166
Schedule II – Valuation and Qualifying Accounts and Reserves	175
AES Indiana – Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm – 2023, 2022 and 2021 (PCAOB ID: 42)	112
Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021	115
Consolidated Balance Sheets as of December 31, 2023 and 2022	116
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021	117
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2023, 2022 and 2021	118
Notes to Consolidated Financial Statements	119
Schedule II – Valuation and Qualifying Accounts and Reserves	175

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(b) Exhibits
Exhibit No.	Document
3.1	Third Amended and Restated Articles of Incorporation of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.1 to IPALCO’s Form 8-K dated as of February 18, 2015)
3.2	Amended and Restated By-Laws of IPALCO Enterprises, Inc. (Incorporated by reference to Exhibit No. 3.2 to IPALCO’s Form 8-K dated as of February 18, 2015)
4.1	Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A. dated as of November 14, 2001 (Incorporated by reference to Exhibit No 4.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.2	Mortgage and Deed of Trust, dated as of May 1, 1940, between IPL and the Bank of New York Mellon Trust Company, NA, as successor in interest to American National Bank & Trust Company of Chicago, Trustee (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
4.3	The following supplemental indentures to the Mortgage and Deed of Trust referenced in 4.2 above:
	Third Supplemental Indenture, dated as of April 1, 1949 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Tenth Supplemental Indenture, dated as of October 1, 1960 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Eighteenth Supplemental Indenture, dated as of February 15, 1974 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Forty-Eighth Supplemental Indenture, dated as of January 1, 2004 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Fifty-Third Supplemental Indenture, dated as of October 1, 2006 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Fifty-Fourth Supplemental Indenture, dated as of June 1, 2007 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
	Sixtieth Supplemental Indenture, dated as of November 1, 2011 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2011 Form 10-K)
	Sixty-First Supplemental Indenture, dated as of June 1, 2013 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2013 Form 10-Q)
	Sixty-Second Supplemental Indenture, dated as of June 1, 2014 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2014 Form 10-Q)
	Sixty-Third Supplemental Indenture, dated as of September 1, 2015 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on September 28, 2015)
	Sixty-Fourth Supplemental Indenture, dated as of May 1, 2016 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s June 30, 2016 Form 10-Q)
	Sixty-Fifth Supplemental Indenture, dated as of December 1, 2016 (Incorporated by reference to Exhibit No. 4.3 to IPALCO’s December 31, 2016 Form 10-K)
	Sixty-Sixth Supplemental Indenture, dated as of November 1, 2018 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2018 Form 10-K)
	Sixty-Seventh Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3A to IPALCO's December 31, 2020 Form 10-K)
	Sixty-Eighth Supplemental Indenture, dated as of December 1, 2020 (Incorporated by reference to Exhibit No. 4.3B to IPALCO's December 31, 2020 Form 10-K)
	Sixty-Ninth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's June 30, 2021 Form 10-Q)
	Seventieth Supplemental Indenture, dated as of July 1, 2021 (Incorporated by reference to Exhibit No. 4.2 to IPALCO's June 30, 2021 Form 10-Q)
	Seventy-First Supplemental Indenture, dated as of November 15, 2022 (Incorporated by reference to Exhibit No. 4.3 to IPALCO's December 31, 2022 Form 10-K)
4.4	Indenture between IPALCO Enterprises, Inc. and U.S. Bank, National Association, as Trustee, dated August 22, 2017 for IPALCO’s 3.70% Senior Secured Notes due 2024 (Incorporated by reference to Exhibit No. 4.1 to IPALCO’s August 22, 2017 Form 8-K)
4.5	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon trust Company, N.A., as Collateral Agent, dated August 22, 2017 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended (Incorporated by reference to Exhibit No. 4.2 to IPALCO’s August 22, 2017 Form 8-K)
4.6	Indenture between IPALCO Enterprises, Inc. and U.S. Bank National Association, as Trustee, dated April 14, 2020 for the 4.250% Senior Secured Notes due 2030 (Incorporated by reference to Exhibit No. 4.1 to IPALCO's April 14, 2020 Form 8-K)
4.7	Pledge Agreement Supplement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company, N.A., as Collateral Agent, dated April 14, 2020 to the Pledge Agreement between IPALCO Enterprises, Inc. and The Bank of New York Mellon Trust Company dated November 14, 2001, as amended and supplemented (Incorporated by reference to Exhibit No. 4.2 to IPALCO's April 14, 2020 Form 8-K)
10.1	Interconnection Agreement, dated April 1, 2008, between American Electric Power Service Corporation, as agent for Indiana Michigan Power Company, and IPL (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)

164

10.2	Interconnection Agreement, dated December 2, 1968, between IPL and Southern Indiana Gas and Electric Company as modified through Modification Number 11 (Incorporated by reference to Exhibit No. 10.2 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.3	Interconnection Agreement dated December 1, 1981, between IPL and Hoosier Energy Rural Electric Cooperative, Inc., as modified through Modification 6 (Incorporated by reference to Exhibit No. 10.3 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.4	Tenth Supplemental Agreement to the Interconnection Agreement between IPL and PSI Energy, Inc., dated as of June 26, 2002, amending and completely restating prior agreements (Incorporated by reference to Exhibit No. 10.4 to IPALCO’s Registration Statement on Form S-4 filed with the SEC on October 11, 2011)
10.5	$350,000,000 Revolving Credit Facility Amended and Restated Credit Agreement, dated December 22, 2022, among Indianapolis Power & Light Company, each lender from time to time party thereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Joint Bookrunner and Joint Lead Arranger, U.S. Bank, National Association, as Syndication Agent, Joint Bookrunner and Joint Lead Arranger and The Huntington National Bank, as Documentation Agent (Incorporated by reference to Exhibit 10.1 to IPALCO's Current Report on Form 8-K filed on December 23, 2022)
10.6	$300,000,000 Term Loan Agreement by and among Indianapolis Power & Light Company, d/b/a AES Indiana the Lenders Party Hereto, PNC Bank, National Association, as Administrative Agent, PNC Capital Markets LLC, as Bookrunner and Joint Lead Arranger, U.S. Bank National Association, as Syndication Agent and Joint Lead Arranger, and The Huntington National Bank, as Documentation Agent and Joint Lead Arranger, dated as of November 21, 2023
10.7	Subscription Agreement by and between IPALCO and CDP Infrastructures Fund G.P., a wholly owned subsidiary of La Caisse de dépȏt et placement du Québec dated December 14, 2014 (Incorporated by reference to Exhibit 10.10 to IPALCO’s December 31, 2014 10-K/A)
10.8	IPALCO’s Shareholders’ Agreement by and among AES U.S. Investments, Inc., IPALCO Enterprises, Inc. and CDP Infrastructures Fund G.P. dated as of February 11, 2015 (Incorporated by reference to Exhibit No. 10.1 to IPALCO’s March 31, 2015 10-Q)
10.9	The AES Corporation 2023 Long Term Compensation Plan, as amended and restated, dated October 11, 2023 (Incorporated by reference to Exhibit 10.5 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.10	The AES Corporation Performance Incentive Plan, as amended and restated on April 23, 2015 (Incorporated by reference to Exhibit 99.2 of The AES Corporation’s Form 8-K filed on April 23, 2015)
10.11	The AES Corporation Severance Plan, as amended and restated on August 4, 2017 (Incorporated by reference to Exhibit 10.1 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2017)
10.12	The AES Corporation Restoration Supplemental Retirement Plan, as amended and restated, effective October 10, 2023 (Incorporated by reference to Exhibit 10.12 of The AES Corporation’s Form 10-K for the year ended December 31, 2023)
10.13	Form of AES Performance Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.13 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.14	Form of AES Restricted Stock Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.14 of The AES Corporation’s Form 10-K for the year ended December 31, 2019)
10.15	Form of AES Performance Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.15 of The AES Corporation’s Form 10-K for the year ended December 31, 2015)
10.16	Form of AES Nonqualified Stock Option Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.4 of The AES Corporation’s Form 10-Q for the quarter ended June 30, 2015)
10.17	Form of AES Performance Cash Unit Award Agreement under The AES Corporation 2003 Long Term Compensation Plan (Incorporated by reference to Exhibit 10.17 of The AES Corporation’s Form 10-K for the year ended December 31, 2019)
10.18	The AES Corporation Amended and Restated Executive Severance Plan dated October 5, 2018 is incorporated by reference to Exhibit 10.1 of the AES Corporation's Form 10-Q for the quarter ended September 30, 2018)
21	Subsidiaries of IPALCO Enterprises, Inc.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.SCH	XBRL Taxonomy Extension Schema Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.LAB	XBRL Taxonomy Extension Label Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (furnished herewith as provided in Rule 406T of Regulation S-T)

165

(c) Financial Statement Schedules

Schedules other than those listed below are omitted as the information is either not applicable, not required, or has been furnished in the financial statements or notes thereto included in Item 8 hereof.

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Statements of Operations
	2023		2022		2021
	(In Thousands)
OTHER INCOME / (EXPENSE), NET:
Equity in income of subsidiaries	$	116,190	$	126,466	$	147,030
Interest expense	(43,877)		(43,805)		(41,380)
Other expense, net	(121)		(571)		(45)
Total other income, net	72,192		82,090		105,605
INCOME FROM OPERATIONS BEFORE INCOME TAX	72,192		82,090		105,605
Income tax benefit	(10,928)		(11,027)		(10,364)
NET INCOME	$	83,120	$	93,117	$	115,969

See Notes to Schedule I.

166

IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Comprehensive Income
	2023		2022		2021
	(In Thousands)
NET INCOME	$	83,120	$	93,117	$	115,969
Derivative activity:
Change in derivative fair value, net of income tax effect of $(528), $(15,309) and $(3,441), for each respective period	1,594		46,245		10,393
Reclassification to earnings, net of income tax effect of $(1,798), $(1,798) and $(1,199), for each respective period	5,431		5,431		3,620
Net change in fair value of derivatives	7,025		51,676		14,013
Other comprehensive income	7,025		51,676		14,013
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	90,145	$	144,793	$	129,982

See Notes to Schedule I.

167

IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Balance Sheets
	December 31, 2023		December 31, 2022
	(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	537	$	191
Taxes receivable	31,341		11,318
Derivative assets, current	14,294		—
Prepayments and other current assets	7,626		7,509
Total current assets	53,798		19,018
OTHER NON-CURRENT ASSETS:
Investment in subsidiaries	1,921,548		1,945,556
Derivative assets, non-current	—		12,172
Other non-current assets	3,540		3,211
Total other non-current assets	1,925,088		1,960,939
TOTAL ASSETS	$	1,978,886	$	1,979,957
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term and current portion of long-term debt	$	404,474	$	—
Accounts payable	—		87
Accrued interest	8,360		8,360
Total current liabilities	412,834		8,447
NON-CURRENT LIABILITIES:
Long-term debt	470,653		873,663
Deferred tax liability - long-term	18,931		7,329
Total non-current liabilities	489,584		880,992
Total liabilities	902,418		889,439
SHAREHOLDERS' EQUITY
Paid in capital	1,021,992		1,068,357
Accumulated other comprehensive income	29,294		22,269
Retained earnings / (accumulated deficit)	25,182		(108)
Total shareholders' equity	1,076,468		1,090,518
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	1,978,886	$	1,979,957

See Notes to Schedule I.

168

IPALCO ENTERPRISES, INC.
Schedule I – Condensed Financial Information of Registrant
Unconsolidated Statements of Cash Flows
	2023		2022		2021
	(In Thousands)
CASH FLOWS FROM OPERATIONS:
Net income	$	83,120	$	93,117	$	115,969
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries	(116,190)		(126,466)		(147,030)
Cash dividends received from subsidiary companies	140,200		127,200		155,700
Amortization of deferred financing costs and debt premium	1,474		1,403		1,379
Deferred income taxes – net	9,276		(121)		(5)
Change in certain assets and liabilities:
Accounts payable	(23)		(194)		(85)
Accrued taxes payable/receivable	(20,022)		(2,406)		2,940
Other – net	6,798		7,744		4,265
Net cash provided by operating activities	104,633		100,277		133,133
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries	—		(253,000)		(275,000)
Net cash used in investing activities	—		(253,000)		(275,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of loans to subsidiary	—		—		(6,110)
Distributions to shareholders	(104,287)		(101,986)		(131,476)
Equity contributions from shareholders	—		253,000		275,000
Deferred financing costs paid and other	—		(2)		(62)
Net cash (used in) provided by financing activities	(104,287)		151,012		137,352
Net change in cash, cash equivalents and restricted cash	346		(1,711)		(4,515)
Cash, cash equivalents and restricted cash at beginning of period	191		1,902		6,417
Cash, cash equivalents and restricted cash at end of period	$	537	$	191	$	1,902
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	35,569	$	35,173	$	35,172
Income taxes	—		31,000		27,500

See Notes to Schedule I.

169

IPALCO ENTERPRISES, INC.
Schedule I - Condensed Financial Information of Registrant
Unconsolidated Statements of Changes in Equity (Deficit)
	Paid in Capital		Accumulated Other Comprehensive Income (Loss)		Retained Earnings (Accumulated Deficit)		Total Shareholders' Equity
	(In Thousands)
Balance at January 1, 2021	$	588,966	$	(43,420)	$	(24,558)	$	520,988
Net comprehensive income	—		14,013		115,969		129,982
Distributions to shareholders(1)	(15,507)		—		(115,969)		(131,476)
Contributions from shareholders	275,000		—		—		275,000
Other	106		—		—		106
Balance at December 31, 2021	848,565		(29,407)		(24,558)		794,600
Net comprehensive income	—		51,676		93,117		144,793
Distributions to shareholders(1)	(33,319)		—		(68,667)		(101,986)
Contributions from shareholders	253,000		—		—		253,000
Other	111		—		—		111
Balance at December 31, 2022	1,068,357		22,269		(108)		1,090,518
Net comprehensive income	—		7,025		83,120		90,145
Distributions to shareholders(1)	(46,457)		—		(57,830)		(104,287)
Other	92		—		—		92
Balance at December 31, 2023	$	1,021,992	$	29,294	$	25,182	$	1,076,468
1) IPALCO made return of capital payments of $46.5 million, $33.3 million and $15.5 million in 2023, 2022 and 2021, respectively, for the portion of current year distributions to shareholders in excess of current year net income at the time of distribution.

See Notes to Schedule I.

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IPALCO ENTERPRISES, INC.

Schedule I – Condensed Financial Information of Registrant

Notes to Schedule I

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting for Subsidiaries and Affiliates – IPALCO has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

2. FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Financial Assets

VEBA Assets

IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Unconsolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Unconsolidated Statements of Operations.

171

Financial Assets

Interest Rate Hedges

IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 3, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.

Summary

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	127	$	—	$	—	$	127	$	5	$	—	$	—	$	5
Mutual funds	3,425		—		—		3,425		3,223		—		—		3,223
Total VEBA investments	3,552		—		—		3,552		3,228		—		—		3,228
Interest rate hedges	—		14,294		—		14,294		—		12,172		—		12,172
Total financial assets measured at fair value	$	3,552	$	14,294	$	—	$	17,846	$	3,228	$	12,172	$	—	$	15,400

Financial Instruments not Measured at Fair Value in the Unconsolidated Balance Sheets

Debt

The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate indebtedness (Level 2) for the periods ending:

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	880,000	$	839,471	$	880,000	$	816,411
Total indebtedness	$	880,000	$	839,471	$	880,000	$	816,411

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $4.6 million and $5.9 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $0.3 million and $0.4 million at December 31, 2023 and 2022, respectively.

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3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, IPALCO's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)		Sales (in thousands)		Net Notional (in thousands)
Interest rate hedges	Designated	USD	$	400,000	$	—	$	400,000

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.

In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment will be amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.

The following tables provide information on gains or losses recognized in AOCL for the cash flow hedges for the period indicated:

	Interest Rate Hedges for the Year Ended December 31,
$ in thousands (net of tax)	2023		2022		2021
Beginning accumulated derivative gain / (loss) in AOCL	$	22,269	$	(29,407)	$	(43,420)
Net gains associated with current period hedging transactions	1,594		46,245		10,393
Net losses reclassified to interest expense	5,431		5,431		3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)	$	29,294	$	22,269	$	(29,407)
Loss expected to be reclassified to earnings in the next twelve months	$	(5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9

When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.

173

The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments:

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	14,294	$	—
Interest rate hedges	Cash Flow Hedge	Derivative assets, non-current	$	—	$	12,172

4. DEBT

The following table presents IPALCO’s long-term indebtedness:

		December 31,
Series	Due	2023		2022
		(In Thousands)
Long-Term Debt
3.70% Senior Secured Notes	September 2024	405,000		405,000
4.25% Senior Secured Notes	May 2030	475,000		475,000
Unamortized discount – net		(319)		(425)
Deferred financing costs – net		(4,554)		(5,912)
Total long-term debt		875,127		873,663
Less: current portion of long-term debt		405,000		—
Net long-term debt		$	470,127	$	873,663

IPALCO’s Senior Secured Notes and Term Loan

The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.

Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

174

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2023, 2022 and 2021
(In Thousands)
Column A – Description	Column B		Column C – Additions				Column D – Deductions		Column E
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Net Write-offs		Balance at End of Period
Year ended December 31, 2023
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	1,117	$	8,930	$	—	$	7,764	$	2,283
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	5,160	$	736	$	—	$	2,456	$	3,440
Year ended December 31, 2022
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	647	$	7,478	$	—	$	7,008	$	1,117
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	3,107	$	2,053	$	—	$	—	$	5,160
Year ended December 31, 2021
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	3,155	$	3,940	$	—	$	6,448	$	647
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	6,133	$	758	$	—	$	3,784	$	3,107

AES INDIANA and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2023, 2022 and 2021
(In Thousands)
Column A – Description	Column B		Column C – Additions				Column D – Deductions		Column E
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Net Write-offs		Balance at End of Period
Year ended December 31, 2023
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	1,117	$	8,930	$	—	$	7,764	$	2,283
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	5,160	$	736	$	—	$	2,456	$	3,440
Year ended December 31, 2022
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	647	$	7,478	$	—	$	7,008	$	1,117
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	3,107	$	2,053	$	—	$	—	$	5,160
Year ended December 31, 2021
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	3,155	$	3,940	$	—	$	6,448	$	647
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	6,133	$	758	$	—	$	3,784	$	3,107

ITEM 16. FORM 10-K SUMMARY

None.

175

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

                    IPALCO ENTERPRISES, INC. 

                    (Registrant)

Date:    February 26, 2024                /s/ Kenneth J. Zagzebski

                    Kenneth J. Zagzebski

                            President and Chief Executive Officer 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/s/ Kenneth J. Zagzebski	President, Chief Executive Officer, Director and Chairman (Principal Executive Officer)	February 26, 2024
Kenneth J. Zagzebski
/s/ Ricardo Manuel Falú	Director	February 26, 2024
Ricardo Manuel Falú
/s/ Bernerd Da Santos	Director	February 26, 2024
Bernerd Da Santos
/s/ Paul L. Freedman	Director	February 26, 2024
Paul L. Freedman
/s/ Susan Harcourt	Director	February 26, 2024
Susan Harcourt
/s/ Marc Michael	Director	February 26, 2024
Marc Michael
/s/ Stephen Coughlin	Director	February 26, 2024
Stephen Coughlin
/s/ Tish Mendoza	Director	February 26, 2024
Tish Mendoza
/s/ Frédéric Lesage	Director	February 26, 2024
Frédéric Lesage
/s/ Olivier Roy Durocher	Director	February 26, 2024
Olivier Roy Durocher
/s/ Sherry Kohan	Interim Vice President and Chief Financial Officer (Principal Financial Officer)	February 26, 2024
Sherry Kohan
/s/ Karin M. Mehringer	Controller (Principal Accounting Officer)	February 26, 2024
Karin M. Mehringer

Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15 (d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act

No annual report or proxy material has been sent to security holders.

176

EX-10.6

Execution Version

TERM LOAN CUSIP: 45543KAG9

$300,000,000 TERM LOAN AGREEMENT

by and among

INDIANAPOLIS POWER & LIGHT COMPANY

d/b/a AES Indiana

THE LENDERS PARTY HERETO

PNC BANK, NATIONAL ASSOCIATION, as Administrative Agent

PNC CAPITAL MARKETS LLC, as Bookrunner and Joint Lead Arranger

U.S. BANK NATIONAL ASSOCIATION, as Syndication Agent and Joint Lead Arranger

and

THE HUNTINGTON NATIONAL BANK, as Documentation Agent and Joint Lead Arranger

Dated as of November 21, 2023

TABLE OF CONTENTS

Page

1.	CERTAIN DEFINITIONS		1
	1.1	Certain Definitions	1
	1.2	Construction	20
	1.3	Accounting Principles	21
	1.4	Term SOFR Notification	21
2.	RESERVED		21
3.	TERM LOAN		21
	3.1	Term Loan Commitments	21
	3.2	Nature of Lenders' Obligations with Respect to Term Loan; Repayment Terms	21
	3.3	Use of Proceeds	22
	3.4	Defaulting Lenders	22
	3.5	Interest Rate Elections; Conversions and Renewals	22
4.	INTEREST RATES		22
	4.1	Interest Rate Options	22
	4.2	Interest Periods	23
	4.3	Interest After Default	24
	4.4	Term SOFR Rate Unascertainable; Increased Costs; Illegality; Benchmark Replacement Setting	24
	4.5	Selection of Interest Rate Options	30
5.	PAYMENTS; Taxes; Yield maintenance		30
	5.1	Payments	30
	5.2	Pro Rata Treatment of Lenders	30
	5.3	Sharing of Payments by Lenders	31
	5.4	Presumptions by Administrative Agent	31
	5.5	Interest Payment Dates	31
	5.6	Voluntary Prepayments	32
	5.7	[Intentionally Omitted]	32
	5.8	Increased Costs	33
	5.9	Taxes	34
	5.10	Indemnity	37

-i-

TABLE OF CONTENTS

(continued)

Page

	5.11	reserved	38
	5.12	reserved	38
	5.13	Replacement of a Lender	38
	5.14	Designation of a Different Lending Office	39
6.	REPRESENTATIONS AND WARRANTIES		39
	6.1	Representations and Warranties	39
7.	CONDITIONS OF LENDING		44
	7.1	Conditions Precedent to Effectiveness of this Agreement	44
8.	COVENANTS		45
	8.1	Affirmative Covenants	45
	8.2	Negative Covenants	47
	8.3	Reporting Requirements	52
	8.4	Other Additional Information	53
9.	DEFAULT		54
	9.1	Events of Default	54
	9.2	Consequences of Event of Default	55
10.	THE ADMINISTRATIVE AGENT		57
	10.1	Appointment and Authority	57
	10.2	Rights as a Lender	57
	10.3	Exculpatory Provisions	58
	10.4	Reliance by Administrative Agent	58
	10.5	Delegation of Duties	59
	10.6	Resignation of Administrative Agent	59
	10.7	Non-Reliance on Administrative Agent and Other Lenders	60
	10.8	No Other Duties, etc.	60
	10.9	Administrative Agent's Fee	60
	10.10	No Reliance on Administrative Agent's Customer Identification Program	60
11.	MISCELLANEOUS		63
	11.1	Modifications, Amendments or Waivers	63
	11.2	No Implied Waivers; Cumulative Remedies	63

-ii-

TABLE OF CONTENTS

(continued)

Page

11.3	Expenses; Indemnity; Damage Waiver	64
11.4	Holidays	65
11.5	Notices; Effectiveness; Electronic Communication	65
11.6	Severability	66
11.7	Duration; Survival	66
11.8	Successors and Assigns	67
11.9	Confidentiality	70
11.10	Counterparts; Integration; Effectiveness	71
11.11	CHOICE OF LAW; SUBMISSION TO JURISDICTION; WAIVER OF VENUE; SERVICE OF PROCESS; WAIVER OF JURY TRIAL	71
11.12	USA Patriot Act Notice	72
11.13	Certain ERISA Matters	72
11.14	Acknowledgement and Consent to Bail-In of Affected Financial Institutions	74
11.15	No Advisory or Fiduciary Responsibility	74

-iii-

LIST OF SCHEDULES AND EXHIBITS

SCHEDULES
SCHEDULE 1.1(B) -	COMMITMENTS OF LENDERS AND ADDRESSES FOR NOTICES
SCHEDULE 6.1(a) -	QUALIFICATIONS TO DO BUSINESS
SCHEDULE 6.1(b) -	SUBSIDIARIES
SCHEDULE 6.1(e) -	LITIGATION
SCHEDULE 6.1(n) -	ENVIRONMENTAL DISCLOSURES
SCHEDULE 7.1(a) -	OPINION OF COUNSEL
SCHEDULE 8.2(p) -	EXISTING INVESTMENTS
EXHIBITS
EXHIBIT A	ASSIGNMENT AND ASSUMPTION AGREEMENT
EXHIBIT B	TERM LOAN NOTE
EXHIBIT C	INTEREST RATE ELECTION
EXHIBIT D-1	U.S. TAX COMPLIANCE CERTIFICATE
EXHIBIT D-2	U.S. TAX COMPLIANCE CERTIFICATE
EXHIBIT D-3	U.S. TAX COMPLIANCE CERTIFICATE
EXHIBIT D-4	U.S. TAX COMPLIANCE CERTIFICATE
EXHIBIT 8.3	QUARTERLY COMPLIANCE CERTIFICATE

- iv -

TERM LOAN AGREEMENT

THIS TERM LOAN AGREEMENT (as hereafter amended, the “Agreement”) is dated as of November 21, 2023, and is made by and among INDIANAPOLIS POWER & LIGHT COMPANY, an Indiana corporation doing business as AES Indiana (the “Borrower”), the LENDERS (as hereinafter defined), and PNC BANK, NATIONAL ASSOCIATION, in its capacity as administrative agent for the Lenders under this Agreement (hereinafter referred to in such capacity as the “Administrative Agent”) PNC CAPITAL MARKETS LLC, as Bookrunner and Joint Lead Arranger (hereinafter referred to in such capacity as the “Joint Lead Arranger”), U.S. BANK NATIONAL ASSOCIATION, as Syndication Agent (hereinafter referred to in such capacity as the "Joint Lead Arranger" and "Syndication Agent"), and THE HUNTINGTON NATIONAL BANK, as Documentation Agent (hereinafter referred to in such capacity as the “Joint Lead Arranger” and “Documentation Agent”).

WHEREAS, the Borrower has requested the Lenders and the Administrative Agent to provide a $300,000,000 term loan facility to the Borrower.

NOW THEREFORE, in consideration of their mutual covenants and agreements hereinafter set forth and intending to be legally bound hereby, the parties hereto covenant and agree as follows in this Agreement.

1.    CERTAIN DEFINITIONS

1.1    Certain Definitions. In addition to words and terms defined elsewhere in this Agreement, the following words and terms shall have the following meanings, respectively, unless the context hereof clearly requires otherwise:

“Acquisition” shall mean any transaction, or any series of related transactions, consummated on or after the date of this Agreement, by which the Borrower or any of its Subsidiaries (i) acquires any going business or all or substantially all of the assets of any firm, corporation, partnership or limited liability company, or division thereof, whether through purchase of assets, merger or otherwise or (ii) directly or indirectly acquires (in one transaction or as the most recent transaction in a series of transactions) at least a majority (in number of votes) of the securities of a corporation which have ordinary voting power for the election of directors (other than securities having such power only by reason of the happening of a contingency) or a majority (by percentage or voting power) of the outstanding ownership interests of a partnership or limited liability company.

“Administrative Agent” shall mean PNC Bank, National Association, and its successors and assigns, in its capacity as administrative agent hereunder.

“Administrative Agent’s Fee” shall have the meaning specified in Section 10.9 [Administrative Agent’s Fee].

“Administrative Agent’s Letter” shall have the meaning specified in Section 10.9 [Administrative Agent’s Fee].

“Administrative Questionnaire” shall mean an administrative questionnaire in a form supplied by the Administrative Agent.

“Affected Financial Institution” shall mean (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Affiliate” as to any Person shall mean any other Person (i) which directly or indirectly controls, is controlled by, or is under common control with such Person, (ii) which beneficially owns or holds 10% or more of any common equity interests of such Person, or (iii) 10% or more of any common equity interests of which is beneficially owned or held, directly or indirectly, by such Person.

“Anti-Corruption Laws” shall mean the United States Foreign Corrupt Practices Act of 1977, as amended, the UK Bribery Act 2010, and any other similar anti-corruption Laws or regulations administered or enforced in any jurisdiction in which the Borrower or any of its Subsidiaries conduct business.

“Anti-Terrorism Law” shall mean any Law in force or hereinafter enacted related to terrorism, money laundering, or economic sanctions, including the Bank Secrecy Act, 31 U.S.C. § 5311 et seq., the USA PATRIOT Act, the International Emergency Economic Powers Act, 50 U.S.C. 1701, et seq., the Trading with the Enemy Act, 50 U.S.C. App. 1, et seq., 18 U.S.C. § 2332d, and 18 U.S.C. § 2339B.

“Applicable Margin” shall mean 0% with respect to the portion of the Loan to which a Base Rate Option applies, and 1.00% with respect to the portion of the Loan to which a Term SOFR Rate Option applies.

“Approved Fund” shall mean any fund that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of business and that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Assignment and Assumption Agreement” shall mean an assignment and assumption agreement entered into by a Lender and an assignee permitted under Section 11.8 [Successors and Assigns], in substantially the form of Exhibit A.

“Authorized Officer” shall mean, with respect to the Borrower, the Chairman, the President and Chief Executive Officer, any Vice President, the Chief Financial Officer, the Controller, the Treasurer, the Assistant Treasurer, the General Counsel and Secretary, or such other individuals, designated by written notice to the Administrative Agent from the Borrower, authorized to execute notices, reports and other documents on behalf of the Borrower required hereunder. The Borrower may amend such list of individuals from time to time by giving written notice of such amendment to the Administrative Agent.

“Bail-In Action” shall mean the exercise of any Write-down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

2

“Bail-In Legislation” shall mean (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Base Rate” shall mean, for any day, a fluctuating per annum rate of interest equal to the highest of (i) the Overnight Bank Funding Rate, plus 0.5%, (ii) the Prime Rate, and (iii) the Daily Simple SOFR, plus 1.00%, so long as Daily Simple SOFR is offered, ascertainable and not unlawful; provided, however, if the Base Rate as determined above would be less than zero, then such rate shall be deemed to be zero. Any change in the Base Rate (or any component thereof) shall take effect at the opening of business on the day such change occurs. Notwithstanding anything to the contrary contained herein, in the case of any event specified in Section 4.4(a) [Unascertainable; Increased Costs] or Section 4.4(b) [Illegality], to the extent any such determination affects the calculation of Base Rate, the definition hereof shall be calculated without reference to clause (iii) until the circumstances giving rise to such event no longer exist.

“Base Rate Option” shall mean the option of the Borrower to have the Loan or a portion thereof bear interest at the rate and under the terms specified in Section 4.1(a)(i) [Term Loan Base Rate Option].

“Benchmark Replacement” shall mean as is specified in Section 4.4(d) [Benchmark Replacement Setting].

“Benefit Plan” shall mean any of (a) an "employee benefit plan" (as defined in ERISA) that is subject to Title I of ERISA, (b) a "plan" as defined in and subject to Section 4975 of the Code or (c) any Person whose assets include (for purposes of ERISA Section 3(42) or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such "employee benefit plan" or "plan".

“Borrower” has the meaning assigned in the first paragraph of this Agreement.

“Borrowing Date” shall mean, with respect to the Loan, the date of the making, renewal or conversion thereof, which shall be a Business Day.

“Borrowing Tranche” shall mean specified portions of the Loan outstanding as follows: (a) any portion of the Loan to which a Term SOFR Rate Option applies and which have the same Interest Period shall constitute one Borrowing Tranche, and (b) any portion of the Loan to which a Base Rate Option applies shall constitute one Borrowing Tranche.

“Business Day” shall mean any day other than a Saturday or Sunday or a legal holiday on which commercial banks are authorized or required to be closed, or are in fact closed, for business in Pittsburgh, Pennsylvania (or, if otherwise, the Lending Office of the Administrative Agent); provided that, when used in connection with an amount that bears interest at a rate based on SOFR or any direct or indirect calculation or determination of SOFR, the term “Business Day” shall mean any such day that is also a U.S. Government Securities Business Day.

3

“Capital Lease” shall mean, as to any Person, a lease of any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, by such Person as lessee that is, or should be, in accordance with Accounting Standards Committee - Leases. Topic 840 (formerly, the Financial Accounting Standards Board Statement No. 13), as amended from time to time, or, if such statement is not then in effect, such statement of GAAP as may be applicable, recorded as a “capital lease” on the balance sheet of the Borrower prepared in accordance with GAAP.

“Cash Equivalent and Short-Term Investments” shall mean: (a) obligations of, or unconditionally guaranteed by, the United States of America; (b) obligations issued or guaranteed by any person controlled or supervised by and acting as an instrumentality of the United States of America pursuant to authority granted by the Congress of the United States of America; (c) negotiable or non-negotiable certificates of deposit and time deposits issued by any bank, trust company or national banking association, including the Administrative Agent, having total assets in excess of one (1) billion Dollars and which has combined capital, surplus and undivided profits of at least $25,000,000; (d) commercial paper of the quality rated on the date of purchase at “A-1” by S&P or “P-1” by Moody’s purchased directly or through recognized money market dealers; (e) municipal obligations the interest on which is excluded from the gross income of the owners thereof for federal tax purposes under Section 103 of the Code, if rated on the date of purchase in one of the two highest rating categories of either Moody’s or S&P; (f) any repurchase agreement secured by any one or more of the foregoing; (g) any repurchase agreement or guaranteed investment contract from a bank or insurance company rated on the date of purchase in one of the two highest rating categories of either Moody’s or S&P and secured by any one or more of the foregoing with collateral equal or greater than 102% of the principal amount originally invested valued on a weekly basis; (h) units or shares of a Qualified Regulated Investment Company which invests solely in obligations described in clause (e) above; for purposes of this clause (h) a Qualified Regulated Investment Company means a qualified regulated investment company as defined by the Internal Revenue Service including any regulated investment company (as defined in Section 851(a) of the Code) which, (i) for the taxable year, meets the requirements of Section 852(a) of the Code, (ii) has authorized and outstanding only one class of units or shares and (iii) to the extent practicable invests all of its assets in tax-exempt bonds, or the weighted average value of its assets is represented by investments in tax-exempt bonds; and (i) money market funds which funds are rated on the date of purchase in one of the two highest rating categories of either Moody’s or S&P.

“Change in Law” shall mean the occurrence, after the date of this Agreement, of any of the following: (i) the adoption or taking effect of any Law, (ii) any change in any Law or in the administration, interpretation, implementation or application thereof by any Official Body or (iii) the making or issuance of any request, rule, guideline or directive (whether or not having the force of Law) by any Official Body; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, regulations, guidelines, interpretations or directives thereunder or issued in connection therewith (whether or not having the force of Law) and (y) all requests, rules, regulations, guidelines, interpretations or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities (whether or not having the force of Law), in each case pursuant to Basel III, shall in each case be deemed to be a Change in Law regardless of the date enacted, adopted, issued, promulgated or implemented.

4

“CIP Regulations” shall have the meaning specified in Section 10.10 [No Reliance on Administrative Agent’s Customer Identification Program].

“Closing Date” shall mean November 21, 2023.

“Code” shall mean the Internal Revenue Code of 1986, as the same may be amended or supplemented from time to time, and any successor statute of similar import, and the rules and regulations thereunder, as from time to time in effect.

“Commitment” shall mean as to any Lender the aggregate of its Term Loan Commitment and “Commitments” shall mean the aggregate of the Term Loan Commitments of all of the Lenders.

“Commodity Hedge” shall mean commodity hedge or similar hedging agreements entered into by the Borrower in the ordinary course of business and not for speculative purposes.

“Compliance Certificate” shall have the meaning specified in Section 8.3(c) [Certificate of the Borrower].

“Conforming Changes” shall mean, with respect to the Term SOFR Rate or any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “Base Rate,” the definition of “Business Day,” the definition of “Interest Period,” the definition of “U.S. Government Securities Business Day,” timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, the applicability and length of lookback periods, the applicability of breakage provisions, and other technical, administrative or operational matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of the Term SOFR Rate or such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of the Term SOFR Rate or the Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Loan Documents).

“Connection Income Taxes” shall mean Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Consolidated Total Capitalization” shall mean at any time the sum of Total Debt and Total Capital, each calculated at such time.

5

“Covered Entity” shall mean the Borrower, each of Borrower’s Subsidiaries, all guarantors and all pledgors of collateral.

“Daily Simple SOFR” shall mean, for any day (a “SOFR Rate Day”), the interest rate per annum determined by the Administrative Agent by dividing (the resulting quotient rounded upwards, at the Administrative Agent’s discretion, to the nearest 1/100th of 1%) (A) SOFR for the day (the “SOFR Determination Date”) that is 2 Business Days prior to (i) such SOFR Rate Day if such SOFR Rate Day is a Business Day or (ii) the Business Day immediately preceding such SOFR Rate Day if such SOFR Rate Day is not a Business Day, by (B) a number equal to 1.00 minus the SOFR Reserve Percentage, in each case, as such SOFR is published by the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate) on the website of the Federal Reserve Bank of New York, currently at http://www.newyorkfed.org, or any successor source identified by the Federal Reserve Bank of New York or its successor administrator for the secured overnight financing rate from time to time. If Daily Simple SOFR as determined above would be less than the SOFR Floor, then Daily Simple SOFR shall be deemed to be the SOFR Floor. If SOFR for any SOFR Determination Date has not been published or replaced with a Benchmark Replacement by 5:00 p.m. (Pittsburgh, Pennsylvania time) on the second Business Day immediately following such SOFR Determination Date, then SOFR for such SOFR Determination Date will be SOFR for the first Business Day preceding such SOFR Determination Date for which SOFR was published in accordance with the definition of “SOFR”; provided that SOFR determined pursuant to this sentence shall be used for purposes of calculating Daily Simple SOFR for no more than 3 consecutive SOFR Rate Days. If and when Daily Simple SOFR as determined above changes, any applicable rate of interest based on Daily Simple SOFR will change automatically without notice to the Borrower, effective on the date of any such change.

“Defaulting Lender” shall mean any Lender that (a) has failed, within two Business Days of the date required to be funded or paid, to (i) fund any portion of the Loan, or (ii) pay over to the Administrative Agent or any Lender any other amount required to be paid by it hereunder, unless, in the case of clause (i) above, such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that a condition precedent to funding (specifically identified and including the particular default, if any) has not been satisfied, (b) has notified the Borrower or the Administrative Agent in writing, or has made a public statement to the effect, that it does not intend or expect to comply with any of its funding obligations under this Agreement (unless such writing or public statement indicates that such position is based on such Lender’s good faith determination that a condition precedent (specifically identified and including the particular default, if any) to funding a loan under this Agreement cannot be satisfied) or generally under other agreements in which it commits to extend credit, (c) has failed, within two Business Days after request by the Administrative Agent or the Borrower, acting in good faith, to provide a certification in writing from an authorized officer of such Lender that it will comply with its obligations (and is financially able to meet such obligations) to fund the Loan under this Agreement, provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon the Administrative Agent’s or the Borrower’s receipt of such certification in form and substance satisfactory to the Administrative Agent or the Borrower, as the case may be, (d) has become the subject of a Bankruptcy Event, (e) has become the subject of a Bail-In Action, or (f) has failed at any time to comply with the provisions of Section 5.3 [Sharing of Payments by Lenders] with respect to purchasing participations from the other Lenders, whereby such Lender’s share of any payment received, whether by setoff or otherwise, is in excess of its Ratable Share of such payments due and payable to all of the Lenders.

6

As used in this definition and in Section 3.4 [Defaulting Lenders], the term “Bankruptcy Event” means, with respect to any Person, such Person or such Person’s direct or indirect parent company becoming the subject of a bankruptcy or insolvency proceeding, or having had a receiver, conservator, trustee, administrator, custodian, assignee for the benefit of creditors or similar Person charged with the reorganization or liquidation of its business appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment, provided that a Bankruptcy Event shall not result solely by virtue of any ownership interest, or the acquisition of any ownership interest, in such Person or such Person’s direct or indirect parent company by an Official Body or instrumentality thereof if, and only if, such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Official Body or instrumentality) to reject, repudiate, disavow or disaffirm any contracts or agreements made by such Person.

“Dollar, Dollars, U. S. Dollars” and the symbol $ shall mean lawful money of the United States of America.

“EEA Financial Institution” shall mean (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” shall mean any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” shall mean any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Effective Federal Funds Rate” shall mean for any day the rate per annum based on a year of 360 days and actual days elapsed and rounded upward to the nearest 1/100 of 1% announced by the Federal Reserve Bank of New York (or any successor) on such day as being the weighted average of the rates on overnight federal funds transactions arranged by federal funds brokers on the previous trading day, as computed and announced by such Federal Reserve Bank (or any successor) in substantially the same manner as such Federal Reserve Bank computes and announces the weighted average it refers to as the “Effective Federal Funds Rate” as of the date of this Agreement; provided that if such Federal Reserve Bank (or its successor) does not announce such rate on any day, the “Effective Federal Funds Rate” for such day shall be the Effective Federal Funds Rate for the last day on which such rate was announced. Notwithstanding the foregoing, if the Effective Federal Funds Rate as determined under any method above would be less than zero percent (0.00%), such rate shall be deemed to be zero percent (0.00%) for purposes of this Agreement.

7

“Environmental Laws” shall mean all applicable federal, state, local, tribal, territorial and foreign Laws (including common law), constitutions, statutes, treaties, regulations, rules, ordinances and codes and any consent decrees, settlement agreements, judgments, orders, directives, policies or programs issued by or entered into with an Official Body pertaining or relating to: (i) pollution or pollution control; (ii) protection of human health from exposure to regulated substances; (iii) protection of the environment and/or natural resources; (iv) employee safety in the workplace; (v) the presence, use, management, generation, manufacture, processing, extraction, treatment, recycling, refining, reclamation, labeling, packaging, sale, transport, storage, collection, distribution, disposal or release or threat of release of regulated substances; (vi) the presence of contamination; (vii) the protection of endangered or threatened species; and (viii) the protection of environmentally sensitive areas.

“Equity Interests” shall have the meaning specified in Section 6.1(b) [Subsidiaries and Owners; Investment Companies].

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as the same may be amended or supplemented from time to time, and any successor statute of similar import, and the rules and regulations thereunder, as from time to time in effect.

“ERISA Affiliate” shall mean, at any time, any trade or business (whether or not incorporated) under common control with the Borrower and are treated as a single employer under Section 414 of the Code.

“ERISA Event” shall mean (a) a reportable event (under Section 4043 of ERISA and regulations thereunder) with respect to a Pension Plan, other than those events as to which the 30-day notice period referred to in Section 4043(c) of ERISA has been waived; (b) a withdrawal by Borrower or any ERISA Affiliate from a Pension Plan subject to Section 4063 of ERISA during a plan year in which it was a substantial employer (as defined in Section 4001(a)(2) of ERISA) or a cessation of operations that is treated as such a withdrawal under Section 4062(e) of ERISA; (c) a complete or partial withdrawal by Borrower or any ERISA Affiliate from a Multiemployer Plan or notification that a Multiemployer Plan is, or is expected to be, “insolvent” (within the meaning of Section 4245 of ERISA), or in “reorganization” (within the meaning of Section 4241 of ERISA); (d) a determination that any Pension Plan is, or is expected to be, in “at risk” status (within the meaning of Section 430 of the Code or Section 303 of ERISA); (e) the filing of a notice of intent to terminate, the treatment of a Plan amendment as a termination under Sections 4041 or 4041A of ERISA, or the commencement of proceedings by the PBGC to terminate a Pension Plan or Multiemployer Plan; (f) an event or condition which constitutes grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Pension Plan or Multiemployer Plan; (g) the imposition of any material liability under Title IV of ERISA, other than for ordinary funding obligations and PBGC premiums due but not delinquent under Section 4007 of ERISA, upon Borrower or any ERISA Affiliate; (h) the occurrence of an act or omission which could give rise to the imposition on a the Borrower or an ERISA Affiliate of material fines, penalties, taxes or related charges under Chapter 43 of the Code or under Sections 406, 409, 502(c)(i) or (l), or 4071 of ERISA in respect of any Plan; or (i) the failure of any “welfare benefit plan” (as described in Section 3(1) of ERISA) sponsored or maintained by the Borrower or any ERISA Affiliate that provides insured medical benefits, to satisfy the non-discrimination requirements of Section 105 of the Code.

8

“ERISA Group” shall mean, at any time, the Borrower and all members of a controlled group of corporations and all trades or businesses (whether or not incorporated) under common control and all other entities which, together with the Borrower, are treated as a single employer under Section 414 of the Code.

“Erroneous Payment” has the meaning assigned to it in Section 10.11(a).

“Erroneous Payment Deficiency Assignment” has the meaning assigned to it in Section 10.11(d).

“Erroneous Payment Impacted Class” has the meaning assigned to it in Section 10.11(d).

“Erroneous Payment Return Deficiency” has the meaning assigned to it in Section 10.11(d).

“Erroneous Payment Subrogation Rights” has the meaning assigned to it in Section 10.11(d).

“EU” shall have the meaning assigned in the definition of “Sanctioned Person”.

“EU Bail-In Legislation Schedule” shall mean the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Event of Default” shall mean any of the events described in Section 9.1 [Events of Default] and referred to therein as an “Event of Default.”

“Excluded Taxes” shall mean any of the following Taxes imposed on or with respect to a Recipient or required to be withheld or deducted from a payment to a Recipient, (i) Taxes imposed on or measured by net income (however denominated), franchise Taxes, and branch profits Taxes, in each case, (a) imposed as a result of such Recipient being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (b) that are Other Connection Taxes, (ii) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in a Loan or Commitment pursuant to a law in effect on the date on which (a) such Lender acquires such interest in such Loan or Commitment (other than pursuant to an assignment request by the Borrower under Section 5.13(b) [Replacement of a Lender]) or (b) such Lender changes its lending office, except in each case to the extent that, pursuant to Section 5.9(g) [Status of Lenders], amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office, (iii) Taxes attributable to such Recipient’s failure to comply with Section 5.9(g) [Status of Lenders], and (iv) any U.S. federal withholding Taxes imposed under FATCA (except to the extent imposed due to the failure of the Borrower to provide documentation or information to the IRS).

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“Executive Order No. 13224” shall mean the Executive Order No. 13224 on Terrorist Financing, effective September 24, 2001, as the same has been, or shall hereafter be, renewed, extended, amended or replaced.

“Facility” shall mean the Commitments of the Lenders to make the Term Loan extended under such Commitments.

“FATCA” shall mean Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof and any agreements entered into pursuant to Section 1471(b)(1) of the Code.

“FERC” shall mean the Federal Energy Regulatory Commission and any successor agency thereto.

“FERC Order” shall mean the order issued by the FERC to the Borrower dated July 20, 2022, Docket No. ES22-47-000, or an extension, renewal or replacement of such order.

“Foreign Lender” shall mean any Lender that is organized under the Laws of a jurisdiction other than that in which the Borrower is resident for tax purposes. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“FPA” shall mean the Federal Power Act, as amended, and all rules and regulations promulgated thereunder.

“GAAP” shall mean generally accepted accounting principles as are in effect from time to time, subject to the provisions of Section 1.3 [Accounting Principles; Changes in GAAP], and applied on a consistent basis both as to classification of items and amounts.

“Guaranty” of any Person shall mean any obligation of such Person guaranteeing or in effect guaranteeing any liability or obligation of any other Person in any manner, whether directly or indirectly, including any agreement to indemnify or hold harmless any other Person, any performance bond or other suretyship arrangement and any other form of assurance against loss, except endorsement of negotiable or other instruments for deposit or collection in the ordinary course of business.

“Indebtedness” shall mean, as to any Person at any time, any and all indebtedness, obligations or liabilities (whether matured or unmatured, liquidated or unliquidated, direct or indirect, absolute or contingent, or joint or several) of such Person for or in respect of: (i) borrowed money, (ii) amounts raised under or liabilities in respect of any note purchase or acceptance credit facility, (iii) reimbursement obligations (contingent or otherwise) under any letter of credit agreement, (iv) obligations under any currency swap agreement, Interest Rate Hedge or Commodity Hedge (v) any other transaction (including forward sale or purchase agreements, capitalized leases and conditional sales agreements) having the commercial effect of a borrowing of money entered into by such Person to finance its operations or capital requirements (but not including trade payables and accrued expenses incurred in the ordinary course of business which are not represented by a promissory note or other evidence of indebtedness and which are not more than thirty (30) days past due), or (vi) any Guaranty of Indebtedness for borrowed money.

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“Indemnified Taxes” shall mean (i) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of the Borrower under any Loan Document, and (ii) to the extent not otherwise described in the preceding clause (i), Other Taxes.

“Indemnitee” shall have the meaning specified in Section 11.3(b) [Indemnification by the Borrower].

“Information” shall mean all information received from the Borrower or any of its Subsidiaries relating to the Borrower or any such Subsidiaries or any of their respective businesses, other than any such information that is available to the Administrative Agent or any Lender on a non-confidential basis prior to disclosure by the Borrower or any of its Subsidiaries, provided that, in the case of information received from the Borrower or any of its Subsidiaries after the date of this Agreement, such information is clearly identified at the time of delivery as confidential.

“Insolvency Proceeding” shall mean, with respect to the Borrower or any Subsidiary of the Borrower, (a) a case, action or proceeding with respect to the Borrower or any Subsidiary of the Borrower (i) before any court or any other Official Body under any bankruptcy, insolvency, reorganization or other similar Law now or hereafter in effect, or (ii) for the appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator, conservator (or similar official) of the Borrower or any Subsidiary of the Borrower or otherwise relating to the liquidation, dissolution, winding-up or relief of the Borrower or any Subsidiary of the Borrower other than as permitted under Section 8.2(c), or (b) any general assignment for the benefit of creditors, composition, marshaling of assets for creditors, or other, similar arrangement in respect of the Borrower’s or such Subsidiary’s creditors generally or any substantial portion of its creditors; undertaken under any Law.

“Interest Period” shall mean one month. Such Interest Period shall commence on the effective date of such Term SOFR Rate Option, which shall be (i) the Borrowing Date, or (ii) the date of renewal of or conversion to the Term SOFR Rate Option if the Borrower is renewing or converting to the Term SOFR Rate Option applicable to the outstanding Loan. Notwithstanding the second sentence hereof: (A) any Interest Period which would otherwise end on a date which is not a Business Day shall be extended to the next succeeding Business Day unless such Business Day falls in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day, (B) the Borrower shall not select, convert to or renew an Interest Period for any portion of the Loan that would end after the Term Loan Maturity Date, and (C) any Interest Period that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period.

“Interest Rate Election” shall have the meaning set forth in Section 3.5 [Interest Rate Election].

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“Interest Rate Hedge” shall mean an interest rate exchange, collar, cap, swap, floor, adjustable strike cap, adjustable strike corridor, cross-currency swap or similar agreements entered into by the Borrower or its Subsidiaries in order to provide protection to, or minimize the impact upon, the Borrower or its Subsidiaries of increasing floating rates of interest applicable to Indebtedness.

“Interest Rate Option” shall mean any Term SOFR Rate Option or Base Rate Option.

“Investment” of a Person shall mean any loan, advance (other than commission, travel and similar advances to officers and employees made in the ordinary course of business), extension of credit (other than accounts receivable arising in the ordinary course of business on terms customary in the trade) or contribution of capital by such Person; stocks, bonds, mutual funds, partnership interests, notes, debentures or other securities owned by such Person; any deposit account and certificate of deposit owned by such Person; and structured notes, derivative financial instruments and other similar instruments or contracts owned by such Person.

“IPALCO” shall mean IPALCO Enterprises, Inc., an Indiana corporation.

“IPSCA” shall mean the Indiana Public Service Commission Act, as amended, I.C. §8-1-2-1 et seq., and all rules and regulations promulgated thereunder.

“IRS” shall mean the United States Internal Revenue Service.

“IURC” shall mean the Indiana Utility Regulatory Commission and any successor agency thereto.

“IURC Order” shall mean the order issued by the IURC to the Borrower dated November 17, 2021, Cause No. 45575, or an extension, renewal or replacement of such order.

“Law” shall mean any law(s) (including common law), constitution, statute, treaty, regulation, rule, ordinance, opinion, issued guidance, release, ruling, order, executive order, injunction, writ, decree, bond, judgment, authorization or approval, lien or award of or any settlement arrangement, by agreement, consent or otherwise, with any Official Body, foreign or domestic.

“Lenders” shall mean the financial institutions named on Schedule 1.1(B) and their respective successors and assigns as permitted hereunder, each of which is referred to herein as a Lender.

“Lending Office” shall mean, as to the Administrative Agent or any Lender, the office or offices of such Person described as such in such Lender’s Administrative Questionnaire, or such other office or offices as such Person may from time to time notify the Borrower and the Administrative Agent.

“Liabilities” shall mean, at any time, all liabilities of the Borrower and its Subsidiaries that would be shown on a consolidated balance sheet of the Borrower prepared in accordance with GAAP at such time.

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“Lien” shall mean any mortgage, deed of trust, pledge, lien, security interest, charge or other encumbrance or security arrangement of any nature whatsoever, whether voluntarily or involuntarily given, including any conditional sale or title retention arrangement, and any assignment, deposit arrangement or lease intended as, or having the effect of, security and any filed financing statement or other notice of any of the foregoing (whether or not a lien or other encumbrance is created or exists at the time of the filing).

“LLC Division” means, in the event the Borrower or any Subsidiary is a limited liability company, (a) the division of the Borrower or any Subsidiary into two or more newly formed limited liability companies (whether or not the Borrower or such Subsidiary is a surviving entity following any such division) pursuant to Section 18-217 of the Delaware Limited Liability Company Act or any similar provision under any similar act governing limited liability companies organized under the Laws of any other State or Commonwealth or of the District of Columbia, or (b) the adoption of a plan contemplating, or the filing of any certificate with any applicable Official Body that results or may result in, any such division.

“Loan” shall mean the Term Loan.

“Loan Documents” shall mean this Agreement, the Administrative Agent’s Letter, the Notes and any other instruments, certificates or documents delivered in connection herewith or therewith.

“Material Adverse Change” shall mean any set of circumstances or events which (a) has any material adverse effect whatsoever upon the validity or enforceability of this Agreement or any other Loan Document, (b) is material and adverse to the business, properties, assets, financial condition or results of operations of the Borrower or the Borrower and its Subsidiaries, taken as a whole, (c) impairs materially the ability of the Borrower to duly and punctually pay or perform any of the Obligations, or (d) impairs materially the ability of the Administrative Agent or any of the Lenders, to the extent permitted, to enforce their legal remedies pursuant to this Agreement or any other Loan Document.

“Moody’s” shall mean Moody’s Investors Service, Inc.

“Multiemployer Plan” shall mean any employee benefit plan which is a “multiemployer plan” within the meaning of Section 4001(a)(3) of ERISA and to which the Borrower or any member of the ERISA Group is then making or accruing an obligation to make contributions or, within the preceding five Plan years, has made or had an obligation to make such contributions.

“Non-Consenting Lender” shall have the meaning specified in Section 11.1 [Modifications, Amendments or Waivers].

“Notes” shall mean, collectively, the promissory notes in the form of Exhibit B evidencing the Term Loan.

“NYFRB” shall mean the Federal Reserve Bank of New York.

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“Obligations” shall mean any obligation or liability of the Borrower, howsoever created, arising or evidenced, whether direct or indirect, absolute or contingent, now or hereafter existing, or due or to become due, under or in connection with this (a) Agreement, the Notes, the Administrative Agent’s Letter or any other Loan Document whether to the Administrative Agent, any of the Lenders or their Affiliates or other persons provided for under such Loan Documents, and (b) any Erroneous Payment Subrogation Rights.

“OFAC” shall have the meaning specified in Section 8.1(g).

“Official Body” shall mean the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank) and any group or body charged with setting financial accounting or regulatory capital rules or standards (including, the Financial Accounting Standards Board, the Bank for International Settlements or the Basel Committee on Banking Supervision or any successor or similar authority to any of the foregoing).

“Other Connection Taxes” shall mean, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient (or an agent or affiliate thereof) and the jurisdiction imposing such Tax (other than connections arising solely from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Loan Document, or sold or assigned an interest in any Loan or Loan Document).

“Other Taxes” shall mean all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment made pursuant to Section 5.13 [Replacement of a Lender]).

“Overnight Bank Funding Rate” shall mean, for any day, the rate comprised of both overnight federal funds and overnight eurocurrency borrowings by U.S.-managed banking offices of depository institutions, as such composite rate shall be determined by the NYFRB, as set forth on its public website from time to time, and as published on the next succeeding Business Day as the overnight bank funding rate by the NYFRB (or by such other recognized electronic source (such as Bloomberg) selected by the Administrative Agent for the purpose of displaying such rate); provided, that if such day is not a Business Day, the Overnight Bank Funding Rate for such day shall be such rate on the immediately preceding Business Day; provided, further, that if such rate shall at any time, for any reason, no longer exist, a comparable replacement rate determined by the Administrative Agent at such time (which determination shall be conclusive absent manifest error). If the Overnight Bank Funding Rate determined as above would be less than zero, then such rate shall be deemed to be zero. The rate of interest charged shall be adjusted as of each Business Day based on changes in the Overnight Bank Funding Rate without notice to the Borrower.

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“Participant” has the meaning specified in Section 11.8(d) [Participations].

“Payment Date” shall mean the first day of each calendar quarter after the date hereof and on the Term Loan Maturity Date or upon acceleration of the Notes.

“Payment In Full” and “Paid In Full” shall mean the indefeasible payment in full in cash of the Loan and other Obligations hereunder, termination of the Commitments.

“PBGC” shall mean the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA or any successor.

“Pension Plan” shall mean any “employee pension benefit plan” (as such term is defined in Section 3(2) of ERISA), other than a Multiemployer Plan, that is subject to Title IV of ERISA or Sections 412 and 430 of the Code or Section 302 of ERISA and is sponsored or maintained by Borrower or any ERISA Affiliate or to which Borrower or any ERISA Affiliate contributes or has an obligation to contribute, or in the case of a multiple employer or other plan described in Section 4064(a) of ERISA, has made contributions at any times during the immediately preceding five plan years

“Permitted Receivables Financing” shall mean any receivables purchase agreement that (i) the Borrower shall have determined in good faith is economically fair and reasonable to the Borrower, (ii) all sales of accounts are made at fair market value (as determined in good faith by the Borrower), (iii) the provisions thereof shall be market terms (as determined in good faith by the Borrower), and (iv) the aggregate “capital” or other liabilities under the transaction shall not exceed $100,000,000.

“Person” shall mean any individual, corporation, partnership, limited liability company, association, joint-stock company, trust, unincorporated organization, joint venture, government or political subdivision or agency thereof, or any other entity.

“Plan” shall mean at any time an employee pension benefit plan (including a “multiple employer plan” as described in Section 4064(a) of ERISA, but not a Multiemployer Plan) which is covered by Title IV of ERISA or is subject to the minimum funding standards under Sections 412 and 430 of the Code or Section 302 of ERISA and either (i) is maintained by any member of the ERISA Group for employees of any member of the ERISA Group or (ii) has at any time within the preceding five years been maintained by any entity which was at such time a member of the ERISA Group for employees of any entity which was at such time a member of the ERISA Group. For avoidance of doubt, the terms Plan, Pension Plan and Multiemployer Plan shall exclude any plan that is maintained outside the United States for the benefit of persons who are nonresidents aliens as provided under Section 4(b)(4) of ERISA.

“PNC” shall mean PNC Bank, National Association, its successors and assigns.

“Potential Default” shall mean any event or condition which with notice or passage of time, or both, would constitute an Event of Default.

“Prime Rate” shall mean the interest rate per annum announced from time to time by the Administrative Agent at its Principal Office as its then prime rate, which rate may not be the lowest or most favorable rate then being charged commercial borrowers or others by the Administrative Agent. Any change in the Prime Rate shall take effect at the opening of business on the day such change is announced.

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“Principal Office” shall mean the main banking office of the Administrative Agent in Pittsburgh, Pennsylvania.

“PTE” shall mean a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“Ratable Share” shall mean with respect to a Lender’s obligation to make its portion of the Term Loan and receive payments, interest, and fees related thereto, proportion that such Lender’s Term Loan Commitment bears to the Term Loan Commitments of all of the Lenders, provided that if the Term Loan have not yet been funded, the computation in this clause shall be determined based upon the Term Loan Commitments of the Lenders and not the amount of their Term Loan and (y) to receive payments, interest, and fees related to Term Loan, the proportion that such Lender’s Term Loan bears to the aggregate Term Loan of all of the Lenders.

“Recipient” shall mean (i) the Administrative Agent, and (ii) any Lender, as applicable.

“Related Parties” shall mean, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents and advisors of such Person and of such Person’s Affiliates.

“Relief Proceeding” shall mean any proceeding seeking a decree or order for relief in respect of the Borrower or any Subsidiary of the Borrower in a voluntary or involuntary case under any applicable bankruptcy, insolvency, reorganization or other similar law now or hereafter in effect, or for the appointment of a receiver, liquidator, assignee, custodian, trustee, sequestrator, conservator (or similar official) of the Borrower or any Subsidiary of the Borrower for any substantial part of its property, or for the winding-up or liquidation of its affairs other than as permitted under Section 8.2(c), or an assignment for the benefit of its creditors.

“Reportable Compliance Event” shall mean that: (a) any Covered Entity becomes a Sanctioned Person, or is charged by indictment, criminal complaint, or similar charging instrument, arraigned, custodially detained, penalized or the subject of an assessment for a penalty, or enters into a settlement with an Official Body in connection with any economic sanctions or other Anti-Terrorism Law or Anti-Corruption law, or any predicate crime to any Anti-Terrorism Law or Anti-Corruption Law, or has knowledge of facts or circumstances to the effect that it is reasonably likely that any aspect of its operations represents a violation of any Anti-Terrorism Law or Anti-Corruption Law; (b) any Covered Entity engages in a transaction that has caused or may cause the Lenders or Administrative Agent to be in violation of any Anti-Terrorism Laws, including a Covered Entity’s use of any proceeds of the Facilities to fund any operations in, finance any investments or activities in, or, make any payments to, directly or indirectly, a Sanctioned Person or Sanctioned Jurisdiction; (c) reserved; or (d) any Covered Entity otherwise violates, or reasonably believes that it will violate, any of the representations or covenant (including any negative covenant) of this Agreement.

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“Required Lenders” shall mean:  (a) if there exists fewer than three (3) Lenders, all Lenders (other than any Defaulting Lender), and (b) if there exist three (3) or more Lenders, Lenders (other than any Defaulting Lender) having more than 50% of the aggregate amount of the Term Loan Commitments of the Lenders (excluding any Defaulting Lender).

“Resolution Authority” shall mean an EEA Resolution Authority or, with respect to any UK Financial Institution, a UK Resolution Authority.

“S&P” shall mean Standard & Poor’s Ratings Group.

“Sanctioned Jurisdiction” shall mean any country, territory, or region that is the subject of sanctions administered by OFAC.

“Sanctioned Person” shall mean (a) a Person that is the subject of sanctions administered by OFAC or the U.S. Department of State (“State”), including by virtue of being (i) named on OFAC’s list of “Specially Designated Nationals and Blocked Persons”; (ii) organized under the Laws of, ordinarily resident in, or physically located in a Sanctioned Jurisdiction; (iii) owned or controlled 50% or more in the aggregate, by one or more Persons that are the subject of sanctions administered by OFAC; (b) a Person that is the subject of sanctions maintained by the European Union (“E.U.”), including by virtue of being named on the E.U.’s “Consolidated list of persons, groups and entities subject to E.U. financial sanctions” or other, similar lists; (c) a Person that is the subject of sanctions maintained by the United Kingdom (“U.K.”), including by virtue of being named on the “Consolidated List Of Financial Sanctions Targets in the U.K.” or other, similar lists; or (d) a Person that is the subject of sanctions imposed by any Official Body of a jurisdiction whose Laws apply to this Agreement.

“Settlement Date” shall mean the Business Day on which the Administrative Agent elects to effect settlement pursuant Section 5.11 [Settlement Date Procedures].

“SOFR” shall mean, for any day, a rate equal to the secured overnight financing rate as administered by the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).

“SOFR Adjustment” shall mean, ten basis points (0.10%).

“SOFR Floor” shall mean a rate of interest per annum equal to zero basis points (0.00%).

“SOFR Reserve Percentage” shall mean, for any day, the maximum effective percentage in effect on such day, if any, as prescribed by the Board of Governors of the Federal Reserve System (or any successor) for determining the reserve requirements (including, without limitation, supplemental, marginal and emergency reserve requirements) with respect to SOFR funding.

“Solvent” shall mean, with respect to any Person on any date of determination, taking into account rights of reimbursement, contribution or similar rights available to such Person from other Persons, that on such date (i) the fair value of the property of such Person is greater than the total amount of liabilities, including, without limitation, contingent liabilities, of such Person, (ii) the present fair saleable value of the assets of such Person is not less than the amount that will be required to pay the probable liability of such Person on its debts as they become absolute and matured, (iii) such Person is able to realize upon its assets and pay its debts and other liabilities, contingent obligations and other commitments as they mature in the normal course of business, (iv) such Person does not intend to, and does not believe that it will, incur debts or liabilities beyond such Person’s ability to pay as such debts and liabilities mature, and

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(v) such Person is not engaged in business or a transaction, and is not about to engage in business or a transaction, for which such Person’s property would constitute unreasonably small capital. The amount of contingent liabilities at any time shall be computed as the amount that, in light of all the facts and circumstances existing at such time, represents the amount that can reasonably be expected to become an actual or matured liability.

“Statements” shall have the meaning specified in Section 6.1(f)(i) [Historical Statements].

“Subsidiary” of any Person at any time shall mean any corporation, trust, partnership, any limited liability company or other business entity (i) of which more than 50% of the outstanding voting securities or other interests normally entitled to vote for the election of one or more directors or trustees (regardless of any contingency which does or may suspend or dilute the voting rights) is at such time owned directly or indirectly by such Person or one or more of such Person’s Subsidiaries, or (ii) which is controlled or capable of being controlled by such Person or one or more of such Person’s Subsidiaries.

“Subsidiary Equity Interests” shall have the meaning specified in Section 6.1(b) [Subsidiaries and Owners; Investment Companies].

“Taxes” shall mean all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Official Body, including any interest, additions to tax or penalties applicable thereto.

“Term Loan” shall mean as is specified in Section 3.1 [Term Loan Commitments].

“Term Loan Commitment” shall mean, as to any Lender at any time, the amount initially specified opposite its name on Schedule 1.1(B) in the column labeled “Amount of Commitment for Term Loan,” as such Commitment is thereafter assigned or modified and Term Loan Commitments shall mean the aggregate Term Loan Commitments of all of the Lenders.

“Term Loan Maturity Date” shall mean November 19, 2024, as such date may be extended pursuant to or Section 11.1 [Modifications, Amendments or Waivers].

“Term SOFR Administrator” shall mean CME Group Benchmark Administration Limited (CBA) (or a successor administrator of the Term SOFR Reference Rate selected by the Administrative Agent in its reasonable discretion).

“Term SOFR Rate” shall mean, with respect to any amount to which the Term SOFR Rate Option applies, for any Interest Period, the interest rate per annum determined by the Administrative Agent by dividing (the resulting quotient rounded upwards, at the Administrative Agent’s discretion, to the nearest 1/100th of 1%) (A) the Term SOFR Reference Rate for a tenor comparable to such Interest Period, as such rate is published by the Term SOFR Administrator on the day (the “Term SOFR Determination Date”) that is two (2) Business Days prior to the first day of such Interest Period, by (B) a number equal to 1.00 minus the SOFR Reserve Percentage. If the Term SOFR Reference Rate for the applicable tenor has not been published or replaced with a Benchmark Replacement by 5:00 p.m. (Pittsburgh, Pennsylvania time) on the Term SOFR Determination Date, then the Term SOFR Reference Rate, for purposes of clause (A) in the preceding sentence, shall be the Term SOFR Reference Rate for such tenor on the first Business Day preceding such Term SOFR Determination Date for which such Term SOFR Reference Rate for such tenor was published in accordance herewith, so long as such first preceding Business Day is not more than three (3) Business Days prior to such Term SOFR Determination Date. If the Term SOFR Rate, determined as provided above, would be less than the SOFR Floor, then

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the Term SOFR Rate shall be deemed to be the SOFR Floor. The Term SOFR Rate shall be adjusted automatically without notice to the Borrower on and as of (i) the first day of each Interest Period, and (ii) the effective date of any change in the SOFR Reserve Percentage.

“Term SOFR Rate Loan” shall mean a Loan that bears interest based on Term SOFR Rate.

“Term SOFR Rate Option” shall mean the option of the Borrower to have the Loan bear interest at the rate and under the terms specified in Section 4.1(a)(ii) [Term SOFR Rate Option].

“Term SOFR Reference Rate” shall mean the forward-looking term rate based on SOFR.

“Total Capital” shall mean, at any time, the amount shown opposite the captions “stockholders’ equity,” and “preferred stock” on the balance sheet of the Borrower at such time.

“Total Debt” shall mean at any time (a) all interest-bearing Liabilities of the Borrower and its Subsidiaries, (b) all securitized facilities of the Borrower and its Subsidiaries, (c) all Capital Lease obligations of the Borrower and its Subsidiaries and (d) all letter of credit obligations of the Borrower and its Subsidiaries; provided, however, that the term “Total Debt” shall not include accounts payable and accruals of the Borrower that would be shown as such on the balance sheet of the Borrower prepared in accordance with GAAP.

“UK Financial Institution” shall mean any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended from time to time) promulgated by the United Kingdom Prudential Regulation Authority) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority” shall mean the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“USA Patriot Act” shall mean the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, Public Law 107¬56, as the same has been, or shall hereafter be, renewed, extended, amended or replaced.

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“U.S. Borrower” shall mean any Borrower that is a U.S. Person.

“U.S. Government Securities Business Day” shall mean any day except for (a) a Saturday or Sunday or (b) a day on which the Securities Industry and Financial Markets Association recommends that the fixed income departments of its members be closed for the entire day for purposes of trading in United States government securities.

“U.S. Person” shall mean any Person that is a “United States Person” as defined in Section 7701(a)(30) of the Code.

“U.S. Tax Compliance Certificate” shall have the meaning specified in Section 5.9(g) [Status of Lenders].

“Withholding Agent” shall mean the Borrower and the Administrative Agent.

“Write-Down and Conversion Powers” shall mean, (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to the United Kingdom, any powers of the applicable Resolution Authority under the Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

1.2    Construction. Unless the context of this Agreement otherwise clearly requires, the following rules of construction shall apply to this Agreement and each of the other Loan Documents: (i) references to the plural include the singular, the plural, the part and the whole and the words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation”; (ii) the words “hereof,” “herein,” “hereunder,” “hereto” and similar terms in this Agreement or any other Loan Document refer to this Agreement or such other Loan Document as a whole; (iii) article, section, subsection, clause, schedule and exhibit references are to this Agreement or other Loan Document, as the case may be, unless otherwise specified; (iv) reference to any Person includes such Person’s successors and assigns; (v) reference to any agreement, including this Agreement and any other Loan Document together with the schedules and exhibits hereto or thereto, document or instrument means such agreement, document or instrument as amended, modified, replaced, substituted for, superseded or restated; (vi) relative to the determination of any period of time, “from” means “from and including,” “to” means “to but excluding,” and “through” means “through and including”; (vii) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights, (viii) section headings herein and in each other Loan Document are included for convenience and shall not affect the interpretation of this Agreement or such Loan Document, and (ix) unless otherwise specified, all references herein to times of day shall be references to Eastern Time (Standard or Daylight Savings, as applicable).

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1.3    Accounting Principles. Except as otherwise provided in this Agreement, all computations and determinations as to accounting or financial matters and all financial statements to be delivered pursuant to this Agreement shall be made and prepared in accordance with GAAP (including principles of consolidation where appropriate), and all accounting or financial terms shall have the meanings ascribed to such terms by GAAP; provided, however, that all accounting terms used in Section 8.2 [Negative Covenants] and all defined terms used in the definition of any accounting term used in Section 8.2 [Negative Covenants] shall have the meaning given to such terms (and defined terms) under GAAP as in effect on the date hereof applied on a basis consistent with those used in preparing Statements referred to in Section 6.1(f)(i) [Historical Statements]. In the event of any change after the date hereof in GAAP, and if such change would affect the computation of any of the financial covenants set forth in Section 8.2 [Negative Covenants] (including without limitation, reclassification of power purchase agreements or operating leases such that they are included within Total Debt and the related financial covenants), then the parties hereto agree to endeavor, in good faith, to agree upon an amendment to this Agreement that would adjust such financial covenants in a manner that would preserve the original intent thereof, but would allow compliance therewith to be determined in accordance with the Borrower’s financial statements at that time, provided that, until so amended such financial covenants shall continue to be computed in accordance with GAAP prior to such change therein.

1.4    Term SOFR Notification. Section 4.4(d) [Benchmark Replacement Setting] of this Agreement provides a mechanism for determining an alternative rate of interest in the event that the Term SOFR Rate is no longer available or in certain other circumstances. The Administrative Agent does not warrant or accept any responsibility for and shall not have any liability with respect to, the administration, submission or any other matter related to the Term SOFR Rate or with respect to any alternative or successor rate thereto, or replacement rate therefor.

2.    RESERVED

3.    TERM LOAN

3.1    Term Loan Commitments. Subject to the terms and conditions hereof, and relying upon the representations and warranties herein specified, each Lender severally agrees to make a term loan (the “Term Loan”) to the Borrower on the Closing Date in such principal amount as the Borrower shall request up to, but not exceeding, such Lender’s Term Loan Commitment.

3.2    Nature of Lenders’ Obligations with Respect to Term Loan; Repayment Terms.

The obligations of each Lender to make the Term Loan to the Borrower shall equal its Ratable Share of the requested Term Loan; provided that no Lender’s Term Loan to the Borrower shall exceed its Term Loan Commitment. The failure of any Lender to make a Term Loan shall not relieve any other Lender of its obligations to make a Term Loan nor shall it impose any additional liability on any other Lender hereunder. The Lenders shall have no obligation to make the Term Loan hereunder after the Closing Date, and any portion of the Term Loan Commitment not drawn on the Closing Date shall automatically expire. The Term Loan Commitments are not revolving credit commitments, and the Borrower shall not have the right to borrow, repay and reborrow under Section 3.1 [Term Loan Commitments]. The Borrower shall repay to the applicable Lenders the aggregate principal amount of the Term Loan outstanding on the Term Loan Maturity Date.

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3.3    Use of Proceeds. The Borrower shall use the proceeds of the Loan for general corporate purposes.

3.4    Defaulting Lenders. Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a)    reserved;

(b)    the Commitment and outstanding Loan of such Defaulting Lender shall not be included in determining whether the Required Lenders have taken or may take any action hereunder (including any consent to any amendment, waiver or other modification pursuant to Section 11.1 [Modifications, Amendments or Waivers]); provided, that this clause (b) shall not apply to the vote of a Defaulting Lender in the case of an amendment, waiver or other modification requiring the consent of such Lender or each Lender directly affected thereby.

3.5    Interest Rate Elections; Conversions and Renewals. Except as otherwise provided herein, the Borrower may from time to time prior to the Term Loan Maturity Date renew or convert the Interest Rate Option applicable to the Term Loan pursuant to Section 4.2 [Interest Periods], by delivering to the Administrative Agent, not later than 10:00 a.m. Eastern Time, (i) three (3) Business Days prior to the proposed conversion to or the renewal of the Term SOFR Rate Option for the Term Loan; and (ii) the last day of the preceding Interest Period with respect to the conversion to the Base Rate Option for any Term Loan, of a duly completed request therefor substantially in the form of Exhibit C or a request by telephone immediately confirmed in writing by letter, facsimile or telex in such form (each, an “Interest Rate Election”), it being understood that the Administrative Agent may rely on the authority of any individual making such a telephonic election without the necessity of receipt of such written confirmation. Each Interest Rate Election shall be irrevocable and shall specify the aggregate amount of the Loan comprising each Borrowing Tranche, and, if applicable, the Interest Period, which amounts shall be in (x) integral multiples of $100,000 and not less than $500,000 for each Borrowing Tranche under the Term SOFR Rate Option, and (y) integral multiples of $100,000 and not less than $500,000 for each Borrowing Tranche under the Base Rate Option.

4.    INTEREST RATES

4.1    Interest Rate Options. The Borrower shall pay interest in respect of the outstanding unpaid principal amount of the Loan as selected by it from the Base Rate Option or Term SOFR Rate Option set forth below applicable to the Loan, it being understood that, subject to the provisions of this Agreement, the Borrower may select different Interest Rate Options and different Interest Periods to apply simultaneously to the Loan comprising different Borrowing Tranches and may convert to or renew one or more Interest Rate Options with respect to all or any portion of the Loan comprising any Borrowing Tranche; provided that there shall not be at any one time outstanding more than five (5) Borrowing Tranches in the aggregate among all of the Loan and provided further that if an Event of Default or Potential Default exists and is continuing, the Borrower may not request, convert to, or renew the Term SOFR Rate Option for any Loan and the Required Lenders may demand that all existing Borrowing Tranches bearing interest under the Term SOFR Rate Option shall be converted immediately to the Base Rate Option, subject to the obligation of the Borrower to pay any indemnity under Section 5.10 [Indemnity] in connection with such conversion. If at any time the designated rate applicable to the Loan made by any Lender exceeds such Lender’s highest lawful rate, the rate of interest on such Lender’s Loan shall be limited to such Lender’s highest lawful rate.

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(a)    Interest Rate Options. The Borrower shall have the right to select from the following Interest Rate Options applicable to the Term Loan:

(i)    Base Rate Option: A fluctuating rate per annum (computed on the basis of a year of 365 or 366 days, as the case may be, and actual days elapsed) equal to the Base Rate plus the Applicable Margin, such interest rate to change automatically from time to time effective as of the effective date of each change in the Base Rate; or

(ii)    Term SOFR Rate Option: A rate per annum (computed on the basis of a year of 360 days and actual days elapsed) equal to the Term SOFR Rate as determined for each applicable Interest Period plus the SOFR Adjustment plus the Applicable Margin.

(b)    Rate Quotations. The Borrower may call the Administrative Agent on or before the date on which an Interest Rate Election is to be delivered to receive an indication of the rates then in effect, but it is acknowledged that such projection shall not be binding on the Administrative Agent or the Lenders nor affect the rate of interest which thereafter is actually in effect when the election is made.

(c)    Conforming Changes Relating to Term SOFR Rate. With respect to the Term SOFR Rate, the Administrative Agent will have the right to make Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Loan Document; provided that, the Administrative Agent shall provide notice to the Borrower and the Lenders of each such amendment implementing such Conforming Changes reasonably promptly after such amendment becomes effective.

4.2    Interest Periods. At any time when the Borrower shall select, convert to or renew a Term SOFR Rate Option, the Borrower shall notify the Administrative Agent thereof at least three (3) Business Days prior to the effective date of such Term SOFR Rate Option by delivering an Interest Rate Election. The notice shall specify an Interest Period during which such Interest Rate Option shall apply. Notwithstanding the preceding sentence, the following provisions shall apply to any selection of, renewal of, or conversion to a Term SOFR Rate Option:

(a)    Amount of Borrowing Tranche. Each Borrowing Tranche of the Loan under the Term SOFR Rate Option shall be in integral multiples of $100,000 and not less than $1,000,000; and

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(b)    Renewals. In the case of the renewal of a Term SOFR Rate Option at the end of an Interest Period, the first day of the new Interest Period shall be the last day of the preceding Interest Period, without duplication in payment of interest for such day.

4.3    Interest After Default. To the extent permitted by Law, upon the occurrence of an Event of Default and until such time such Event of Default shall have been cured or waived, and at the discretion of the Administrative Agent or upon written demand by the Required Lenders to the Administrative Agent:

(a)    Interest Rate. The rate of interest for each Loan otherwise applicable pursuant to Section 4.1 [Interest Rate Options] shall be increased by two percent (2.0%) per annum;

(b)    Other Obligations. Each other Obligation hereunder if not paid when due shall bear interest at a rate per annum equal to the sum of the rate of interest applicable under the Base Rate Option plus an additional two percent (2%) per annum from the time such Obligation becomes due and payable and until it is Paid In Full; and

(c)    Acknowledgment. The Borrower acknowledges that the increase in rates referred to in this Section 4.3 reflects, among other things, the fact that such Loan or other amounts have become a substantially greater risk given their default status and that the Lenders are entitled to additional compensation for such risk; and all such interest shall be payable by Borrower upon demand by Administrative Agent.

4.4    Term SOFR Rate Unascertainable; Increased Costs; Illegality; Benchmark Replacement Setting.

(a)    Unascertainable; Increased Costs.  If, on or prior to the first day of an Interest Period:

(i)    the Administrative Agent shall have determined (which determination shall be conclusive and binding absent manifest error) that (x) the Term SOFR Rate cannot be determined pursuant to the definition thereof; or (y) a fundamental change has occurred with respect to the Term SOFR Rate (including, without limitation, changes in national or international financial, political or economic conditions), or

(ii)    any Lender determines that for any reason in connection with any request for a Term SOFR Rate Loan or a conversion thereto or a continuation thereof that the Term SOFR Rate for any requested Interest Period with respect to a proposed Term SOFR Rate Loan does not adequately and fairly reflect the cost to such Lenders of funding, establishing or maintaining such Loan, and such Lender has provided notice of such determination to the Administrative Agent,

then the Administrative Agent shall have the rights specified in Section 4.4(c) [Administrative Agent’s and Lender’s Rights].

(b)    Illegality.  If at any time any Lender shall have determined, or any Official Body shall have asserted, that the making, maintenance or funding of any Term SOFR Rate Loan, or the determination or charging of interest rates based on the Term SOFR Rate, has been made impracticable or unlawful by compliance by such Lender in good faith with any Law or any interpretation or application thereof by any Official Body or with any request or directive of any such Official Body (whether or not having the force of Law), then the Administrative Agent shall have the rights specified in Section 4.4(c) [Administrative Agent’s and Lender’s Rights].

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(c)    Administrative Agent’s and Lender’s Rights. In the case of any event specified in Section 4.4(a) [Unascertainable; Increased Costs] above, the Administrative Agent shall promptly notify the Lenders and the Borrower thereof, and in the case of an event specified in Section 4.4(b) [Illegality] above, such Lender shall promptly notify the Administrative Agent and endorse a certificate to such notice as to the specific circumstances of such notice, and the Administrative Agent shall promptly send copies of such notice and certificate to the other Lenders and the Borrower.  Upon such date as shall be specified in such notice (which shall not be earlier than the date such notice is given), the obligation of (i) the Lenders, in the case of such notice given by the Administrative Agent, or (ii) such Lender, in the case of such notice given by such Lender, to allow the Borrower to select, convert to or renew a Term SOFR Rate Loan shall be suspended (to the extent of the affected Term SOFR Rate Loan or Interest Periods) until the Administrative Agent shall have later notified the Borrower, or such Lender shall have later notified the Administrative Agent, of the Administrative Agent’s or such Lender’s, as the case may be, determination that the circumstances giving rise to such previous determination no longer exist.  If at any time the Administrative Agent makes a determination under Section 4.4(a) [Unascertainable; Increased Costs] and the Borrower has previously notified the Administrative Agent of its selection of, conversion to or renewal of a Term SOFR Rate Option and the Term SOFR Rate Option has not yet gone into effect, such notification shall be deemed to provide for selection of, conversion to or renewal of the Base Rate Option otherwise available with respect to the Loan.  If any Lender notifies the Administrative Agent of a determination under Section 4.4(b) [Illegality], the Borrower shall, subject to the Borrower’s indemnification Obligations under Section 5.10 [Indemnity], as to any Loan of the Lender to which a Term SOFR Rate Option applies, on the date specified in such notice either convert such Loan to the Base Rate Option otherwise available with respect to such Loan or prepay such Loan in accordance with Section 5.2 [Voluntary Prepayments].  Absent due notice from the Borrower of conversion or prepayment, such Loan shall automatically be converted to the Base Rate Option otherwise available with respect to such Loan upon such specified date.

(d)    Benchmark Replacement Setting.

(i)    Benchmark Replacement. Notwithstanding anything to the contrary herein or in any other Loan Document (and any agreement executed in connection with an Interest Rate Hedge shall be deemed not to be a “Loan Document” for purposes of this Section titled “Benchmark Replacement Setting”), if a Benchmark Transition Event and its related Benchmark Replacement Date have occurred prior to any setting of the then-current Benchmark, then (A) if a Benchmark Replacement is determined in accordance with clause (1) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Loan Document in respect of such Benchmark setting and subsequent Benchmark settings without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document and (B) if a Benchmark Replacement is determined in accordance with clause (2) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Loan Document in respect of any Benchmark setting at or after 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Loan Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Required Lenders.

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(ii)    Benchmark Replacement Conforming Changes. In connection with the use, administration, adoption or implementation of a Benchmark Replacement, the Administrative Agent will have the right to make Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Loan Document, any amendments implementing such Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Loan Document.

(iii)    Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (A) the implementation of any Benchmark Replacement, and (B) the effectiveness of any Conforming Changes in connection with the use, administration, adoption or implementation of a Benchmark Replacement. The Administrative Agent will notify the Borrower of (x) the removal or reinstatement of any tenor of a Benchmark pursuant to paragraph (iv) below and (y) the commencement of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party to this Agreement or any other Loan Document except, in each case, as expressly required pursuant to this Section.

(iv)    Unavailability of Tenor of Benchmark. Notwithstanding anything to the contrary herein or in any other Loan Document, at any time (including in connection with the implementation of a Benchmark Replacement), (A) if the then-current Benchmark is a term rate and either (I) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (II) the regulatory supervisor for the administrator of such Benchmark has provided a public statement or publication of information announcing that any tenor for such Benchmark is not or will not be representative, then the Administrative Agent may modify the definition of “Interest Period” (or any similar or analogous definition) for any Benchmark settings at or after such time to remove such unavailable or non-representative tenor; and (B) if a tenor that was removed pursuant to clause (A) above either (I) is subsequently displayed on a screen or information service for a Benchmark (including a Benchmark Replacement) or (II) is not, or is no longer, subject to an announcement that it is not or will not be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” (or any similar or analogous definition) for all Benchmark settings at or after such time to reinstate such previously removed tenor.

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(v)    Benchmark Unavailability Period. Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any pending request for a Loan bearing interest based on the Term SOFR Rate, conversion to or continuation of the portion of the Loan bearing interest based on the Term SOFR Rate to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any such request into a request for a Loan of or conversion to a Loan bearing interest under the Base Rate Option. During a Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of the Base Rate based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of the Base Rate.

(vi)    Definitions. As used in this Section:

“Available Tenor” shall mean, as of any date of determination and with respect to the then-current Benchmark, as applicable, (x) if such Benchmark is a

term rate or is based on a term rate, any tenor for such Benchmark (or component thereof) that is or may be used for determining the length of an interest period pursuant to this Agreement or (y) otherwise, any payment period for interest calculated with reference to such Benchmark (or component thereof) that is or may be used for determining any frequency of making payments of interest calculated with reference to such Benchmark pursuant to this Agreement, in each case, as of such date and not including, for the avoidance of doubt, any tenor of such Benchmark that is then-removed from the definition of “Interest Period” pursuant to clause (iv) of this Section.

“Benchmark” shall mean, initially, the Term SOFR Rate; provided that if a Benchmark Transition Event has occurred with respect to the Term SOFR Rate or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate pursuant to this Section.

    “Benchmark Replacement”shall mean, with respect to any Benchmark Transition Event, the first alternative set forth in the order below that can be determined by the Administrative Agent for the applicable Benchmark Replacement Date:

(1)    the sum of: (A) Daily Simple SOFR and (B) the SOFR Adjustment;

(2)    the sum of (A) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower, giving due consideration to (x) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (y) any evolving or then-prevailing market convention for determining a benchmark rate as a replacement to the then-current Benchmark for U.S. dollar-denominated syndicated credit facilities at such time and (B) the related Benchmark Replacement Adjustment; provided that if the Benchmark Replacement as determined pursuant to clause (2) above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Loan Documents; and providedfurther, that any Benchmark Replacement shall be administratively feasible as determined by the Administrative Agent in its sole discretion.

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    “Benchmark Replacement Adjustment”shall mean, with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement, the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower, giving due consideration to (A) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body or (B) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for U.S. dollar-denominated syndicated credit facilities at such time.

“Benchmark Replacement Date” shall mean a date and time determined by the Administrative Agent, which date shall be no later than the earliest to occur of the following events with respect to the then-current Benchmark:

(1) in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (A) the date of the public statement or publication of information referenced therein and (B) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof); or

(2) in the case of clause (3) of the definition of “Benchmark Transition Event,” the date determined by the Administrative Agent, which date shall promptly follow the date of the public statement or publication of information referenced therein;

For the avoidance of doubt, the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

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“Benchmark Transition Event” shall mean, the occurrence of one or more of the following events, with respect to the then-current Benchmark:

(1)    a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(2)    a public statement or publication of information by an Official Body having jurisdiction over the Administrative Agent, the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Federal Reserve Board, the Federal Reserve Bank of New York, an insolvency official with jurisdiction over the administrator for such Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark (or such component), which states that the administrator of such Benchmark (or such component) has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof) permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof); or

(3)    a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof) or an Official Body having jurisdiction over the Administrative Agent announcing that all Available Tenors of such Benchmark (or such component thereof) are not, or as of a specified future date will not be, representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period”shall mean the period (if any) (x) beginning at the time that a Benchmark Replacement Date has occurred if, at such time, no Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Loan Document in accordance with this Section 4.4(d) titled “Benchmark Replacement Setting” and (y) ending at the time that a Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Loan Document in accordance with this Section 4.4(d) titled “Benchmark Replacement Setting.”

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“Floor” shall mean the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to the Term SOFR Rate or, if no floor is specified, zero.

“Relevant Governmental Body” shall mean the Board of Governors of the Federal Reserve System and/or the Federal Reserve Bank of New York, or a committee officially endorsed or convened by the Board of Governors of the Federal Reserve System and/or the Federal Reserve Bank of New York, or any successor thereto.

“Unadjusted Benchmark Replacement” shall mean the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

4.5    Selection of Interest Rate Options. If the Borrower fails to select a new Interest Period to apply to any Borrowing Tranche of the Loan under the Term SOFR Rate Option at the expiration of an existing Interest Period applicable to such Borrowing Tranche in accordance with the provisions of Section 4.2 [Interest Periods], the Borrower shall be deemed to have converted such Borrowing Tranche to the Base Rate Option, as applicable to the Term Loan as the case may be, commencing upon the last day of the existing Interest Period. Each Interest Rate Election that the Borrower provides related to a Loan at the Term SOFR Rate Option shall be deemed to request an Interest Period of one (1) month. Any Interest Rate Election that fails to select an Interest Rate Option shall be deemed to be a request for the Base Rate Option.

5.    PAYMENTS; TAXES; YIELD MAINTENANCE

5.1    Payments. All payments and prepayments to be made in respect of principal, interest, Administrative Agent’s Fee or other fees or amounts due from the Borrower hereunder shall be payable prior to 12:00 noon on the date when due without presentment, demand, protest or notice of any kind, all of which are hereby expressly waived by the Borrower, and without set-off, counterclaim or other deduction of any nature, and an action therefor shall immediately accrue. Such payments shall be made to the Administrative Agent at the Principal Office for the ratable accounts of the Lenders with respect to the Term Loan in U.S. Dollars and in immediately available funds, and the Administrative Agent shall promptly distribute such amounts to the Lenders in immediately available funds; provided that in the event payments are received by 12:00 noon by the Administrative Agent with respect to the Loan and such payments are not distributed to the Lenders on the same day received by the Administrative Agent, the Administrative Agent shall pay the Lenders interest at the Effective Federal Funds Rate with respect to the amount of such payments for each day held by the Administrative Agent and not distributed to the Lenders. The Administrative Agent’s and each Lender’s statement of account, ledger or other relevant record shall, in the absence of manifest error, be conclusive as the statement of the amount of principal of and interest on the Loan and other amounts owing under this Agreement and shall be deemed an “account stated.”

5.2    Pro Rata Treatment of Lenders. The Term Loan shall be allocated to each Lender according to its Ratable Share. Each selection of, conversion to or renewal of any Interest Rate Option and each payment or prepayment by the Borrower with respect to principal, interest, or other fees (except for the Administrative Agent’s Fee) or amounts due from the Borrower hereunder to the Lenders with respect to the Commitments and the Loan, shall (except as otherwise may be provided with respect to a Defaulting Lender and except as provided in Section 4.4(c) [Administrative Agent’s and Lender’s Rights] in the case of an event specified in Section 4.4 [Term SOFR Rate Unascertainable; Etc.], 5.13 [Replacement of a Lender] or 5.8 [Increased Costs]) be payable ratably among the Lenders entitled to such payment in accordance with the

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amount of principal, interest, and other fees or amounts then due or payable such Lenders as set forth in this Agreement.

5.3    Sharing of Payments by Lenders. If any Lender shall, by exercising any right of setoff, counterclaim or banker’s lien, by receipt of voluntary payment, by realization upon security, or by any other non-pro rata source, obtain payment in respect of any principal of or interest on any of the Loan or other obligations hereunder resulting in such Lender’s receiving payment of a proportion of the aggregate amount of the Loan and accrued interest thereon or other such obligations greater than the pro-rata share of the amount such Lender is entitled thereto, then the Lender receiving such greater proportion shall (a) notify the Administrative Agent of such fact, and (b) purchase (for cash at face value) participations in the Loan and such

other obligations of the other Lenders, or make such other adjustments as shall be equitable, so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective portion of the Loan and other amounts owing them, provided that:

(i)    if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, together with interest or other amounts, if any, required by Law (including court order) to be paid by the Lender or the holder making such purchase; and

(ii)    the provisions of this Section 5.3 shall not be construed to apply to (x) any payment made by the Borrower pursuant to and in accordance with the express terms of the Loan Documents or (y) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its portion of the Loan to any assignee or participant, other than to the Borrower or any Subsidiary thereof (as to which the provisions of this Section 5.3 shall apply).

The Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable Law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of setoff and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

5.4    Presumptions by Administrative Agent. Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders the amount due. In such event, if the Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Effective Federal Funds Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

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5.5    Interest Payment Dates. Interest on Loan to which the Base Rate Option applies shall be due and payable in arrears on each Payment Date. Interest on the Loan to which the Term SOFR Rate Option applies shall be due and payable on the last day of each Interest Period. Interest on the principal amount of each Loan or other monetary Obligation shall be due and payable on demand after such principal amount or other monetary Obligation becomes due and payable (whether on the stated Term Loan Maturity Date, upon acceleration or otherwise). Interest shall be computed to, but excluding, the date payment is due.

5.6    Voluntary Prepayments.

(a)    Right to Prepay. The Borrower shall have the right at its option from time to time to prepay the Loan in whole or part without premium or penalty (except as provided in Section 5.13 [Replacement of a Lender] below, in Section 5.8 [Increased Costs] and Section 5.10 [Indemnity]). Whenever the Borrower desires to prepay any part of the Loan, it shall provide a prepayment notice to the Administrative Agent by 1:00 p.m. Eastern Time at least one (1) Business Day prior to the date of prepayment of the Term Loan that bear interest at the Base Rate Option and at least three (3) Business Days in the case of Loan bearing interest at the Term SOFR Rate Option:

(i)    the date, which shall be a Business Day, on which the proposed prepayment is to be made;

(ii)    a statement indicating the application of the prepayment between the portion of the Loan to which the Base Rate Option applies and the portion of the Loan to which the Term SOFR Rate Option applies; and

(iii)    the total principal amount of such prepayment, which shall not be less than $500,000 for the Term Loan.

All prepayment notices shall be irrevocable. The principal amount of the Loan for which a prepayment notice is given, together with interest on such principal amount, shall be due and payable on the date specified in such prepayment notice as the date on which the proposed prepayment is to be made. Except as provided in Section 4.4(c) [Administrative Agent’s and Lender’s Rights], if the Borrower prepays a Loan but fails to specify the applicable Borrowing Tranche which the Borrower is prepaying, the prepayment shall be applied first to the portion of the Loan to which the Base Rate Option applies, then to the portion of the Loan to which the Term SOFR Rate Option applies. Any prepayment hereunder shall be subject to the Borrower’s Obligation to indemnify the Lenders under Section 5.10 [Indemnity].

5.7    [Intentionally Omitted].

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5.8    Increased Costs.

(a)    Increased Costs Generally. If any Change in Law shall:

(i)    impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement reflected in the Term SOFR Rate);

(ii)    subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (ii) through (iv) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto; or

(iii)    impose on any Lender, or the London interbank market any other condition, cost or expense (other than Taxes) affecting this Agreement or the Loan under the Term SOFR Rate Option made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making converting to, continuing or maintaining the Loan under the Term SOFR Rate Option (or of maintaining its obligation to make any such Loan), or to increase the cost to such Lender, or to reduce the amount of any sum received or receivable by such Lender, (whether of principal, interest or any other amount) then, upon request of such Lender, the Borrower will pay to such Lender, such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

(b)    Capital Requirements. If any Lender determines that any Change in Law affecting such Lender or any lending office of such Lender or such Lender’s holding company, if any, regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement, the Commitments of such Lender or the Loan made by, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender, such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

(c)    Certificates for Reimbursement; Repayment of Outstanding Loan. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in Sections 5.8(a) [Increased Costs Generally] or 5.8(b) [Capital Requirements] and delivered to the Borrower shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within twenty (20) days after receipt thereof.

(d)    Delay in Requests. Failure or delay on the part of any Lender to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s right to demand such compensation, provided that the Borrower shall not be required to compensate a Lender pursuant to this Section for any increased costs incurred or reductions suffered more than six months prior to the date that such Lender notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s intention to claim compensation therefor (except that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the six (6) month period referred to above shall be extended to include the period of retroactive effect thereof).

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5.9    Taxes.

(a)    reserved.

(b)    Payments Free of Taxes. Any and all payments by or on account of any obligation of any Borrower under any Loan Document shall be without deduction or withholding for any Taxes, except as required by applicable Law. If any applicable Law (as determined in the good faith discretion of an applicable Withholding Agent) requires the deduction or withholding of any Tax from any such payment by a Withholding Agent, then the applicable Withholding Agent shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant Official Body in accordance with applicable Law and, if such Tax is an Indemnified Tax, then the sum payable by the Borrower shall be increased as necessary so that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section 5.9 [Taxes]) the applicable Recipient receives an amount equal to the sum it would have received had no such deduction or withholding been made.

(c)    Payment of Other Taxes by the Borrower. The Borrower shall timely pay to the relevant Official Body in accordance with applicable Law, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes.

(d)    Indemnification by the Borrower. The Borrower shall indemnify each Recipient, within ten (10) days after demand therefor, for the full amount of any Indemnified Taxes (including Indemnified Taxes imposed or asserted on or attributable to amounts payable under this Section 5.9 [Taxes]) payable or paid by such Recipient or required to be withheld or deducted from a payment to such Recipient and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Official Body. A certificate as to the amount of such payment or liability delivered to the Borrower by a Lender (with a copy to the Administrative Agent), or by the Administrative Agent on its own behalf or on behalf of a Lender, shall be conclusive absent manifest error.

(e)    Indemnification by the Lenders. Each Lender shall severally indemnify the Administrative Agent, within ten (10) days after demand therefor, for (i) any Indemnified Taxes attributable to such Lender (but only to the extent that any Borrower has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Borrower to do so), (ii) any Taxes attributable to such Lender’s failure to comply with the provisions of Section 11.8(d) [Participations] relating to the maintenance of a Participant Register, and (iii) any Excluded Taxes attributable to such Lender, in each case, that are payable or paid by the Administrative Agent in connection with any Loan Document, and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Official Body. A certificate as to the amount of such payment or liability delivered to any Lender by the Administrative Agent shall be conclusive absent manifest error. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under any Loan Document or otherwise payable by the Administrative Agent to the Lender from any other source against any amount due to the Administrative Agent under this Section (e) [Indemnification by the Lenders].

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(f)    Evidence of Payments. As soon as practicable after any payment of Taxes by any Borrower to an Official Body pursuant to this Section 5.9 [Taxes], such Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Official Body evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(g)    Status of Lenders.

(i)    Any Lender that is entitled to an exemption from or reduction of withholding Tax with respect to payments made under any Loan Document shall deliver to the Borrower and the Administrative Agent, at the time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Lender, if reasonably requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable Law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set forth in Section 5.9(g)(ii)A, 5.9(g)(ii)B and (ii)D below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender.

(ii)    Without limiting the generality of the foregoing, in the event that the Borrower is a U.S. Borrower,

A.    any Lender that is a U.S. Person shall deliver to the Borrower and the Administrative Agent on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of IRS Form W-9 certifying that such Lender is exempt from U.S. federal backup withholding tax;

B.    any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), whichever of the following is applicable:

(1)    in the case of a Foreign Lender claiming the benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, executed originals of IRS Form W-8BEN-E (or W-8BEN if applicable) establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “interest” article of such tax treaty and (y) with respect to any other applicable payments under any Loan Document, IRS Form W-8BEN-E (or W-8BEN if applicable) establishing an exemption from, or reduction of, U.S. federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

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(2)    executed originals of IRS Form W-8ECI;

(3)    in the case of a Foreign Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate substantially in the form of Exhibit P-1 to the effect that such Foreign Lender is not (A) a “bank” within the meaning of Section 881(c)(3)(A) of the Code, (B) a “10 percent shareholder” of the Borrower within the meaning of Section 881(c)(3)(B) of the Code, or (C) a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code (a “U.S. Tax Compliance Certificate”) and (y) executed originals of IRS Form W-8BEN-E (or W-8BEN if applicable); or

(4)    to the extent a Foreign Lender is not the beneficial owner, executed originals of IRS Form W-8IMY, accompanied by IRS Form W-8ECI, IRS Form W-8BEN-E (or W-8BEN if applicable), a U.S. Tax Compliance Certificate substantially in the form of Exhibit D-2 or Exhibit D-3, IRS Form W-9, and/or other certification documents from each beneficial owner, as applicable; provided that if the Foreign Lender is a partnership and one or more direct or indirect partners of such Foreign Lender are claiming the portfolio interest exemption, such Foreign Lender may provide a U.S. Tax Compliance Certificate substantially in the form of Exhibit D-4 on behalf of each such direct and indirect partner;

C.    any Foreign Lender shall, to the extent it is legally entitled to do so, deliver to the Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of the Borrower or the Administrative Agent), executed originals of any other form prescribed by applicable Law as a basis for claiming exemption from or a reduction in U.S. federal withholding Tax, duly completed, together with such supplementary documentation as may be prescribed by applicable Law to permit the Borrower or the Administrative Agent to determine the withholding or deduction required to be made; and

D.    if a payment made to a Lender under any Loan Document would be subject to U.S. federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable Law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA and to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment. Solely for purposes of this clause (D), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

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Each Lender agrees that if any form or certification it previously delivered expires or becomes obsolete or inaccurate in any respect, it shall update such form or certification or promptly notify the Borrower and the Administrative Agent in writing of its legal inability to do so.

(h)    Treatment of Certain Refunds. If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 5.9 [Taxes] (including by the payment of additional amounts pursuant to this Section 5.9 [Taxes]), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section 5.9 [Taxes] with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Official Body with respect to such refund). Such indemnifying party, upon the request of such indemnified party incurred in connection with obtaining such refund, shall repay to such indemnified party the amount paid over pursuant to this Section 5.9(h) [Treatment of Certain Refunds] (plus any penalties, interest or other charges imposed by the relevant Official Body) in the event that such indemnified party is required to repay such refund to such Official Body. Notwithstanding anything to the contrary in this Section 5.9(h) [Treatment of Certain Refunds], in no event will the indemnified party be required to pay any amount to an indemnifying party pursuant to this Section (h) [Treatment of Certain Refunds] the payment of which would place the indemnified party in a less favorable net after-Tax position than the indemnified party would have been in if the Tax subject to indemnification and giving rise to such refund had not been deducted, withheld or otherwise imposed and the indemnification payments or additional amounts with respect to such Tax had never been paid. This paragraph shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.

(i)    Survival. Each party’s obligations under this Section 5.9 [Taxes] shall survive the resignation of the Administrative Agent or any assignment of rights by, or the replacement of, a Lender, the termination of the Commitments and the repayment, satisfaction or discharge of all Obligations.

5.10    Indemnity. In addition to the compensation or payments required by Section 5.8 [Increased Costs] or Section 5.9 [Taxes], the Borrower shall indemnify each Lender against all liabilities, losses or expenses (including loss of anticipated profits, any foreign exchange losses and any loss or expense arising from the liquidation or reemployment of funds obtained by it to maintain such Loan, from fees payable to terminate the deposits from which such funds were obtained or from the performance of any foreign exchange contract) which such Lender sustains or incurs as a consequence of any:

(a)    payment, prepayment, conversion or renewal of any Loan to which a Term SOFR Rate Option applies on a day other than the last day of the corresponding Interest Period (whether or not such payment or prepayment is mandatory, voluntary or automatic and whether or not such payment or prepayment is then due),

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(b)    attempt by the Borrower to revoke (expressly, by later inconsistent notices or otherwise) in whole or part any Interest Rate Election under Section 4.2 [Interest Periods] or notice relating to prepayments under Section 5.6 [Voluntary Prepayments] or failure by the Borrower (for a reason other than the failure of such Lender to make a Loan) to prepay, borrow, continue or convert any Loan other than a Loan under the Base Rate Option on the date or in the amount notified by the Borrower, or

(c)    any assignment of a Loan under the Term SOFR Rate Option on a day other than the last day of the Interest Period therefor as a result of a request by the Borrower pursuant to Section 5.13 [Replacement of a Lender].

(d)    default by the Borrower in the performance or observance of any covenant or condition contained in this Agreement or any other Loan Document, including any failure of the Borrower to pay when due (by acceleration or otherwise) any principal, interest or any other amount due hereunder, as applicable.

If any Lender sustains or incurs any such loss or expense, it shall from time to time notify the Borrower of the amount determined in good faith by such Lender (which determination may include such assumptions, allocations of costs and expenses and averaging or attribution methods as such Lender shall deem reasonable) to be necessary to indemnify such Lender for such loss or expense. Such notice shall specify in reasonable detail the basis for such determination. Such amount shall be due and payable by the Borrower to such Lender ten (10) Business Days after such notice is given.

5.11    reserved.

5.12    reserved.

5.13    Replacement of a Lender. If any Lender requests compensation under Section 5.8 [Increased Costs], or if the Borrower is required to pay any Indemnified Taxes or additional amounts to any Lender or any Official Body for the account of any Lender pursuant to Section 5.9 [Taxes] and, in each case, such Lender has declined or is unable to designate a different lending office in accordance with Section 5.14 [Designation of a Different Lending Office], or if any Lender is a Defaulting Lender or a Non-Consenting Lender, then the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative Agent, require such Lender to assign and delegate, without recourse (in accordance with and subject to the restrictions contained in, and consents required by, Section 11.8 [Successors and Assigns]), all of its interests, rights (other than its existing rights to payments pursuant to Section 5.8 [Increased Costs] or Section 5.9 [Taxes]) and obligations under this Agreement and the related Loan Documents to an eligible assignee that shall assume such obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that:

(a)    the Borrower shall have paid to the Administrative Agent the assignment fee (if any) specified in Section 11.8 [Successors and Assigns];

(b)    such Lender shall have received payment of an amount equal to the outstanding principal of its portion of the Loan, accrued interest thereon, accrued fees and all other amounts payable to it hereunder and under the other Loan Documents (including any amounts under Section 5.10 [Indemnity]) from the assignee (to the extent of such outstanding principal and accrued interest and fees) or the Borrower (in the case of all other amounts);

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(c)    in the case of any such assignment resulting from a claim for compensation under Section 5.8 [Increased Costs] or payments required to be made pursuant to Section 5.9 [Taxes], such assignment will result in a reduction in such compensation or payments thereafter;

(d)    such assignment does not conflict with applicable Law; and

(e)    in the case of any assignment resulting from a Lender becoming a Non-Consenting Lender, the applicable assignee shall have consented to the applicable amendment, waiver or consent.

A Lender shall not be required to make any such assignment or delegation if, prior thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the Borrower to require such assignment and delegation cease to apply.

5.14    Designation of a Different Lending Office. If any Lender requests compensation under Section 5.8 [Increased Costs], or the Borrower is or will be required to pay any Indemnified Taxes or additional amounts to any Lender or any Official Body for the account of any Lender pursuant to Section 5.9 [Taxes], then such Lender shall (at the request of the Borrower) use reasonable efforts to designate a different Lending Office for funding or booking its Loan hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 5.8 [Increased Costs] or Section 5.9 [Taxes], as the case may be, in the future, and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

6.    REPRESENTATIONS AND WARRANTIES

6.1    Representations and Warranties. The Borrower represents and warrants to the Administrative Agent and each of the Lenders as follows:

(a)    Organization and Qualification; Power and Authority; Compliance With Laws; Title to Properties; Event of Default. The Borrower and each Subsidiary of the Borrower (i) is a corporation, partnership or limited liability company duly organized, and validly existing under the laws of its jurisdiction of organization, (ii) has the lawful power to own or lease its properties and to engage in the business it presently conducts or proposes to conduct, (iii) is duly licensed or qualified and in good standing in each jurisdiction listed on Schedule 6.1(a) and in all other jurisdictions where the property owned or leased by it or the nature of the business transacted by it or both makes such licensing or qualification necessary, (iv) is in compliance in all material respects with all applicable Laws (other than Environmental Laws which are specifically addressed in Section (n) [Environmental Matters]) in all jurisdictions in which any the Borrower or Subsidiary of the Borrower is presently or will be doing business except where the failure to do so would not constitute a Material Adverse Change, and (v) has good and marketable title to or valid leasehold interest in all properties, assets and other rights which it purports to own or lease or which are reflected as owned or leased on its books and records, free and clear of all Liens and encumbrances except those Liens as are permitted under Section 8.2(a). The Borrower has full power to enter into, execute, deliver and carry out this Agreement and the other Loan Documents to incur the Indebtedness contemplated by the Loan Documents and to perform its Obligations under the Loan Documents, and all such actions have been duly authorized by all necessary proceedings on its part. No Event of Default or Potential Default exists or is continuing.

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(b)    Subsidiaries and Owners; Investment Companies. Schedule 6.1(b) states (i) the name of each of the Borrower’s Subsidiaries, its jurisdiction of organization and the amount, percentage and type of equity interests in such Subsidiary (the “Subsidiary Equity Interests”), (ii) the name of each holder of common equity interest in the Borrower, the amount, percentage and type of such common equity interests (the “Borrower Equity Interests”), and (iii) any options, warrants or other rights outstanding to purchase any such equity interests referred to in clause (i) or (ii) (collectively the “Equity Interests”). The Borrower and each Subsidiary of the Borrower has good and marketable title to all of the Subsidiary Equity Interests it purports to own, free and clear in each case of any Lien and all such Subsidiary Equity Interests have been validly issued, fully paid and nonassessable. Neither the Borrower nor any of its Subsidiaries is an “investment company” registered or required to be registered under the Investment Company Act of 1940 or under the “control” of an “investment company” as such terms are defined in the Investment Company Act of 1940 and shall not become such an “investment company” or under such “control.”

(c)    Validity and Binding Effect. This Agreement and each of the other Loan Documents (i) has been duly and validly executed and delivered by the Borrower, and (ii) constitutes, or will constitute, legal, valid and binding obligations of the Borrower, enforceable against the Borrower in accordance with its terms except to the extent enforceability thereof is limited by bankruptcy, insolvency or other laws affecting the enforcement of creditors’ rights generally, and by general principles of equity.

(d)    No Conflict; Material Agreements; Consents. Neither the execution and delivery of this Agreement or the other Loan Documents by the Borrower nor the consummation of the transactions herein or therein contemplated or compliance with the terms and provisions hereof or thereof by any of them will conflict with, constitute a default under or result in any breach of (i) the terms and conditions of the certificate of incorporation, bylaws, certificate of limited partnership, partnership agreement, certificate of formation, limited liability company agreement or other organizational documents of the Borrower or any Subsidiary of the Borrower, or (ii) any Law or any material agreement or instrument or order, writ, judgment, injunction or decree to which the Borrower or any of its Subsidiaries is a party or by which it or any of its Subsidiaries is bound or to which it is subject, or result in the creation or enforcement of any Lien, charge or encumbrance whatsoever upon any property (now or hereafter acquired) of the Borrower or any Subsidiary of the Borrower. There is no default under such material agreement (referred to above) and neither the Borrower nor any Subsidiary of the Borrower is bound by any contractual obligation, or subject to any restriction in any organization document, or any requirement of Law which could result in a Material Adverse Change. No authorization, consent, approval, license or exemption of, or filing or registration with, any court or governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign (including without limitation any authorization, consent, approval, license or exemption of, or filing with, the FERC, the IURC and any other regulatory authority having jurisdiction) is necessary for the valid execution and delivery to the Administrative Agent and the Lenders, the incurrence by the Borrower of the Indebtedness under the Loan Documents and the performance by the Borrower of its obligations under the Loan Documents, other than those already obtained and copies of which have been provided to the Administrative Agent.

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(e)    Litigation. Except as set forth on Schedule 6.1(e), there are no actions, suits, proceedings or investigations pending or, to the knowledge of the Borrower, threatened in writing against the Borrower or any Subsidiaries of the Borrower at law or in equity before any Official Body which individually or in the aggregate may reasonably be expected to result in any Material Adverse Change. Neither the Borrower nor any Subsidiaries of the Borrower are in violation of any order, writ, injunction or any decree of any Official Body which may reasonably be expected to result in any Material Adverse Change.

(f)    Financial Statements.

(i)    Historical Statements. The Borrower has delivered to the Administrative Agent copies of its audited consolidated year-end financial statements for and as of the end of the three fiscal years ended December 31, 2022 (all such annual statements being collectively referred to as the “Statements”). The Statements were compiled from the books and records maintained by the Borrower’s management, are correct and complete in all material respects and fairly represent the consolidated financial condition of the Borrower and its Subsidiaries as of the respective dates thereof and the results of operations for the fiscal periods then ended and have been prepared in accordance with GAAP consistently applied.

(ii)    Accuracy of Financial Statements. Neither the Borrower nor any Subsidiary of the Borrower has any liabilities, contingent or otherwise, or forward or long-term commitments that are required to be disclosed in accordance with GAAP which are not disclosed in the Statements or in the notes thereto, and except as disclosed therein, there are no unrealized losses from any commitments of the Borrower or any Subsidiary of the Borrower which would reasonably be expected to cause a Material Adverse Change.

(g)    Margin Stock. Neither the Borrower nor any Subsidiaries of the Borrower engage or intend to engage principally, or as one of its important activities, in the business of extending credit for the purpose, immediately, incidentally or ultimately, of purchasing or carrying margin stock (within the meaning of Regulation U, T or X as promulgated by the Board of Governors of the Federal Reserve System). No part of the proceeds of the Loan has been or will be used, immediately, incidentally or ultimately, to purchase or carry any margin stock or to extend credit to others for the purpose of purchasing or carrying any margin stock or which is inconsistent with the provisions of the regulations of the Board of Governors of the Federal Reserve System. Neither the Borrower nor any Subsidiaries of the Borrower holds or intends to hold margin stock in such amounts that more than 25% of the reasonable value of the assets of the Borrower and the Subsidiaries of the Borrower are or will be represented by margin stock.

(h)    Full Disclosure. Neither this Agreement nor any other Loan Document, nor any certificate, statement, agreement or other documents furnished to the Administrative Agent or any Lender in connection herewith or therewith, contains any untrue statement of a material fact or omits to state a material fact necessary in order to make the statements contained herein and therein, in light of the circumstances under which they were made, not misleading. There is no fact known to the Borrower which materially adversely affects the business, property, assets, financial condition or results of operations of the Borrower and its Subsidiaries taken as a whole, which has not been set forth in this Agreement or in the certificates, statements, agreements or other documents furnished in writing to the Administrative Agent and the Lenders prior to or on the Closing Date in connection with the transactions contemplated hereby.

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(i)    Taxes. All federal, state, local and other tax returns required to have been filed with respect to the Borrower and each Subsidiary of the Borrower have been filed, and payment or adequate provision has been made for the payment of all taxes, fees, assessments and other governmental charges which have or may become due pursuant to said returns or to assessments received, except to the extent that such taxes, fees, assessments and other charges are being contested in good faith by appropriate proceedings diligently conducted and for which such reserves or other appropriate provisions, if any, as shall be required by GAAP shall have been made.

(j)    Patents, Trademarks, Copyrights, Licenses, Etc. The Borrower and each Subsidiary of the Borrower owns or possesses all the material patents, trademarks, service marks, trade names, copyrights, licenses, registrations, franchises, permits and rights necessary to own and operate its properties and to carry on its business as presently conducted and planned to be conducted by the Borrower or such Subsidiary of the Borrower, without known possible, alleged or actual conflict with the rights of others.

(k)    Licenses, Registrations and Compliance with Laws. Each of the Borrower and each of its Subsidiaries has all permits, governmental licenses, registrations, and approvals necessary to carry out its businesses as presently conducted and as required by law (including, without limitation, the FPA and the IPSCA) or the rules and regulations of any federal, foreign, governmental, state, county or local association, corporation, or governmental agency, body, instrumentality or commission having jurisdiction over the Borrower or its Subsidiaries, including, but not limited to, the FERC, the IURC, the United States Environmental Protection Agency, the United States Department of Labor, the United States Occupational Safety and Health Administration, the United States Equal Employment Opportunity Commission and analogous and related state and foreign agencies, except for such permits, licenses, registrations and approvals the failure to obtain would not reasonably be expected to have a Material Adverse Change. There is no violation or failure of compliance on the part of the Borrower or any Subsidiary with any of the foregoing permits, licenses, registrations, approvals, rules or regulations, and there is no action, proceeding or investigation pending or, to the knowledge of the Borrower, threatened, nor has the Borrower received any notice of such, which might result in the termination or suspension of any such permit, license, registration or approval, except for such violations, failures, actions, proceedings or investigations which would not reasonably be expected to have a Material Adverse Change.

(l)    Insurance. The properties of the Borrower and each of its Subsidiaries are insured pursuant to policies and other bonds which are valid and in full force and effect and which provide adequate coverage from reputable and financially sound insurers in amounts sufficient to insure the assets and risks of the Borrower and each such Subsidiary in accordance with prudent business practice in the industry of the Borrower and its Subsidiaries. At the request of the Administrative Agent, the Borrower shall deliver to the Administrative Agent on the Closing Date an original certificate of insurance describing and certifying as to the existence of the insurance required to be maintained by this Agreement and the other Loan Documents.

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(m)    ERISA Compliance.

(a)    Each Plan of the Borrower is in compliance in all material respects with the applicable provisions of ERISA, the Code and other federal or state Laws. Each Plan of the Borrower that is intended to qualify under Section 401(a) of the Code has received a favorable determination letter from the IRS or an application for such a letter is currently being processed by the IRS with respect thereto and, to the best knowledge of Borrower, nothing has occurred which would prevent, or cause the loss of, such qualification. Borrower has made all required contributions to each Plan subject to Section 412 of the Code, and no application for a funding waiver or an extension of any amortization period pursuant to Section 412 of the Code has been made with respect to any Plan of the Borrower.

(b)    (i) No ERISA Event has occurred or is reasonably expected to occur which causes, or could reasonably be expected to cause, an Event of Default under Section 9.1(i); (ii) no contribution failure under Section 412 and 430 of the Code, Section 302 of ERISA or the terms of any Plan has occurred with respect to any Plan to which the Borrower is a contributing sponsor, sufficient to give rise to a Lien under Section 430(k) of the Code, or otherwise to have a Material Adverse Change; (iii) the Borrower has not incurred, nor reasonably expects to incur, any liability under Title IV of ERISA with respect to any Pension Plan or Multiemployer Plan (other than for ordinary funding obligations and premiums due and not delinquent under Section 4007 of ERISA) which causes, or could reasonably be expected to cause, an Event of Default under Section 9.1(i); (iv) the Borrower has not incurred, nor reasonably expects to incur, any liability (and no event has occurred which, with the giving of notice under Section 4219 of ERISA, would result in such liability) under Sections 4201 or 4243 of ERISA with respect to a Multiemployer Plan which causes, or could reasonably be expected to cause, an Event of Default under Section 9.1(i); and (v) the Borrower has not engaged in a transaction that could be subject to Sections 4069 or 4212(c) of ERISA.

(n)    Environmental Matters. The Borrower, and to the knowledge of the Borrower, each of its Subsidiaries, is in material compliance with applicable Environmental Laws except as disclosed on Schedule 6.1(n); provided that such matters so disclosed could not in the aggregate reasonably be expected to result in a Material Adverse Change.

(o)    Solvency. Before and after giving effect to the Loan hereunder, the Borrower is Solvent.

(p)    Pari Passu Indebtedness. The Indebtedness of the Borrower under this Agreement ranks at least pari passu with all other unsecured Indebtedness of the Borrower.

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(q)    Sanctions and other Anti-Terrorism Laws. No Covered Entity: (i) is a Sanctioned Person; (ii) directly, or indirectly through any third party, is engaged in any transactions or other dealings with or for the benefit of any Sanctioned Person or Sanctioned Jurisdiction, or any transactions or other dealings that otherwise are prohibited by any Anti-Terrorism Laws.

(r)    Anti-Corruption Laws. Each Covered Entity has (a) conducted its business in compliance with all Anti-Corruption Laws and (b) has instituted and maintains policies and procedures designed to ensure compliance with such Anti-Corruption Laws.

7.    CONDITIONS OF LENDING

The effectiveness of this Agreement shall be subject to the satisfaction or waiver of the following further conditions:

7.1    Conditions Precedent to Effectiveness of this Agreement.

(a)    Deliveries. On the Closing Date, the Administrative Agent shall have received each of the following in form and substance reasonably satisfactory to the Administrative Agent:

(i)    A certificate of the Borrower signed by an Authorized Officer, dated as of the Closing Date stating that (w) all representations and warranties of the Borrower set forth in this Agreement are true and correct in all material respects, (x) the Borrower is in compliance with each of the covenants and conditions hereunder, (y) no Event of Default or Potential Default exists, and (z) no Material Adverse Change has occurred since the date of the last audited financial statements of the Borrower delivered to the Administrative Agent;

(ii)    A certificate dated the Closing Date and signed by the Secretary or an Assistant Secretary of the Borrower, certifying as appropriate as to: (a) all action taken by the Borrower in connection with this Agreement and the other Loan Documents; (b) the names of the Authorized Officers authorized to sign the Loan Documents and their true signatures; and (c) copies of its organizational documents as in effect on the Closing Date certified by the appropriate state official where such documents are filed in a state office together with certificates from the appropriate state officials as to the continued existence and good standing of the Borrower in each state where organized or qualified to do business;

(iii)    This Agreement and each of the other Loan Documents signed by an Authorized Officer;

(iv)    Certified copies of the FERC Order and the IURC Order;

(v)    A written opinion of counsel for the Borrower, dated the Closing Date and as to the matters set forth in Schedule 7.1(a);

(vi)    Evidence that adequate insurance required to be maintained under this Agreement is in full force and effect;

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(vii)    such documentation and other information requested in connection with applicable “know your customer” and anti-money laundering rules and regulations, including the USA Patriot Act; and

(viii)    USA PATRIOT Act Diligence. The Administrative Agent and each Lender shall have received, in form and substance acceptable to the Administrative Agent and each Lender such documentation and other information requested in connection with applicable “know your customer” and anti-money laundering rules and regulations, including the USA PATRIOT Act.

(ix)    All material consents required to effectuate the transactions contemplated hereby; and

(x)    Such other documents in connection with such transactions as the Administrative Agent or said counsel may reasonably request.

(b)    Payment of Fees. The Borrower shall have paid all fees and reasonable and documented out-of-pocket expenses payable by the Borrower on or before the Closing Date as required by this Agreement, the Administrative Agent’s Letter or any other Loan Document, in each case, invoiced at least three (3) Business Days prior to the Closing Date.

8.    COVENANTS

8.1    Affirmative Covenants. From the date hereof and thereafter for so long as any Obligations are outstanding or the Borrower is indebted to the Lenders under any of the Loan Documents and until Payment in Full, the Borrower shall ensure that it shall, and shall cause each of its Subsidiaries to comply with the following affirmative covenants:

(a)    Preservation of Existence, Etc. The Borrower shall, and shall cause each of its Subsidiaries to, maintain its legal existence as a corporation, limited partnership or limited liability company and its license or qualification and good standing in each jurisdiction in which its ownership or lease of property or the nature of its business makes such license or qualification necessary, except as otherwise expressly permitted in Section 8.2(c).

(b)    Payment of Liabilities, Including Taxes, Etc. The Borrower shall, and shall cause each of its Subsidiaries to, duly pay and discharge all liabilities to which it is subject or which are asserted against it, promptly as and when the same shall become due and payable, including all taxes, assessments and governmental charges upon it or any of its properties, assets, income or profits, prior to the date on which penalties attach thereto, except to the extent that such liabilities, including taxes, assessments or charges, are being contested in good faith and by appropriate and lawful proceedings diligently conducted and for which such reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made.

(c)    Maintenance of Insurance. The Borrower shall, and shall cause each of its Subsidiaries to, insure its properties and assets against loss or damage by fire and such other insurable hazards as such assets are commonly insured (including fire, extended coverage, property damage, workers’ compensation, public liability and business interruption insurance) and against other risks (including errors and omissions) in such amounts as similar properties and

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assets are insured by prudent companies in similar circumstances carrying on similar businesses, and with reputable and financially sound insurers, including self-insurance to the extent customary.

(d)    Maintenance of Properties and Leases. The Borrower shall, and shall cause each of its Subsidiaries to, maintain in good repair, working order and condition (ordinary wear and tear excepted) in accordance with the general practice of other businesses of similar character and size, all of those properties used and useful to its business, and from time to time, the Borrower will make or cause to be made all appropriate repairs, renewals or replacements thereof.

(e)    Visitation Rights. The Borrower shall, and shall cause each of its Subsidiaries to, permit any of the officers or authorized employees or representatives of the Administrative Agent or any of the Lenders to visit and inspect any of its properties and to examine and make excerpts from its books and records and discuss its business affairs, finances and accounts with its officers, all in such detail and at such times (during regular business hours) and as often as any of the Lenders may reasonably request, provided that each Lender shall provide the Borrower with reasonable notice prior to any visit or inspection. In the event any Lender desires to conduct a visit or inspection of the Borrower or any of its Subsidiaries, such Lender shall coordinate such visit or inspection with the Administrative Agent, such inspection shall be at the expense of such Lender, and any such visit by the Lender shall not exceed one visit annually absent an Event of Default. In the event the Administrative Agent desires to conduct an visit or inspection of the Borrower or any of its Subsidiaries, such visit or inspection will be at the expense of the Administrative Agent, and the Administrative Agent shall be limited to one visit or inspection annually, unless an Event of Default has occurred which has not been waived.

(f)    Keeping of Records and Books of Account. The Borrower shall, and shall cause each Subsidiary of the Borrower to, maintain and keep proper books of record and account which enable the Borrower and its Subsidiaries to issue financial statements in accordance with GAAP and as otherwise required by applicable Laws of any Official Body having jurisdiction over the Borrower or any Subsidiary of the Borrower, and in which full, true and correct entries shall be made in all material respects of all its dealings and business and financial affairs.

(g)    Compliance with Laws. The Borrower shall, and shall cause each Subsidiary of the Borrower, to (i) comply with the requirements of all present and future applicable laws (including, without limitation, the FPA and the IPSCA), rules, regulations and orders of any governmental authority having jurisdiction over it and/or its business, except where the failure to comply would not have a Material Adverse Change, (ii) without limiting clause (i)a above, ensure that no person who owns a controlling interest in or otherwise controls the Borrower is or shall be (x) listed on the Specially Designated Nationals and Blocked Person List maintained by the Office of Foreign Assets Control (“OFAC”), Department of the Treasury, and/or any other similar lists maintained by OFAC pursuant to any authorizing statute, Executive Order or regulation or (y) a person designated under Section 1(b), (c) or (d) of Executive Order No. 13224 (September 23, 2001), any related enabling legislation or any other similar Executive Orders and (iii) without limiting clause (i) above, comply with all applicable Bank Secrecy Act and anti-money laundering laws and regulations.

(h)    Use of Proceeds. The Borrower will use the proceeds of the Loan only in accordance with Section 3.3 [Use of Proceeds] and as permitted by applicable Law; provided that, for the avoidance of doubt, the Borrower will not, directly or indirectly, use the proceeds of the Loan (a) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption

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Laws or (b)(i) to fund any activities or business of or with any Person, or in any country or territory, that, at the time of such funding, is the subject of Sanctions, or (ii) in any other manner that would result in a violation of Sanctions by any Person (including any Person participating in the Loan, whether as Administrative Agent, Joint Lead Arranger, Lender, underwriter, advisor, investor, or otherwise).

(i)    Sanctions and other Anti-Terrorism Laws; Anti-Corruption Laws.

(a) The Borrower covenants and agrees that it shall immediately notify the Administrative Agent and each of the Lenders in writing upon the occurrence of a Reportable Compliance Event.

(b) Each Covered Entity shall conduct their business in compliance with all Anti-Corruption Laws and maintain policies and procedures designed to ensure compliance with such Laws.

8.2    Negative Covenants. From the date hereof and thereafter for so long as any Obligations are outstanding or the Borrower is indebted to the Lenders under any of the Loan Documents and until Payment in Full, the Borrower shall not, and shall not permit any of its Subsidiaries to:

(a)    Liens. Create, incur, assume, or suffer to exist any Lien of any nature, upon or with respect to any of its properties, now owned or hereafter acquired, or assign as collateral or otherwise convey as collateral, any right to receive income, except that the foregoing restrictions shall not apply to:

(i)    Liens for taxes, assessments, or governmental charges or levies on property if the same shall not at the time be delinquent or thereafter can be paid without penalty or interest, or (if foreclosure, distraint, sale or other similar proceedings shall not have been commenced) are being contested in good faith and by appropriate proceedings diligently conducted and for which proper reserve or other provision has been made in accordance with GAAP;

(ii)    Liens imposed by law, such as carriers’, warehousemen’s and mechanics’ liens, bankers’ set-off rights and other similar liens arising in the ordinary course of business for sums not yet due or being contested in good faith and by appropriate proceedings diligently conducted and for which proper reserve or other provisions has been made in accordance with GAAP;

(iii)    Liens arising in the ordinary course of business out of pledges or deposits under worker’s compensation laws, unemployment insurance, old age pensions, or other Social Security or retirement benefits, or similar legislation;

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(iv)    Liens arising from or upon any judgment or award, provided that such judgment or award is being contested in good faith by proper appeal proceedings and only so long as execution thereon shall be stayed;

(v)    deposits to secure the performance of bids, trade contracts (other than for borrowed money), leases, statutory obligations, surety bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business;

(vi)    easements, rights of way, restrictions and other similar encumbrances incurred in the ordinary course of business which, in the aggregate, are not substantial in amount, and which do not in any case materially detract from the value of the property subject thereto or interfere with the ordinary conduct of business by the Borrower or the applicable Subsidiary;

(vii)    Liens against property of the Borrower securing Indebtedness of the Borrower which is evidenced by the Mortgage and Deed of Trust dated May 1, 1940, from the Borrower to American National Bank and Trust Company of Chicago (or any successor trustee), and any and all supplements thereto;

(viii)    Liens on any property acquired, constructed or improved by the Borrower or any Subsidiary after the Closing Date which are created or assumed contemporaneously with, or within one hundred twenty days after, such acquisition or completion of such construction or improvement, or within six months thereafter pursuant to a firm commitment for financing arranged with a lender or investor within such one hundred twenty day period, to secure or provide for the payment of all or any part of such acquisition, construction or improvement incurred after the Closing Date (provided that no such Lien shall extend to or cover any property other than the property so acquired or constructed, or the improvements on the property so improved), or in addition to Liens contemplated by clause (ix) below, Liens on any property existing at the time of acquisition thereof (other than any such Lien created in contemplation of such acquisition), provided that the Liens shall not apply to any property theretofore owned by the Borrower or any Subsidiary other than, in the case of any such construction or improvement, any theretofore unimproved real property on which the property is constructed or the improvement is located;

(ix)    Liens existing on any property of a Person existing at the time such Person is merged into or consolidated with the Borrower or any Subsidiary or becomes a Subsidiary; provided that such Liens were not created in contemplation of such merger, consolidation or acquisition and do not extend to any assets other than those of the Person so merged into or consolidated with the Borrower or such Subsidiary or acquired by the Borrower or such Subsidiary;

(x)    Liens or charges incurred in the ordinary course of business of the Borrower or any Subsidiary which were not incurred in connection with the borrowing of money or the obtaining of an advance or credit, and which do not in the aggregate materially detract from the value of its property or assets or materially impair the use thereof in the operation of its business;

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(xi)    Liens to secure obligations under the Permitted Receivables Financing, in those accounts or contracts giving rise to accounts of the Borrower, which accounts or contracts giving rise to accounts are to be sold by the Borrower as part of the Permitted Receivables Financing; and

(xii)    Liens with respect to cash collateral deposited by the Borrower and its Subsidiaries with counterparties in the ordinary course of the Borrower and its Subsidiaries’ purchase and sale of energy, power, interest rate hedges, coal and other commodities.

(b)    Assumptions or Guaranties of Indebtedness. Assume, guarantee, endorse, or otherwise become contingently liable in connection with any obligation, except:

(i)    pursuant to the provisions of this Agreement and Indebtedness to the Lenders;

(ii)    Indebtedness incurred in the ordinary course of business, excluding Indebtedness for borrowed money or having the commercial effect of a borrowing of money of Persons which are not Subsidiaries of the Borrower;

(iii)    assumptions, guaranties, endorsements and contingent liabilities within the definition of Indebtedness or permitted by Section 8.2 [Indebtedness];

(iv)    if such is approved by the IURC or the FERC; or

(v)    such other contingent liabilities incurred after the date hereof which do not exceed $40,000,000 in the aggregate at any time.

(c)    Dissolution. Dissolve, liquidate, wind up, merge or consolidate with another Person; provided, however (i) the Borrower may merge with another Person if upon the completion of such merger, the Borrower is the surviving entity, (ii) any Subsidiary may be merged into the Borrower or a wholly owned Subsidiary and (iii) the Borrower may liquidate, dissolve or wind-up immaterial Subsidiaries (a Subsidiary being deemed “immaterial” for this purpose if it has less than 5% of the assets of the Borrower and its consolidated Subsidiaries).

(d)    Sale of Assets. Sell, lease, transfer or dispose of any of its assets (including by way of an LLC Division) except:

(i)    in the ordinary course of business;

(ii)    as approved by the IURC;

(iii)    any sale of accounts or contracts giving rise to accounts pursuant to the Permitted Receivables Financing or

(iv)    as such are released under the Mortgage and Deed of Trust dated May 1, 1940, from the Borrower to American National Bank and Trust Company of Chicago (or any successor trustee), and any and all supplements thereto.

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(e)    Change in Nature of Business.

Make any material change in the nature of its business.

(f)    Sale and Leaseback. Enter into any sale and leaseback arrangement with any lender or investor, or enter into any leases except in the normal course of business at reasonable rents comparable to those paid for similar leasehold interests in the area and except for those which do not exceed $40,000,000 in any single transaction.

(g)    Sale of Accounts. Sell, assign, discount, or dispose in any way of promissory notes or trade acceptances held by the Borrower or any Subsidiary, with or without recourse, except pursuant to a Permitted Receivables Financing or otherwise in the ordinary course of business.

(h)    Indebtedness. Incur, create, become or be liable directly or indirectly in any manner with respect to or permit to exist any Indebtedness except:

(i)    Indebtedness arising in the ordinary course of business (other than Indebtedness for borrowed money);

(i)    Indebtedness under the Loan Documents;

(ii)    Indebtedness with respect to trade obligations and other normal accruals and customer deposits in the ordinary course of business not yet due and payable in accordance with customary trade terms or with respect to which the Borrower or the applicable Subsidiary is contesting in good faith the amount or validity thereof by appropriate proceedings and then only to the extent such Person has set aside on its books adequate reserves therefor;

(iii)    Indebtedness of the Borrower arising under commercial paper obligations;

(iv)    Indebtedness of the Borrower approved by the IURC or the FERC (“Approved Indebtedness”);

(v)    Indebtedness secured by Liens permitted under Section 8.2(a) [Liens];

(vi)    Indebtedness under the Permitted Receivables Financing;

(vii)    Indebtedness entered into in connection with Interest Rate Hedges and Commodity Hedges; and

(viii)    Indebtedness incurred under Section 8.2(b) [Assumptions or Guaranties of Indebtedness].

(ix)    Other Agreements. If there exists an Event of Default or a Potential Default, amend any of the terms or conditions of any indenture, agreement, documents, note or other instrument evidencing, securing, or relating to any other Indebtedness permitted under Section 8.2(h) [Indebtedness].

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(j)    Prepayment of Other Loans. If there exists an Event of Default or Potential Default, make any prepayment of any principal of or interest on any Indebtedness (other than the Obligations) or any payment, prepayment, redemption, defeasance, sinking fund payment, other repayment or deposit for the purpose of any such prepayment.

(k)    Change of Fiscal Year. Change its fiscal year.

(l)    Subordination of Claims. If there exists an Event of Default or Potential Default, subordinate or permit to be subordinated any present or future claim against or obligation of another Person, except as ordered in a bankruptcy or similar creditors’ remedy proceeding of such other Person.

(m)    Dividends. If there exists an Event of Default or Potential Default, declare or make payment of dividends to holders of common equity interests of the Borrower; provided that Subsidiaries may pay dividends to the Borrower or to Subsidiaries that are wholly owned by the Borrower.

(n)    Financial Covenant. Permit the ratio, determined as of the end of each of its fiscal quarters, of (i) Total Debt to (ii) Consolidated Total Capitalization to be greater than 0.67 to 1.00.

(o)    Affiliates. Enter into any transaction (including, without limitation, the purchase or sale of any property or service) with, or make any payment or transfer to, any Affiliate except (i) in the ordinary course of business and pursuant to the reasonable requirements of the Borrower’s or such Subsidiary’s business and upon fair and reasonable terms no less favorable to the Borrower or such Subsidiary than the Borrower or such Subsidiary would obtain in a comparable arms’-length transaction or (ii) for the payment of dividends pursuant to Section 8.2(m).

(p)    Investments and Acquisitions. Make or suffer to exist any Investments (including without limitation, loans and advances to, and other Investments in, Subsidiaries), or commitments therefor, or to create any Subsidiary or to become or remain a partner in any partnership or joint venture, or to make any Acquisition of any Person or consummate an LLC Division, except:

(i)    Cash Equivalent and Short-Term Investments.

(ii)    Investments in Subsidiaries and other Investments, in each case in existence on the date hereof and described in Schedule 8.2(p).

(iii)    Investments in Persons principally engaged in a field of enterprise engaged in by the Borrower and its Subsidiaries on the date hereof and any other field of enterprise substantially related, ancillary or complementary thereto.

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(iv)    other Investments not exceeding $50,000,000 in the aggregate outstanding at any time.

(q)    Certain Restrictions. Directly or indirectly, create or otherwise cause or suffer to exist or become effective any encumbrance or restriction on the ability of any Subsidiary to (a) pay dividends or make other distributions on its capital stock owned by the Borrower or any Subsidiary, or pay any Indebtedness owed to the Borrower or any Subsidiary (other than customary limits imposed by corporate law and fraudulent conveyance statutes), (b) make loans or advances to the Borrower or (c) transfer any of its assets or properties to the Borrower (other than pursuant to a Permitted Receivables Financing), except for such encumbrances or restrictions existing by reason of or under (i) applicable law, (ii) this Agreement and the other Loan Documents, (iii) customary restrictions with respect to a Subsidiary pursuant to an agreement that has been entered into for the sale or disposition of all or substantially all of the capital stock of such Subsidiary and (iv) restrictions binding on any Subsidiary on the date it becomes a Subsidiary, provided such restrictions were not created in contemplation of such Person becoming a Subsidiary.

8.3    Reporting Requirements. The Borrower will furnish or cause to be furnished to the Administrative Agent and each of the Lenders:

(a)    Quarterly Financial Statements. As soon as available and in any event within forty-five (45) calendar days after the end of each of the first three fiscal quarters in each fiscal year, financial statements of the Borrower, consisting of a consolidated balance sheet as of the end of such fiscal quarter and related consolidated statements of income, stockholders’ equity and cash flows for the fiscal quarter then ended and the fiscal year through that date, all in reasonable detail and certified (subject to normal year-end audit adjustments) by the Chief Executive Officer, President, any Vice President, Chief Financial Officer, Controller, Treasurer, or Assistant Treasurer of the Borrower as having been prepared in accordance with GAAP, consistently applied, and setting forth in comparative form the respective financial statements for the corresponding date and period in the previous fiscal year.

(b)    Annual Financial Statements. As soon as available and in any event within one hundred twenty (120) days after the end of each fiscal year of the Borrower, audited financial statements of the Borrower consisting of a consolidated balance sheet as of the end of such fiscal year, and related consolidated statements of income, stockholders’ equity and cash flows for the fiscal year then ended, all in reasonable detail and setting forth in comparative form the financial statements as of the end of and for the preceding fiscal year, and certified by independent certified public accountants of nationally recognized standing reasonably satisfactory to the Administrative Agent. The certificate or report of accountants shall be free of qualifications (other than any consistency qualification that may result from a change in the method used to prepare the financial statements as to which such accountants concur) and shall not indicate the occurrence or existence of any event, condition or contingency which would materially impair the payment or performance of any covenant, agreement or duty of any the Borrower under any of the Loan Documents.

(c)    Certificate of the Borrower. Concurrently with the financial statements of the Borrower furnished to the Administrative Agent and to the Lenders pursuant to Sections 8.3(a) [Quarterly Financial Statements] and 8.3(b) [Annual Financial Statements], a certificate (each a “Compliance Certificate”) of the Borrower signed by the Chief Executive Officer, President, any Vice President, Chief Financial Officer, Controller, Treasurer, or Assistant Treasurer of the Borrower, in the form of Exhibit 8.3.

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(d)    Notices.

(i)    Default. Promptly after any officer of the Borrower has learned of the occurrence of an Event of Default or Potential Default, a certificate signed by an Authorized Officer setting forth the details of such Event of Default or Potential Default and the action which the Borrower proposes to take with respect thereto.

(ii)    Litigation. Promptly after the commencement thereof, notice of all actions, suits, proceedings or investigations before or by any Official Body or any other Person against the Borrower or any Subsidiary of the Borrower which involve a claim or series of claims which could reasonably be expected to result in liability in excess of $25,000,000 or which if adversely determined would constitute a Material Adverse Change.

(iii)    Organizational Documents. Promptly and in any event within five dates thereafter, any amendment to the Articles of Incorporation or Bylaws of the Borrower.

(iv)    Erroneous Financial Information. Promptly in the event that the Borrower or its accountants conclude or advise that any previously issued financial statement, audit report or interim review should no longer be relied upon or that disclosure should be made or action should be taken to prevent future reliance.

(v)    ERISA Event. Promptly upon the occurrence of any ERISA Event.

(vi)    Preferred Stock Filing. Promptly, written notice of any filing with the IURC to seek authority to issue any preferred stock;

(vii)    FERC Order. Promptly upon receipt of the same, a copy of any extension, renewal or replacement of the FERC Order, certified by an officer of the Borrower; and

(viii)    Other Reports. Promptly upon their becoming available to the Borrower:

A.    Management Letters. Any reports including management letters submitted to the Borrower by independent accountants in connection with any annual, interim or special audit.

B.    Other Information. Such other reports and information as any of the Lenders may from time to time reasonably request.

8.4    Other Additional Information. Provide to the Administrative Agent and the Lenders: (i) reserved; (ii) reserved; and (iii) such information and documentation as may reasonably be requested by the Administrative Agent or any Lender from time to time for purposes of compliance by the Administrative Agent or such Lender with applicable Laws (including without limitation the USA PATRIOT Act and other “know your customer” and anti-money laundering rules and regulations), and any policy or procedure implemented by the Administrative Agent or such Lender to comply therewith.

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9.    DEFAULT

9.1    Events of Default. An Event of Default shall mean the occurrence or existence of any one or more of the following events or conditions (whatever the reason therefor and whether voluntary, involuntary or effected by operation of Law):

(a)    Payments Under Loan Documents. The Borrower shall fail to pay any principal of the Term Loan, on the date on which such principal is due or any interest on the Term Loan or any other amount owing hereunder or under the other Loan Documents within five (5) Business Days of the date on which such interest or other amount becomes due in accordance with the terms hereof or thereof;

(b)    Breach of Warranty. Any representation or warranty made at any time by the Borrower herein or in any other Loan Document, or in any certificate, other instrument or statement furnished pursuant to the provisions hereof or thereof, shall prove to have been false or misleading in any material respect as of the time it was made or furnished;

(c)    Breach of Negative Covenants or Visitation Rights. The Borrower shall default in the observance or performance of any covenant contained in Section 8.1(a) [Preservation of Existence], Section 8.1(e) [Visitation Rights], Section 8.1(i) [Anti-Terrorism Laws] or Section 8.2 [Negative Covenants];

(d)    Breach of Other Covenants. The Borrower shall default in the observance or performance of any other covenant, condition or provision hereof or of any other Loan Document and such default shall continue unremedied for a period of thirty (30) days;

(e)    Defaults in Other Agreements or Indebtedness. A default or event of default shall occur at any time under the terms of any other agreement involving borrowed money or the extension of credit or any other Indebtedness under which the Borrower or any Subsidiary of the Borrower may be obligated as a borrower or guarantor in excess of $25,000,000 in the aggregate, and such breach, default or event of default consists of the failure to pay (beyond any period of grace permitted with respect thereto, whether waived or not) any Indebtedness when due (whether at stated maturity, by acceleration or otherwise) or if such breach or default permits or causes the acceleration of any Indebtedness (whether or not such right shall have been waived) or the termination of any commitment to lend;

(f)    Final Judgments or Orders. Any final judgments or orders for the payment of money in excess of $50,000,000 in the aggregate shall be entered against the Borrower by a court having jurisdiction in the premises, which judgment is not discharged, vacated, bonded or stayed pending appeal within a period of thirty (30) consecutive days from the date of entry;

(g)    Loan Document Unenforceable. Any of the Loan Documents shall cease to be legal, valid and binding agreements enforceable against the party executing the same or such party’s successors and assigns (as permitted under the Loan Documents) in accordance with the respective terms thereof or shall in any way be terminated (except in accordance with its terms) or become or be declared ineffective or inoperative or shall in any way be challenged or contested or cease to give or provide the respective Liens, security interests, rights, titles, interests, remedies, powers or privileges intended to be created thereby;

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(h)    Uninsured Losses; Proceedings Against Assets. There shall occur any material uninsured damage to or loss, theft or destruction of any assets of the Borrower in excess of $50,000,000 or the Borrower’s assets in excess of $50,000,000 are attached, seized, levied upon or subjected to a writ or distress warrant; or such come within the possession of any receiver, trustee, custodian or assignee for the benefit of creditors and the same is not cured within thirty (30) days thereafter;

(i)    Events Relating to Plans and Benefit Arrangements. (i) An ERISA Event occurs which has resulted or could reasonably be expected to result in liability of Borrower (a) under Title IV of ERISA to a Pension Plan, Multiemployer Plan or the PBGC, (b) to the IRS under Chapter 43 of the Code or to the U.S. Department of Labor, PBGC or other person under Sections 406, 409, 502(c)(i) or (l), or 4071 of ERISA, or (c) to the IRS because of the failure of any “welfare benefit plan” (as described in Section 3(1) of ERISA) sponsored or maintained by the Borrower or any ERISA Affiliate that provides insured medical benefits, to satisfy the non-discrimination requirements of Section 105 of the Code, in each case in an aggregate amount in excess of $50,000,000, or (ii) the Borrower fails to pay when due, after the expiration of any applicable grace period, any installment payment with respect to its withdrawal liability under Section 4201 of ERISA under a Multiemployer Plan in an aggregate amount in excess of $50,000,000;

(j)    Change of Control. (i) IPALCO shall at any time fail to own, directly or indirectly, all of the issued and outstanding common stock of the Borrower or (ii) IPALCO shall at any time not be entitled to elect a majority of the members of the Board of Directors of the Borrower;

(k)    Mortgage Event of Default. The Borrower shall suffer to exist beyond any applicable grace period any event of default under the Mortgage and Deed of Trust from the Borrower to American National Bank and Trust Company of Chicago (or any successor trustee), dated May 1, 1940, and any and all supplements thereto, unless such event of default has been waived in writing by the appropriate party or parties to such agreement; or

(l)    Relief Proceedings. (i) A Relief Proceeding shall have been instituted against any the Borrower or any Subsidiary of the Borrower and such Relief Proceeding shall remain undismissed or unstayed and in effect for a period of sixty (60) consecutive days or such court shall enter a decree or order granting any of the relief sought in such Relief Proceeding, (ii) the Borrower or any Subsidiary of the Borrower institutes, or takes any action in furtherance of, a Relief Proceeding, or (iii) any Borrower or any Subsidiary of the Borrower ceases to be Solvent or admits in writing its inability to pay its debts as they mature.

9.2    Consequences of Event of Default.

(a)    Events of Default Other Than Bankruptcy, Insolvency or Reorganization Proceedings. If an Event of Default specified under Sections 9.1(a) through 9.1(k) shall occur and be continuing, the Lenders and the Administrative Agent shall be under no further obligation to make or continue or convert any portion of the Loan and the Administrative Agent may, and upon the request of the Required Lenders, shall by written notice to the Borrower, declare the unpaid principal amount of the Notes then outstanding and all interest accrued thereon, any unpaid fees and all other Indebtedness of the Borrower to the Lenders hereunder and thereunder to be forthwith due and payable, and the same shall thereupon become and be immediately due and payable to the Administrative Agent for the benefit of each Lender without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived; and

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(b)    Bankruptcy, Insolvency or Reorganization Proceedings. If an Event of Default specified under Section 9.1(l) [Relief Proceedings] shall occur, the Lenders shall be under no further obligations to make or continue or convert the Loan hereunder and the unpaid principal amount of the Loan then outstanding and all interest accrued thereon, any unpaid fees and all other Indebtedness of the Borrower to the Lenders hereunder and thereunder shall be immediately due and payable, without presentment, demand, protest or notice of any kind, all of which are hereby expressly waived; and

(c)    Set-off. If an Event of Default shall have occurred and be continuing, each Lender, and each of its respective Affiliates and any participant of such Lender or Affiliate which has agreed in writing to be bound by the provisions of Section 5.3 [Sharing of Payments] is hereby authorized at any time and from time to time, to the fullest extent permitted by applicable Law, to set off and apply any and all deposits (general or special, time or demand, provisional or final, in whatever currency) at any time held and other obligations (in whatever currency) at any time owing by such Lender, or any such Affiliate or participant to or for the credit or the account of the Borrower against any and all of the Obligations of the Borrower now or hereafter existing under this Agreement or any other Loan Document to such Lender, Affiliate or participant, irrespective of whether or not such Lender, Affiliate or participant shall have made any demand under this Agreement or any other Loan Document and although such Obligations of the Borrower may be contingent or unmatured or are owed to a branch or office of such Lender different from the branch or office holding such deposit or obligated on such Indebtedness. The rights of each Lender and its respective Affiliates and participants under this Section are in addition to other rights and remedies (including other rights of setoff) that such Lender, or its respective Affiliates and participants may have. Each Lender agrees to notify the Borrower and the Administrative Agent promptly after any such setoff and application; provided that the failure to give such notice shall not affect the validity of such setoff and application; and

(d)    Application of Proceeds. From and after the date on which the Administrative Agent has taken any action pursuant to this Section 9.2 and until all Obligations of the Borrower have been Paid in Full, any and all proceeds received by the Administrative Agent from the exercise of any other remedy by the Administrative Agent, shall be applied as follows:

(i)    first, to reimburse the Administrative Agent and the Lenders for out-of-pocket costs, expenses and disbursements, including reasonable attorneys’ and paralegals’ fees and legal expenses, incurred by the Administrative Agent or the Lenders in connection with collection of any Obligations of the Borrower under any of the Loan Documents, including advances made by the Administrative Agent for the reasonable maintenance, preservation, protection or enforcement of, or realization upon, the assets of the Borrower;

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(ii)    second, to the repayment of all Obligations then due and unpaid of the Borrower to the Lenders or their Affiliates incurred under this Agreement, whether of principal, interest, fees, expenses or otherwise, in such manner as the Administrative Agent may determine in its discretion; and

(iii)    the balance, if any, as required by Law.

(e)    Enforcement of Rights and Remedies. Notwithstanding anything to the contrary contained herein or in any other Loan Document, the authority to enforce rights and remedies hereunder and under the other Loan Documents against the Borrower shall be vested exclusively in, and all actions and proceedings at law in connection with such enforcement shall be instituted and maintained exclusively by, the Administrative Agent in accordance with this Section 9.2 for the benefit of all the Lenders; provided that the foregoing shall not prohibit (i) the Administrative Agent from exercising on its own behalf the rights and remedies that inure to its benefit (solely in its capacity as Administrative Agent) hereunder and under the other Loan Documents, (ii) any Lender from exercising setoff rights in accordance with Section 9.2(c) (subject to the terms of Section 5.3 [Sharing of Payments by Lenders]), or (iii) any Lender from filing proofs of claim or appearing and filing pleadings on its own behalf during the pendency of a proceeding relative to the Borrower under any Insolvency Proceeding; and provided, further, that if at any time there is no Person acting as Administrative Agent hereunder and under the other Loan Documents, then (1) the Required Lenders shall have the rights otherwise ascribed to the Administrative Agent pursuant to this Section 9.2(e), and (2) in addition to the matters set forth in clauses (ii), (iii) and (iv) of the preceding proviso and subject to Section 5.3 [Sharing of Payments by Lenders], any Lender may, with the consent of the Required Lenders, enforce any rights and remedies available to it and as authorized by the Required Lenders.

10.    THE ADMINISTRATIVE AGENT

10.1    Appointment and Authority. Each of the Lenders hereby irrevocably appoints PNC to act on its behalf as the Administrative Agent hereunder and under the other Loan Documents and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. The provisions of this Section 10 are solely for the benefit of the Administrative Agent and the Lenders, and the Borrower shall not have rights as a third party beneficiary of any of such provisions.

10.2    Rights as a Lender. The Person serving as the Administrative Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not the Administrative Agent and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated or unless the context otherwise requires, include the Person serving as the Administrative Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, act as the financial advisor or in any other advisory capacity for and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if such Person were not the Administrative Agent hereunder and without any duty to account therefor to the Lenders.

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10.3    Exculpatory Provisions. The Administrative Agent shall not have any duties or obligations except those expressly set forth herein and in the other Loan Documents. Without limiting the generality of the foregoing, the Administrative Agent:

(a)    shall not be subject to any fiduciary or other implied duties, regardless of whether a Potential Default or Event of Default has occurred and is continuing;

(b)    shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Administrative Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein or in the other Loan Documents); provided that the Administrative Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Administrative Agent to liability or that is contrary to any Loan Document or applicable Law; and

(c)    shall not, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as the Administrative Agent or any of its Affiliates in any capacity.

The Administrative Agent shall not be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Lenders (or such other number or percentage of the Lenders as shall be necessary, or as the Administrative Agent shall believe in good faith shall be necessary, under the circumstances as provided in Sections 11.1 [Modifications, Amendments or Waivers] and 9.2 [Consequences of Event of Default]) or (ii) in the absence of its own gross negligence or willful misconduct. The Administrative Agent shall be deemed not to have knowledge of any Potential Default or Event of Default unless and until notice describing such Potential Default or Event of Default is given to the Administrative Agent by the Borrower or a Lender.

The Administrative Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Potential Default or Event of Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document or (v) the satisfaction of any condition set forth herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent.

10.4    Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, Internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of a Loan that by its terms must be fulfilled to the satisfaction of a Lender, the Administrative Agent may presume that such condition is satisfactory to such Lender unless the Administrative Agent shall have received notice to the contrary from such Lender prior to the making of such Loan. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent

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accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

10.5    Delegation of Duties. The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Loan Document by or through any one or more sub agents appointed by the Administrative Agent. The Administrative Agent and any such sub agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Section 10 shall apply to any such sub agent and to the Related Parties of the Administrative Agent and any such sub agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

10.6    Resignation of Administrative Agent. The Administrative Agent may at any time give notice of its resignation to the Lenders and the Borrower. Upon receipt of any such notice of resignation, the Required Lenders shall have the right, with approval from the Borrower (so long as no Event of Default has occurred and is continuing), to appoint a successor, such approval not to be unreasonably withheld or delayed. If no such successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within thirty (30) days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may on behalf of the Lenders appoint a successor Administrative Agent; provided that if the Administrative Agent shall notify the Borrower and the Lenders that no qualifying Person has accepted such appointment, then such resignation shall nonetheless become effective in accordance with such notice and (i) the retiring Administrative Agent shall be discharged from its duties and obligations hereunder and under the other Loan Documents, and (ii) all payments, communications and determinations provided to be made by, to or through the Administrative Agent shall instead be made by or to each Lender directly, until such time as the Required Lenders appoint a successor Administrative Agent as provided for above in this Section 10.6. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Administrative Agent, and the retiring Administrative Agent shall be discharged from all of its duties and obligations hereunder or under the other Loan Documents (if not already discharged therefrom as provided above in this Section). The fees payable by the Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring Administrative Agent’s resignation hereunder and under the other Loan Documents, the provisions of this Section 10 and Section 11.3 [Expenses; Indemnity; Damage Waiver] shall continue in effect for the benefit of such retiring Administrative Agent, its sub agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Administrative Agent was acting as Administrative Agent.

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10.7    Non-Reliance on Administrative Agent and Other Lenders. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document or any related agreement or any document furnished hereunder or thereunder.

10.8    No Other Duties, etc. Anything herein to the contrary notwithstanding, none of the Bookrunner, Joint Lead Arranger, Documentation Agent, and Syndication Agent listed on the cover page hereof shall have any powers, duties or responsibilities under this Agreement or any of the other Loan Documents, except in its capacity, as applicable, as the Administrative Agent or a Lender hereunder.

10.9    Administrative Agent’s Fee. The Borrower shall pay to the Administrative Agent a nonrefundable fee (the “Administrative Agent’s Fee”) under the terms of a letter (the “Administrative Agent’s Letter”) between the Borrower and Administrative Agent, as amended from time to time.

10.10    No Reliance on Administrative Agent’s Customer Identification Program. Each Lender acknowledges and agrees that neither such Lender, nor any of its Affiliates, participants or assignees, may rely on the Administrative Agent to carry out such Lender’s, Affiliate’s, participant’s or assignee’s customer identification program, or other obligations required or imposed under or pursuant to the USA Patriot Act or the regulations thereunder, including the regulations contained in 31 CFR 103.121 (as hereafter amended or replaced, the “CIP Regulations”), or any other Anti-Terrorism Law, including any programs involving any of the following items relating to or in connection with any of the Borrower, its Affiliates or their agents, the Loan Documents or the transactions hereunder or contemplated hereby: (i) any identity verification procedures, (ii) any recordkeeping, (iii) comparisons with government lists, (iv) customer notices or (v) other procedures required under the CIP Regulations or such other Laws.

10.11    Erroneous Payments.

(a)    If the Administrative Agent notifies a Lender, or any Person who has received funds on behalf of a Lender, such Lender (any such Lender or other recipient, a “Payment Recipient”) that the Administrative Agent has determined in its sole discretion (whether or not after receipt of any notice under immediately succeeding clause (b)) that any funds received by such Payment Recipient from the Administrative Agent or any of its Affiliates were erroneously transmitted to, or otherwise erroneously or mistakenly received by, such Payment Recipient (whether or not known to such Lender or other Payment Recipient on its behalf) (any such funds, whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise, individually and collectively, an “Erroneous Payment”) and demands the return of such Erroneous Payment (or a portion thereof), such Erroneous Payment shall at all times remain the property of the Administrative Agent and shall be segregated by the Payment Recipient and held in trust for the benefit of the Administrative Agent, and such Lender shall (or, with respect to any Payment Recipient who received such funds on its behalf, shall cause such Payment Recipient to) promptly, but in no event later than two Business Days thereafter, return to the Administrative Agent the amount of any such Erroneous Payment (or portion thereof) as to which such a demand was made, in same day funds (in the currency so received), together with interest thereon in respect of each day from and including the date such Erroneous Payment (or portion thereof) was received by such Payment

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Recipient to the date such amount is repaid to the Administrative Agent in same day funds at the greater of the Overnight Bank Funding Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect. A notice of the Administrative Agent to any Payment Recipient under this clause (a) shall be conclusive, absent manifest error.

(b)    Without limiting immediately preceding clause (a), each Lender or any Person who has received funds on behalf of a Lender, such Lender, hereby further agrees that if

it receives a payment, prepayment or repayment (whether received as a payment, prepayment or repayment of principal, interest, fees, distribution or otherwise) from the Administrative Agent (or any of its Affiliates) (x) that is in a different amount than, or on a different date from, that specified in a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates) with respect to such payment, prepayment or repayment, (y) that was not preceded or accompanied by a notice of payment, prepayment or repayment sent by the Administrative Agent (or any of its Affiliates), or (z) that such Lender or other such recipient, otherwise becomes aware was transmitted, or received, in error or by mistake (in whole or in part) in each case:

(i)    (A) in the case of immediately preceding clauses (x) or (y), an error shall be presumed to have been made (absent written confirmation from the Administrative Agent to the contrary) or (B) an error has been made (in the case of immediately preceding clause (z)), in each case, with respect to such payment, prepayment or repayment; and

(ii)    such Lender shall (and shall cause any other recipient that receives funds on its respective behalf to) promptly (and, in all events, within one Business Day of its knowledge of such error) notify the Administrative Agent of its receipt of such payment, prepayment or repayment, the details thereof (in reasonable detail) and that it is so notifying the Administrative Agent pursuant to this Section 10.11(b).

(c)    Each Lender hereby authorizes the Administrative Agent to set off, net and apply any and all amounts at any time owing to such Lender under any Loan Document, or otherwise payable or distributable by the Administrative Agent to such Lender from any source, against any amount due to the Administrative Agent under immediately preceding clause (a) or under the indemnification provisions of this Agreement.

(d)    In the event that an Erroneous Payment (or portion thereof) is not recovered by the Administrative Agent for any reason, after demand therefor by the Administrative Agent in accordance with immediately preceding clause (a), from any Lender that has received such Erroneous Payment (or portion thereof) (and/or from any Payment Recipient who received such Erroneous Payment (or portion thereof) on its respective behalf) (such unrecovered amount, an “Erroneous Payment Return Deficiency”), upon the Administrative Agent’s notice to such Lender at any time, (i) such Lender shall be deemed to have assigned its Loan (but not its Commitments) of the relevant class with respect to which such Erroneous Payment was made (the “Erroneous Payment Impacted Class”) in an amount equal to the Erroneous Payment Return Deficiency (or such lesser amount as the Administrative Agent may specify) (such assignment of the Loan (but not Commitments) of the Erroneous Payment Impacted Class, the “Erroneous Payment Deficiency Assignment”) at par plus any accrued and unpaid interest (with the assignment fee to be waived by the Administrative Agent in such instance), and is hereby (together with the Borrower) deemed to execute and deliver an Assignment and Assumption Agreement with respect to such Erroneous Payment Deficiency Assignment, and such Lender shall deliver any Notes evidencing such Loan to the Borrower or

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the Administrative Agent, (ii) the Administrative Agent as the assignee Lender shall be deemed to acquire the Erroneous Payment Deficiency Assignment, (iii) upon such deemed acquisition, the Administrative Agent as the assignee Lender shall become a Lender hereunder with respect to such Erroneous Payment Deficiency Assignment and the assigning Lender shall cease to be a Lender hereunder with respect to such Erroneous Payment Deficiency Assignment, excluding,

for the avoidance of doubt, its obligations under the indemnification provisions of this Agreement and its applicable Commitments which shall survive as to such assigning Lender and (iv) the Administrative Agent may reflect in the Register its ownership interest in the Loan subject to the Erroneous Payment Deficiency Assignment. The Administrative Agent may, in its discretion, sell any portion of the Loan acquired pursuant to an Erroneous Payment Deficiency Assignment and upon receipt of the proceeds of such sale, the Erroneous Payment Return Deficiency owing by the applicable Lender shall be reduced by the net proceeds of the sale of such Loan (or portion thereof), and the Administrative Agent shall retain all other rights, remedies and claims against such Lender (and/or against any recipient that receives funds on its respective behalf). For the avoidance of doubt, no Erroneous Payment Deficiency Assignment will reduce the Commitments of any Lender and such Commitments shall remain available in accordance with the terms of this Agreement. In addition, each party hereto agrees that, except to the extent that the Administrative Agent has sold a Loan (or portion thereof) acquired pursuant to an Erroneous Payment Deficiency Assignment, and irrespective of whether the Administrative Agent may be equitably subrogated, the Administrative Agent shall be contractually subrogated to all the rights and interests of the applicable Lender under the Loan Documents with respect to each Erroneous Payment Return Deficiency (the “Erroneous Payment Subrogation Rights”).

(e)    The parties hereto agree that an Erroneous Payment shall not pay, prepay, repay, discharge or otherwise satisfy any Obligations owed by the Borrower, except, in each case, to the extent such Erroneous Payment is, and solely with respect to the amount of such Erroneous Payment that is, comprised of funds received by the Administrative Agent from the Borrower for the purpose of making such Erroneous Payment.

(f)    To the extent permitted by applicable Law, no Payment Recipient shall assert any right or claim to an Erroneous Payment, and hereby waives, and is deemed to waive, any claim, counterclaim, defense or right of set-off or recoupment with respect to any demand, claim or counterclaim by the Administrative Agent for the return of any Erroneous Payment received, including without limitation waiver of any defense based on “discharge for value” or any similar doctrine

(g)    Each party’s obligations, agreements and waivers under this Section 10.11 shall survive the resignation or replacement of the Administrative Agent, the termination of the Commitments and/or the repayment, satisfaction or discharge of all Obligations (or any portion thereof) under any Loan Document.    

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11.    MISCELLANEOUS

11.1    Modifications, Amendments or Waivers. With the written consent of the Required Lenders, the Administrative Agent, acting on behalf of all the Lenders, and the Borrower, may from time to time enter into written agreements amending or changing any provision of this Agreement or any other Loan Document or the rights of the Lenders or the Borrower hereunder or thereunder, or may grant written waivers or consents hereunder or thereunder. Any such agreement, waiver or consent made with such written consent shall be effective to bind all the Lenders and the Borrower; provided, that no such agreement, waiver or consent may be made which will:

(a)    Increase of Commitment. Increase the amount of the Term Loan Commitment of any Lender hereunder without the consent of such Lender;

(b)    Extension of Payment; Reduction of Principal, Interest or Fees; Modification of Terms of Payment. Whether or not the Loan is outstanding, extend the Term Loan Maturity Date or the time for payment of principal or interest of the Loan or any fee payable to any Lender, or reduce the principal amount of or the rate of interest borne by the Loan or reduce any fee payable to any Lender, without the consent of each Lender directly affected thereby; or

(c)    Miscellaneous. Amend Section 5.2 [Pro Rata Treatment of Lenders], 10.3 [Exculpatory Provisions, Etc.] or 5.3 [Sharing of Payments by Lenders] or this Section 11.1, alter any provision regarding the pro rata treatment of the Lenders or requiring all Lenders to authorize the taking of any action or reduce any percentage specified in the definition of Required Lenders, in each case without the consent of all of the Lenders.

provided that no agreement, waiver or consent which would modify the interests, rights or obligations of the Administrative Agent may be made without the written consent of such Administrative Agent, and provided, further that, if in connection with any proposed waiver, amendment or modification referred to in Sections 11.1(a) through 11.1(c) above, the consent of the Required Lenders is obtained but the consent of one or more of such other Lenders whose consent is required is not obtained (each a “Non-Consenting Lender”), then the Borrower shall have the right to replace any such Non-Consenting Lender with one or more replacement Lenders pursuant to Section 5.13 [Replacement of a Lender]. Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to approve or disapprove any amendment, waiver or consent hereunder (and any amendment, waiver or consent which by its terms requires the consent of all Lenders or each affected Lender may be effected with the consent of the applicable Lenders other than Defaulting Lenders), except that (x) the Commitment of any Defaulting Lender may not be increased or extended without the consent of such Lender, and (y) any waiver, amendment or modification requiring the consent of all Lenders or each affected Lender that by its terms affects any Defaulting Lender disproportionately adversely relative to other affected Lenders shall require the consent of such Defaulting Lender.

11.2    No Implied Waivers; Cumulative Remedies. No course of dealing and no delay or failure of the Administrative Agent or any Lender in exercising any right, power, remedy or privilege under this Agreement or any other Loan Document shall affect any other or future exercise thereof or operate as a waiver thereof, nor shall any single or partial exercise thereof preclude any further exercise thereof or of any other right, power, remedy or privilege. The rights and remedies of the Administrative Agent and the Lenders under this Agreement and any other Loan Documents are cumulative and not exclusive of any rights or remedies which they would otherwise have.

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11.3    Expenses; Indemnity; Damage Waiver.

(a)    Costs and Expenses. The Borrower shall pay (i) all reasonable out of pocket expenses incurred by the Administrative Agent and its Affiliates (including the reasonable fees, charges and disbursements of counsel for the Administrative Agent), in connection with the syndication of the credit facilities provided for herein, the preparation, negotiation, execution, delivery and administration of this Agreement and the other Loan Documents or any amendments, modifications or waivers of the provisions hereof or thereof (whether or not the transactions contemplated hereby or thereby shall be consummated), and (ii) all reasonable out-of-pocket expenses incurred by the Administrative Agent, any Lender (including the reasonable fees, charges and disbursements of any counsel for the Administrative Agent, or any Lender), in connection with the enforcement or protection of its rights (A) in connection with this Agreement and the other Loan Documents, including its rights under this Section, or (B) in connection with the Loan made hereunder, including all such reasonable out of pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loan.

(b)    Indemnification by the Borrower. The Borrower shall indemnify the Administrative Agent (and any sub-agent thereof), each Lender and each Related Party of any of the foregoing Persons (each such Person being called an “Indemnitee”) against, and hold each Indemnitee harmless from, any and all losses, claims, damages, liabilities and related expenses (including the reasonable fees, charges and disbursements of any counsel for any Indemnitee), incurred by any Indemnitee or asserted against any Indemnitee by any third party or by the Borrower arising out of, in connection with, or as a result of (i) the execution or delivery of this Agreement, any other Loan Document or any agreement or instrument contemplated hereby or thereby, the performance or nonperformance by the parties hereto of their respective obligations hereunder or thereunder or the consummation of the transactions contemplated hereby or thereby, (ii) the Loan or the use or proposed use of the proceeds therefrom, (iii) breach of representations, warranties or covenants of the Borrower under the Loan Documents, or (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, including any such items or losses relating to or arising under Environmental Laws or pertaining to environmental matters, whether based on contract, tort or any other theory, whether brought by a third party or by the Borrower, and regardless of whether any Indemnitee is a party thereto; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses (x) are determined by a court of competent jurisdiction by final and nonappealable judgment to have resulted from the gross negligence or willful misconduct of such Indemnitee or (y) result from a claim brought by the Borrower against an Indemnitee for breach in bad faith of such Indemnitee’s obligations hereunder or under any other Loan Document, if the Borrower has obtained a final and nonappealable judgment in its favor on such claim as determined by a court of competent jurisdiction. This Section 11.3(b) [Indemnification by the Borrower] shall not apply with respect to Taxes other than any Taxes that represent losses, claims, damages, etc. arising from any non-Tax claim.

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(c)    Reimbursement by Lenders. To the extent that the Borrower for any reason fails to indefeasibly pay any amount required under Sections (a) [Costs and Expenses] or 11.3(b) [Indemnification by the Borrower] to be paid by it to the Administrative Agent (or any sub-agent thereof) or any Related Party of any of the foregoing, each Lender severally agrees to pay to the Administrative Agent (or any such sub-agent) or such Related Party, as the case may be, such Lender’s Ratable Share (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount, provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent (or any such sub-agent) in its capacity as such, or against any Related Party of any of the foregoing acting for the Administrative Agent (or any such sub-agent) in connection with such capacity.

(d)    Waiver of Consequential Damages, Etc. To the fullest extent permitted by applicable Law, the Borrower shall not assert, and hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document or any agreement or instrument contemplated hereby, the transactions contemplated hereby or thereby, the Loan or the use of the proceeds thereof. No Indemnitee referred to in Section 11.3(b) [Indemnification by Borrower] shall be liable for any damages arising from the use by unintended recipients of any information or other materials distributed by it through telecommunications, electronic or other information transmission systems in connection with this Agreement or the other Loan Documents or the transactions contemplated hereby or thereby.

(e)    Payments. All amounts due under this Section shall be payable not later than ten (10) days after demand therefor.

11.4    Holidays. Whenever payment of the Loan to be made or taken hereunder shall be due on a day which is not a Business Day such payment shall be due on the next Business Day (except as provided in Section 4.2 [Interest Periods]) and such extension of time shall be included in computing interest and fees, except that the Loan shall be due on the Business Day preceding the Term Loan Maturity Date if the Term Loan Maturity Date is not a Business Day. Whenever any payment or action to be made or taken hereunder (other than payment of the Loan) shall be stated to be due on a day which is not a Business Day, such payment or action shall be made or taken on the next following Business Day, and such extension of time shall not be included in computing interest or fees, if any, in connection with such payment or action.

11.5    Notices; Effectiveness; Electronic Communication.

(a)    Notices Generally. Except in the case of notices and other communications expressly permitted to be given by telephone (and except as provided in Section 11.5(b) [Electronic Communications]), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopier (i) if to a Lender, to it at its address set forth in its administrative questionnaire, or (ii) if to any other Person, to it at its address set forth on Schedule 1.1(B).

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Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices sent by telecopier shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next Business Day for the recipient). Notices delivered through electronic communications to the extent provided in Section 11.5(b) [Electronic Communications], shall be effective as provided in such Section.

(b)    Electronic Communications. Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communication (including e-mail and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices to any Lender if such Lender has notified the Administrative Agent that it is incapable of receiving notices under such Article by electronic communication. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications. Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement); provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next Business Day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

(c)    Change of Address, Etc. Any party hereto may change its address, e mail address or telecopier number for notices and other communications hereunder by notice to the other parties hereto.

11.6    Severability. The provisions of this Agreement are intended to be severable. If any provision of this Agreement shall be held invalid or unenforceable in whole or in part in any jurisdiction, such provision shall, as to such jurisdiction, be ineffective to the extent of such invalidity or unenforceability without in any manner affecting the validity or enforceability thereof in any other jurisdiction or the remaining provisions hereof in any jurisdiction.

11.7    Duration; Survival. All representations and warranties of the Borrower contained herein or made in connection herewith shall survive the execution and delivery of this Agreement, the completion of the transactions hereunder and Payment In Full. All covenants and agreements of the Borrower contained herein relating to the payment of principal, interest, premiums, additional compensation or expenses and indemnification, including those set forth in the Notes, Section 5 [Payments] and Section 11.3 [Expenses; Indemnity; Damage Waiver], shall survive Payment In Full. All other covenants and agreements of the Borrower shall continue in full force and effect from and after the date hereof and until Payment In Full.

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11.8    Successors and Assigns.

(a)    Successors and Assigns Generally. The provisions of this Agreement shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns permitted hereby, except that the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder (including by way of an LLC Division) without the prior written consent of the Administrative Agent and each Lender and no Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of Section 11.8(b) [Assignments by Lenders], (ii) by way of participation in accordance with the provisions of Section 11.8(d) [Participations], or (iii) by way of pledge or assignment of a security interest subject to the restrictions of Section 11.8(e) [Certain Pledges; Successors and Assigns Generally] (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in Section 11.8(d) [Participations] and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)    Assignments by Lenders. Any Lender may at any time assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loan at the time owing to it); provided that any such assignment shall be subject to the following conditions:

(i)    Minimum Amounts.

A.    in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and the Loan at the time owing to it or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund, no minimum amount need be assigned; and

B.    in any case not described in clause (i)(A) of this Section 11.8(b), the aggregate amount of the Commitment (which for this purpose includes the Loan outstanding thereunder) or, if the applicable Commitment is not then in effect, the principal outstanding balance of the Loan of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption Agreement with respect to such assignment is delivered to the Administrative Agent or, if “Trade Date” is specified in the Assignment and Assumption Agreement, as of the Trade Date) shall not be less than $5,000,000, in the case of any assignment in respect of the Term Loan Commitment of the assigning Lender, unless each of the Administrative Agent and, so long as no Event of Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed).

(ii)    Proportionate Amounts. Each partial assignment shall (a) be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Loan or the Commitment assigned, and (b) be made on a pro-rata basis relating to such Lender’s Term Loan Commitment.

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A.    Required Consents. No consent shall be required for any assignment except for the consent of the Administrative Agent (which shall not be unreasonably withheld or delayed) and the consent of the Borrower (such consent not to be unreasonably withheld or delayed) shall be required unless (x) an Event of Default has occurred and is continuing at the time of such assignment or (y) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; provided that the Borrower shall be deemed to have consented to any such assignment unless it shall object thereto by written notice to the Administrative Agent within five (5) Business Days after having received notice thereof.

(iii)    Assignment and Assumption Agreement. The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption Agreement, together with a processing and recordation fee of $3,500, and the assignee, if it is not a Lender, shall deliver to the Administrative Agent an administrative questionnaire provided by the Administrative Agent.

(iv)    No Assignment to Certain Persons. No such assignment shall be made to (A) the Borrower or any of the Borrower’s Affiliates or Subsidiaries or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute a Defaulting Lender or a Subsidiary thereof.

(v)    No Assignment to Natural Persons. No such assignment shall be made to a natural person (including, without limitation, holding companies, investment vehicles or trusts for, or owned and operated for the primary benefit of, a natural person).

Subject to acceptance and recording thereof by the Administrative Agent pursuant to Section (c) [Register], from and after the effective date specified in each Assignment and Assumption Agreement, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption Agreement, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption Agreement, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption Agreement covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 4.4 [Term SOFR Rate Unascertainable; Illegality; Increased Costs; Deposits Not Available], 5.8 [Increased Costs], and 11.3 [Expenses, Indemnity; Damage Waiver] with respect to facts and circumstances occurring prior to the effective date of such assignment. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 11.8(b) shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 11.8(d) [Participations].

(c)    Register. The Administrative Agent, acting solely for this purpose as an agent of the Borrower, shall maintain a record of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loan owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). Such register shall be conclusive, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is in such register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. Such Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

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(d)    Participations. Any Lender may at any time, without the consent of, or notice to, the Borrower or the Administrative Agent, sell participations to any Person (other than a natural person (including, without limitation, holding companies, investment vehicles or trusts for, or owned and operated for the primary benefit of, a natural person) or the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Loan owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) the Borrower, the Administrative Agent and the Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement.

Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree (other than as is already provided for herein) to any amendment, modification or waiver with respect to Sections 11.1(a) [Increase of Commitment] or 11.1(b) [Extension of Payment, Etc.] that affects such Participant. The Borrower agrees that each Participant shall be entitled to the benefits of Sections 4.4 [Term SOFR Rate Unascertainable, Etc.], 5.8 [Increased Costs], 5.10 [Indemnity] and 5.9 [Taxes] (subject to the requirements and limitations therein, including the requirements under Section 5.9(g) [Status of Lenders] (it being understood that the documentation required under Section 5.9(g) [Status of Lenders] shall be delivered to the participating Lender)) to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 11.8(b) [Assignments by Lenders]; provided that such Participant (A) agrees to be subject to the provisions of Section 5.13 [Replacement of a Lender] and Section 5.14 [Designation of a Different Lending Office] as if it were an assignee under Section 11.8(b) [Assignments by Lenders]; and (B) shall not be entitled to receive any greater payment under Sections 5.8 [Increased Costs] or 5.9 [Taxes], with respect to any participation, than its participating Lender would have been entitled to receive, except to the extent such entitlement to receive a greater payment results from a Change in Law that occurs after the Participant acquired the applicable participation. Each Lender that sells a participation agrees, at the Borrower’s request and expense, to use reasonable efforts to cooperate with the Borrower to effectuate the provisions of Section 5.13 [Replacement of a Lender] and Section 5.14 [Designation of Different Lending Office] with respect to any Participant. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 9.2(c) [Set-off] as though it were a Lender; provided that such Participant agrees to be subject to Section 5.3 [Sharing of Payments by Lenders] as though it were a Lender.

Each Lender that sells a participation shall, acting solely for this purpose as a non-fiduciary agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loan or other obligations under the Loan Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any commitments, loans, letters of credit or its other obligations under any Loan Document) to any Person except to the extent that such disclosure is necessary to establish that such commitment, loan, letter of credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, the Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

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(e)    Certain Pledges; Successors and Assigns Generally. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

11.9    Confidentiality.

(a)    General. Each of the Administrative Agent and the Lenders agrees to maintain the confidentiality of the Information, except that Information may be disclosed (i) to its Affiliates and to its and its Affiliates’ respective partners, directors, officers, employees, agents, advisors and other representatives (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (ii) to the extent requested by any regulatory authority purporting to have jurisdiction over it (including any self-regulatory authority, such as the National Association of Insurance Commissioners), (iii) to the extent required by applicable Laws or regulations or by any subpoena or similar legal process, (iv) to any other party hereto, (v) in connection with the exercise of any remedies hereunder or under any other Loan Document or any action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (vi) subject to an agreement containing provisions substantially the same as those of this Section, to (A) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (B) any actual or prospective counterparty (or its advisors) to any swap or derivative transaction relating to the Borrower and its obligations, (vii) with the consent of the Borrower or (viii) to the extent such Information (Y) becomes publicly available other than as a result of a breach of this Section or (Z) becomes available to the Administrative Agent, any Lender, or any of their respective Affiliates on a nonconfidential basis from a source other than the Borrower. Any Person required to maintain the confidentiality of Information as provided in this Section shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information. In addition, the Administrative Agent and the Lenders may disclose the existence of this Agreement and information about this Agreement to market data collectors, similar service providers to the lending industry and service providers to the Administrative Agent and the Lenders in connection with the administration of this Agreement, the other Loan Documents, and the Commitments.

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(b)    Sharing Information With Affiliates of the Lenders. The Borrower acknowledges that from time to time financial advisory, investment banking and other services may be offered or provided to the Borrower or one or more of its Affiliates (in connection with this Agreement or otherwise) by any Lender or by one or more Subsidiaries or Affiliates of such Lender and the Borrower hereby authorizes each Lender to share any information delivered to such Lender by the Borrower and its Subsidiaries pursuant to this Agreement to any such Subsidiary or Affiliate subject to the provisions of Section 11.9(a) [General].

11.10    Counterparts; Integration; Effectiveness.

(a)    Counterparts; Integration; Effectiveness. This Agreement may be executed in counterparts (and by different parties hereto in different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract. This Agreement and the other Loan Documents, and any separate letter agreements with respect to fees payable to the Administrative Agent, constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof including any prior confidentiality agreements and commitments. This Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof that, when taken together, bear the signatures of each of the other parties hereto. Delivery of an executed counterpart of a signature page of this Agreement by telecopy or e mail shall be effective as delivery of a manually executed counterpart of this Agreement.

11.11    CHOICE OF LAW; SUBMISSION TO JURISDICTION; WAIVER OF VENUE; SERVICE OF PROCESS; WAIVER OF JURY TRIAL.

(a)    Governing Law. This Agreement shall be deemed to be a contract under the Laws of the State of Indiana without regard to its conflict of laws principles.

(b)    SUBMISSION TO JURISDICTION. THE BORROWER IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE NONEXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF INDIANA SITTING IN MARION COUNTY AND OF THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF INDIANA, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN SUCH INDIANA STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT OR IN ANY OTHER LOAN DOCUMENT SHALL AFFECT ANY RIGHT THAT THE ADMINISTRATIVE AGENT, OR ANY LENDER MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AGAINST THE BORROWER OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

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(c)    WAIVER OF VENUE. THE BORROWER IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT IN ANY COURT REFERRED TO IN THIS SECTION 11.11. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT AND AGREES NOT ASSERT ANY SUCH DEFENSE.

(d)    SERVICE OF PROCESS. EACH PARTY HERETO IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER PROVIDED FOR NOTICES IN SECTION 11.5 [NOTICES; EFFECTIVENESS; ELECTRONIC COMMUNICATION]. NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY PARTY HERETO TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY APPLICABLE LAW.

(e)    WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

11.12    USA Patriot Act Notice. Each Lender that is subject to the USA Patriot Act and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act, it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender or Administrative Agent, as applicable, to identify the Borrower in accordance with the USA Patriot Act.

11.13    Certain ERISA Matters.

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A.    Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and its Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that at least one of the following is and will be true:

(1)    such Lender is not using “plan assets” (within the meaning of Section 3(42) of ERISA) of one or more Benefit Plans in connection with the Loan, the Commitments or this Agreement,

(2)    the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loan, the Commitments and this Agreement,

(3)    (A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loan, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loan, the Commitments and this Agreement satisfies the requirements of subsections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loan, the Commitments and this Agreement, or

(4)    such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

B.    In addition, unless either subclause (A)(1) in the immediately preceding Section 11.13 is true with respect to a Lender or such Lender has not provided another representation, warranty and covenant as provided in subclause (A)(4) in the immediately preceding Section 11.13, such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and its Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower, that the Administrative Agent is not a fiduciary with respect to the assets of such Lender involved in such Lender’s entrance into, participation in, administration of and performance of the Loan, the Commitments and this Agreement (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Loan Document or any documents related to hereto or thereto).

73

11.14    Acknowledgement and Consent to Bail-In of Affected Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)    the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(i)    the effects of any Bail-in Action on any such liability, including, if applicable:

(ii)    a reduction in full or in part or cancellation of any such liability;

(iii)    a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(b)    the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of the applicable Resolution Authority.

11.15    No Advisory or Fiduciary Responsibility.

(a)    In connection with all aspects of each transaction contemplated hereby, the Borrower acknowledges and agrees, and acknowledges its Affiliates’ understanding, that (i) the facilities provided for hereunder and any related arranging or other services in connection therewith (including in connection with any amendment, waiver or other modification hereof or of any other Loan Document) are an arm’s-length commercial transaction between the Borrower and its Affiliates, on the one hand, and the Administrative Agent, the Joint Lead Arrangers and the Lenders, on the other hand, and the Borrower is capable of evaluating and understanding and understands and accepts the terms, risks and conditions of the transactions contemplated hereby and by the other Loan Documents (including any amendment, waiver or other modification hereof or thereof), (ii) in connection with the process leading to such transaction, each of the Administrative Agent, the Joint Lead Arrangers and the Lenders is and has been acting solely as a principal and is not the financial advisor, agent or fiduciary, for the Borrower or any of its Affiliates, stockholders, creditors or employees or any other Person, (iii) none of the Administrative Agent, the Joint Lead Arrangers or the Lenders has assumed or will assume an advisory, agency or fiduciary responsibility in favor of the Borrower with respect to any of the transactions contemplated hereby or the process leading thereto, including with respect to any amendment, waiver or other modification hereof or of any other Loan Document (irrespective of whether any Joint Lead Arranger or Lender has advised or is currently advising the Borrower or any of its Affiliates on other matters) and none of the Administrative Agent, the Joint Lead Arrangers or the Lenders has any obligation to the Borrower or any of its Affiliates with respect to the financing transactions contemplated hereby except those obligations expressly set forth herein and in the other Loan Documents, (iv) the Joint Lead Arrangers and the Lenders and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from, and may conflict with, those of the Borrower and its Affiliates, and none of the Administrative Agent, the Joint Lead Arrangers or the Lenders has any obligation to disclose any of such interests by virtue of any advisory, agency or fiduciary relationship and (v) the

74

Administrative Agent, the Joint Lead Arrangers and the Lenders have not provided and will not provide any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby (including any amendment, waiver or other modification hereof or of any other Loan Document) and the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate.

(b)    The Borrower acknowledges and agrees that each Lender, each Joint Lead Arranger and any Affiliate thereof may lend money to, invest in, and generally engage in any kind of business with, any of the Borrower, any Affiliate thereof or any other person or entity that may do business with or own securities of any of the foregoing, all as if such Lender, Joint Lead Arranger or Affiliate thereof were not a Lender or Joint Lead Arranger or an Affiliate thereof (or an agent or any other person with any similar role under the facilities provided for hereunder) and without any duty to account therefor to any other Lender or Joint Lead Arranger, the Borrower or any Affiliate of the foregoing. Each Lender, each Joint Lead Arranger and any Affiliate thereof may accept fees and other consideration from the Borrower or any Affiliate thereof for services in connection with this Agreement, the facilities provided for hereunder or otherwise without having to account for the same to any other Lender or Joint Lead Arranger, the Borrower or any Affiliate of the foregoing.

[SIGNATURE PAGES FOLLOW]

75

[SIGNATURE PAGE TO TERM LOAN AGREEMENT]

IN WITNESS WHEREOF, the parties hereto, by their officers thereunto duly authorized, have executed this Agreement as of the day and year first above written.

INDIANAPOLIS POWER & LIGHT COMPANY

By: /s/ Dustin Illyes

Name: Dustin Illyes

Title: Treasurer

[SIGNATURE PAGE TO TERM LOAN AGREEMENT]

PNC BANK, NATIONAL ASSOCIATION, individually and as Administrative Agent

By: /s/ Ryan Rockwood

Name: Ryan Rockwood

Title: Vice President

[SIGNATURE PAGE TO TERM LOAN AGREEMENT]

U.S. BANK NATIONAL ASSOCIATION, individually and as Syndication Agent

By: /s/ Kevin S. Murphy

Name: Kevin S. Murphy

Title: Senior Vice President

[SIGNATURE PAGE TO TERM LOAN AGREEMENT]

THE HUNTINGTON NATIONAL BANK, individually and as Documentation Agent

By: /s/ Christopher Olsen

Name: Christopher Olsen

Title: Vice President

EX-21

Exhibit 21

Subsidiaries of IPALCO Enterprises, Inc.

Name of Subsidiary	State of Incorporation or Organization	D/B/A
Indianapolis Power & Light Company	Indiana	AES Indiana
Mid-America Capital Resources Inc.	Indiana	N/A
AES Indiana Devco Holdings 1, LLC	Indiana	N/A
AES Indiana Devco Holdings 2, LLC	Indiana	N/A
AES Indiana Devco Holdings 3, LLC	Indiana	N/A
AES Indiana Partner Sub, LLC	Delaware	N/A
AES Indiana Sponsor	Delaware	N/A
Tecumseh Coal Corporation	Indiana	N/A
AES Pike County Energy Storage, LLC	Delaware	N/A
Hardy Hills JV, LLC	Delaware	N/A
Hardy Hills Solar Energy LLC	Delaware	N/A
Petersburg Energy Center, LLC	Delaware	N/A

EX-31.1

Exhibit 31.1

Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the SecuritiesandExchange Act of 1934

I, Kenneth J. Zagzebski, certify that:

1.I have reviewed this annual report on Form 10-K of IPALCO Enterprises, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:     February 26, 2024/s/ Kenneth J. Zagzebski

                    Kenneth J. Zagzebski

                    President and Chief Executive Officer 

EX-31.2

Exhibit 31.2

Certification Pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities and Exchange Act of 1934

I, Sherry Kohan, certify that:

1.I have reviewed this annual report on Form 10-K of IPALCO Enterprises, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:    February 26, 2024/s/ Sherry Kohan

                    Sherry Kohan

                    Interim Vice President and Chief Financial Officer 

EX-32.1

Exhibit 32.1

Certification Pursuant to Rule 13a-14(b) or 15d-14(b) of the Securities and Exchange Act of 1934 and Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

The certification set forth below is being submitted in connection with the Annual Report on Form 10-K for the year ended December 31, 2023 (the “Report”) for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Kenneth J. Zagzebski, Chief Executive Officer of IPALCO Enterprises, Inc. (“IPALCO”), certifies that, to the best of his knowledge:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of IPALCO.

Date:    February 26, 2024/s/ Kenneth J. Zagzebski

                    Kenneth J. Zagzebski

                    President and Chief Executive Officer 

A signed original of this written statement required by Section 906 has been provided to IPALCO and will be retained by IPALCO and furnished to the SEC or its staff upon request. 

EX-32.2

Exhibit 32.2

Certification Pursuant to Rule 13a-14(b) or 15d-14(b) of the Securities and Exchange Act of 1934 and Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

The certification set forth below is being submitted in connection with the Annual Report on Form 10-K for the year ended December 31, 2023 (the “Report”) for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Sherry Kohan, Interim Chief Financial Officer of IPALCO Enterprises, Inc. (“IPALCO”), certifies that, to the best of her knowledge:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of IPALCO.

Date:    February 26, 2024/s/ Sherry Kohan

                    Sherry Kohan

                    Interim Vice President and Chief Financial Officer 

A signed original of this written statement required by Section 906 has been provided to IPALCO and will be retained by IPALCO and furnished to the SEC or its staff upon request. 

XML

Cover Document $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) shares
Entity Information [Line Items]
Entity Central Index Key	0000728391
Entity Filer Category	Non-accelerated Filer
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity Registrant Name	IPALCO ENTERPRISES, INC.
Entity Incorporation, State or Country Code	IN
Entity File Number	1-8644
Entity Tax Identification Number	35-1575582
Entity Address, Address Line One	One Monument Circle
Entity Address, City or Town	Indianapolis
Entity Address, State or Province	IN
Entity Address, Postal Zip Code	46204
City Area Code	317
Local Phone Number	261-8261
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	108,907,318
Document Fiscal Year Focus	2023
Document Fiscal Period Focus (i.e. Q1,Q2,Q3,FY)	FY
Amendment Flag	false
Entity Public Float | $	$ 0.0
ICFR Auditor Attestation Flag	false
ICFR Auditor Attestation Flag	false
Document Type	10-K
Document Period End Date	Dec. 31, 2023
AES U.S. Investments [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding	89,685,177
CDPQ [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding	19,222,141

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor [Line Items]
Auditor Name	Ernst & Young LLP
Auditor Firm ID	42
Auditor Location	Indianapolis, Indiana

XML

Consolidated Statements Of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132
OPERATING COSTS AND EXPENSES:
Fuel	494,000	568,676	255,817
Utilities Operating Expense, Purchased Power	159,908	199,860	175,025
Utilities Operating Expense, Maintenance and Operations	477,880	493,674	449,746
Depreciation and amortization	287,863	266,504	256,085
Taxes other than income taxes	24,864	33,048	44,419
Other Operating Income (Expense), Net	(361)	3,201	5,630
Operating Expenses	1,444,154	1,558,561	1,175,462
Operating Income (Loss)	205,763	233,150	250,670
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction	9,315	4,784	5,412
Interest Expense	(142,926)	(131,232)	(125,626)
Other (expense) / income, net	(410)	11,783	17,667
Total other expense, net	(134,021)	(114,665)	(102,547)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	71,742	118,485	148,123
Income tax expense	14,715	21,859	28,941
NET INCOME	57,027	96,626	119,182
Dividends on and redemption of preferred stock	0	3,509	3,213
NET INCOME ATTRIBUTABLE TO COMMON STOCK	83,120	93,117	115,969
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest	(26,093)	0	0
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Indianapolis Power And Light Company
REVENUE	1,649,917	1,791,711	1,426,132
OPERATING COSTS AND EXPENSES:
Fuel	494,000	568,676	255,817
Utilities Operating Expense, Purchased Power	159,908	199,860	175,025
Utilities Operating Expense, Maintenance and Operations	477,497	493,454	449,317
Depreciation and amortization	287,863	266,504	256,085
Taxes other than income taxes	24,865	33,048	44,419
Other Operating Income (Expense), Net	(361)	(3,201)	(5,630)
Operating Expenses	1,443,772	1,558,341	1,175,033
Operating Income (Loss)	206,145	233,370	251,099
OTHER (EXPENSE) / INCOME, NET:
Allowance for equity funds used during construction	9,315	4,784	5,412
Interest Expense	(99,051)	(87,428)	(84,257)
Other (expense) / income, net	(646)	12,136	17,294
Total other expense, net	(90,382)	(70,508)	(61,551)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	115,763	162,862	189,548
Income tax expense	25,666	32,887	39,305
NET INCOME	90,097	129,975	150,243
Dividends on and redemption of preferred stock	0	3,509	3,213
NET INCOME ATTRIBUTABLE TO COMMON STOCK	116,190	126,466	147,030
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Electricity [Member]
REVENUE	1,649,917	1,791,711	1,426,132
Electricity [Member] | Indianapolis Power And Light Company
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
CURRENT ASSETS:
Cash and cash equivalents	$ 28,579	$ 201,548
Restricted Cash and Cash Equivalents	5	5
Accounts Receivable, after Allowance for Credit Loss, Current	233,921	216,523
Inventory, Net	143,590	123,608
Regulatory assets	89,419	119,723
Income Taxes Receivable, Current	36,481	18,000
Derivative Asset, Current	15,682	7,545
Other Assets, Current	26,358	19,882
Total current assets	574,030	706,829
NON-CURRENT ASSETS:
Property, plant and equipment	7,082,443	6,982,314
Less: Accumulated depreciation	2,954,555	3,243,968
	4,127,888	3,738,346
Construction work in progress	359,014	294,985
Property, Plant and Equipment, Net	4,486,902	4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net	235,656	138,978
Regulatory assets, non-current	541,784	593,939
Assets for Plan Benefits, Defined Benefit Plan	41,172	33,611
Derivative Asset, Noncurrent	0	12,172
Other non-current assets	301,979	70,354
Total other non-current assets	1,120,591	849,054
TOTAL ASSETS	6,181,523	5,589,214
CURRENT LIABILITIES:
Short-term debt	899,159	0
Accounts payable	292,851	189,845
Accrued taxes	22,580	22,474
Accrued interest	33,639	33,447
Customer deposits	29,308	35,097
Regulatory liabilities	23,371	23,348
Accrued and other current liabilities	27,547	19,014
Total current liabilities	1,328,455	323,225
Long-term Debt and Lease Obligation	2,576,798	3,016,810
Deferred Income Tax Liabilities, Net	361,488	312,641
NON-CURRENT LIABILITIES:
Regulatory liabilities	527,224	612,585
Accrued other postretirement benefits	2,776	3,085
Asset retirement obligations	249,930	218,729
Other non-current liabilities	5,130	11,621
Total non-current liabilities	3,723,346	4,175,471
Liabilities	$ 5,051,801	$ 4,498,696
Common Stock, Shares Authorized	290,000,000
Common Stock, Shares, Outstanding	108,907,318	108,907,000
Common shareholders' equity:
Additional Paid in Capital	$ 1,021,992	$ 1,068,357
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294	22,269
Accumulated deficit	25,182	(108)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,129,722	1,090,518
Equity, Attributable to Noncontrolling Interest	53,254	0
Total common shareholders' equity	1,076,468	1,090,518
TOTAL LIABILITIES AND EQUITY	6,181,523	5,589,214
Accounts receivable and unbilled revenue, allowance for doubtful accounts	2,283	1,117
Indianapolis Power And Light Company
CURRENT ASSETS:
Cash and cash equivalents	25,767	199,103
Restricted Cash and Cash Equivalents	5	5
Accounts Receivable, after Allowance for Credit Loss, Current	233,970	216,572
Inventory, Net	143,590	123,608
Regulatory assets	89,419	119,723
Income Taxes Receivable, Current	5,140	6,682
Other Assets, Current	27,741	27,422
Total current assets	525,627	693,110
NON-CURRENT ASSETS:
Property, plant and equipment	7,082,443	6,982,314
Less: Accumulated depreciation	2,954,555	3,243,968
	4,127,888	3,738,346
Construction work in progress	359,014	294,985
Property, Plant and Equipment, Net	4,486,902	4,033,331
OTHER NON-CURRENT ASSETS:
Intangible assets - net	235,656	138,978
Regulatory assets, non-current	541,784	593,939
Assets for Plan Benefits, Defined Benefit Plan	41,172	33,611
Other non-current assets	298,439	67,008
Total other non-current assets	1,117,051	833,536
TOTAL ASSETS	6,129,580	5,559,977
CURRENT LIABILITIES:
Short-term debt	494,685	0
Accounts payable	292,835	189,806
Accrued taxes	22,580	22,474
Accrued interest	25,245	25,054
Customer deposits	29,308	35,097
Regulatory liabilities	23,371	23,348
Accrued and other current liabilities	34,748	26,214
Total current liabilities	922,772	321,993
Long-term Debt and Lease Obligation	2,106,146	2,143,147
Deferred Income Tax Liabilities, Net	342,557	305,107
NON-CURRENT LIABILITIES:
Regulatory liabilities	527,224	612,585
Accrued other postretirement benefits	2,776	3,085
Asset retirement obligations	249,930	218,729
Other non-current liabilities	5,129	11,621
Total non-current liabilities	3,233,762	3,294,274
Liabilities	$ 4,156,534	$ 3,616,267
Common Stock, Shares Authorized	20,000,000
Common Stock, Shares, Outstanding	17,206,630	17,207,000
Common shareholders' equity:
Common Stock, Value, Issued	$ 324,537	$ 324,537
Additional Paid in Capital	1,193,199	1,193,107
Accumulated deficit	402,056	426,066
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,973,046	1,943,710
Equity, Attributable to Noncontrolling Interest	53,254	0
Total common shareholders' equity	1,919,792	1,943,710
TOTAL LIABILITIES AND EQUITY	6,129,580	5,559,977
Accounts receivable and unbilled revenue, allowance for doubtful accounts	$ 2,283	$ 1,117

XML

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 57,027,000	$ 96,626,000	$ 119,182,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	287,863,000	266,504,000	256,085,000
Amortization of deferred financing costs and debt discounts	3,880,000	3,914,000	3,915,000
Deferred income taxes and investment tax credit adjustments - net	32,653,000	(6,706,000)	(7,378,000)
Allowance for equity funds used during construction	(9,315,000)	(4,784,000)	(5,412,000)
Cash Acquired from Acquisition	0	0	(5,630,000)
Change in certain assets and liabilities:
Accounts receivable	(17,398,000)	(37,387,000)	(13,943,000)
Inventories	(30,171,000)	(47,489,000)	(12,017,000)
Prepayments and other current assets	(6,476,000)	19,056,000	(4,593,000)
Accounts payable	(46,993,000)	(32,038,000)	(21,417,000)
Accrued and other current liabilities	2,790,000	6,532,000	(13,017,000)
Accrued taxes payable/receivable	(18,375,000)	(5,858,000)	638,000
Accrued interest	192,000	2,813,000	(1,099,000)
Pension and other postretirement benefit assets and liabilities	1,625,000	(8,727,000)	(16,592,000)
Current and non-current regulatory assets and liabilities	54,358,000	38,863,000	(104,759,000)
Other non-current liabilities	(9,445,000)	(14,384,000)	10,446,000
Other - net	(4,268,000)	5,335,000	(2,026,000)
Net Cash Provided by (Used in) Operating Activities	391,933,000	346,346,000	225,217,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(902,705,000)	(496,510,000)	(291,510,000)
Project development costs	(4,462,000)	(3,910,000)	(1,304,000)
Cost of removal payments	(45,595,000)	(23,948,000)	(35,260,000)
Proceeds from Insurance Settlement, Investing Activities	4,900,000	0	0
Purchase of intangibles	(44,650,000)	0	(26,261,000)
Other	(361,000)	(719,000)	(14,380,000)
Net cash used in investing activities	(992,873,000)	(525,087,000)	(368,715,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities	435,000,000	300,000,000	320,000,000
Repayments from revolving credit facilities	280,000,000	360,000,000	335,000,000
Short-term borrowings	300,000,000	200,000,000	0
Repayments of short-term borrowings	0	(200,000,000)	0
Long-term borrowings	0	350,000,000	95,000,000
Retirement of long-term borrowings, including early payment premium	0	0	(95,000,000)
Distributions to shareholders	(104,287,000)	(101,986,000)	(131,476,000)
Equity contributions from shareholders	0	253,000,000	275,000,000
Proceeds from (Payments to) Noncontrolling Interests	77,921,000	0	0
Redemption of preferred stock	0	(60,080,000)	0
Preferred dividends of subsidiary	0	(3,213,000)	(3,213,000)
Contributions from shareholders		253,000,000	275,000,000
Payments of deferred financing costs and discounts	(350,000)	(4,309,000)	(1,387,000)
Other	(313,000)	(35,000)	(131,000)
Net cash provided by financing activities	427,971,000	373,377,000	123,793,000
Net change in cash, cash equivalents and restricted cash	(172,969,000)	194,636,000	(19,705,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	28,584,000	201,553,000	6,917,000
Cash and Cash Equivalents, at Carrying Value	28,579,000	201,548,000
Cash paid during the period for:
Interest (net of amount capitalized)	129,113,000	115,277,000	118,052,000
Income taxes	0	31,000,000	27,500,000
Non-cash investing activities:
Accruals for capital expenditures	124,626,000	66,949,000	81,325,000
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	983,000	(3,402,000)	19,763,000
Change in Right-of-Use Asset Lease Liability	(1,408,000)	(3,402,000)	19,763,000
Indianapolis Power And Light Company
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	90,097,000	129,975,000	150,243,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	287,863,000	266,504,000	256,085,000
Amortization of deferred financing costs and debt discounts	2,406,000	2,511,000	2,536,000
Deferred income taxes and investment tax credit adjustments - net	23,582,000	(6,584,000)	(7,373,000)
Allowance for equity funds used during construction	(9,315,000)	(4,784,000)	(5,412,000)
Cash Acquired from Acquisition	0	0	(5,630,000)
Change in certain assets and liabilities:
Accounts receivable	(17,398,000)	(37,391,000)	(13,746,000)
Inventories	(30,171,000)	(47,489,000)	(12,017,000)
Prepayments and other current assets	(6,476,000)	19,016,000	(4,556,000)
Accounts payable	(47,016,000)	(32,232,000)	(21,502,000)
Accrued and other current liabilities	2,790,000	6,532,000	(13,017,000)
Accrued taxes payable/receivable	1,647,000	(3,452,000)	(2,302,000)
Accrued interest	192,000	2,813,000	(1,099,000)
Pension and other postretirement benefit assets and liabilities	1,625,000	(8,727,000)	(16,592,000)
Current and non-current regulatory assets and liabilities	54,358,000	38,863,000	(104,759,000)
Other non-current liabilities	(16,663,000)	(21,717,000)	5,566,000
Other - net	(4,074,000)	4,967,000	(1,645,000)
Net Cash Provided by (Used in) Operating Activities	427,479,000	373,269,000	247,784,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(902,705,000)	(496,510,000)	(291,510,000)
Project development costs	(4,462,000)	(3,910,000)	(1,304,000)
Cost of removal payments	(45,595,000)	(23,948,000)	(35,260,000)
Proceeds from Insurance Settlement, Investing Activities	4,900,000	0	0
Loan repayments from parents	0	0	6,110,000
Purchase of intangibles	44,650,000	0	26,261,000
Other	(361,000)	(719,000)	(14,380,000)
Net cash used in investing activities	(992,873,000)	(525,087,000)	(362,605,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from revolving credit facilities	435,000,000	300,000,000	320,000,000
Repayments from revolving credit facilities	280,000,000	360,000,000	335,000,000
Short-term borrowings	300,000,000	200,000,000	0
Repayments of short-term borrowings	0	200,000,000	0
Long-term borrowings	0	350,000,000	95,000,000
Retirement of long-term borrowings, including early payment premium	0	0	(95,000,000)
Distributions to shareholders	(140,200,000)	(127,200,000)	(155,700,000)
Proceeds from (Payments to) Noncontrolling Interests	77,921,000	0	0
Redemption of preferred stock	0	60,080,000	0
Preferred dividends of subsidiary	0	(3,213,000)	(3,213,000)
Contributions from shareholders	0	253,000,000	275,000,000
Payments of deferred financing costs and discounts	(350,000)	(4,309,000)	(1,325,000)
Other	(313,000)	(33,000)	(131,000)
Net cash provided by financing activities	392,058,000	348,165,000	99,631,000
Net change in cash, cash equivalents and restricted cash	(173,336,000)	196,347,000	(15,190,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	25,772,000	199,108,000	2,761,000
Cash and Cash Equivalents, at Carrying Value	25,767,000	199,103,000
Cash paid during the period for:
Interest (net of amount capitalized)	93,544,000	80,104,000	82,880,000
Income taxes	0	39,500,000	40,800,000
Non-cash investing activities:
Accruals for capital expenditures	124,626,000	66,949,000	81,325,000
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	983,000	(3,402,000)	19,763,000
Change in Right-of-Use Asset Lease Liability	$ (1,408,000)	$ (3,402,000)	$ 19,763,000

XML

Consolidated Statements Of Common Shareholders' Equity (Deficit) And Noncontrolling Interest - USD ($) $ in Thousands	Total	Corporate Stocks - Common [Member]	Paid In Capital [Member]	AOCI Attributable to Parent [Member]	Accumulated Deficit [Member]	Cumulative Preferred Stock Of Subsidiary [Member]	Indianapolis Power And Light Company	Indianapolis Power And Light Company Corporate Stocks - Common [Member]	Indianapolis Power And Light Company Paid In Capital [Member]	Indianapolis Power And Light Company Accumulated Deficit [Member]	Indianapolis Power And Light Company Cumulative Preferred Stock Of Subsidiary [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Outstanding	108,907,000						17,207,000
Stockholders' Equity Attributable to Parent	$ 520,988	$ 0	$ 588,966	$ (43,420)	$ (24,558)		$ 1,424,893	$ 324,537	$ 664,886	$ 435,470
Equity, Attributable to Noncontrolling Interest						$ 59,784
Other Comprehensive Income (Loss), Net of Tax	14,013			14,013	0
Net income / (loss)	115,969				119,182		147,030
Preferred Stock Dividends, Income Statement Impact	3,213						3,213				$ 3,213
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	(3,213)				(3,213)	(3,213)	(3,213)				(3,213)
Distributions to AES	(131,476)				(115,969)
Contributions from shareholders	275,000		275,000				275,000		275,000
Beginning Balance at Dec. 31, 2020											59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Partners' Capital Account, Return of Capital			(15,507)
Net income	119,182						150,243			150,243
Dividends, Preferred Stock										3,213
Return of Capital			(15,500)
Cash dividends declared on common stock							(155,700)			(155,700)
Equity contributions from shareholders	275,000
Other	106		106				$ 107		107
Ending Balance at Dec. 31, 2021											59,784
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 119,182
Common Stock, Shares, Outstanding	108,907,000						17,207,000
Stockholders' Equity Attributable to Parent	$ 794,600		848,565	(29,407)	(24,558)		$ 1,691,330	324,537	939,993	426,800
Equity, Attributable to Noncontrolling Interest						59,784
Other Comprehensive Income (Loss), Net of Tax	51,676			51,676	0
Net income / (loss)	93,117				96,626		126,466
Preferred Stock Dividends, Income Statement Impact	3,509						3,509				3,213
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	(3,213)				(3,213)	(3,213)	(3,213)				(3,213)
Distributions to AES	(101,986)				(68,667)
Contributions from shareholders	253,000		253,000				253,000		253,000
Partners' Capital Account, Return of Capital			(33,319)
Net income	96,626						129,975			129,975
Dividends, Preferred Stock	3,213									3,213
Stock Redeemed or Called During Period, Value	(296)				(296)	(59,784)	(296)			(296)	(59,784)
Return of Capital			(33,300)
Cash dividends declared on common stock							(127,200)			(127,200)
Equity contributions from shareholders	253,000
Other	111		111				114		114
Ending Balance at Dec. 31, 2022	1,090,518						$ 1,943,710				0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 96,626
Common Stock, Shares, Outstanding	108,907,000						17,207,000
Stockholders' Equity Attributable to Parent	$ 1,090,518		1,068,357	22,269	(108)		$ 1,943,710	324,537	1,193,107	426,066
Equity, Attributable to Noncontrolling Interest	0					0	0
Other Comprehensive Income (Loss), Net of Tax	7,025			7,025	0
Net income / (loss)	83,120				83,120		116,190
Preferred Stock Dividends, Income Statement Impact	0						0				0
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	0						0
Distributions to AES	(104,287)				(57,830)
Contributions from shareholders							0		0
Partners' Capital Account, Return of Capital			(46,457)
Net income	57,027						90,097
Dividends, Preferred Stock	0						3,200
Return of Capital			(46,500)
Cash dividends declared on common stock							(140,200)			(140,200)
Proceeds from Noncontrolling Interests	79,347						79,347
Equity contributions from shareholders	0
Other	92		92				92		92
Ending Balance at Dec. 31, 2023	1,129,722						1,973,046				$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent							116,190			116,190
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)						$ (26,093)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	$ 83,120
Common Stock, Shares, Outstanding	108,907,318						17,206,630
Stockholders' Equity Attributable to Parent	$ 1,076,468		$ 1,021,992	$ 29,294	$ 25,182		$ 1,919,792	$ 324,537	$ 1,193,199	$ 402,056
Equity, Attributable to Noncontrolling Interest	$ 53,254					$ 0	$ 53,254

XML

Consolidated Statements of Comprehensive Income Statement - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Net Income (Loss) Available to Common Stockholders, Basic	$ 83,120	$ 93,117	$ 115,969
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528)	(15,309)	(3,441)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594	46,245	10,393
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,798)	(1,199)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), before Tax	64,052	148,302	133,195
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest	(26,093)	0	0
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	$ 5,431	$ 3,620
Net Income (Loss) Attributable to Noncontrolling Interest	$ (26,093)

XML

Overview and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Overview and Summary of Significant Accounting Policies

OVERVIEW AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPALCO is a holding company incorporated under the laws of the state of Indiana. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments (82.35%) and CDPQ (17.65%). AES U.S. Investments is owned by AES U.S. Holdings, LLC (85%) and CDPQ (15%). IPALCO owns all of the outstanding common stock of IPL, which does business as AES Indiana. Substantially all of IPALCO’s business consists of generating, transmitting, distributing and selling of electric energy conducted through its principal subsidiary, AES Indiana. AES Indiana was incorporated under the laws of the state of Indiana in 1926. AES Indiana has approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.

AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation - 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.

In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.

In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.

For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."

IPALCO’s other direct subsidiary is Mid-America. Mid-America is the holding company for IPALCO’s unregulated activities, which have not been material to the financial statements in the periods covered by this report. IPALCO’s regulated business is conducted through AES Indiana. IPALCO has two business segments: utility and nonutility. The utility segment consists of the operations of AES Indiana and everything else is included in the nonutility segment.

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on

allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. IPALCO uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by IPALCO. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	28,579	$	201,548
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	28,584	$	201,553

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,178		239
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,921	$	216,523

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk

characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

Inventories

We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Regulatory Accounting

The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
AFUDC equity	$	9,315	$	4,784	$	5,412
AFUDC debt	$	13,739	$	8,215	$	4,815

Impairment of Long-lived Assets

GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:

			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	8		$	261,872	$	205,910
Project development intangible assets	28		84,097		39,455
Other	Various		797		797
Less: Accumulated amortization			(111,110)		(107,184)
Intangible assets - net			$	235,656	$	138,978
	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	14,570	$	10,122	$	11,241
Estimated future amortization
Years ending December 31,
2024					$	20,764
2025					20,764
2026					22,550
2027					22,550
2028					22,550
Total					$	109,178

Implementation Costs Related to Software as a Service

IPALCO has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.

Contingencies

IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If IPALCO’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Additionally, we use interest rate hedges to manage the interest rate risk associated with refinancing our long-term debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in the fair value being recorded within accumulated other comprehensive income, a component of shareholders' equity. We have elected not to offset net derivative positions in the Financial Statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 5, “Derivative Instruments and Hedging Activities” for additional information.

Leases

The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.

Accumulated Other Comprehensive Income / (Loss)

The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):

Details about AOCI / (AOCL) components	Affected line item in the Consolidated Statements of Operations	For the Years Ended December 31,
		2023		2022		2021
Net losses on cash flow hedges (Note 5):	Interest expense	$	7,229	$	7,229	$	4,819
	Income tax effect	(1,798)		(1,798)		(1,199)
Total reclassifications for the period, net of income taxes		$	5,431	$	5,431	$	3,620

See Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information on the changes in the components of AOCL.

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Operating Expenses – Other, Net

Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition.

Pension and Postretirement Benefits

We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at

fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities, which are included in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

IPALCO and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.

New Accounting Pronouncements

We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on the Company's Financial Statements.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the Company's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on the Company's Financial Statements.

ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative	In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.	The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.	We will provide the required disclosures on a prospective basis on the date each amendment becomes effective. We do not expect ASU 2023-06 will have any impact to our consolidated financial statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures	The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.	The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures	The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.	The amendments in this Update are effective for fiscal years beginning after December 15, 2024.	We are currently evaluating the impact of adopting the standard on our consolidated financial statements.

Indianapolis Power And Light Company

Entity Information [Line Items]

Overview and Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

IPL, which does business as AES Indiana, was incorporated under the laws of the state of Indiana in 1926. All of the outstanding common stock of AES Indiana is owned by IPALCO. IPALCO, acquired by AES in March 2001, is owned by AES U.S. Investments and CDPQ. AES U.S. Investments is owned by AES (85%) and CDPQ (15%). AES Indiana is engaged primarily in generating, transmitting, distributing and selling of electric energy to approximately 523,000 retail customers in the city of Indianapolis and neighboring cities, towns and communities, and adjacent rural areas all within the state of Indiana. AES Indiana has an exclusive right to provide electric service to those customers.

AES Indiana owns and operates four generating stations all within the state of Indiana. The first station, Petersburg, is coal-fired, and AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023, which resulted in 630 MW of total retired economic capacity at this station. AES Indiana plans to convert the remaining two coal units at Petersburg to natural gas (for further discussion, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation 2022 IRP"). The second station, Harding Street, consists of three natural gas-fired boilers and steam turbines and uses natural gas and fuel oil to power five combustion turbines. In addition, AES Indiana operates a 20 MW battery energy storage unit at this location, which provides frequency response. The third station, Eagle Valley, is a CCGT natural gas plant. The fourth station, Georgetown, is a peaking station that uses natural gas to power combustion turbines. As of December 31, 2023, AES Indiana’s net electric generation capacity for winter is 3,070 MW and net summer capacity is 2,925 MW.

In December 2021, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Hardy Hills Solar Energy LLC, including the development of a 195 MW solar project (the "Hardy Hills Solar Project"). In December 2023, the first stage of construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. The final stage for construction of the project is expected to be completed during the first half of 2024.

In August 2023, AES Indiana, through a wholly-owned subsidiary, completed the acquisition of Petersburg Energy Center, LLC, including the development of a 250 MW solar and 45 MW (180 MWh) energy storage facility (the "Petersburg Energy Center Project"). The Petersburg Energy Center Project is expected to be completed in 2025.

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana, subject to IURC approval, which was received in January 2024. The Pike County BESS Project is expected to be completed in 2024.

For further discussion about AES Indiana's plans for wind, solar, and battery energy storage projects, please see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation."

Principles of Consolidation

AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which

consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Reclassifications

Certain immaterial amounts from prior periods have been reclassified to conform to the current year presentation.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	25,767	$	199,103
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	25,772	$	199,108

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,227		288
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,970	$	216,572

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

Inventories

AES Indiana maintains coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Regulatory Accounting

The retail utility operations of AES Indiana are subject to the jurisdiction of the IURC. AES Indiana’s wholesale power transactions are subject to the jurisdiction of the FERC. These agencies regulate AES Indiana’s utility business operations, tariffs, accounting, depreciation allowances, services, issuances of securities and the sale and acquisition of utility properties. The financial statements of AES Indiana are based on GAAP, including the provisions of FASB ASC 980 “Regulated Operations,” which gives recognition to the ratemaking and accounting practices of these agencies. See also Note 2, “Regulatory Matters - Regulatory Assets and Liabilities” for a discussion of specific regulatory assets and liabilities.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
AFUDC equity	$	9,315	$	4,784	$	5,412
AFUDC debt	$	13,739	$	8,215	$	4,815

Impairment of Long-lived Assets

GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to

current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:

			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	8		$	261,872	$	205,910
Project development intangible assets	28		84,097		39,455
Other	Various		797		797
Less: Accumulated amortization			(111,110)		(107,184)
Intangible assets - net			$	235,656	$	138,978
	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	14,570	$	10,122	$	11,241
Estimated future amortization
Years ending December 31,
2024					$	20,764
2025					20,764
2026					22,550
2027					22,550
2028					22,550
Total					$	109,178

Implementation Costs Related to Software as a Service

AES Indiana has recorded prepayments for implementation costs related to software as a service in support of utility customer services of $7.1 million and $8.2 million as of December 31, 2023 and 2022, respectively, which are recorded within "Other non-current assets" on the accompanying Consolidated Balance Sheets.

Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and presented as a direct reduction from the face amount of that debt and amortized over the related financing period using the effective interest method. Debt issuance costs related to a line-of-credit or revolving credit facility are deferred and presented as an asset and amortized over the related financing period. Make-whole payments in connection with early debt retirements are classified as cash flows from financing activities.

Contingencies

AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been

the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Leases

The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. AES Indiana’s provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated

Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, AES Indiana is one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Operating Expenses – Other, Net

Operating expenses – Other, net generally includes gains or losses on asset sales, dispositions or acquisitions, gains or losses on the sale or acquisition of businesses, and other expense or income from miscellaneous operating transactions. For the year ended December 31, 2022, the $3.2 million is primarily due to a gain on remeasurement of contingent consideration associated with the Hardy Hills Solar Project acquisition. For the year ended December 31, 2021, the $5.6 million represents a gain on acquisition.

Pension and Postretirement Benefits

AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. AES Indiana establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. AES Indiana’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. AES Indiana’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities which are included in allowable costs for ratemaking purposes in future years are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

AES Indiana files U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.

New Accounting Pronouncements

We have assessed and determined that the new accounting pronouncements adopted did not have a material impact on AES Indiana's Financial Statements.

New Accounting Pronouncements Issued But Not Yet Effective

The following table provides a brief description of recent accounting pronouncements that could have a material impact on the AES Indiana's Financial Statements once adopted. Accounting pronouncements not listed below were assessed and determined to be either not applicable or are expected to have no material impact on AES Indiana's Financial Statements.

ASU Number and Name	Description	Date of Adoption	Effect on the Financial Statements upon adoption
2023-06 Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative	In U.S. Securities and Exchange Commission (SEC) Release No. 33-10532, Disclosure Update and Simplification, issued August 17, 2018, the SEC referred certain of its disclosure requirements that overlap with, but require incremental information to, generally accepted accounting principles (GAAP) to the FASB for potential incorporation into the Codification. The amendments in this Update are the result of the Board’s decision to incorporate into the Codification 14 of the 27 disclosures referred by the SEC. The amendments in this Update represent changes to clarify or improve disclosure and presentation requirements of a variety of Topics. Many of the amendments allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the SEC’s requirements. Also, the amendments align the requirements in the Codification with the SEC’s regulations.	The effective date for each amendment will be the date on which the SEC's removal of that related disclosure becomes effective, with early adoption prohibited. The amendments in this Update should be applied prospectively.	AES Indiana will provide the required disclosures on a prospective basis on the date each amendment becomes effective. AES Indiana does not expect ASU 2023-06 will have any impact to its Financial Statements.
2023-07 Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures	The amendments in this section are designed to improve the disclosures related to Segment reporting on an interim and annual basis. Public companies must disclose significant segment expenses and an amount for other segment items. This will also require that a company disclose its annual disclosures under Topic 280 in each interim period. Furthermore, companies will need to disclose the Chief Operating Decision Maker (CODM) and how the CODM assesses the performance of a segment. Lastly, public companies that have a single reportable segment must report the required disclosures under topic 280.	The amendments in this Update are effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted.	AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.
2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures	The amendments in this Update require that public business entities on an annual basis (1) disclose specific categories in the rate reconciliation and (2) provide additional information for reconciling items that meet a quantitative threshold. Furthermore, companies are required to disclose a disaggregated amount of income taxes paid at a federal, state, and foreign level as well as a break down of income taxes paid in a jurisdiction that comprises 5% of a company's total income taxes paid. Lastly, this ASU requires that companies disclose income (loss) from continuing operations before income tax at a domestic and foreign level and that companies disclose income tax expense from continuing operations on a federal, state, and foreign level.	The amendments in this Update are effective for fiscal years beginning after December 15, 2024.	AES Indiana is currently evaluating the impact of adopting the standard on its Financial Statements.

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Regulatory Matters

12 Months Ended

Dec. 31, 2023

Indianapolis Power And Light Company

Entity Information [Line Items]

Regulatory Assets and Liabilities

. REGULATORY MATTERS

General

AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.

Basic Rates and Charges

AES Indiana’s basic rates and charges represent the largest component of its annual revenue. AES Indiana’s basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

AES Indiana’s declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.

Regulatory Rate Review and Base Rate Orders

AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.

FAC and Authorized Annual Jurisdictional Net Operating Income

AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each

FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.

In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.

ECCRA 

AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million.

DSM

Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively.

On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

AES Indiana is currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). AES Indiana is also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, AES Indiana has 94.5 MW of solar-generated electricity in its service territory under long-term contracts

(these long-term contracts have expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. AES Indiana has authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.

TDSIC

In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue.

On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million, The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million.

IRP Filings and Replacement Generation

Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.

2022 IRP

AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.

In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

2019 IRP

In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.

AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. AES Indiana's modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023.

AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.

Hardy Hills Solar Project

In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.

On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.

On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of

$79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.

Petersburg Energy Center Project

In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).

Pike County BESS Project

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.

Hoosier Wind Project

On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.

Incentives for Clean Energy Projects

Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.

IURC COVID-19 Orders

Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and

2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.

EDG Rates

On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.

EV Portfolio Program

On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.

House Bill 1002

In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on AES Indiana's net income.

Regulatory Assets and Liabilities

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:

	2023		2022		Recovery Period
	(In Thousands)
Regulatory assets, current:
Undercollections of rate riders	$	75,416	$	26,047	Approximately 1 year(1)
Fuel costs	—		79,861		Approximately 1 year(1)
Unamortized reacquisition premium on debt	188		—		Approximately 1 year
Costs being recovered through basic rates and charges	13,815		13,815		Approximately 1 year(1)
Total regulatory assets, current	89,419		119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs	115,847		131,907		Various(2)
Deferred MISO costs	21,091		34,483		Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	2,812		3,866		Through 2026(1)(3)
Unamortized reacquisition premium on debt	13,379		14,429		Over remaining life of debt
Environmental costs	66,837		68,947		Through 2046(1)(3)
COVID-19 costs	5,426		5,426		4 years(4)
Major storm damage	1,493		—		To be determined
TDSIC costs	35,979		18,547		36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs	259,892		287,463		Through 2034(1)(3)
Hardy Hills Solar Project development costs	6,774		5,744		30 years(3)
Petersburg Energy Center Project development costs	2,469		1,582		30 years(3)
Pike County BESS Project development costs	2,623		—		20 years(3)
Fuel costs	4,275		20,518		Through 2025(1)
Other miscellaneous	2,887		1,027		Various(5)
Total regulatory assets, non-current	541,784		593,939
Total regulatory assets	$	631,203	$	713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders	$	19,649	$	15,803	Approximately 1 year(1)
FTRs	3,722		7,545		Approximately 1 year(1)
Total regulatory liabilities, current	23,371		23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs	451,886		518,797		Not applicable
Deferred income taxes payable to customers through rates	74,796		88,662		Various
Hardy Hills sponsor investment tax credit	542		—		To be determined(6)
Major storm damage	—		5,126		To be determined
Total regulatory liabilities, non-current	527,224		612,585
Total regulatory liabilities	$	550,595	$	635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

Current Regulatory Assets and Liabilities

Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.

Deferred Fuel

Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs. 

The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.

Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs

These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.

Unamortized Reacquisition Premium on Debt

This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.

Environmental Costs

These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years.

COVID-19 Costs

These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.

TDSIC Costs

These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from 1 to 36 years. See "TDSIC" above for additional discussion.

Petersburg Unit 1 and 2 Retirement Costs

These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.

Hardy Hills Solar Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Petersburg Energy Center Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Pike County BESS Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.

ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, AES Indiana has a net regulatory deferred income tax liability of $74.8 million and $88.7 million as of December 31, 2023 and 2022, respectively.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2023

Dec. 31, 2019

Entity Information [Line Items]

Utility Plant In Service

The original cost of property, plant and equipment segregated by functional classifications follows:

	As of December 31,
	2023		2022
	(In Thousands)
Production	$	3,942,052	$	4,164,416
Transmission	487,527		461,245
Distribution	2,304,526		2,045,579
General plant	348,338		311,074
Total property, plant and equipment	$	7,082,443	$	6,982,314

As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).

Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information.

ARO

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel. 

AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances:

	2023		2022
	(In Thousands)
Balance as of January 1	$	218,729	$	189,509
Liabilities incurred	17,080		1,159
Liabilities settled	(11,902)		(24,699)
Revisions to cash flow and timing estimates	12,921		44,679
Accretion expense	13,102		8,081
Balance as of December 31	$	249,930	$	218,729

ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.

Indianapolis Power And Light Company

Entity Information [Line Items]

Utility Plant In Service

. PROPERTY, PLANT AND EQUIPMENT

The original cost of property, plant and equipment segregated by functional classifications follows:

	As of December 31,
	2023		2022
	(In Thousands)
Production	$	3,942,052	$	4,164,416
Transmission	487,527		461,245
Distribution	2,304,526		2,045,579
General plant	348,338		311,074
Total property, plant and equipment	$	7,082,443	$	6,982,314

As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of net property, plant and equipment associated with the Petersburg Unit 1 and Unit 2 retirements recorded as long-term regulatory assets (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation”).

Substantially all of AES Indiana’s property is subject to a $2,153.8 million direct first mortgage lien, as of December 31, 2023, securing AES Indiana’s first mortgage bonds. Total non-contractually or legally required accrued removal costs of utility plant in service at December 31, 2023 and 2022 were $680.9 million and $694.0 million, respectively; and total contractually or legally required removal costs of property, plant and equipment at December 31, 2023 and 2022 were $249.9 million and $218.7 million, respectively. Please see “ARO” below for further information.

ARO

ASC 410 “Asset Retirement and Environmental Obligations” addresses financial accounting and reporting for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation. A legal obligation for purposes of ASC 410 is an obligation that a party is required to settle as a result of an existing law, statute, ordinance, written or oral contract or the doctrine of promissory estoppel.

AES Indiana’s ARO relates primarily to environmental issues involving asbestos-containing materials, ash ponds, landfills and miscellaneous contaminants associated with its generating plants, transmission system and distribution system. The following is a roll forward of the ARO legal liability year end balances:

	2023		2022
	(In Thousands)
Balance as of January 1	$	218,729	$	189,509
Liabilities incurred	17,080		1,159
Liabilities settled	(11,902)		(24,699)
Revisions to cash flow and timing estimates	12,921		44,679
Accretion expense	13,102		8,081
Balance as of December 31	$	249,930	$	218,729

ARO liabilities incurred in 2023 and 2022 primarily relate to FGD residual water disposal and AES Indiana's solar projects. AES Indiana recorded revisions to its ARO liabilities in 2023 and 2022 primarily to reflect revisions to cash flow estimates and timing due to increases to estimated ash pond closure costs and changes to expected landfill closure dates. As of December 31, 2023 and 2022, AES Indiana did not have any assets that are legally restricted for settling its ARO liability.

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Fair Value

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Fair Value

FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Financial Assets

VEBA Assets

IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Consolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other (expense) / income, net" on the accompanying Consolidated Statements of Operations and were not material to the consolidated financial statements in the periods covered by this report.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on our Consolidated Statements of Operations.

Forward Power Contracts

As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.

Interest Rate Hedges

IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 5, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.

Recurring Fair Value Measurements

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	127	$	—	$	—	$	127	$	5	$	—	$	—	$	5
Mutual funds	3,425		—		—		3,425		3,223		—		—		3,223
Total VEBA investments	3,552		—		—		3,552		3,228		—		—		3,228
FTRs	—		—		1,388		1,388		—		—		7,545		7,545
Interest rate hedges	—		14,294		—		14,294		—		12,172		—		12,172
Total financial assets measured at fair value	$	3,552	$	14,294	$	1,388	$	19,234	$	3,228	$	12,172	$	7,545	$	22,945

The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	1,235
Issuances	15,338
Settlements	(9,028)
Balance at December 31, 2022	7,545
Issuances	3,624
Settlements	(9,781)
Balance at December 31, 2023	$	1,388

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	3,033,800	$	2,860,467	$	3,033,800	$	2,775,644
Variable-rate	455,000		455,000		—		—
Total indebtedness	$	3,488,800	$	3,315,467	$	3,033,800	$	2,775,644

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $24.8 million and $26.3 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $6.8 million and $7.1 million at December 31, 2023 and 2022, respectively.

Indianapolis Power And Light Company

Entity Information [Line Items]

Fair Value

FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of AES Indiana’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defines and establishes a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, AES Indiana has categorized its financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of AES Indiana’s financial instruments. AES Indiana’s financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that AES Indiana could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Financial Assets

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. FTRs are used in the MISO market to hedge AES Indiana’s exposure to congestion charges, which result from constraints on the transmission system. AES Indiana’s FTRs are valued at the cleared auction prices for FTRs in MISO’s annual auction. Because of the infrequent nature of this valuation, the fair value assigned to the FTRs is considered a Level 3 input under the fair value hierarchy required by ASC 820. An offsetting regulatory liability has been recorded as these revenue or costs will be flowed through to customers through the FAC. As such, there is no impact on AES Indiana’s Consolidated Statements of Operations.

Forward Power Contracts

As of December 31, 2023 and 2022, all outstanding forward power contracts had settled and there was no notional amount outstanding. All changes in the market value of the forward power contracts were recorded in the Consolidated Statements of Operations in the period in which the change occurred. See also Note 5, "Derivative Instruments and Hedging Activities - Derivatives Not Designated as Hedge" for further information.

Recurring Fair Value Measurements

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
FTRs	$	—	$	—	$	1,388	$	1,388	$	—	$	—	$	7,545	$	7,545
Total financial assets measured at fair value	$	—	$	—	$	1,388	$	1,388	$	—	$	—	$	7,545	$	7,545

The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	1,235
Issuances	15,338
Settlements	(9,028)
Balance at December 31, 2022	7,545
Issuances	3,624
Settlements	(9,781)
Balance at December 31, 2023	$	1,388

Financial Instruments not Measured at Fair Value in the Consolidated Balance Sheets

Debt

The fair value of AES Indiana’s outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: 

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	2,153,800	$	2,020,997	$	2,153,800	$	1,959,233
Variable-rate	455,000		455,000		—		—
Total indebtedness	$	2,608,800	$	2,475,997	$	2,153,800	$	1,959,233

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $20.2 million and $20.4 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $6.4 million and $6.7 million at December 31, 2023 and 2022, respectively.

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2023

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt and the risk of price changes for purchased power. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)		Sales (in thousands)		Net Notional (in thousands)
Interest rate hedges	Designated	USD	$	400,000	$	—	$	400,000
FTRs	Not Designated	MWh	3,919		—		3,919

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.

In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment is being amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.

The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:

	Interest Rate Hedges for the Years Ended December 31,
$ in thousands (net of tax)	2023		2022		2021
Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)	$	22,269	$	(29,407)	$	(43,420)
Net gains associated with current period hedging transactions	1,594		46,245		10,393
Net losses reclassified to interest expense	5,431		5,431		3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)	$	29,294	$	22,269	$	(29,407)
Loss expected to be reclassified to earnings in the next twelve months	$	(5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9

Derivatives Not Designated as Hedge

AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when

acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.

When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments (in thousands):

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
FTRs	Not a Cash Flow Hedge	Derivative assets, current	$	1,388	$	7,545
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	14,294	$	—
Interest rate hedges	Cash Flow Hedge	Derivative assets, non-current	$	—	$	12,172

Subsidiaries [Member]

Derivative [Line Items]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

AES Indiana uses derivatives principally to manage the risk of price changes for purchased power. The derivatives that AES Indiana uses to economically hedge this risk is governed by our risk management policies for forward and futures contracts. AES Indiana's net positions are continually assessed within its structured hedging programs to determine whether new or offsetting transactions are required. AES Indiana monitors and values derivative positions monthly as part of its risk management processes. AES Indiana uses published sources for pricing, when possible, to mark positions to market. All of AES Indiana's derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)	Sales (in thousands)	Net Notional (in thousands)
FTRs	Not Designated	MWh	3,919	—	3,919

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Derivatives Not Designated as Hedge

AES Indiana's FTRs and forward power contracts do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value using the income approach when acquired and subsequently amortized over the annual period as they are used. The forward power contracts are recorded at fair value using the market approach with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. This is commonly referred to as "MTM accounting." Realized gains and losses on the forward power contracts are included in future FAC filings, therefore any realized and unrealized gains and losses are deferred as regulatory liabilities or regulatory assets. There were net realized gains of $0.0 million and $1.3 million related to forward power contracts during the years ended December 31, 2023 and 2022, respectively, related to the forward power contracts that were deferred and included with deferred fuel costs in "Regulatory assets, current" on the accompanying Consolidated Balance Sheets.

Certain qualifying derivative instruments have been designated as normal purchases or normal sales contracts, as provided under GAAP. Derivative contracts that have been designated as normal purchases or normal sales under GAAP are not subject to hedge or MTM accounting and are recognized in the Consolidated Statements of Operations on an accrual basis.

When applicable, AES Indiana has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, AES Indiana did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of AES Indiana's derivative instruments (in thousands):

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
FTRs	Not a Cash Flow Hedge	Prepayments and other current assets	$	1,388	$	7,545

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Debt

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Debt

DEBT

The following table presents our long-term debt:

		December 31,
Series	Due	2023		2022
		(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)	December 2024	$	40,000	$	40,000
0.65% (1)	August 2025	40,000		40,000
0.75% (2)	April 2026	30,000		30,000
0.95% (2)	April 2026	60,000		60,000
1.40% (1)	August 2029	55,000		55,000
5.65%	December 2032	350,000		350,000
6.60%	January 2034	100,000		100,000
6.05%	October 2036	158,800		158,800
6.60%	June 2037	165,000		165,000
4.875%	November 2041	140,000		140,000
4.65%	June 2043	170,000		170,000
4.50%	June 2044	130,000		130,000
4.70%	September 2045	260,000		260,000
4.05%	May 2046	350,000		350,000
4.875%	November 2048	105,000		105,000
Unamortized discount – net		(6,449)		(6,651)
Deferred financing costs		(19,058)		(20,362)
Total AES Indiana first mortgage bonds		2,128,293		2,126,787
Total long-term debt – AES Indiana		2,128,293		2,126,787
Long-term debt – IPALCO:
3.70% Senior Secured Notes	September 2024	405,000		405,000
4.25% Senior Secured Notes	May 2030	475,000		475,000
Unamortized discount – net		(319)		(425)
Deferred financing costs		(4,554)		(5,912)
Total long-term debt – IPALCO		875,127		873,663
Total consolidated IPALCO long-term debt		3,003,420		3,000,450
Less: current portion of long-term debt		445,000		—
Net consolidated IPALCO long-term debt		$	2,558,420	$	3,000,450

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

Line of Credit

AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31,

2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:

Year	Amount
	(In Thousands)
2024	$	445,000
2025	40,000
2026	90,000
2027	—
2028	—
Thereafter	2,458,800
	3,033,800
Unamortized discounts	(6,768)
Deferred financing costs, net	(23,612)
Total long-term debt	$	3,003,420

Significant Transactions

AES Indiana Term Loans

In November 2023, AES Indiana entered into an unsecured $300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt.

In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.

AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes.

In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par.

IPALCO’s Senior Secured Notes and Term Loan

The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.

Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

Restrictions on Issuance of Debt 

All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.

The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.

Credit Ratings

Our ability to borrow money or to refinance existing indebtedness and the interest rates at which we can borrow money or refinance existing indebtedness are affected by our credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES could result in AES Indiana’s and/or IPALCO’s credit ratings being downgraded.

Indianapolis Power And Light Company

Entity Information [Line Items]

Debt

. DEBT

The following table presents AES Indiana’s long-term debt:

		December 31,
Series	Due	2023		2022
		(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)	December 2024	$	40,000	$	40,000
0.65% (1)	August 2025	40,000		40,000
0.75% (2)	April 2026	30,000		30,000
0.95% (2)	April 2026	60,000		60,000
1.40% (1)	August 2029	55,000		55,000
5.650%	December 2032	350,000		350,000
6.60%	January 2034	100,000		100,000
6.05%	October 2036	158,800		158,800
6.60%	June 2037	165,000		165,000
4.875%	November 2041	140,000		140,000
4.65%	June 2043	170,000		170,000
4.50%	June 2044	130,000		130,000
4.70%	September 2045	260,000		260,000
4.05%	May 2046	350,000		350,000
4.875%	November 2048	105,000		105,000
Unamortized discount – net		(6,449)		(6,651)
Deferred financing costs		(19,058)		(20,362)
Total AES Indiana first mortgage bonds		2,128,293		2,126,787
Total consolidated AES Indiana long-term debt		2,128,293		2,126,787
Less: current portion of long-term debt		40,000		—
Net consolidated AES Indiana long-term debt		$	2,088,293	$	2,126,787

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

Line of Credit

AES Indiana entered into a second amendment and restatement of its $350 million revolving Credit Agreement on December 22, 2022 with a syndication of bank lenders. This Credit Agreement is an unsecured committed line of credit to be used: (i) to finance capital expenditures; (ii) to refinance certain existing indebtedness, (iii) to support working capital; and (iv) for general corporate purposes. This agreement matures on December 22, 2027, and bears interest at variable rates as described in the Credit Agreement. It includes an uncommitted $150 million accordion feature to provide AES Indiana with an option to request an increase in the size of the facility at any time prior to December 22, 2026, subject to approval by the lenders. The Credit Agreement also includes two one-year extension options, allowing AES Indiana to extend the maturity date subject to approval by the lenders. As of December 31, 2023 and 2022, AES Indiana had $155.0 million and $0.0 million in outstanding borrowings on the committed Credit Agreement, respectively.

Debt Maturities

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:

Year	Amount
	(In Thousands)
2024	$	40,000
2025	40,000
2026	90,000
2027	—
2028	—
Thereafter	1,983,800
	2,153,800
Unamortized discounts	(6,449)
Deferred financing costs, net	(19,058)
Total long-term debt	$	2,128,293

Significant Transactions

AES Indiana Term Loans

In November 2023, AES Indiana entered into an unsecured$300 million 364-day term loan agreement ("$300 million Term Loan Agreement"). The $300 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement matures on November 19, 2024, and bears interest at variable rates as described in the $300 million Term Loan Agreement. The $300 million Term Loan Agreement contains customary representations, warranties and covenants, including a leverage covenant consistent with the leverage covenant contained in AES Indiana's Credit Agreement. AES Indiana has classified this $300 million Term Loan Agreement as short-term indebtedness as it matures November 2024. Although current liquid funds are not sufficient to repay the amount due at maturity, management plans to refinance this $300 million Term Loan Agreement with new long-term debt.

In June 2022, AES Indiana entered into an unsecured $200 million 364-day term loan agreement ("$200 million Term Loan Agreement"). The $200 million Term Loan Agreement was fully drawn at closing with the proceeds being used for general corporate purposes. This agreement was set to mature on June 22, 2023, but was fully repaid in November 2022.

AES Indiana First Mortgage Bonds and Recent Indiana Finance Authority Bond Issuances

In November 2022, AES Indiana issued $350 million aggregate principal amount of first mortgage bonds, 5.65% Series, due December 2032, pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from this offering were approximately $345.6 million, after deducting the initial purchasers’ discounts and fees and expenses for the offering. The net proceeds from this offering were used to repay amounts due under the Credit Agreement and the $200 million Term Loan Agreement, and for general corporate purposes.

In July 2021, the Indiana Finance Authority issued at the request of AES Indiana an aggregate principal amount of $95 million of Environmental Facilities Refunding Revenue Bonds, Series 2021A&B. AES Indiana issued $95 million aggregate principal amount of first mortgage bonds to the Indiana Finance Authority in two series: $55 million Series 2021A bonds at an interest rate of 1.40% due August 1, 2029 and $40 million Series 2021B notes at an interest rate of 0.65% due August 1, 2025 to secure the loan of proceeds from these bonds issued by the Indiana Finance Authority. Proceeds of the bond offering were used to refund $95 million of Indiana Finance Authority Environmental Facilities Refunding Revenue Bonds Series 2011A&B at a redemption price of 100% of par.

Restrictions on Issuance of Debt

All of AES Indiana’s long-term borrowings must first be approved by the IURC and the aggregate amount of AES Indiana’s short-term indebtedness must be approved by the FERC. AES Indiana has approval from FERC to borrow up to $750 million of short-term indebtedness outstanding at any time through July 26, 2024. In November 2021, AES Indiana received an order from the IURC granting AES Indiana authority through December 31, 2024 to, among other things, issue up to $740 million in aggregate principal amount of long-term debt, of which $390 million remains available as of December 31, 2023. This order also grants AES Indiana authority to have up to $750 million of long-term credit agreements and liquidity facilities outstanding at any one time, of which $100.0 million remains available under the order as of December 31, 2023. As an alternative to the sale of all or a portion of $65 million in principal of the long-term debt mentioned above, we have authority to issue up to $65 million of new preferred stock, all of which authority remains available under the order as of December 31, 2023. AES Indiana also has restrictions on the amount of new debt that may be issued due to contractual obligations of AES and by financial covenant restrictions under our existing debt obligations. Under such restrictions, AES Indiana is generally allowed to fully draw the amounts available on its Credit Agreement, refinance existing debt and issue new debt approved by the IURC and issue certain other indebtedness. On September 29, 2023, AES Indiana filed a petition for approval of a financing program for the approximately three-year period ending December 31, 2026. The OUCC filed testimony on December 1, 2023 with certain recommended parameters for future debt issuances that AES Indiana accepted. A hearing was held January 10, 2024 and an agreed proposed order between AES Indiana and the OUCC was submitted on that date. AES Indiana awaits an IURC order in the matter and it remains pending.

The mortgage and deed of trust of AES Indiana, together with the supplemental indentures thereto, secure the first mortgage bonds issued by AES Indiana. Pursuant to the terms of the mortgage, substantially all property owned by AES Indiana is subject to a first mortgage lien securing indebtedness of $2,153.8 million as of December 31, 2023. The AES Indiana first mortgage bonds require net income as calculated thereunder be at least two and one-half times the annual interest requirements before additional bonds can be authenticated on the basis of property additions. AES Indiana was in compliance with such requirements as of December 31, 2023.

Credit Ratings

AES Indiana’s ability to borrow money or to refinance existing indebtedness and the interest rates at which AES Indiana can borrow money or refinance existing indebtedness are affected by AES Indiana’s credit ratings. In addition, the applicable interest rates on AES Indiana’s Credit Agreement are dependent upon the credit ratings of AES Indiana. Downgrades in the credit ratings of AES and/or IPALCO could result in AES Indiana’s credit ratings being downgraded.

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Income Taxes

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Income Taxes

INCOME TAXES

IPALCO follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if IPALCO and its subsidiaries each filed separate income tax returns. IPALCO is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. IPALCO made tax sharing payments to AES of $0.0 million, $31.0 million and $27.5 million in 2023, 2022 and 2021, respectively.

Income Tax Provision

Federal and state income taxes charged to income are as follows: 

	2023		2022		2021
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	(14,222)	$	22,539	$	28,100
State	(3,716)		6,026		8,218
Total current income taxes	(17,938)		28,565		36,318
Deferred income taxes:
Federal	24,885		(6,920)		(7,286)
State	7,768		214		(91)
Total deferred income taxes	32,653		(6,706)		(7,377)
Total income tax expense	$	14,715	$	21,859	$	28,941

Effective and Statutory Rate Reconciliation

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows: 

	2023		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
State income tax, net of federal tax benefit	3.9	%	3.9	%	4.0	%
Depreciation flow through and amortization	(12.9)	%	(7.8)	%	(6.3)	%
AFUDC - equity	(0.3)	%	0.9	%	0.4	%
Noncontrolling interests in subsidiaries	9.0	%	—	%	—	%
Other – net	(0.2)	%	0.4	%	0.4	%
Effective tax rate	20.5	%	18.4	%	19.5	%

Deferred Income Taxes

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:

	2023		2022
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	409,675	$	341,473
Regulatory assets recoverable through future rates	108,823		123,669
Other	17,694		17,953
Total deferred tax liabilities	536,192		483,095
Deferred tax assets:
Investment tax credit	5		6
Regulatory liabilities including ARO	168,619		167,725
Investments in tax partnerships	2,501		—
Other	3,579		2,723
Total deferred tax assets	174,704		170,454
Deferred income tax liability – net	$	361,488	$	312,641

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	—	$	—	$	7,368
Gross decreases – prior period tax positions	—		—		(7,368)
Unrecognized tax benefits at December 31	$	—	$	—	$	—

The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, IPALCO reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.

Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult to predict the final outcome or the timing of resolution of any particular uncertain tax position, we believe unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact our previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed our provision for current unrecognized tax benefits.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

Indianapolis Power And Light Company

Entity Information [Line Items]

Income Taxes

INCOME TAXES

AES Indiana follows a policy of comprehensive interperiod income tax allocation. Investment tax credits related to utility property have been deferred and are being amortized over the estimated useful lives of the related property.

AES files federal and state income tax returns which consolidate IPALCO and AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes as if AES Indiana filed separate income tax returns. AES Indiana is no longer subject to U.S. or state income tax examinations for tax years through 2016, but is open for all subsequent periods. AES Indiana made tax sharing payments to IPALCO of $0.0 million, $39.5 million and $40.8 million in 2023, 2022 and 2021, respectively.

Income Tax Provision

Federal and state income taxes charged to income are as follows:

	2023		2022		2021
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	1,816	$	31,286	$	36,353
State	268		8,185		10,325
Total current income taxes	2,084		39,471		46,678
Deferred income taxes:
Federal	17,631		(6,822)		(7,283)
State	5,951		238		(90)
Total deferred income taxes	23,582		(6,584)		(7,373)
Total income tax expense	$	25,666	$	32,887	$	39,305

Effective and Statutory Rate Reconciliation

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows:

	2023		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
State income tax, net of federal tax benefit	3.9	%	3.9	%	4.0	%
Depreciation flow through and amortization	(8.0)	%	(5.7)	%	(4.9)	%
AFUDC - equity	(0.2)	%	0.7	%	0.3	%
Noncontrolling interests in subsidiaries	5.6	%	—	%	—	%
Other – net	(0.1)	%	0.3	%	0.3	%
Effective tax rate	22.2	%	20.2	%	20.7	%

Deferred Income Taxes

The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 

	2023		2022
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	409,675	$	341,473
Regulatory assets recoverable through future rates	108,823		123,669
Other	7,975		22,717
Total deferred tax liabilities	526,473		487,859
Deferred tax assets:
Investment tax credit	5		6
Regulatory liabilities including ARO	168,619		167,726
Investments in tax partnerships	2,483		—
Operating loss carryforwards	9,230		—
Other	3,579		15,020
Total deferred tax assets	183,916		182,752
Deferred income tax liability – net	$	342,557	$	305,107

Uncertain Tax Positions

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:

	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	—	$	—	$	7,368
Gross decreases – prior period tax positions	—		—		(7,368)
Unrecognized tax benefits at December 31	$	—	$	—	$	—

The prior period unrecognized tax benefits represent tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. As a result of the resolution of federal and state audits in 2021, AES Indiana reviewed its uncertain positions and determined that they are more likely than not to be sustained upon examination by taxing authorities. Consequently, the uncertain tax positions were reversed; because of the impact of deferred tax accounting the reversal did not affect the annual effective tax rate but were reclassified to plant related deferred tax balances.

Tax years subsequent to 2016 remain open to examination by taxing authorities. While it is often difficult

to predict the final outcome or the timing of resolution of any particular uncertain tax position, AES Indiana believes

unrecognized tax benefits of $0 at December 31, 2023 and 2022, respectively, is the appropriate accrual for our uncertain tax positions. However, audit outcomes and the timing of audit settlements and future events that would impact AES Indiana's previously recorded unrecognized tax benefits are subject to significant uncertainty. It is possible that the ultimate outcome of future examinations may exceed AES Indiana's provision for current unrecognized tax benefits.

Tax-related interest expense and income is reported as part of the provision for federal and state income taxes. Penalties, if incurred, would also be recognized as a component of tax expense. There are no interest or penalties applicable to the periods contained in this report.

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Benefit Plans

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Benefit Plans

BENEFIT PLANS

Defined Contribution Plans

All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:

The Thrift Plan

Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively.

The RSP

Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively.

Defined Benefit Plans

Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants.

AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.

The following table presents information relating to the Pension Plans: 

	Pension benefits as of December 31,
	2023		2022
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	577,530	$	772,040
Service cost	5,189		8,949
Interest cost	29,818		18,099
Actuarial loss (gain)	9,681		(182,590)
Amendments (primarily increases in pension bands)	653		—
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Projected benefit obligation at December 31	549,546		577,529
Change in plan assets:
Fair value of plan assets at January 1	611,125		820,684
Actual return/(loss) on plan assets	52,905		(171,002)
Employer contributions	114		412
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Fair value of plan assets at December 31	590,819		611,125
Funded status	$	41,273	$	33,596
Amounts recognized in the statement of financial position:
Non-current assets	$	41,273	$	33,611
Non-current liabilities	—		(15)
Net amount recognized at end of year	$	41,273	$	33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	653	$	—
Net (gain)/loss arising during period	(10,117)		24,069
Amortization of prior service cost	(2,172)		(2,589)
Amortization of loss	(6,145)		(2,622)
Total recognized in regulatory assets	$	(17,781)	$	18,858
Amounts included in regulatory assets:
Net loss	$	115,297	$	131,559
Prior service cost	10,136		11,655
Total amounts included in regulatory assets	$	125,433	$	143,214

(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period

As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.

Pension Benefits and Expense

Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are

impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.

The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023.

	Pension benefits for years ended December 31,
	2023			2022			2021
	(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost	$	5,189		$	8,949		$	9,339
Interest cost	29,818			18,099			15,660
Expected return on plan assets	(33,107)			(35,656)			(41,815)
Amortization of prior service cost	2,172			2,589			2,944
Amortization of actuarial loss	6,145			2,424			5,529
Amortization of settlement loss	—			199			—
Net periodic benefit cost / (credit)	10,217			(3,396)			(8,343)
Less: amounts capitalized	1,689			(316)			(771)
Amount charged to expense	$	8,528		$	(3,080)		$	(7,572)
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	5.41		%	2.83		%	2.46		%
Discount rate – supplemental retirement plan	5.32		%	2.62		%	2.31		%
Expected return on defined benefit pension plan assets	5.60		%	4.45		%	5.05		%
Expected return on supplemental retirement plan assets	6.45		%	5.50		%	3.60		%

Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively.

In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.

The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing our expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data. 

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations.

The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a combination of historical analysis, current market environment assessment and by applying the consultant’s own

judgment. The consultant then determines an equilibrium long-term rate of return. We then take into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, we have the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. We use an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes the Company’s target pension plan allocation for 2023:

Asset Category:	Target Allocations
Equity Securities	13.5%
Debt Securities	86.5%

	Fair Value Measurements at
	December 31, 2023
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	82,652	$	2,267	$	80,385	14	%
Debt securities (b)	387,979		1,168		386,811		66	%
Government debt securities (c)	117,397		178		117,219		20	%
Total common collective trusts	588,028		3,613		584,415		100	%
Cash and cash equivalents (d)	2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

	Fair Value Measurements at
	December 31, 2022
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	85,341	$	2,017	$	83,324	14	%
Debt securities (b)	400,291		1,254		399,037		66	%
Government debt securities (c)	122,704		420		122,284		20	%
Total common collective trusts	608,336		3,691		604,645		100	%
Cash and cash equivalents (d)	2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

Pension Funding

We contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans’ underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. 

Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:

Year	Pension Benefits
	(In Thousands)
2024	$	37,997
2025	38,794
2026	39,665
2027	40,085
2028	41,477
2029 through 2033	200,574

Indianapolis Power And Light Company

Entity Information [Line Items]

Benefit Plans

BENEFIT PLANS

Defined Contribution Plans

All of AES Indiana’s employees are covered by one of two defined contribution plans, the Thrift Plan or the RSP:

The Thrift Plan

Approximately 77% of AES Indiana’s active employees are covered by the Thrift Plan, a qualified defined contribution plan. All union new hires are covered under the Thrift Plan. Participants elect to make contributions to the Thrift Plan based on a percentage of their base compensation. Each participant’s contribution is matched up to certain thresholds of base compensation. The IBEW clerical-technical union new hires receive an annual lump sum company contribution into the Thrift Plan in addition to the company match. Employer contributions to the Thrift Plan were $3.7 million, $3.6 million and $3.4 million for 2023, 2022 and 2021, respectively. 

The RSP

Approximately 23% of AES Indiana’s active employees are covered by the RSP, a qualified defined contribution plan containing both match and nondiscretionary components. All non-union new hires are covered under the RSP. Participants elect to make contributions to the RSP based on a percentage of their eligible compensation. Each participant’s contribution is matched in amounts up to, but not exceeding, 5% of the participant’s eligible compensation. Starting in 2018, the RSP also includes a 4% nondiscretionary contribution based as a percentage of each participant's eligible compensation. Employer contributions (by AES Indiana) relating to the RSP were $2.5 million, $2.1 million and $1.9 million for 2023, 2022 and 2021, respectively.

Defined Benefit Plans

Approximately 65% of AES Indiana’s active employees are covered by the qualified Defined Benefit Pension Plan; while approximately 12% of active employees are IBEW clerical-technical unit employees who are only eligible for the Thrift Plan. The remaining 23% of active employees are covered by the RSP. All non-union new hires are covered under the RSP, while IBEW physical unit union new hires are covered under the Defined Benefit Pension Plan and Thrift Plan. The IBEW clerical-technical unit new hires are no longer covered under the Defined Benefit Pension Plan but do receive an annual lump sum company contribution into the Thrift Plan, in addition to the company match. The Defined Benefit Pension Plan is noncontributory and is funded by AES Indiana through a trust. Benefits for non-union participants in the Defined Benefit Pension Plan are based on salary, years of service and accrued benefits at April 1, 2015. Benefits for eligible union participants are based on each individual employee's pension band and years of service as opposed to their compensation. Pension bands are based primarily on job duties and responsibilities.

Additionally, a small group of former officers and their surviving spouses are covered under a funded non-qualified Supplemental Retirement Plan. The total number of participants in the plan as of December 31, 2023 was 19. The plan is closed to new participants.

AES Indiana also provides postretirement health care benefits to certain active or retired employees and the spouses of certain active or retired employees. Approximately 123 active employees and 26 retirees (including spouses) were receiving such benefits or entitled to future benefits as of January 1, 2023. The plan is unfunded. These postretirement health care benefits and the related unfunded obligation of $3.0 million and $3.2 million at December 31, 2023 and 2022, respectively, were not material to the consolidated financial statements in the periods covered by this report.

The following table presents information relating to the Pension Plans:

	Pension benefits as of December 31,
	2023		2022
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	577,530	$	772,040
Service cost	5,189		8,949
Interest cost	29,818		18,099
Actuarial loss (gain)	9,681		(182,590)
Amendments (primarily increases in pension bands)	653		—
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Projected benefit obligation at December 31	549,546		577,529
Change in plan assets:
Fair value of plan assets at January 1	611,125		820,684
Actual return/(loss) on plan assets	52,905		(171,002)
Employer contributions	114		412
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Fair value of plan assets at December 31	590,819		611,125
Funded status	$	41,273	$	33,596
Amounts recognized in the statement of financial position:
Non-current assets	$	41,273	$	33,611
Non-current liabilities	—		(15)
Net amount recognized at end of year	$	41,273	$	33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	653	$	—
Net (gain)/loss arising during period	(10,117)		24,069
Amortization of prior service cost	(2,172)		(2,589)
Amortization of loss	(6,145)		(2,622)
Total recognized in regulatory assets	$	(17,781)	$	18,858
Amounts included in regulatory assets:
Net loss	$	115,297	$	131,559
Prior service cost	10,136		11,655
Total amounts included in regulatory assets	$	125,433	$	143,214

(1)Amounts that would otherwise be charged/credited to Accumulated Other Comprehensive Income or Loss upon application of ASC 715, “Compensation – Retirement Benefits,” are recorded as a regulatory asset or liability because AES Indiana has historically recovered and currently recovers pension and other postretirement benefit expenses in rates. These are unrecognized amounts not yet recognized as components of net periodic benefit costs.

Significant Loss / (Gain) Related to Changes in the Benefit Obligation for the Period

As shown in the table above, an actuarial loss of $9.7 million and an actuarial gain of $182.6 million for the year ended December 31, 2023 and December 31, 2022, respectively, were recognized in the benefit obligation, primarily due to changes in the discount rate.

Pension Benefits and Expense

Reported expenses relevant to the Defined Benefit Pension Plan are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience, including the performance of plan assets and actual benefits paid out in future years. Pension costs associated with the Defined Benefit Pension Plan are

impacted by the level of contributions made to the plan, income on plan assets, the adoption of new mortality tables, and employee demographics, including age, job responsibilities, salary and employment periods. Changes made to the provisions of the Defined Benefit Pension Plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the corporate bond discount rates, as well as, the adoption of a new mortality table used in determining the projected benefit obligation and pension costs.

The 2023 net actuarial gain of $10.1 million recognized in regulatory assets is comprised of two parts: (1) a $9.7 million pension liability actuarial loss primarily due to a decrease in the discount rate used to value pension liabilities; and (2) a $19.8 million pension asset actuarial gain primarily due to higher than expected return on assets. The unrecognized net loss of $115.3 million in the Pension Plans has accumulated over time primarily due to the long-term declining trend in corporate bond rates and the adoption of new mortality tables which have historically increased the expected benefit obligation due to the longer expected lives of plan participants. In 2023, the accumulated net loss decrease was primarily attributed to an annuity buyout involving a small portion of retirees, which was partially offset by factors such as a reduced discount rate utilized in valuing pension liabilities, along with the amortization of accumulated losses incurred during the year. The unrecognized net loss, to the extent that it exceeds 10% of the greater of the benefit obligation or the assets, will be amortized and included as a component of net periodic benefit cost in future years. The amortization period is approximately 11.66 years based on estimated demographic data as of December 31, 2023. The projected benefit obligation of $549.5 million less the fair value of assets of $590.8 million results in an overfunded status of $41.3 million at December 31, 2023.

	Pension benefits for years ended December 31,
	2023			2022			2021
	(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost	$	5,189		$	8,949		$	9,339
Interest cost	29,818			18,099			15,660
Expected return on plan assets	(33,107)			(35,656)			(41,815)
Amortization of prior service cost	2,172			2,589			2,944
Amortization of actuarial loss	6,145			2,424			5,529
Amortization of settlement loss	—			199			—
Net periodic benefit cost / (credit)	10,217			(3,396)			(8,343)
Less: amounts capitalized	1,689			(316)			(771)
Amount charged to expense	$	8,528		$	(3,080)		$	(7,572)
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	5.41		%	2.83		%	2.46		%
Discount rate – supplemental retirement plan	5.32		%	2.62		%	2.31		%
Expected return on defined benefit pension plan assets	5.60		%	4.45		%	5.05		%
Expected return on supplemental retirement plan assets	6.45		%	5.50		%	3.60		%

Pension expense / (income) for the following year is determined as of the December 31 measurement date based on the fair value of the Pension Plans’ assets, the expected long-term rate of return on plan assets, a mortality table assumption that reflects the life expectancy of plan participants, and a discount rate used to determine the projected benefit obligation. For 2023, pension expense / (income) was determined using an assumed long-term rate of return on plan assets of 5.60% for the Defined Benefit Pension Plan and 6.45% for the Supplemental Retirement Plan. As of the December 31, 2023 measurement date, AES Indiana decreased the discount rate from 5.41% to 5.15% for the Defined Benefit Pension Plan and increased the discount rate from 5.32% to 5.66% for the Supplemental Retirement Plan. The discount rate assumptions affect the pension expense / (income) determined for 2024. In addition, AES Indiana decreased the expected long-term rate of return on plan assets from 5.60% to 5.20% for the Defined Benefit Pension Plan and from 6.45% to 6.35% for the Supplemental Retirement Plan for 2024. The expected long-term rate of return assumptions affect the pension expense / (income) determined for 2024. The effect on 2024 total pension expense / (income) of a 25 basis point increase and decrease in the assumed discount rate is $(0.8) million and $0.8 million, respectively.

In determining the discount rate to use for valuing liabilities, we use the market yield curve on high-quality fixed income investments as of December 31, 2023. We project the expected benefit payments under the plan based on participant data and based on certain assumptions concerning mortality, retirement rates, termination rates, etc. The expected benefit payments for each year are discounted back to the measurement date using the appropriate spot rate for each half-year from the yield curve, thereby obtaining a present value of all expected future benefit payments using the yield curve. Finally, an equivalent single discount rate is determined which produces a present value equal to the present value determined using the full yield curve.

Pension Plan Assets and Fair Value Measurements

Pension plan assets consist of investments in cash and cash equivalents, government debt securities, and mutual funds (equity and debt). Differences between actual portfolio returns and expected returns may result in increased or reduced pension costs in future periods. Pension costs for 2024 are determined as of the plans' measurement date of December 31, 2023. Pension costs are determined for the following year based on the market value of pension plan assets, expected employer contributions, a discount rate used to determine the projected benefit obligation and the expected long-term rate of return on plan assets.

Fair value is defined under ASC 820 as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Purchases and sales of securities are recorded on a trade-date basis. Interest income is recorded as earned. Dividends are recorded on the ex-dividend date. Net appreciation includes the Pension Plans’ gains and losses on investments bought and sold, as well as held, during the year.

A description of the valuation methodologies used for each major class of assets and liabilities measured at fair value follows:

•The non-qualified Supplemental Retirement Plan investments have quoted market prices and are categorized as Level 1 in the fair value hierarchy.

•The qualified Defined Benefit Pension Plan investments in common collective trusts are valued based on the daily net asset value and are categorized as Level 2 in the fair value hierarchy, except for cash and cash equivalents which are categorized as level 1.

The primary objective of the Pension Plans’ is to provide a source of retirement income for its participants and beneficiaries, while the primary financial objective is to improve the funded status of the Pension Plans. A secondary financial objective is, where possible, to minimize pension expense volatility. The objective is based on a long-term investment horizon, so that interim fluctuations should be viewed with appropriate perspective. There can be no assurance that these objectives will be met.

In establishing AES Indiana’s expected long-term rate of return assumption, we utilize a methodology developed by the plan’s investment consultant who maintains a capital market assumption model that takes into consideration risk, return and correlation assumptions across asset classes. A combination of quantitative analysis of historical data and qualitative judgment is used to capture trends, structural changes and potential scenarios not reflected in historical data. 

The result of the analyses is a series of inputs that produce a picture of how the plan consultant believes portfolios are likely to behave through time. Capital market assumptions are intended to reflect the behavior of asset classes observed over several market cycles. Stress assumptions are also examined, since the characteristics of asset classes are constantly changing. A dynamic model is employed to manage the numerous assumptions required to estimate portfolio characteristics under different base currencies, time horizons and inflation expectations. 

The Pension Plans’ consultant develops forward-looking, long-term capital market assumptions for risk, return and correlations for a variety of global asset classes, interest rates and inflation. These assumptions are created using a

combination of historical analysis, current market environment assessment and by applying the consultant’s own judgment. The consultant then determines an equilibrium long-term rate of return. AES Indiana then takes into consideration the investment manager/consultant expenses, as well as any other expenses expected to be paid out of the Pension Plans’ trust. Finally, AES Indiana has the Pension Plans’ actuary perform a tolerance test of the consultant’s equilibrium expected long-term rate of return. AES Indiana uses an expected long-term rate of return compatible with the actuary’s tolerance level.

The following table summarizes AES Indiana’s target pension plan allocation for 2023: 

Asset Category:	Target Allocations
Equity Securities	13.5%
Debt Securities	86.5%

	Fair Value Measurements at
	December 31, 2023
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	82,652	$	2,267	$	80,385	14	%
Debt securities (b)	387,979		1,168		386,811		66	%
Government debt securities (c)	117,397		178		117,219		20	%
Total common collective trusts	588,028		3,613		584,415		100	%
Cash and cash equivalents (d)	2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

	Fair Value Measurements at
	December 31, 2022
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	85,341	$	2,017	$	83,324	14	%
Debt securities (b)	400,291		1,254		399,037		66	%
Government debt securities (c)	122,704		420		122,284		20	%
Total common collective trusts	608,336		3,691		604,645		100	%
Cash and cash equivalents (d)	2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

Pension Funding

AES Indiana contributed $0.1 million, $0.4 million, and $0.0 million to the Pension Plans in 2023, 2022 and 2021, respectively. Funding for the qualified Defined Benefit Pension Plan is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under ERISA, as amended by the Pension Protection Act of 2006, as well as targeted funding levels necessary to meet certain thresholds.

From an ERISA funding perspective, AES Indiana’s funded target liability percentage was estimated to be 98%. In general, AES Indiana must contribute the normal service cost earned by active participants during the plan year; however, this amount can be offset by any surplus or credit balance carried by the Pension Plan. The normal cost is expected to be approximately $6.3 million in 2024 (including $0.4 million for plan expenses), which is expected to be fully offset by the surplus amount. Each year thereafter, if the Pension Plans' underfunding increases to more than the present value of the remaining annual installments, the excess is separately amortized over a seven-year period. AES Indiana does not expect to make an employer contribution for the calendar year 2024. AES Indiana’s funding policy for the Pension Plans is to contribute annually no less than the minimum required by applicable law, and no more than the maximum amount that can be deducted for federal income tax purposes. 

Benefit payments made from the Pension Plans for the years ended December 31, 2023, 2022 and 2021 were $73.3 million, $38.6 million and $63.2 million, respectively. Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows: 

Year	Pension Benefits
	(In Thousands)
2024	$	37,997
2025	38,794
2026	39,665
2027	40,085
2028	41,477
2029 through 2033	200,574

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Equity

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Equity

EQUITY AND CUMULATIVE PREFERRED STOCK

Cumulative Preferred Stock

On December 30, 2022 (the “Redemption Date”), AES Indiana redeemed all of its issued and outstanding preferred stock for $60.1 million On the Redemption Date, the Preferred Stock of each series was redeemed with all applicable premiums, plus, in each case an amount equal to all accrued dividends payable with respect to such Preferred Stock to the Redemption Date. Dividends on the Preferred Stock ceased to accrue on the Redemption Date. Upon redemption, the Preferred Stock was no longer outstanding, and all rights of the holders thereof as shareholders of AES Indiana ceased to exist, except for the right to payment of the redemption price. AES Indiana recorded a charge of $0.3 million on the redemption for the difference between the carrying value and redemption value of the preferred shares.

Prior to the redemption, AES Indiana had five separate series of cumulative preferred stock. Holders of the preferred stock were entitled to receive dividends at rates per annum ranging from 4.0% to 5.65%. During the years ended December 31, 2023, 2022 and 2021, total preferred stock dividends declared were $0.0 million, $3.2 million, and $3.2 million, respectively. Holders of preferred stock were entitled to two votes per share for AES Indiana matters, and if four full quarterly dividends are in default on all shares of the preferred stock then outstanding, they were entitled to elect the smallest number of AES Indiana directors to constitute a majority of AES Indiana’s Board of Directors. Based on the preferred stockholders’ ability to elect a majority of AES Indiana’s Board of Directors in this circumstance, the redemption of the preferred shares was considered to be not solely within the control of the issuer and the preferred stock was considered temporary equity and presented in the mezzanine level of the audited consolidated balance sheets in accordance with the relevant accounting guidance for non-controlling interests and redeemable securities.

Paid In Capital

On December 12, 2022, AES U.S. Investments received equity capital contributions totaling $208.3 million, of which $177.0 million was contributed by AES U.S. Holdings, LLC and $31.3 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $253.0 million, of which $208.3 million was contributed by AES U.S. Investments and $44.7 million was contributed by CDPQ.

On December 13, 2021, AES U.S. Investments received equity capital contributions totaling $226.5 million, of which $192.5 million was contributed by AES U.S. Holdings, LLC and $34.0 million was contributed by CDPQ. IPALCO then received equity capital contributions totaling $275.0 million, of which $226.5 million was contributed by AES U.S. Investments and $48.5 million was contributed by CDPQ.

IPALCO then made the same investments in AES Indiana in 2021 and 2022. The proceeds are intended primarily for funding needs related to AES Indiana’s TDSIC and replacement generation projects. The capital contributions were made on a proportional share basis and, therefore, did not change CDPQ’s or AES’ ownership interests in IPALCO or AES U.S. Investments.

Dividend Restrictions

AES Indiana’s mortgage and deed of trust and its amended articles of incorporation contain restrictions on AES Indiana’s ability to issue certain securities or pay cash dividends. So long as any of the several series of bonds of AES Indiana issued under its mortgage remains outstanding, and subject to certain exceptions, AES Indiana is restricted in the declaration and payment of dividends, or other distribution on shares of its capital stock of any class, or in the purchase or redemption of such shares, to the aggregate of its net income, as defined in the mortgage, after December 31, 1939. In addition, pursuant to AES Indiana’s articles, no dividends may be paid or accrued, and no other distribution may be made on AES Indiana’s common stock unless dividends on all outstanding shares of AES Indiana preferred stock have been paid or declared and set apart for payment. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with these restrictions. Additionally, all of AES Indiana's preferred stock was redeemed on December 30, 2022 (see "Cumulative Preferred Stock" above for further details).

AES Indiana is also restricted in its ability to pay dividends if it is in default under the terms of its Credit Agreement and $300 million Term Loan Agreement, which could happen if AES Indiana fails to comply with certain covenants. These covenants, among other things, require AES Indiana to maintain a ratio of total debt to total capitalization not in excess of 0.67 to 1. As of December 31, 2023, and as of the filing of this report, AES Indiana was in compliance with all covenants and no event of default existed.

IPALCO’s Third Amended and Restated Articles of Incorporation contain provisions which state that IPALCO may not make a distribution to its shareholders or make a loan to any of its affiliates (other than its subsidiaries), unless: (a) there exists no event of default (as defined in the articles) and no such event of default would result from the making of the distribution or loan; and either (b)(i) at the time of, and/or as a result of, the distribution or loan, IPALCO’s leverage ratio does not exceed 0.67 to 1 and IPALCO’s interest coverage ratio is not less than 2.50 to 1 or, (b)(ii) if such ratios are not within the parameters, IPALCO’s senior long-term debt rating from one of the three major credit rating agencies is at least investment grade. As of December 31, 2023, and as of the filing of this report, IPALCO was in compliance with all covenants and no event of default existed.

During the years ended December 31, 2023, 2022 and 2021, IPALCO declared and paid distributions to its shareholders totaling $104.3 million, $102.0 million and $131.5 million, respectively.

Equity Transactions with Noncontrolling Interests

The Hardy Hills Solar Project has been financed with a tax equity structure, in which a tax equity investor receives a portion of the economic attributes of the facility, including tax attributes, that vary over the life of the project. On December 1, 2023, the Class B Member and the Class A Member, entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of $79.3 million through December 31, 2023. A noncontrolling interest was recorded by AES Indiana at the amount of cash contributed by the Class A Member.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:

	Payments due in:
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation	$	933.5	$	249.7	$	267.3	$	225.7	$	190.8
Other	$	409.1	$	355.0	$	32.8	$	20.2	$	1.1

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.

Purchase orders and other contractual obligations:

At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies (see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.

Contingencies

Legal Matters

IPALCO and AES Indiana are involved in litigation arising in the normal course of business. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on IPALCO’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.

Coal Ash Insurance Litigation

In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.

Environmental Matters

We are subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of our employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. We cannot assure that we have been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

NSR and other CAA NOVs

In October 2009, AES Indiana received a NOV and Finding of Violation from the EPA pursuant to the CAA Section 113(a). The NOV alleged violations of the CAA at AES Indiana’s three primarily coal-fired electric generating facilities at the time, dating back to 1986. The alleged violations primarily pertain to the PSD and non-attainment NSR requirements under the CAA. In addition, on October 1, 2015, AES Indiana received a NOV from the EPA pursuant to CAA Section 113(a) alleging violations of the CAA, the Indiana SIP, and the Title V operating permit related to alleged particulate matter and opacity violations at AES Indiana Petersburg Unit 3. Also, on February 5, 2016, the EPA issued a NOV pursuant to CAA Section 113(a) alleging violations of PSD, non-attainment NSR and other CAA regulations, the Indiana SIP, and the Title V operating permit at Petersburg Generating Station. On August 31, 2020, AES Indiana reached a settlement with the EPA, the DOJ and IDEM resolving the purported violations of the CAA with respect to the coal-fired generation units at AES Indiana's Petersburg location. The settlement agreement, in the form of a proposed judicial consent decree was approved and entered by the U.S. District Court for the Southern District of Indiana on March 23, 2021, and includes, among other items, the following requirements: annual caps on NOx and SO2 emissions and more stringent emissions limits than AES Indiana's prior Title V air permit; payment of civil penalties totaling $1.525 million (the payment of which was satisfied by AES Indiana in April 2021); a $5 million environmental mitigation project consisting of the construction and operation of a new, non-emitting source of generation at the site; expenditure of $0.325 million on a state-only environmentally beneficial project to preserve local, ecologically-significant lands; and retirement of Units 1 and 2 prior to July 1, 2023 (which has occurred). AES Indiana previously had a contingent liability recorded related to these NSR and other CAA NOV matters.

Indianapolis Power And Light Company

Entity Information [Line Items]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Contractual Obligations and Commercial Commitments

We enter into various contractual obligations and other commercial commitments that may affect the liquidity of our operations. At December 31, 2023, these include:

	Payments due in:
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation	$	933.5	$	249.7	$	267.3	$	225.7	$	190.8
Other	$	409.1	$	355.0	$	32.8	$	20.2	$	1.1

Purchase obligations:

Purchase commitments for coal, gas, purchased power and related transportation:

AES Indiana enters into long-term contracts for the purchase of coal, gas, purchased power and related transportation. In general, these contracts are subject to variable quantities or prices and are terminable only in limited circumstances.

Purchase orders and other contractual obligations:

At December 31, 2023, we had various other contractual obligations including contracts to purchase goods and services with various terms and expiration dates, as well as obligations under long-term construction contracts. Due to uncertainty regarding the timing and payment of future obligations to the Service Company, and our ability to terminate such obligations upon 90 days' notice, we have excluded such amounts in the contractual obligations table above. This table also does not include (i) regulatory liabilities (see Note 2, "Regulatory Matters"), (ii) derivatives (see Note 5, "Derivative Instruments and Hedging Activities"), (iii) taxes (see Note 7, "Income Taxes"), (iv) pension and other postretirement employee benefit liabilities (see Note 8, "Benefit Plans") and (v) contingencies

(see Note 10, "Commitments and Contingencies"). See the indicated notes to the Financial Statements for additional information on the items excluded.

Contingencies

Legal Matters

AES Indiana is involved in litigation arising in the normal course of business. AES Indiana accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. While the ultimate outcome of outstanding litigation cannot be predicted with certainty, management believes that final outcomes will not have a material adverse effect on AES Indiana’s results of operations, financial condition and cash flows. Accruals for legal loss contingencies were not material as of December 31, 2023 and 2022.

Coal Ash Insurance Litigation

In August 2021, AES Indiana filed a civil action against various third-party insurance providers. The complaint seeks damages for breach of contract and a declaratory judgment declaring that such insurers must defend and indemnify AES Indiana under liability insurance policies issued between 1950 and the filing of the civil action against certain environmental liabilities arising from CCR at Harding Street, Petersburg and Eagle Valley. At this time, we cannot predict the outcome of this matter.

Environmental Matters

AES Indiana is subject to various federal, state, regional and local environmental protection and health and safety laws and regulations governing, among other things, the generation, storage, handling, use, disposal and transportation of regulated materials, including ash; the use and discharge of water used in generation boilers and for cooling purposes; the emission and discharge of hazardous and other materials, including GHGs, into the environment; climate change; and the health and safety of AES Indiana's employees. These laws and regulations often require a lengthy and complex process of obtaining and renewing permits and other governmental authorizations from federal, state and local agencies. Violation of these laws, regulations or permits can result in substantial fines, other sanctions, permit revocation and/or facility shutdowns. AES Indiana cannot assure that it has been or will be at all times in full compliance with such laws, regulations and permits. Accruals for environmental contingencies were not material as of December 31, 2023 and 2022.

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Related Party Transactions

RELATED PARTY TRANSACTIONS

AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including IPALCO, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, we had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets. 

AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and

is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. We had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively.

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries. Under a tax sharing agreement with AES, IPALCO is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. IPALCO had a receivable balance under this agreement of $36.5 million and $18.0 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.

Long-term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on IPALCO’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

See also Note 8, “Benefit Plans” to the Financial Statements for a description of benefits awarded to AES Indiana employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of IPALCO were $73.8 million, $60.3 million and $58.4 million during 2023, 2022 and 2021, respectively. Total costs incurred by IPALCO on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses - Operation and maintenance” on IPALCO’s Consolidated Statements of Operations. IPALCO had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.

Other

In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

Indianapolis Power And Light Company

Entity Information [Line Items]

Related Party Transactions

RELATED PARTY TRANSACTIONS

AES Indiana participates in a property insurance program in which AES Indiana buys insurance from AES Global Insurance Company, a wholly-owned subsidiary of AES. AES Indiana is not self-insured on property insurance, but does take a $5 million per occurrence deductible. Except for AES Indiana’s large substations, AES Indiana does not carry insurance on transmission and distribution assets, which are considered to be outside the scope of property insurance. AES and other AES subsidiaries, including AES Indiana, also participate in the AES global insurance program. AES Indiana pays premiums for a policy that is written and administered by a third-party insurance company. The premiums paid to this third-party administrator by the participants are paid to AES Global Insurance Company and all claims are paid from a trust fund funded by and owned by AES Global Insurance Company, but controlled by the third-party administrator. AES Indiana also has third-party insurance in which the premiums are paid directly to the third-party insurers. The cost to AES Indiana of coverage under the property insurance program with AES Global Insurance Company was approximately $11.7 million, $9.5 million, and $7.0 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. As of December 31, 2023 and 2022, AES Indiana had prepaid approximately $7.5 million and $3.4 million, respectively, for coverage under these plans, which is recorded in "Prepayments and other current assets" on the accompanying Consolidated Balance Sheets. 

AES Indiana participates in an agreement with Health and Welfare Benefit Plans LLC, an affiliate of AES, to participate in a group benefits program, including but not limited to, health, dental, vision and life benefits. Health and Welfare Benefit Plans LLC administers the financial aspects of the group insurance program, receives all premium payments from the participating affiliates, and makes all vendor payments. The cost of coverage under this program was approximately $19.0 million, $25.2 million, and $23.7 million in 2023, 2022 and 2021, respectively, and is recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations. AES Indiana had no prepaids for coverage under this plan as of December 31, 2023 and 2022, respectively. 

AES files federal and state income tax returns which consolidate IPALCO and its subsidiaries, including AES Indiana. Under a tax sharing agreement with IPALCO, AES Indiana is responsible for the income taxes associated with its own taxable income and records the provision for income taxes using a separate return method. AES Indiana had a receivable balance under this agreement of $5.1 million and $6.7 million as of December 31, 2023 and 2022, respectively, which is recorded in “Taxes receivable” on the accompanying Consolidated Balance Sheets. See Note 7, "Income Taxes" for more information.

Long-term Compensation Plan

During 2023, 2022 and 2021, many of AES Indiana’s non-union employees received benefits under the AES Long-term Compensation Plan, a deferred compensation program. This type of plan is a common employee retention tool used in our industry. Benefits under this plan are granted in the form of performance units payable in cash and AES restricted stock units. Restricted stock units vest ratably over a three-year period. The performance units payable in cash vest at the end of the three-year performance period and are subject to certain AES performance criteria. Total deferred compensation expense recorded during 2023, 2022 and 2021 was $0.3 million, $0.2 million and $0.2 million, respectively, and was included in “Operating expenses - Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. The value of these benefits is being recognized over the 36 month vesting period and a portion is recorded as miscellaneous deferred credits with the remainder recorded as “Paid in capital” on AES Indiana’s Consolidated Balance Sheets in accordance with ASC 718 “Compensation – Stock Compensation.”

See also Note 8, “Benefit Plans” to the audited consolidated financial statements of AES Indiana for a description of benefits awarded to AES Indiana employees by AES under the RSP.

Service Company

Total costs incurred by the Service Company on behalf of AES Indiana were $73.6 million, $60.1 million and $58.2 million during 2023, 2022 and 2021, respectively. Total costs incurred by AES Indiana on behalf of the Service Company during 2023, 2022 and 2021 were $11.9 million, $10.0 million and $10.4 million, respectively, which are included as a reduction to charges from the Service Company. These costs were included in “Operating expenses -

Operation and maintenance” on AES Indiana’s Consolidated Statements of Operations. AES Indiana had a payable balance with the Service company of $25.6 million and $2.1 million as of December 31, 2023 and 2022, respectively, which is recorded in "Accounts payable" on the accompanying Consolidated Balance Sheets.

Other

During the year ended December 31, 2021, AES Indiana received loan repayments of $6.1 million from IPALCO.

In the second quarter of 2023, AES Indiana engaged a vendor that is a related party through a competitive RFP process as part of its replacement capacity resource construction projects. AES Indiana had payments of $223.3 million to this vendor during the year ended December 31, 2023, which are included in "Other non-current assets" on the accompanying Consolidated Balance Sheets. Additionally, transactions with various other related parties were $7.4 million, $5.7 million and $4.3 million during 2023, 2022 and 2021, respectively. These expenses were primarily recorded in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations.

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Business Segment Information

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Business Segment Information

BUSINESS SEGMENTS

IPALCO manages its business through one reportable operating segment, the Utility segment. The primary segment performance measure is income / (loss) from continuing operations before income tax as management has concluded that this measure best reflects the underlying business performance of IPALCO and is the most relevant measure considered in IPALCO's internal evaluation of the financial performance of its segment. The Utility segment is comprised of AES Indiana, a vertically integrated electric utility, with all other nonutility business activities aggregated separately. See Note 1, "Overview and Summary of Significant Accounting Policies" for further information on AES Indiana. The “Other” nonutility category primarily includes the 2024 IPALCO Notes and 2030 IPALCO Notes and related interest expense, balance associated with IPALCO's interest rate hedges, cash and other immaterial balances. The accounting policies of the identified segment are consistent with those policies and procedures described in the summary of significant accounting policies.

The following table provides information about IPALCO’s business segments (in thousands):

	2023						2022						2021
	Utility		Other		Total		Utility		Other		Total		Utility		Other		Total
Revenue	$	1,649,917	$	—	$	1,649,917	$	1,791,711	$	—	$	1,791,711	$	1,426,132	$	—	$	1,426,132
Depreciation and amortization	$	287,863	$	—	$	287,863	$	266,504	$	—	$	266,504	$	256,085	$	—	$	256,085
Interest expense	$	99,051	$	43,875	$	142,926	$	87,428	$	43,804	$	131,232	$	84,256	$	41,370	$	125,626
Income/(loss) before income tax	$	115,763	$	(44,021)	$	71,742	$	162,862	$	(44,377)	$	118,485	$	189,548	$	(41,425)	$	148,123
Capital expenditures(1)	$	902,705	$	—	$	902,705	$	496,510	$	—	$	496,510	$	291,546	$	—	$	291,546
(1) Capital expenditures includes $0 thousand, $0 thousand and $36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively.
	As of December 31, 2023						As of December 31, 2022						As of December 31, 2021
Total assets	$	6,129,581	$	51,942	$	6,181,523	$	5,559,977	$	29,237	$	5,589,214	$	5,222,987	$	16,780	$	5,239,767

Indianapolis Power And Light Company

Entity Information [Line Items]

Business Segment Information

BUSINESS SEGMENTS

Operating segments are components of an enterprise that engage in business activities from which it may earn revenue and incur expenses, for which separate financial information is available, and is evaluated regularly by the chief operating decision maker in assessing performance and deciding how to allocate resources. All of AES Indiana’s current business consists of the generation, transmission, distribution and sale of electric energy, and therefore AES Indiana had only one reportable segment.

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Revenue

12 Months Ended

Dec. 31, 2023

Disaggregation of Revenue [Line Items]

Revenue from Contract with Customer [Text Block]

REVENUE

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.

Indianapolis Power And Light Company

Disaggregation of Revenue [Line Items]

Revenue from Contract with Customer [Text Block]

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

AES Indiana has elected to apply the optional disclosure exemptions under ASC 606. Therefore, AES Indiana has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration

relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.

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Leases

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Leases

LEASES

LESSEE

The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	December 31, 2023		December 31, 2022
Assets
Right-of-use assets — finance leases	Other non-current assets	$	16,357	$	15,819
Liabilities
Finance lease liabilities (noncurrent)	Long-term debt	$	17,769	$	16,361
Total finance lease liabilities		$	17,769	$	16,361

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate	December 31, 2023		December 31, 2022
Weighted-average remaining lease term — finance leases	35 years		36 years
Weighted-average discount rate — finance leases	5.30	%	5.650	%

The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):

	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021
Finance lease cost:
Amortization of right-of-use assets	$	445	$	542	$	—
Interest on lease liabilities	933		782		—
Total lease cost	$	1,378	$	1,324	$	—

Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):

	Finance Leases
2024	$	891
2025	909
2026	927
2027	945
2028	965
Thereafter	39,958
Total	$	44,595
Less: Imputed interest	(26,826)
Present value of lease payments	$	17,769

LESSOR

The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.

The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):

	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	1,537	$	1,134	$	1,439

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):

Property, Plant and Equipment, Net	December 31, 2023		December 31, 2022
Gross assets	$	4,341	$	4,334
Less: Accumulated depreciation	(1,222)		(1,060)
Net assets	$	3,119	$	3,274

The option to extend or terminate a lease is based on customary early termination provisions in the contract.

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

Future Minimum Lease Receipts

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

Subsidiaries [Member]

Entity Information [Line Items]

Leases

LEASES

LESSEE

The Company is the lessee under financing leases primarily for land. Right-of-use assets are long-term by nature. The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	December 31, 2023		December 31, 2022
Assets
Right-of-use assets — finance leases	Other non-current assets	$	16,357	$	15,819
Liabilities
Finance lease liabilities (noncurrent)	Long-term debt	$	17,769	$	16,361
Total finance lease liabilities		$	17,769	$	16,361

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate	December 31, 2023	December 31, 2022
Weighted-average remaining lease term — finance leases	35 years	36 years
Weighted-average discount rate — finance leases	5.30%	5.650%

The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):

	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021
Finance lease cost:
Amortization of right- of-use assets	$	445	$	542	$	—
Interest on lease liabilities	933		782		—
Total lease cost	$	1,378	$	1,324	$	—

Operating cash outflows from finance leases were $0.6 million, $0.3 million and $0.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):

	Finance Leases
2024	$	891
2025	909
2026	927
2027	945
2028	965
Thereafter	39,958
Total	$	44,595
Less: Imputed interest	(26,826)
Present value of lease payments	$	17,769

LESSOR

The Company is the lessor under operating leases for land, office space and operating equipment. Lease receipts from such contracts are recognized as operating lease revenue on a straight-line basis over the lease term whereas contingent rentals are recognized when earned.

The following table presents lease revenue from operating leases in which the Company is the lessor for the periods indicated (in thousands):

	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	1,537	$	1,134	$	1,439

The following table presents the underlying gross assets and accumulated depreciation of operating leases included in Property, plant and equipment, net for the periods indicated (in thousands):

Property, Plant and Equipment, Net	December 31, 2023		December 31, 2022
Gross assets	$	4,341	$	4,334
Less: Accumulated depreciation	(1,222)		(1,060)
Net assets	$	3,119	$	3,274

The option to extend or terminate a lease is based on customary early termination provisions in the contract.

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

Future Minimum Lease Receipts

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

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Schedule I - Condensed Financial Information Of Registrant

12 Months Ended

Dec. 31, 2023

Condensed Financial Information Disclosure [Abstract]

Schedule I - Condensed Financial Information Of Registrant

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting for Subsidiaries and Affiliates – IPALCO has accounted for the earnings of its subsidiaries on the equity method in the unconsolidated condensed financial information.

FAIR VALUE

The fair value of current financial assets and liabilities approximate their reported carrying amounts. The estimated fair values of the Company’s assets and liabilities have been determined using available market information. Because these amounts are estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Fair Value Hierarchy and Valuation Techniques

ASC 820 defined and established a framework for measuring fair value and expands disclosures about fair value measurements for financial assets and liabilities that are adjusted to fair value on a recurring basis and/or financial assets and liabilities that are measured at fair value on a nonrecurring basis, which have been adjusted to fair value during the period. In accordance with ASC 820, we have categorized our financial assets and liabilities that are adjusted to fair value, based on the priority of the inputs to the valuation technique, following the three-level fair value hierarchy prescribed by ASC 820 as follows:

Level 1 - unadjusted quoted prices for identical assets or liabilities in an active market; 

Level 2 - inputs from quoted prices in markets where trading occurs infrequently or quoted prices of instruments with similar attributes in active markets; and

Level 3 - unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

Whenever possible, quoted prices in active markets are used to determine the fair value of our financial instruments. Our financial instruments are not held for trading or other speculative purposes. The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Financial Assets

VEBA Assets

IPALCO has VEBA investments that are to be used to fund certain employee postretirement health care benefit plans. These assets are primarily comprised of open-ended mutual funds, which are valued using the net assets value per unit. These investments are recorded at fair value within "Other non-current assets" on the accompanying Unconsolidated Balance Sheets and classified as equity securities. All changes to fair value on the VEBA investments are included in income in the period that the changes occur. These changes to fair value were not material for the years ended December 31, 2023, 2022, or 2021. Any unrealized gains or losses are recorded in "Other income / (expense), net" on the accompanying Unconsolidated Statements of Operations.

Financial Assets

Interest Rate Hedges

IPALCO's interest rate hedges have a combined notional amount of $400.0 million. All changes in the market value of the interest rate hedges are recorded in AOCI. See also Note 3, "Derivative Instruments and Hedging Activities - Cash Flow Hedges" for further information.

Summary

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	127	$	—	$	—	$	127	$	5	$	—	$	—	$	5
Mutual funds	3,425		—		—		3,425		3,223		—		—		3,223
Total VEBA investments	3,552		—		—		3,552		3,228		—		—		3,228
Interest rate hedges	—		14,294		—		14,294		—		12,172		—		12,172
Total financial assets measured at fair value	$	3,552	$	14,294	$	—	$	17,846	$	3,228	$	12,172	$	—	$	15,400

Financial Instruments not Measured at Fair Value in the Unconsolidated Balance Sheets

Debt

The fair value of our outstanding fixed-rate debt has been determined on the basis of the quoted market prices of the specific securities issued and outstanding. In certain circumstances, the market for such securities was inactive and therefore the valuation was adjusted to consider changes in market spreads for similar securities. Accordingly, the purpose of this disclosure is not to approximate the value on the basis of how the debt might be refinanced.

The following table shows the face value and the fair value of fixed-rate indebtedness (Level 2) for the periods ending:

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	880,000	$	839,471	$	880,000	$	816,411
Total indebtedness	$	880,000	$	839,471	$	880,000	$	816,411

The difference between the face value and the carrying value of this indebtedness represents the following:

•unamortized deferred financing costs of $4.6 million and $5.9 million at December 31, 2023 and 2022, respectively; and

•unamortized discounts of $0.3 million and $0.4 million at December 31, 2023 and 2022, respectively.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use derivatives principally to manage the interest rate risk associated with refinancing our long-term debt. The derivatives that we use to economically hedge these risks are governed by our risk management policies for forward and futures contracts. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. We monitor and value derivative positions monthly as part of our risk management processes. We use published sources for pricing, when possible, to mark positions to market. All of our derivative instruments are used for risk management purposes and are designated as cash flow hedges if they qualify under ASC 815 for accounting purposes.

At December 31, 2023, IPALCO's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)		Sales (in thousands)		Net Notional (in thousands)
Interest rate hedges	Designated	USD	$	400,000	$	—	$	400,000

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Cash Flow Hedges

As part of our risk management processes, we identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The fair values of cash flow hedges determined by current public market prices will continue to fluctuate with changes in market prices up to contract expiration. The change in the fair value of a hedging instrument is recorded in other comprehensive income and amounts deferred are reclassified to earnings in the same income statement line as the hedged item in the period in which it settles.

In March 2019, we entered into three forward interest rate swaps to hedge the interest risk associated with refinancing the IPALCO 2020 maturities. The three interest rate swaps had a combined notional amount of $400.0 million. In April 2020, we de-designated the swaps as cash flow hedges and froze the AOCL of $72.3 million at the date of de-designation. The interest rate swaps were then amended and re-designated as cash flow hedges to hedge the interest rate risk associated with refinancing the 2024 IPALCO Notes. The amended interest rate swaps have a combined notional amount of $400.0 million and will be settled when the 2024 IPALCO Notes are refinanced. The $72.3 million of AOCL associated with the interest rate swaps through the date of the amendment will be amortized out of AOCL into interest expense over the remaining life of the 2030 IPALCO Notes, while any changes in fair value associated with the amended interest rate swaps will be recognized in AOCL going forward.

The following tables provide information on gains or losses recognized in AOCL for the cash flow hedges for the period indicated:

	Interest Rate Hedges for the Year Ended December 31,
$ in thousands (net of tax)	2023		2022		2021
Beginning accumulated derivative gain / (loss) in AOCL	$	22,269	$	(29,407)	$	(43,420)
Net gains associated with current period hedging transactions	1,594		46,245		10,393
Net losses reclassified to interest expense	5,431		5,431		3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)	$	29,294	$	22,269	$	(29,407)
Loss expected to be reclassified to earnings in the next twelve months	$	(5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9

When applicable, IPALCO has elected not to offset derivative assets and liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivative agreements. As of December 31, 2023 and 2022, IPALCO did not have any offsetting positions.

The following table summarizes the fair value, balance sheet classification and hedging designation of IPALCO's derivative instruments:

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	14,294	$	—
Interest rate hedges	Cash Flow Hedge	Derivative assets, non-current	$	—	$	12,172

DEBT

The following table presents IPALCO’s long-term indebtedness:

		December 31,
Series	Due	2023		2022
		(In Thousands)
Long-Term Debt
3.70% Senior Secured Notes	September 2024	405,000		405,000
4.25% Senior Secured Notes	May 2030	475,000		475,000
Unamortized discount – net		(319)		(425)
Deferred financing costs – net		(4,554)		(5,912)
Total long-term debt		875,127		873,663
Less: current portion of long-term debt		405,000		—
Net long-term debt		$	470,127	$	873,663

IPALCO’s Senior Secured Notes and Term Loan

The 2024 IPALCO Notes are due September 1, 2024. Although current liquid funds are not sufficient to repay the collective amounts due under the 2024 IPALCO Notes at maturity, the Company believes it will be able to refinance the 2024 IPALCO Notes based on conversations with investment bankers, which currently indicate more than adequate demand for new IPALCO debt at its current credit ratings, and considering the Company's previous successful debt issuances.

Pursuant to a registration rights agreement dated April 14, 2020, IPALCO agreed to register the 2030 IPALCO Notes under the Securities Act by filing an exchange offer registration statement or, under specified circumstances, a shelf registration statement with the SEC. IPALCO filed a registration statement on Form S-4 with respect to the 2030 IPALCO Notes with the SEC on March 22, 2021 in respect of its obligations under such registration rights agreement, and this registration statement was declared effective on April 7, 2021. The exchange offer closed on May 11, 2021.

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Schedule II - Valuation And Qualifying Accounts And Reserves

12 Months Ended

Dec. 31, 2023

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation And Qualifying Accounts And Reserves

IPALCO ENTERPRISES, INC. and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2023, 2022 and 2021
(In Thousands)
Column A – Description	Column B		Column C – Additions				Column D – Deductions		Column E
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Net Write-offs		Balance at End of Period
Year ended December 31, 2023
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	1,117	$	8,930	$	—	$	7,764	$	2,283
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	5,160	$	736	$	—	$	2,456	$	3,440
Year ended December 31, 2022
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	647	$	7,478	$	—	$	7,008	$	1,117
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	3,107	$	2,053	$	—	$	—	$	5,160
Year ended December 31, 2021
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	3,155	$	3,940	$	—	$	6,448	$	647
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	6,133	$	758	$	—	$	3,784	$	3,107

AES INDIANA and SUBSIDIARIES
Valuation and Qualifying Accounts and Reserves
For the Years Ended December 31, 2023, 2022 and 2021
(In Thousands)
Column A – Description	Column B		Column C – Additions				Column D – Deductions		Column E
	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Net Write-offs		Balance at End of Period
Year ended December 31, 2023
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	1,117	$	8,930	$	—	$	7,764	$	2,283
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	5,160	$	736	$	—	$	2,456	$	3,440
Year ended December 31, 2022
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	647	$	7,478	$	—	$	7,008	$	1,117
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	3,107	$	2,053	$	—	$	—	$	5,160
Year ended December 31, 2021
Accumulated Provisions Deducted from
Assets – Doubtful Accounts	$	3,155	$	3,940	$	—	$	6,448	$	647
Deducted from Inventories
Valuation Allowance for Materials and Supplies	$	6,133	$	758	$	—	$	3,784	$	3,107

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Overview and Summary of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,178		239
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,921	$	216,523

Inventory, Policy [Policy Text Block]

Inventories

We maintain coal, fuel oil, natural gas, materials and supplies inventories for use in the production of electricity. These inventories are accounted for at the lower of cost or net realizable value, using the average cost. The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Intangible Assets, Finite-Lived, Policy [Policy Text Block]

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:

			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	8		$	261,872	$	205,910
Project development intangible assets	28		84,097		39,455
Other	Various		797		797
Less: Accumulated amortization			(111,110)		(107,184)
Intangible assets - net			$	235,656	$	138,978
	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	14,570	$	10,122	$	11,241
Estimated future amortization
Years ending December 31,
2024					$	20,764
2025					20,764
2026					22,550
2027					22,550
2028					22,550
Total					$	109,178

Principles of Consolidation

Principles of Consolidation

IPALCO’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of IPALCO, its regulated utility subsidiary, AES Indiana, and its unregulated subsidiary, Mid-America. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on

allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If IPALCO enters into transactions impacting equity interests in its affiliates, IPALCO must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which consolidation model applies to the transaction, IPALCO is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and IPALCO is determined to have power and benefits, the entity will be consolidated by IPALCO.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. IPALCO uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by IPALCO. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of ITCs or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	28,579	$	201,548
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	28,584	$	201,553

Revenues and Accounts Receivable

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,178		239
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,921	$	216,523

Contingencies

Contingencies

IPALCO accrues for loss contingencies when the amount of the loss is probable and estimable. We are subject to various environmental regulations and are involved in certain legal proceedings. If IPALCO’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentration of Risk

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
AFUDC equity	$	9,315	$	4,784	$	5,412
AFUDC debt	$	13,739	$	8,215	$	4,815

Derivatives

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Additionally, we use interest rate hedges to manage the interest rate risk associated with refinancing our long-term debt. We use cash flow hedge accounting when the hedge or a portion of the hedge is deemed to be highly effective, which results in changes in the fair value being recorded within accumulated other comprehensive income, a component of shareholders' equity. We have elected not to offset net derivative positions in the Financial Statements. Accordingly, we do not offset such derivative positions against the fair value of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral under master netting agreements. See Note 5, “Derivative Instruments and Hedging Activities” for additional information

Impairment of Long-Lived Assets

Impairment of Long-lived Assets

GAAP requires that we test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, we are required to write down the asset to its fair value with a charge to current earnings. The net book value of our property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). We do not believe any of these assets are currently impaired. In making this assessment, we consider such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in our service territory and wholesale electricity in the region; and the cost of fuel.

Income Taxes

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases. The Company establishes a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The Company’s tax positions are evaluated under a more likely than not recognition threshold and measurement analysis before they are recognized for financial statement reporting.

Uncertain tax positions are classified as noncurrent income tax liabilities unless expected to be paid within one year. The Company’s policy for interest and penalties is to recognize interest and penalties as a component of the provision for income taxes in the Consolidated Statements of Operations.

Income tax assets or liabilities, which are included in allowable costs for ratemaking purposes in future years, are recorded as regulatory assets or liabilities with a corresponding deferred tax liability or asset. Investment tax credits that reduced federal income taxes in the years they arose have been deferred and are being amortized to income over the useful lives of the properties in accordance with regulatory treatment. See Note 2, "Regulatory Matters" for additional information.

IPALCO and its subsidiaries file U.S. federal income tax returns as part of the consolidated U.S. income tax return filed by AES. The consolidated tax liability is allocated to each subsidiary based on the separate return method which is specified in our tax allocation agreement and which provides a consistent, systematic and rational approach. See Note 7, "Income Taxes" for additional information.

Repair and Maintenance Costs

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

Per Share Data

IPALCO is owned by AES U.S. Investments and CDPQ. IPALCO does not report earnings on a per-share basis.

Lessee, Leases

Leases

The Company has finance leases primarily for land in which the Company is the lessee. Operating leases with an initial term of 12 months or less are not recorded on the balance sheet, but are expensed on a straight-line basis over the lease term. The Company’s leases do not contain any material residual value guarantees, restrictive covenants or subleases.

Right-of-use assets represent our right to use an underlying asset for the lease term while lease liabilities represent our obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. Generally, the rate implicit in the lease is not readily determinable; as such, we use the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company determines discount rates based on its existing credit rates of its borrowings, which are then adjusted for the appropriate lease term. The right-of-use asset also includes any lease payments made and excludes lease incentives that are paid or payable to the lessee at commencement. The lease term includes periods covered by the option to extend if it is reasonably certain that the option will be exercised and periods covered by an option to terminate if it is reasonably certain that the option will not be exercised.

Pension and Other Postretirement Plans, Pensions, Policy

Pension and Postretirement Benefits

We recognize in our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at

fair value. We follow the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

We account for and disclose pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, we apply a disaggregated discount rate approach for determining service cost and interest cost for our defined benefit pension plans and postretirement plans.

See Note 8, "Benefit Plans" for more information.

Revenue Recognition, Revenue Reductions

Revenue Recognition

Revenue related to the sale of energy is generally recognized when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to certain customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is accrued. In making its estimates of unbilled revenue, AES Indiana uses models that consider various factors including daily generation volumes; known amounts of energy usage by nearly all residential, commercial and industrial customers; and estimated customer rates based on prior period billings. Given the use of these models, and that customers are billed on a monthly cycle, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. An allowance for potential credit losses is maintained and amounts are written off when normal collection efforts have been exhausted. Our provision for expected credit losses included in “Operating expenses - Operation and maintenance” on the accompanying Consolidated Statements of Operations was $7.5 million, $5.9 million and $3.0 million for the years ended December 31, 2023, 2022 and 2021, respectively.

AES Indiana’s basic rates include a provision for fuel costs as established in AES Indiana’s most recent rate proceeding, which last adjusted AES Indiana’s rates in December 2018. AES Indiana is permitted to recover actual costs of purchased power and fuel consumed, subject to certain restrictions. This is accomplished through quarterly FAC proceedings, in which AES Indiana estimates the amount of fuel and purchased power costs in future periods. Through these proceedings, AES Indiana is also permitted to recover, in future rates, underestimated fuel and purchased power costs from prior periods, subject to certain restrictions, and therefore the over or underestimated costs are deferred or accrued and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted. See also Note 2, “Regulatory Matters” for a discussion of other costs that AES Indiana is permitted to recover through periodic rate adjustment proceedings and the status of current rate adjustment proceedings.

In addition, we are one of many transmission system owner members of MISO, a RTO which maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. See Note 13, "Revenue" for additional information of MISO sales and other revenue streams.

Credit Loss, Financial Instrument

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

The allowance for credit losses primarily relates to utility customer receivables, including unbilled amounts. Expected credit loss estimates are developed by disaggregating customers into those with similar credit risk

characteristics and using historical credit loss experience. In addition, we also consider how current and future economic conditions are expected to impact collectability, as applicable, of our receivable balance. Amounts are written off when reasonable collections efforts have been exhausted.

Indianapolis Power And Light Company

Entity Information [Line Items]

Property, Plant and Equipment, Policy [Policy Text Block]

Property, Plant and Equipment

Property, plant and equipment is stated at original cost as defined for regulatory purposes. The cost of additions to property, plant and equipment and replacements of retirement units of property are charged to plant accounts. Units of property replaced or abandoned in the ordinary course of business are retired from the plant accounts at cost; such amounts, less salvage, are charged to accumulated depreciation. Depreciation is computed by the straight-line method based on functional rates approved by the IURC and averaged 3.7%, 3.8% and 3.7% during 2023, 2022 and 2021, respectively. Depreciation expense was $244.8 million, $247.5 million, and $239.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. "Depreciation and amortization" expense on the accompanying Consolidated Statements of Operations is presented net of regulatory deferrals of depreciation expense and also includes amortization of intangible assets and amortization of previously deferred regulatory costs.

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,227		288
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,970	$	216,572

Intangible Assets, Finite-Lived, Policy [Policy Text Block]

Intangible Assets

Finite-lived intangible assets primarily include capitalized software and project development intangible assets amortized on a straight-line basis over their useful lives. The following table presents information related to the Company's intangible assets, including the gross amount capitalized and related amortization:

			December 31,
$ in thousands	Weighted average amortization periods (in years)		2023		2022
Capitalized software	8		$	261,872	$	205,910
Project development intangible assets	28		84,097		39,455
Other	Various		797		797
Less: Accumulated amortization			(111,110)		(107,184)
Intangible assets - net			$	235,656	$	138,978
	For the Years Ended December 31,
	2023		2022		2021
Amortization expense	$	14,570	$	10,122	$	11,241
Estimated future amortization
Years ending December 31,
2024					$	20,764
2025					20,764
2026					22,550
2027					22,550
2028					22,550
Total					$	109,178

Principles of Consolidation

Principles of Consolidation

AES Indiana’s consolidated financial statements are prepared in accordance with GAAP and in conjunction with the rules and regulations of the SEC. The consolidated financial statements include the accounts of AES Indiana and its wholly owned subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, as described below, have been consolidated. All intercompany items have been eliminated in consolidation. Certain costs for shared resources amongst AES Indiana and IPALCO, such as labor and benefits, are allocated to each entity based on allocation methodologies that management believes to be reasonable. We have evaluated subsequent events through the date this report is issued.

If AES Indiana enters into transactions impacting equity interests in its affiliates, AES Indiana must determine whether the transaction impacts the Company's consolidation conclusion by first determining whether the transaction should be evaluated under the variable interest model or the voting model. In determining which

consolidation model applies to the transaction, AES Indiana is required to make judgments about how the entity operates, the most significant of which are whether (i) the entity has sufficient equity to finance its activities, (ii) the equity holders, as a group, have the characteristics of a controlling financial interest, and (iii) whether the entity has non-substantive voting rights. If the entity is determined to be a variable interest entity and AES Indiana is determined to have power and benefits, the entity will be consolidated by AES Indiana.

Noncontrolling Interests

Noncontrolling interests are classified as a separate component of equity in the Consolidated Balance Sheets and Consolidated Statements of Changes in Equity. Additionally, net income attributable to noncontrolling interests is reflected separately from consolidated net income on the Consolidated Statements of Operations. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests' basis has been reduced to zero.

Allocation of Earnings

Hardy Hills JV is subject to profit-sharing arrangements where the allocation of earnings, cash distributions, and tax benefits are not based on fixed ownership percentages. This arrangement exists to designate different allocations of value among the investors, where the allocations change in form or percentage over the life of the partnership. AES Indiana uses the HLBV method when it is a reasonable approximation of the profit-sharing arrangement. The HLBV method calculates the proceeds that would be attributable to each partner based on the liquidation provisions of the respective operating partnership agreement if the partnership was to be liquidated at book value at the balance sheet date. Each partner’s share of income in the period is equal to the change in the amount of net equity they are legally able to claim based on a hypothetical liquidation of the entity at the end of a reporting period compared to the beginning of that period, adjusted for any capital transactions (for further discussion about the Equity Capital Contribution Agreement, see Note 2, "Regulatory Matters - IRP Filings and Replacement Generation").

The HLBV method is used to calculate the earnings attributable to noncontrolling interest when the business is consolidated by AES Indiana. In the early months of operations of a renewable generation facility where HLBV results in a significant decrease in the hypothetical liquidation proceeds attributable to the tax equity investor due to the recognition of investment tax credits ("ITCs") or other adjustments as required by the U.S. Internal Revenue Code, the Company records the impact (sometimes referred to as the ‘Day one gain’) to income in the same period.

Use of Management Estimates

Use of Management Estimates

The preparation of financial statements in conformity with GAAP requires that management make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenue and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results may differ from those estimates. Significant items subject to such estimates and assumptions include: recognition of revenue including unbilled revenue; the carrying value of property, plant and equipment; the valuation of insurance and claims liabilities; the valuation of allowances for credit losses and deferred income taxes; regulatory assets and liabilities; liabilities recorded for income tax exposures; litigation; contingencies; and assets and liabilities related to AROs and employee benefits.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. All highly liquid short-term investments with original maturities of three months or less are considered cash equivalents.

Restricted Cash

Restricted cash includes cash which is restricted as to withdrawal or usage. The nature of the restrictions includes restrictions imposed by agreements related to deposits held as collateral.

The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	25,767	$	199,103
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	25,772	$	199,108

Revenues and Accounts Receivable

Accounts Receivable and Allowance for Credit Losses

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,227		288
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,970	$	216,572

Contingencies

Contingencies

AES Indiana accrues for loss contingencies when the amount of the loss is probable and estimable. AES Indiana is subject to various environmental regulations and is involved in certain legal proceedings. If AES Indiana’s actual environmental and/or legal obligations are different from our estimates, the recognition of the actual amounts may have a material impact on our results of operations, financial condition and cash flows; although that has not been

the case during the periods covered by this report. Accruals for loss contingencies were not material as of December 31, 2023 and 2022. See Note 10, "Commitments and Contingencies - Contingencies" for additional information.

Concentration of Risk

Concentrations of Risk

Substantially all of AES Indiana’s customers are located within the Indianapolis area. Approximately 68% of AES Indiana’s employees are covered by collective bargaining agreements in two bargaining units: a physical unit and a clerical-technical unit. AES Indiana’s contract with the physical unit expires on December 4, 2024, and the contract with the clerical-technical unit expires February 12, 2026. Additionally, AES Indiana has long-term coal contracts with one supplier, and substantially all of AES Indiana's coal is currently mined in the state of Indiana.

Allowance For Funds Used During Construction

AFUDC

In accordance with the Uniform System of Accounts prescribed by FERC, AES Indiana capitalizes an allowance for the net cost of funds (interest on borrowed funds and a reasonable rate of return on equity funds) used for construction purposes during the period of construction with a corresponding credit to income. AES Indiana capitalized amounts using pretax composite rates of 7.1%, 5.4% and 5.7% during 2023, 2022 and 2021, respectively. AFUDC equity and AFUDC debt were as follows for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
AFUDC equity	$	9,315	$	4,784	$	5,412
AFUDC debt	$	13,739	$	8,215	$	4,815

Derivatives

Financial Derivatives

All derivatives are recognized as either assets or liabilities in the balance sheets and are measured at fair value. Changes in the fair value are recorded in earnings unless the derivative is designated as a cash flow hedge of a forecasted transaction or it qualifies for the normal purchases and sales exception.

AES Indiana has contracts involving the physical delivery of energy and fuel. Because some of these contracts qualify for the normal purchases and normal sales scope exception in ASC 815, AES Indiana has elected to account for them as accrual contracts, which are not adjusted for changes in fair value. AES Indiana has or previously had FTRs and forward power contracts that do not qualify for hedge accounting or the normal purchases and sales exceptions under ASC 815. Accordingly, FTRs are recorded at fair value when acquired and subsequently amortized over the annual period as they are used. FTRs are initially recorded at fair value using the income approach. The forward power contracts are recorded at fair value with changes in the fair value charged or credited to the Consolidated Statements of Operations in the period in which the change occurred. Forward power contracts are fair valued using the market approach.

Impairment of Long-Lived Assets

Impairment of Long-lived Assets

GAAP requires that AES Indiana test long-lived assets for impairment when indicators of impairment exist. If an asset is deemed to be impaired, AES Indiana is required to write down the asset to its fair value with a charge to

current earnings. The net book value of AES Indiana’s property, plant, and equipment was $4.5 billion and $4.0 billion as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, AES Indiana had $259.9 million and $287.5 million, respectively, of long-term regulatory assets associated with Petersburg Unit 1 and 2 retirement costs (for further discussion, see Note 2, “Regulatory Matters - IRP Filings and Replacement Generation” and Note 3, "Property, Plant and Equipment"). AES Indiana does not believe any of these assets are currently impaired. In making this assessment, AES Indiana considers such factors as: the overall condition and generating and distribution capacity of the assets; the expected ability to recover additional expenditures in the assets; the anticipated demand and relative pricing of retail electricity in its service territory and wholesale electricity in the region; and the cost of fuel.

Pension and Postretirement Benefits

Pension and Postretirement Benefits

AES Indiana recognizes in its Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in the funded status, that would otherwise be recognized in AOCI, recorded as a regulatory asset as this can be recovered through future rates. All plan assets are recorded at fair value. AES Indiana follows the measurement date provisions of the accounting guidance, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

AES Indiana accounts for and discloses pension and postretirement benefits in accordance with the provisions of GAAP relating to the accounting for pension and other postretirement plans. These GAAP provisions require the use of assumptions, such as the discount rate for liabilities and long-term rate of return on assets, in determining the obligations, annual cost and funding requirements of the plans. Consistent with the requirements of ASC 715, AES Indiana applies a disaggregated discount rate approach for determining service cost and interest cost for its defined benefit pension plans and postretirement plans.

Repair and Maintenance Costs

Repair and Maintenance Costs

Repair and maintenance costs are expensed as incurred.

Per Share Data

Per Share Data

IPALCO owns all of the outstanding common stock of AES Indiana. AES Indiana does not report earnings on a per-share basis.

XML

Overview and Summary of Significant Accounting Policies Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Schedule of Utility Inventory [Table Text Block]

The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,178		239
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,921	$	216,523

Schedule of Cash and Cash Equivalents [Table Text Block]

The following table provides a summary of cash, cash equivalents, and restricted cash amounts reported within the Consolidated Balance Sheets that reconcile to the total of such amounts as shown on the Consolidated Statements of Cash Flows:

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	28,579	$	201,548
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	28,584	$	201,553

Reclassification out of Accumulated Other Comprehensive Income

The amounts reclassified out of AOCI / (AOCL) by component during the years ended December 31, 2023, 2022 and 2021 are as follows (in thousands):

Details about AOCI / (AOCL) components	Affected line item in the Consolidated Statements of Operations	For the Years Ended December 31,
		2023		2022		2021
Net losses on cash flow hedges (Note 5):	Interest expense	$	7,229	$	7,229	$	4,819
	Income tax effect	(1,798)		(1,798)		(1,199)
Total reclassifications for the period, net of income taxes		$	5,431	$	5,431	$	3,620

Indianapolis Power And Light Company

Entity Information [Line Items]

Schedule of Utility Inventory [Table Text Block]

The following table summarizes our inventories balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Inventories
Fuel	$	77,198	$	60,497
Materials and supplies, net	66,392		63,111
Total inventories	$	143,590	$	123,608

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

The following table summarizes our accounts receivable balances at December 31:

	As of December 31,
	2023		2022
	(In Thousands)
Accounts receivable, net
Customer receivables	$	125,715	$	125,540
Unbilled revenue	91,463		74,488
Amounts due from related parties	5,227		288
Other	13,848		17,373
Allowance for credit losses	(2,283)		(1,117)
Total accounts receivable, net	$	233,970	$	216,572

Schedule of Cash and Cash Equivalents [Table Text Block]

	As of December 31,
	2023		2022
	(In Thousands)
Cash, cash equivalents and restricted cash
Cash and cash equivalents	$	25,767	$	199,103
Restricted cash (included in Prepayments and other current assets)	5		5
Total cash, cash equivalents and restricted cash	$	25,772	$	199,108

Allowance for Credit Losses

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

XML

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Schedule Of Regulatory Assets And Liabilities [Table Text Block]

	2023		2022		Recovery Period
	(In Thousands)
Regulatory assets, current:
Undercollections of rate riders	$	75,416	$	26,047	Approximately 1 year(1)
Fuel costs	—		79,861		Approximately 1 year(1)
Unamortized reacquisition premium on debt	188		—		Approximately 1 year
Costs being recovered through basic rates and charges	13,815		13,815		Approximately 1 year(1)
Total regulatory assets, current	89,419		119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs	115,847		131,907		Various(2)
Deferred MISO costs	21,091		34,483		Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	2,812		3,866		Through 2026(1)(3)
Unamortized reacquisition premium on debt	13,379		14,429		Over remaining life of debt
Environmental costs	66,837		68,947		Through 2046(1)(3)
COVID-19 costs	5,426		5,426		4 years(4)
Major storm damage	1,493		—		To be determined
TDSIC costs	35,979		18,547		36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs	259,892		287,463		Through 2034(1)(3)
Hardy Hills Solar Project development costs	6,774		5,744		30 years(3)
Petersburg Energy Center Project development costs	2,469		1,582		30 years(3)
Pike County BESS Project development costs	2,623		—		20 years(3)
Fuel costs	4,275		20,518		Through 2025(1)
Other miscellaneous	2,887		1,027		Various(5)
Total regulatory assets, non-current	541,784		593,939
Total regulatory assets	$	631,203	$	713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders	$	19,649	$	15,803	Approximately 1 year(1)
FTRs	3,722		7,545		Approximately 1 year(1)
Total regulatory liabilities, current	23,371		23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs	451,886		518,797		Not applicable
Deferred income taxes payable to customers through rates	74,796		88,662		Various
Hardy Hills sponsor investment tax credit	542		—		To be determined(6)
Major storm damage	—		5,126		To be determined
Total regulatory liabilities, non-current	527,224		612,585
Total regulatory liabilities	$	550,595	$	635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

Schedule of Regulatory Assets

2. REGULATORY MATTERS

General

AES Indiana is subject to regulation by the IURC as to its services and facilities, the valuation of property, the construction, purchase, or lease of electric generating facilities, the classification of accounts, rates of depreciation, retail rates and charges, the issuance of securities (other than evidences of indebtedness payable less than twelve months after the date of issue), the acquisition and sale of some public utility properties or securities and certain other matters.

In addition, AES Indiana is subject to the jurisdiction of the FERC with respect to, among other things, short-term borrowings not regulated by the IURC, the sale of electricity at wholesale, the transmission of electric energy in interstate commerce, the classification of accounts, reliability standards, and the acquisition and sale of utility property in certain circumstances as provided by the Federal Power Act. As a regulated entity, AES Indiana is required to use certain accounting methods prescribed by regulatory bodies which may differ from those accounting methods required to be used by unregulated entities.

AES Indiana is also affected by the regulatory jurisdiction of the EPA at the federal level, and the IDEM at the state level. Other significant regulatory agencies affecting AES Indiana include, but are not limited to, the NERC, the U.S. Department of Labor and the IOSHA.  

Basic Rates and Charges

Our basic rates and charges represent the largest component of our annual revenue. Our basic rates and charges are determined after giving consideration, on a pro-forma basis, to all allowable costs for ratemaking purposes including a fair return on the fair value of the utility property used and useful in providing service to customers. These basic rates and charges are set and approved by the IURC after public hearings. Such proceedings, which have occurred at irregular intervals, involve AES Indiana, the IURC, the Indiana Office of Utility Consumer Counselor, and other interested stakeholders. Pursuant to statute, the IURC is to conduct a periodic review of the basic rates and charges of all Indiana utilities at least once every four years, but the IURC has the authority to review the rates of any Indiana utility at any time. Once set, the basic rates and charges authorized do not assure the realization of a fair return on the fair value of property.

Our declining block rate structure generally provides for residential and commercial customers to be charged a lower per kWh rate at higher consumption levels. Therefore, as volumes increase, the weighted average price per kWh decreases. Numerous factors including, but not limited to, weather, inflation, customer growth and usage, the level of actual operating and maintenance expenditures, fuel costs, generating unit availability, and capital expenditures including those required by environmental regulations can affect the return realized.

Regulatory Rate Review and Base Rate Orders

AES Indiana filed a petition with the IURC on June 28, 2023, for authority to increase its basic rates and charges to cover the rising operational costs and needs associated with continuing to serve its customers safely and reliably. The factors leading to AES Indiana's first base rate increase request in five years include inflationary impacts on operations and maintenance expenses, investments in the transmission and distribution systems, and modernization of its customer systems. AES Indiana is also seeking recovery of increased costs to support its vegetation management plan, which covers the removal of overhang and tree trimming in its service territory. AES Indiana also seeks to better align depreciation expense with the period in which the generation plants provide service to customers and remove operational costs of the retired Petersburg units from rates. On November 22, 2023, AES Indiana entered into a unanimous stipulation and settlement agreement (the "settlement") with the OUCC and the intervening parties which, if approved by the IURC, would increase its annual revenue requirement by $73 million. AES Indiana expects to receive an order from the IURC and place new rates into effect by the end of the second quarter of 2024.

On October 31, 2018, the IURC issued an order approving an uncontested settlement agreement previously filed with the IURC by AES Indiana for a $43.9 million, or 3.2%, increase to annual revenue (the "2018 Base Rate Order"). The 2018 Base Rate Order includes recovery through rates of the CCGT at Eagle Valley completed in the first half of 2018, as well as other construction projects and changes to operating income since the 2016 Base Rate Order. New basic rates and charges became effective on December 5, 2018. The 2018 Base Rate Order provides that annual wholesale margins earned above (or below) the benchmark of $16.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism. Similarly, the 2018 Base Rate Order provides that all capacity sales above (or below) a benchmark of $11.3 million shall be passed back (or charged) to customer rates through a rate adjustment mechanism.

FAC and Authorized Annual Jurisdictional Net Operating Income

AES Indiana may apply to the IURC for a change in AES Indiana’s fuel charge every three months to recover AES Indiana’s estimated fuel costs, including the energy portion of purchased power costs, which may be above or below the levels included in AES Indiana’s basic rates and charges. AES Indiana must present evidence in each

FAC proceeding that it has made every reasonable effort to acquire fuel and generate or purchase power or both so as to provide electricity to its retail customers at the lowest fuel cost reasonably possible.

Independent of the IURC’s ability to review basic rates and charges, Indiana law requires electric utilities under the jurisdiction of the IURC to meet operating expense and income test requirements as a condition for approval of requested changes in the FAC. A utility may be unable to recover all of its fuel costs if its rolling twelve-month operating income, determined at quarterly measurement dates, exceeds its authorized annual jurisdictional net operating income and there are not sufficient applicable cumulative net operating income deficiencies (“Cumulative Deficiencies”) to offset it. The Cumulative Deficiencies calculation provides that only five years’ worth of historical earnings deficiencies or surpluses are included, unless it has been greater than five years since the most recent rate case.

In calendar years 2021 and 2022, AES Indiana reported earnings in excess of the authorized level for certain quarterly reporting periods in those years. AES Indiana has not reported earnings in excess of the authorized level for any FAC periods in the calendar year 2023. Prior to 2020, AES Indiana was not required to reduce its fuel cost recovery because of its Cumulative Deficiencies. During 2020, AES Indiana's Cumulative Deficiencies dropped to zero. AES Indiana recorded a reduction to revenue of $0.0 million, $0.3 million and $5.5 million in 2023, 2022 and 2021, respectively. As of the FAC period ending with the twelve months of October 31, 2023, AES Indiana has Cumulative Deficiencies; therefore, AES will not be required to reduce its fuel cost recovery for future earnings in excess of the authorized level until there are no longer Cumulative Deficiencies.

ECCRA 

AES Indiana may apply to the IURC for approval of a rate adjustment known as the ECCRA periodically to recover costs (including a return) to comply with certain environmental regulations applicable to AES Indiana’s generating stations and to recover certain investments in renewable and battery storage projects. The total amount of AES Indiana’s environmental equipment and renewable projects approved for ECCRA recovery as of December 31, 2023 was $129.7 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending February 2024 is a net cost to customers of $8.9 million.

DSM

Through various rate orders from the IURC, AES Indiana has been able to recover its costs of implementing various DSM programs throughout the periods covered by this report. In 2023, 2022 and 2021, AES Indiana also had the ability to receive performance incentives, dependent upon the level of success of the programs. Performance incentives included in rates for the years ended December 31, 2023, 2022 and 2021 were $2.7 million, $8.3 million and $7.2 million, respectively.

On December 29, 2020, the IURC approved a settlement agreement establishing a new three year DSM plan for AES Indiana through 2023. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

AES Indiana filed a petition with the IURC on May 26, 2023 asking for approval of a one year DSM interim plan. On December 27, 2023, the IURC approved a one-year DSM plan for AES Indiana through 2024. The approval included cost recovery of programs as well as performance incentives, depending on the level of success of the programs. The order also approved recovery of lost revenue, consistent with the provisions of the settlement agreement.

Wind and Solar Power Purchase Agreements

We are currently committed under a power purchase agreement to purchase all wind-generated electricity through 2029 from a wind project in Indiana ("Hoosier Wind Project"). On July 28, 2023, AES Indiana executed the Purchase Agreement and is currently in the process of acquiring this project. The existing power purchase agreement will be terminated upon closing (see "IRP Filings and Replacement Generation - Hoosier Wind Project" below for further information). We are also committed under another agreement to purchase all wind-generated electricity through 2031 from a project in Minnesota. The Indiana project has a maximum output capacity of approximately 100 MW and the Minnesota project has a maximum output capacity of approximately 200 MW. In addition, we have 94.5 MW of solar-generated electricity in our service territory under long-term contracts (these long-term contracts have

expiration dates ranging from 2026 to 2033), of which 94.0 MW was in operation as of December 31, 2023. We have authority from the IURC to recover the costs for all of these agreements through an adjustment mechanism administered within the FAC. If and when AES Indiana sells the renewable energy attributes (in the form of renewable energy credits) generated from these facilities, the proceeds would pass back to benefit AES Indiana’s retail customers through the FAC.

TDSIC

In 2013, Senate Enrolled Act 560, the Transmission, Distribution, and Storage System Improvement Charge ("TDSIC") statute, was signed into law. The TDSIC statute was revised in 2019. Among other provisions, this legislation provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization, or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a plan of at least five years and not more than seven for eligible investments. The first eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism. The cost recovery mechanism is referred to as a TDSIC mechanism. Recoverable costs include a return on, and of, the investment, including AFUDC, post-in-service carrying charges, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are to be deferred for future recovery in the public utility’s next base rate case. The periodic rate adjustment mechanism is capped at an annual increase of no more than two percent of total retail revenue.

On March 4, 2020, the IURC issued an order approving the projects in a seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $1.2 billion from 2020 through 2026. Beginning in June 2020, AES Indiana files an annual TDSIC rate adjustment for a return on and of investments through March 31 with rates requested to be effective each November. Annual TDSIC plan update filings are required to be staggered by six months as ordered by the IURC and are filed each December. The total amount of AES Indiana’s equipment net of depreciation, including carrying costs, approved for TDSIC recovery as of December 31, 2023 was $399.6 million. The jurisdictional revenue requirement approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2024 is a net cost to customers of $56.5 million.

IRP Filings and Replacement Generation

Electric utilities in Indiana are required to submit Integrated Resource Plans (IRPs) every three years. The IRPs are subject to a rigorous stakeholder process. IRPs describe how the utility plans to deliver safe, reliable, and efficient electricity at just and reasonable rates.

2022 IRP

AES Indiana held public advisory meetings for the 2022 IRP in January, April, June, September and October of 2022. Changes to our generation portfolio are evaluated and decided through the IRP. AES Indiana issued an all-source Request for Proposal on April 14, 2022, in order to competitively procure energy and capacity in the near term; such need was evaluated in AES Indiana's 2022 IRP.

In December 2022, AES Indiana filed its 2022 IRP with the IURC, which describes AES Indiana's Preferred Resource Portfolio for meeting generation capacity needs for serving AES Indiana's retail customers over the next several years. The Preferred Resource Portfolio is AES Indiana's reasonable least cost option and provides a cleaner and more diverse generation mix for customers. The 2022 IRP short-term action plan includes converting the two remaining coal units at Petersburg to natural gas. AES Indiana has not yet filed for the regulatory approvals from the IURC to convert Petersburg units 3 and 4; however, AES Indiana expects to do so in the first half of 2024. Construction is expected to begin in 2025 and be completed by the end of 2026. Additionally, AES Indiana plans to add up to 1,300 MW of wind, solar, and battery energy storage by 2027. As new technologies, such as green hydrogen, small modular reactors and carbon capture are developed and cost effective, AES Indiana will evaluate them in the future planning processes. As a result of the plan to convert Petersburg units 3 and 4 to natural gas, AES Indiana recorded a $1.5 million write off of capital projects during the period ended December 31, 2022 to "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

2019 IRP

In December 2019, AES Indiana filed its 2019 IRP, which included the retirement of approximately 630 MW of coal-fired generation at Petersburg Units 1 and 2 in 2021 and 2023, respectively. Based on extensive modeling, AES Indiana determined that the cost of operating Petersburg Units 1 and 2 exceeded the value customers received compared to alternative resources. Retirement of these units allowed the company to cost-effectively diversify the portfolio and transition to lower cost and cleaner resources while maintaining a reliable system.

AES Indiana issued an all-source Request for Proposal on December 20, 2019, in order to competitively procure replacement capacity by June 1, 2023, which was the first year AES Indiana was expected to have a capacity shortfall. Our modeling indicated that a combination of wind, solar, storage, and energy efficiency would be the lowest reasonable cost option for the replacement capacity. As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana recorded $0.7 million, $2.1 million, and $0.8 million of obsolescence losses, during the periods ended December 31, 2023, 2022, and 2021, respectively, for materials and supplies inventory AES Indiana did not believe will be utilized by the planned retirement dates, which is recorded in "Operating expenses - Operation and maintenance" on the accompanying Consolidated Statements of Operations.

As a result of the plans to retire Petersburg Units 1 and 2, AES Indiana filed a petition with the IURC on February 26, 2021 for approvals and cost recovery associated with these retirements. On August 6, 2021, AES Indiana filed an uncontested Stipulation and Settlement Agreement with the other parties in the case which includes: (1) AES Indiana's creation of regulatory assets for the net book value of Petersburg units 1 and 2 upon retirement; (2) a method for amortization of the regulatory assets; and (3) recovery of the regulatory assets through ongoing amortization in AES Indiana’s future rate cases. The Settlement Agreement also reserves all rights of all the parties with respect to the ratemaking treatment related to the regulatory assets, including the proper rate of return and mechanisms for recovery. On November 17, 2021, the IURC approved the Settlement Agreement without modification. AES Indiana retired 230 MW Petersburg Unit 1 in May 2021 and 415 MW Petersburg Unit 2 in June 2023.

AES Indiana had $35.7 million and $224.2 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2023. AES Indiana had $47.6 million and $239.9 million of Petersburg Units 1 and 2 retirement costs, respectively, net of accumulated amortization, recorded as long-term regulatory assets as of December 31, 2022.

Hardy Hills Solar Project

In January 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of the 195 MW Hardy Hills Solar Project to be developed in Clinton County, Indiana. In December 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2024, and adjusting for increased project costs. On January 13, 2023, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in August 2023.

On June 16, 2021, AES Indiana received an order from the IURC approving a petition and case-in-chief seeking a CPCN for this solar project, including a joint venture structure between an AES Indiana subsidiary and one or more tax equity partners upon completion and approval for recovery of project development costs and carrying costs on AES Indiana's investment in the project. The transaction closed in December 2021 and was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets and liabilities were recorded at their fair values. Total net assets of $51.6 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of a development project intangible asset (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets"). A gain for the difference between the consideration transferred and the assets and liabilities recognized was recorded in “Operating costs and expenses - Other, net” on the accompanying Consolidated Statements of Operations. Total consideration included a future payment contingent on certain future costs incurred by the project. As such, a $3.2 million contingent liability was recorded in "Other Non-Current Liabilities" on the accompanying Consolidated Balance Sheets as of December 31, 2021. During 2022, this liability was remeasured due to updated cost estimates and was reduced to $0.0 million.

On December 1, 2023, AES Indiana, through a wholly-owned subsidiary (the "Class B Member"), and a third-party investor (the "Class A Member"), entered into an Equity Capital Contribution Agreement, pursuant to which each member made certain capital contributions to Hardy Hills JV. The Class A member made total contributions of

$79.3 million through December 31, 2023. Hardy Hills JV is consolidated by the Class B Member under the Variable Interest Model, and noncontrolling interest (“NCI”) was recorded by AES Indiana at the amount of cash contributed by the Class A Member. In December 2023, the first stage of the construction for the Hardy Hills Solar Project was completed and placed in service, with initial operations for over half of the project commencing on December 28, 2023. Upon the first stage of the project being placed in service, the Company recognized $26.1 million of earnings from tax attributes using the HLBV method. The final stage for construction of the project is expected to be completed during the first half of 2024.

Petersburg Energy Center Project

In July 2021, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the acquisition and construction of a 250 MW solar and 45MW (180 MWh) energy storage facility to be developed in Pike County, Indiana. In October 2022, the agreement was amended to revise the project schedule, including shifting the completion date to 2025, and adjusting for increased project costs. On December 22, 2022, AES Indiana filed a petition with the IURC for approval of these revisions, which was approved in May 2023. On August 31, 2023, AES Indiana closed on the agreement for the acquisition and construction of the Petersburg Energy Center Project. This transaction was accounted for as an asset acquisition of a variable interest entity that did not meet the definition of a business; therefore, the individual assets were recorded at their fair values. Total net assets of $48.7 million were recorded in the accompanying Consolidated Balance Sheets associated with the transaction, primarily consisting of project development intangible assets (see Note 1, "Overview and Summary of Significant Accounting Policies - Intangible Assets" for further information).

Pike County BESS Project

In June 2023, AES Indiana, through a wholly-owned subsidiary, executed an agreement for the construction of the 200 MW (800 MWh) Pike County BESS Project to be developed at the AES Indiana Petersburg Plant site in Pike County, Indiana. On July 19, 2023, AES Indiana filed a petition and case-in-chief with the IURC seeking approval for a Clean Energy Project and associated timely cost recovery under Indiana Code for this project. A hearing for this case was held in October 2023, and IURC approval was received on January 17, 2024. The Pike County BESS Project is expected to be completed in 2024.

Hoosier Wind Project

On July 5, 2023, AES Indiana filed a Notice of Intent with the IURC to request approval of a Clean Energy Project and for issuance of a CPCN for the Hoosier Wind Project acquisition. The proposed Project is the acquisition of the Hoosier Wind Project, which is an existing 106 MW wind facility located in Benton County, Indiana. The Company executed the Purchase Agreement on July 28, 2023. A CPCN for this case was filed in early August 2023, and IURC approval was received on January 24, 2024. The acquisition of the Hoosier Wind Project is expected to be completed in the first quarter of 2024.

Incentives for Clean Energy Projects

Indiana Code 8-1-8 (the "clean energy statute") offers certain incentives for clean energy projects. Primarily, it allows for the timely recovery of costs and expenses incurred during construction and operation of eligible projects outside of a base rate proceeding. Clean energy projects eligible for incentives under this statute include renewable energy resources such as wind, photovoltaic cells and panels, solar energy, and energy storage systems or technologies, among others. AES Indiana filed for and received IURC approval of the Hoosier Wind Project and Pike County BESS Project under this statute. AES Indiana continues to evaluate projects which may also be filed under this statute.

IURC COVID-19 Orders

Due to the COVID-19 pandemic, there was a disconnection moratorium in 2020 for IURC-jurisdictional utilities, as well as suspension of certain utility fees (late fees, convenience fees, deposits, and disconnection/reconnection fees) from residential customers. The IURC authorized Indiana utilities to use regulatory accounting for any impacts associated with the moratorium and suspension. The IURC also authorized regulatory accounting treatment for COVID-19 related uncollectible and incremental bad debt expense. As a result of the IURC's COVID-19 related orders issued in 2020, AES Indiana has recorded a regulatory asset of $5.4 million as of December 31, 2023 and

2022, which will be recovered through base rates under the stipulation and settlement agreement entered into on November 22, 2023, if approved by the IURC.

EDG Rates

On March 1, 2021, AES Indiana filed a petition with the IURC for approval of its proposed rate for the procurement of EDG and related consumer EDG credit issues. The EDG rate replaced the net metering program beginning in July 2022, when net metering was no longer available to new customers. The IURC approved the EDG rate by order dated January 26, 2022, On March 16, 2022, the IURC denied the petition for reconsideration filed by the other parties on February 15, 2022. The matter was subject to an appeal filed by the other parties on February 22, 2022, which was held in abeyance by the Indiana Court of Appeals pending resolution of a petition to transfer to the Indiana Supreme Court filed in a similar case involving a different and unaffiliated utility. The stay was extended by the Indiana Court of Appeals on July 11, 2022. On January 4, 2023, the Indiana Supreme Court issued a final decision in favor of the utility in the similar case that served as the basis of the stay in the AES Indiana case. On February 3, 2023, the OUCC moved to dismiss the appeal, which motion was granted on February 13, 2023.

EV Portfolio Program

On January 27, 2023, AES Indiana filed with the IURC a request to approve its EV Portfolio and associated accounting and ratemaking treatment. The EV Portfolio includes two separate parts: (1) a set of EV specific rates, tariffs, and alternative pricing structures, and (2) a set of Public Use EV Pilot Programs. The EV portfolio is designed to produce net benefits for all customers through new retail margins and grid optimization. The projected costs to successfully implement the services proposed in the EV Portfolio are estimated at $16.2 million over the three-year period. AES Indiana requested approval to defer as a regulatory asset and recover in future base rates the cost necessary to implement the EV Portfolio, including carrying charges. A hearing on this request was held in July 2023. On November 22, 2023, the IURC issued an order approving AES Indiana's EV Portfolio filing with approval to defer as a regulatory asset and to seek recovery in future base rates the cost necessary to implement the EV Portfolio, including carrying charges with no other significant modifications.

Storm Outage Restoration Inquiry

On July 11, 2023, the OUCC and the Citizens Action Coalition (“CAC”) filed a Joint Petition through which they requested the IURC open an investigation into AES Indiana’s practices and procedures regarding storm outage restoration. A technical conference was held on October 2, 2023, to discuss AES Indiana’s response to outages and storm restoration; particularly the storms that occurred between June 29, 2023 and July 2, 2023.

House Bill 1002

In the first quarter of 2022, the 2022 Indiana General Assembly passed House Enrolled Act 1002, which includes language regarding the repeal of the URT. AES Indiana filed a rate adjustment with the IURC on April 29, 2022, which was approved by the IURC on June 28, 2022. AES Indiana began charging the new rates excluding URT in July 2022. Prior to the repeal, the URT was recoverable through a current charge to customer rates. After the repeal, the new rates approved by the IURC adjusted both revenue and tax expense. As a result, the repeal of the URT had no impact on the Company's net income.

Regulatory Assets and Liabilities

Regulatory assets represent deferred costs or credits that have been included as allowable costs or credits for ratemaking purposes. AES Indiana has recorded regulatory assets or liabilities relating to certain costs or credits as authorized by the IURC or established regulatory practices in accordance with ASC 980. AES Indiana is amortizing non tax-related regulatory assets to expense over periods ranging from 1 to 43 years. Tax-related regulatory assets represent the net income tax costs to be considered in future regulatory proceedings generally as the tax-related amounts are paid.

The amounts of regulatory assets and regulatory liabilities at December 31 are as follows:

	2023		2022		Recovery Period
	(In Thousands)
Regulatory assets, current:
Undercollections of rate riders	$	75,416	$	26,047	Approximately 1 year(1)
Fuel costs	—		79,861		Approximately 1 year(1)
Unamortized reacquisition premium on debt	188		—		Approximately 1 year
Costs being recovered through basic rates and charges	13,815		13,815		Approximately 1 year(1)
Total regulatory assets, current	89,419		119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs	115,847		131,907		Various(2)
Deferred MISO costs	21,091		34,483		Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	2,812		3,866		Through 2026(1)(3)
Unamortized reacquisition premium on debt	13,379		14,429		Over remaining life of debt
Environmental costs	66,837		68,947		Through 2046(1)(3)
COVID-19 costs	5,426		5,426		4 years(4)
Major storm damage	1,493		—		To be determined
TDSIC costs	35,979		18,547		36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs	259,892		287,463		Through 2034(1)(3)
Hardy Hills Solar Project development costs	6,774		5,744		30 years(3)
Petersburg Energy Center Project development costs	2,469		1,582		30 years(3)
Pike County BESS Project development costs	2,623		—		20 years(3)
Fuel costs	4,275		20,518		Through 2025(1)
Other miscellaneous	2,887		1,027		Various(5)
Total regulatory assets, non-current	541,784		593,939
Total regulatory assets	$	631,203	$	713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders	$	19,649	$	15,803	Approximately 1 year(1)
FTRs	3,722		7,545		Approximately 1 year(1)
Total regulatory liabilities, current	23,371		23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs	451,886		518,797		Not applicable
Deferred income taxes payable to customers through rates	74,796		88,662		Various
Hardy Hills sponsor investment tax credit	542		—		To be determined(6)
Major storm damage	—		5,126		To be determined
Total regulatory liabilities, non-current	527,224		612,585
Total regulatory liabilities	$	550,595	$	635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

Current Regulatory Assets and Liabilities

Current regulatory assets and liabilities primarily represent costs that are being recovered per specific rate orders; recovery for the remaining costs is probable, but not certain. As current assets, this includes undercollection of adjustment mechanisms for: (i) DSM, (ii) ECCRA costs, (iii) Off System Sales Margin Sharing, (iv) Capacity rider costs and (v) TDSIC. It also includes the current portion of deferred MISO costs and environmental costs collected through base rates which are described in greater detail below. With the exception of environmental costs, these costs do not earn a return on investment. As current liabilities, this includes (i) overcollection of MISO rider costs, (ii) Green Power, and (iii) deferred fuel costs.

Deferred Fuel

Deferred fuel costs are a component of current and long-term regulatory assets or liabilities (which is a result of AES Indiana charging either more or less for fuel than our actual costs to our jurisdictional customers) and are expected to be recovered through future FAC proceedings. AES Indiana records deferred fuel in accordance with standards prescribed by the FERC. The deferred fuel adjustment is the result of variances between estimated fuel and purchased power costs in AES Indiana’s FAC and actual fuel and purchased power costs. AES Indiana is generally permitted to recover underestimated fuel and purchased power costs in future rates through the FAC proceedings and therefore the costs are deferred when incurred and amortized into fuel expense in the same period that AES Indiana’s rates are adjusted to reflect these costs. 

The Eagle Valley CCGT was on unplanned outage from late April 2021 until mid-March 2022, impacting several FAC periods. In November 2021, a sub-docket was created with the IURC to examine the unplanned outage. On October 25, 2022, AES Indiana and various intervening parties reached a unanimous settlement regarding the Eagle Valley CCGT unplanned outage, resolving all issues related to the FAC sub-docket and all outage related costs including energy purchases, Off-System Sales margins, Capacity trackers and base rate proceedings. As part of this comprehensive settlement, AES Indiana agreed not to recover $21.0 million of previously deferred costs and to credit an additional $6.8 million to customers in future rates. As such, AES Indiana recorded a $27.8 million charge to "Power purchased" in the Consolidated Statements of Operations during the third quarter of 2022. On January 18, 2023, AES Indiana received an order from the IURC approving the settlement.

Unrecognized Pension and Postretirement Benefit Plan Costs

In accordance with ASC 715 “Compensation – Retirement Benefits” and ASC 980, we recognize a regulatory asset equal to the unrecognized actuarial gains and losses and prior service costs. Pension expenses or income are recorded based on the benefit plan’s actuarially determined pension liability or asset and associated level of annual expenses or income to be recognized. The other postretirement benefit plan’s deferred benefit cost is the excess of the other postretirement benefit liability over the amount previously recognized.

Deferred MISO Costs

These consist of administrative costs for transmission services, transmission expansion cost sharing, and certain other operational and administrative costs from the MISO market. These costs are being recovered per specific rate order.  

Unamortized Petersburg Unit 4 Carrying Charges and Certain Other Costs

These consist of deferred debt carrying costs, depreciation, and post-in-service AFUDC on Petersburg Unit 4. These costs are being recovered per specific rate order.

Unamortized Reacquisition Premium on Debt

This regulatory asset represents losses on long-term debt reacquired or redeemed in prior periods that have been deferred. These deferred losses are being amortized over the lives of the original issues in accordance with the rules of the FERC and the IURC.

Environmental Costs

These consist of various costs incurred to comply with environmental regulations. These costs were approved for recovery either through AES Indiana's ECCRA proceedings or in the 2018 Base Rate Order. Amortization periods vary, ranging from 3 to 43 years.

COVID-19 Costs

These consist of deferred fees (foregone late fees, reconnection fees and disconnection fees), as well as deferred convenience payments and incremental bad debt expense as the result of COVID-19. See "IURC COVID-19 Orders" above for additional discussion.

TDSIC Costs

These consist of various costs incurred for AES Indiana's approved TDSIC Plan. These costs were approved for recovery through AES Indiana's TDSIC proceedings and amortization periods range from 1 to 36 years. See "TDSIC" above for additional discussion.

Petersburg Unit 1 and 2 Retirement Costs

These consist of the remaining unamortized net book value of Petersburg Unit 1 and 2. In accordance with ASC 980, it was determined that the Petersburg Unit 1 retirement became probable, in the fourth quarter of 2020, and the Petersburg Unit 2 retirement became probable in the fourth quarter of 2021. As the entire carrying value of these assets will be recoverable through future rates, no loss on abandonment was recorded and the asset was reclassified from net property, plant and equipment to a long-term regulatory asset. See "IRP Filings and Replacement Generation" above for additional discussion.

Hardy Hills Solar Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Hardy Hills Solar Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Hardy Hills Solar Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Petersburg Energy Center Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Petersburg Energy Center Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Petersburg Energy Center Project regulatory proceedings with an amortization period of 30 years. Amortization of the project development costs will be determined in a future rate case filing.

Pike County BESS Project Development Costs

These consist of project development costs, mainly legal and consulting fees, incurred for the Pike County BESS Project as well as carrying costs on AES Indiana's investment in the project. The investment costs were approved for recovery via the ECCRA rider through AES Indiana’s Pike County BESS Project regulatory proceedings with an amortization period of 20 years. Amortization of the project development costs will be determined in a future rate case filing.

FTRs

In connection with AES Indiana’s participation in MISO, in the second quarter of each year AES Indiana is granted financial instruments that can be converted into cash or FTRs based on AES Indiana’s forecasted peak load for the period. See Note 4, "Fair Value - Fair Value Hierarchy and Valuation Techniques - Financial Assets - FTRs" for additional information.

ARO and Accrued Asset Removal Costs

In accordance with ASC 410 and ASC 980, AES Indiana recognizes the amount collected in customer rates for costs of removal not yet incurred that do not have an associated legal retirement obligation as a deferred regulatory liability. This amount is net of the portion of legal ARO costs that are deferred that is also being recovered in rates.

Deferred Income Taxes Recoverable/Payable Through Rates

A deferred income tax asset or liability is created from a difference in timing of income recognition between tax laws and accounting methods. As a regulated utility, AES Indiana includes in ratemaking the impacts of current income taxes and changes in deferred income tax liabilities or assets.

On December 22, 2017, the U.S. federal government enacted the TCJA, which, among other things, reduced the federal corporate income tax rate from 35% to 21%, beginning January 1, 2018. As required by GAAP, on December 31, 2017, AES Indiana and IPALCO remeasured their deferred income tax assets and liabilities using the new tax rate. The impact of the reduction of the income tax rate on deferred income taxes was utilized in the 2018 Base Rate Order to reduce jurisdictional retail rates. Accordingly, we have a net regulatory deferred income tax liability of $74.8 million and $88.7 million as of December 31, 2023 and 2022, respectively.

Indianapolis Power And Light Company

Entity Information [Line Items]

Schedule Of Regulatory Assets And Liabilities [Table Text Block]

	2023		2022		Recovery Period
	(In Thousands)
Regulatory assets, current:
Undercollections of rate riders	$	75,416	$	26,047	Approximately 1 year(1)
Fuel costs	—		79,861		Approximately 1 year(1)
Unamortized reacquisition premium on debt	188		—		Approximately 1 year
Costs being recovered through basic rates and charges	13,815		13,815		Approximately 1 year(1)
Total regulatory assets, current	89,419		119,723
Regulatory assets, non-current:
Unrecognized pension and other
postretirement benefit plan costs	115,847		131,907		Various(2)
Deferred MISO costs	21,091		34,483		Through 2026(1)
Unamortized Petersburg Unit 4 carrying
charges and certain other costs	2,812		3,866		Through 2026(1)(3)
Unamortized reacquisition premium on debt	13,379		14,429		Over remaining life of debt
Environmental costs	66,837		68,947		Through 2046(1)(3)
COVID-19 costs	5,426		5,426		4 years(4)
Major storm damage	1,493		—		To be determined
TDSIC costs	35,979		18,547		36.3 years(1)(3)
Petersburg Unit 1 and 2 retirement costs	259,892		287,463		Through 2034(1)(3)
Hardy Hills Solar Project development costs	6,774		5,744		30 years(3)
Petersburg Energy Center Project development costs	2,469		1,582		30 years(3)
Pike County BESS Project development costs	2,623		—		20 years(3)
Fuel costs	4,275		20,518		Through 2025(1)
Other miscellaneous	2,887		1,027		Various(5)
Total regulatory assets, non-current	541,784		593,939
Total regulatory assets	$	631,203	$	713,662
Regulatory liabilities, current:
Overcollections and other credits being passed
to customers through rate riders	$	19,649	$	15,803	Approximately 1 year(1)
FTRs	3,722		7,545		Approximately 1 year(1)
Total regulatory liabilities, current	23,371		23,348
Regulatory liabilities, non-current:
ARO and accrued asset removal costs	451,886		518,797		Not applicable
Deferred income taxes payable to customers through rates	74,796		88,662		Various
Hardy Hills sponsor investment tax credit	542		—		To be determined(6)
Major storm damage	—		5,126		To be determined
Total regulatory liabilities, non-current	527,224		612,585
Total regulatory liabilities	$	550,595	$	635,933

(1)Recovered (credited) per specific rate orders

(2)AES Indiana receives a return on its discretionary funding

(3)Recovered with a current return

(4)Per the signed stipulation in the 2023 distribution rate case, Cause No. 45911

(5)Some of these costs are being recovered in basic rates and charges through 2026. For the remainder, recovery over four years was agreed to in the signed stipulation in the 2023 distribution rate case, Cause No. 45911. AES Indiana will include this credit in a future ECR filing.

(6)Will be included in a future ECR filing

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Schedule Of Original Cost Of Utility Plant In Service

	As of December 31,
	2023		2022
	(In Thousands)
Production	$	3,942,052	$	4,164,416
Transmission	487,527		461,245
Distribution	2,304,526		2,045,579
General plant	348,338		311,074
Total property, plant and equipment	$	7,082,443	$	6,982,314

Reconciliation Of Asset Retirement Obligation Liability

The following is a roll forward of the ARO legal liability year end balances:

	2023		2022
	(In Thousands)
Balance as of January 1	$	218,729	$	189,509
Liabilities incurred	17,080		1,159
Liabilities settled	(11,902)		(24,699)
Revisions to cash flow and timing estimates	12,921		44,679
Accretion expense	13,102		8,081
Balance as of December 31	$	249,930	$	218,729

Indianapolis Power And Light Company

Entity Information [Line Items]

Schedule Of Original Cost Of Utility Plant In Service

	As of December 31,
	2023		2022
	(In Thousands)
Production	$	3,942,052	$	4,164,416
Transmission	487,527		461,245
Distribution	2,304,526		2,045,579
General plant	348,338		311,074
Total property, plant and equipment	$	7,082,443	$	6,982,314

Reconciliation Of Asset Retirement Obligation Liability

The following is a roll forward of the ARO legal liability year end balances:

	2023		2022
	(In Thousands)
Balance as of January 1	$	218,729	$	189,509
Liabilities incurred	17,080		1,159
Liabilities settled	(11,902)		(24,699)
Revisions to cash flow and timing estimates	12,921		44,679
Accretion expense	13,102		8,081
Balance as of December 31	$	249,930	$	218,729

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Summary of Fair Value Assets and Liabilities Measured on a Recurring Basis, Level 3

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for IPALCO was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
VEBA investments:
Money market funds	$	127	$	—	$	—	$	127	$	5	$	—	$	—	$	5
Mutual funds	3,425		—		—		3,425		3,223		—		—		3,223
Total VEBA investments	3,552		—		—		3,552		3,228		—		—		3,228
FTRs	—		—		1,388		1,388		—		—		7,545		7,545
Interest rate hedges	—		14,294		—		14,294		—		12,172		—		12,172
Total financial assets measured at fair value	$	3,552	$	14,294	$	1,388	$	19,234	$	3,228	$	12,172	$	7,545	$	22,945

Reconciliation of Financial Instruments Classified as Level 3

The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	1,235
Issuances	15,338
Settlements	(9,028)
Balance at December 31, 2022	7,545
Issuances	3,624
Settlements	(9,781)
Balance at December 31, 2023	$	1,388

Schedule of Face and Fair Value of Debt

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending:

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	3,033,800	$	2,860,467	$	3,033,800	$	2,775,644
Variable-rate	455,000		455,000		—		—
Total indebtedness	$	3,488,800	$	3,315,467	$	3,033,800	$	2,775,644

Indianapolis Power And Light Company

Entity Information [Line Items]

Fair Value Assets And Liabilities Measured On A Recurring Basis Unobservable Inputs [Table Text Block]

The fair value of assets at December 31, 2023 and 2022 measured on a recurring basis and the respective category within the fair value hierarchy for AES Indiana was determined as follows:

	Fair Value as of December 31, 2023								Fair Value as of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(In Thousands)
Financial assets:
FTRs	$	—	$	—	$	1,388	$	1,388	$	—	$	—	$	7,545	$	7,545
Total financial assets measured at fair value	$	—	$	—	$	1,388	$	1,388	$	—	$	—	$	7,545	$	7,545

Reconciliation of Financial Instruments Classified as Level 3

The following table sets forth a roll forward of financial instruments, measured at fair value on a recurring basis, classified as Level 3 in the fair value hierarchy (note, amounts in this table indicate carrying values, which approximate fair values):

	Reconciliation of Financial Instruments Classified as Level 3
	(In Thousands)
Balance at January 1, 2022	$	1,235
Issuances	15,338
Settlements	(9,028)
Balance at December 31, 2022	7,545
Issuances	3,624
Settlements	(9,781)
Balance at December 31, 2023	$	1,388

Schedule of Face and Fair Value of Debt

The following table shows the face value and the fair value of fixed-rate and variable-rate indebtedness (Level 2) for the periods ending: 

	December 31, 2023				December 31, 2022
	Face Value		Fair Value		Face Value		Fair Value
	(In Thousands)
Fixed-rate	$	2,153,800	$	2,020,997	$	2,153,800	$	1,959,233
Variable-rate	455,000		455,000		—		—
Total indebtedness	$	2,608,800	$	2,475,997	$	2,153,800	$	1,959,233

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2023

Derivative [Line Items]

Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]

The following tables provide information on gains or losses recognized in AOCI / (AOCL) for the cash flow hedges for the periods indicated:

	Interest Rate Hedges for the Years Ended December 31,
$ in thousands (net of tax)	2023		2022		2021
Beginning accumulated derivative gain / (loss) in AOCI / (AOCL)	$	22,269	$	(29,407)	$	(43,420)
Net gains associated with current period hedging transactions	1,594		46,245		10,393
Net losses reclassified to interest expense	5,431		5,431		3,620
Ending accumulated derivative gain / (loss) in AOCI / (AOCL)	$	29,294	$	22,269	$	(29,407)
Loss expected to be reclassified to earnings in the next twelve months	$	(5,375)
Maximum length of time that we are hedging our exposure to variability in future cash flows related to forecasted transactions (in months)	9

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
FTRs	Not a Cash Flow Hedge	Derivative assets, current	$	1,388	$	7,545
Interest rate hedges	Cash Flow Hedge	Derivative assets, current	$	14,294	$	—
Interest rate hedges	Cash Flow Hedge	Derivative assets, non-current	$	—	$	12,172

Schedule of Derivative Instruments [Table Text Block]

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)		Sales (in thousands)		Net Notional (in thousands)
Interest rate hedges	Designated	USD	$	400,000	$	—	$	400,000
FTRs	Not Designated	MWh	3,919		—		3,919

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

Subsidiaries [Member]

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

			December 31,
Commodity	Hedging Designation	Balance sheet classification	2023		2022
FTRs	Not a Cash Flow Hedge	Prepayments and other current assets	$	1,388	$	7,545

Schedule of Derivative Instruments [Table Text Block]

At December 31, 2023, AES Indiana's outstanding derivative instruments were as follows:

Commodity	Accounting Treatment (a)	Unit	Notional (in thousands)	Sales (in thousands)	Net Notional (in thousands)
FTRs	Not Designated	MWh	3,919	—	3,919

(a)    Refers to whether the derivative instruments have been designated as a cash flow hedge.

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Debt (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Schedule Long-Term Indebtedness

The following table presents our long-term debt:

		December 31,
Series	Due	2023		2022
		(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)	December 2024	$	40,000	$	40,000
0.65% (1)	August 2025	40,000		40,000
0.75% (2)	April 2026	30,000		30,000
0.95% (2)	April 2026	60,000		60,000
1.40% (1)	August 2029	55,000		55,000
5.65%	December 2032	350,000		350,000
6.60%	January 2034	100,000		100,000
6.05%	October 2036	158,800		158,800
6.60%	June 2037	165,000		165,000
4.875%	November 2041	140,000		140,000
4.65%	June 2043	170,000		170,000
4.50%	June 2044	130,000		130,000
4.70%	September 2045	260,000		260,000
4.05%	May 2046	350,000		350,000
4.875%	November 2048	105,000		105,000
Unamortized discount – net		(6,449)		(6,651)
Deferred financing costs		(19,058)		(20,362)
Total AES Indiana first mortgage bonds		2,128,293		2,126,787
Total long-term debt – AES Indiana		2,128,293		2,126,787
Long-term debt – IPALCO:
3.70% Senior Secured Notes	September 2024	405,000		405,000
4.25% Senior Secured Notes	May 2030	475,000		475,000
Unamortized discount – net		(319)		(425)
Deferred financing costs		(4,554)		(5,912)
Total long-term debt – IPALCO		875,127		873,663
Total consolidated IPALCO long-term debt		3,003,420		3,000,450
Less: current portion of long-term debt		445,000		—
Net consolidated IPALCO long-term debt		$	2,558,420	$	3,000,450

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

Schedule Of Maturities On Long-Term Indebtedness

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:

Year	Amount
	(In Thousands)
2024	$	445,000
2025	40,000
2026	90,000
2027	—
2028	—
Thereafter	2,458,800
	3,033,800
Unamortized discounts	(6,768)
Deferred financing costs, net	(23,612)
Total long-term debt	$	3,003,420

Indianapolis Power And Light Company

Entity Information [Line Items]

Schedule Long-Term Indebtedness

The following table presents AES Indiana’s long-term debt:

		December 31,
Series	Due	2023		2022
		(In Thousands)
AES Indiana first mortgage bonds:
3.125% (1)	December 2024	$	40,000	$	40,000
0.65% (1)	August 2025	40,000		40,000
0.75% (2)	April 2026	30,000		30,000
0.95% (2)	April 2026	60,000		60,000
1.40% (1)	August 2029	55,000		55,000
5.650%	December 2032	350,000		350,000
6.60%	January 2034	100,000		100,000
6.05%	October 2036	158,800		158,800
6.60%	June 2037	165,000		165,000
4.875%	November 2041	140,000		140,000
4.65%	June 2043	170,000		170,000
4.50%	June 2044	130,000		130,000
4.70%	September 2045	260,000		260,000
4.05%	May 2046	350,000		350,000
4.875%	November 2048	105,000		105,000
Unamortized discount – net		(6,449)		(6,651)
Deferred financing costs		(19,058)		(20,362)
Total AES Indiana first mortgage bonds		2,128,293		2,126,787
Total consolidated AES Indiana long-term debt		2,128,293		2,126,787
Less: current portion of long-term debt		40,000		—
Net consolidated AES Indiana long-term debt		$	2,088,293	$	2,126,787

(1)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority.

(2)First mortgage bonds issued to the Indiana Finance Authority, to secure the loan of proceeds from tax-exempt bonds issued by the Indiana Finance Authority. The notes have a final maturity date of December 31, 2038, but are subject to a mandatory put in April 2026.

Schedule Of Maturities On Long-Term Indebtedness

Maturities on long-term indebtedness subsequent to December 31, 2023 are as follows:

Year	Amount
	(In Thousands)
2024	$	40,000
2025	40,000
2026	90,000
2027	—
2028	—
Thereafter	1,983,800
	2,153,800
Unamortized discounts	(6,449)
Deferred financing costs, net	(19,058)
Total long-term debt	$	2,128,293

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Schedule Of Federal And State Income Taxed Charged To Income

Federal and state income taxes charged to income are as follows: 

	2023		2022		2021
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	(14,222)	$	22,539	$	28,100
State	(3,716)		6,026		8,218
Total current income taxes	(17,938)		28,565		36,318
Deferred income taxes:
Federal	24,885		(6,920)		(7,286)
State	7,768		214		(91)
Total deferred income taxes	32,653		(6,706)		(7,377)
Total income tax expense	$	14,715	$	21,859	$	28,941

Schedule Of Effective Income Tax Rate

The provision for income taxes (including net investment tax credit adjustments) is different than the amount computed by applying the statutory tax rate to pretax income. The reasons for the difference, stated as a percentage of pretax income, are as follows: 

	2023		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
State income tax, net of federal tax benefit	3.9	%	3.9	%	4.0	%
Depreciation flow through and amortization	(12.9)	%	(7.8)	%	(6.3)	%
AFUDC - equity	(0.3)	%	0.9	%	0.4	%
Noncontrolling interests in subsidiaries	9.0	%	—	%	—	%
Other – net	(0.2)	%	0.4	%	0.4	%
Effective tax rate	20.5	%	18.4	%	19.5	%

Schedule Of Deferred Tax Assets And Liabilities

The significant items comprising IPALCO’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows:

	2023		2022
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	409,675	$	341,473
Regulatory assets recoverable through future rates	108,823		123,669
Other	17,694		17,953
Total deferred tax liabilities	536,192		483,095
Deferred tax assets:
Investment tax credit	5		6
Regulatory liabilities including ARO	168,619		167,725
Investments in tax partnerships	2,501		—
Other	3,579		2,723
Total deferred tax assets	174,704		170,454
Deferred income tax liability – net	$	361,488	$	312,641

Reconciliation Of Unrecognized Tax Benefits

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021: 

	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	—	$	—	$	7,368
Gross decreases – prior period tax positions	—		—		(7,368)
Unrecognized tax benefits at December 31	$	—	$	—	$	—

Indianapolis Power And Light Company

Entity Information [Line Items]

Schedule Of Federal And State Income Taxed Charged To Income

Federal and state income taxes charged to income are as follows:

	2023		2022		2021
	(In Thousands)
Components of income tax expense:
Current income taxes:
Federal	$	1,816	$	31,286	$	36,353
State	268		8,185		10,325
Total current income taxes	2,084		39,471		46,678
Deferred income taxes:
Federal	17,631		(6,822)		(7,283)
State	5,951		238		(90)
Total deferred income taxes	23,582		(6,584)		(7,373)
Total income tax expense	$	25,666	$	32,887	$	39,305

Schedule Of Effective Income Tax Rate

The reasons for the difference, stated as a percentage of pretax income, are as follows:

	2023		2022		2021
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
State income tax, net of federal tax benefit	3.9	%	3.9	%	4.0	%
Depreciation flow through and amortization	(8.0)	%	(5.7)	%	(4.9)	%
AFUDC - equity	(0.2)	%	0.7	%	0.3	%
Noncontrolling interests in subsidiaries	5.6	%	—	%	—	%
Other – net	(0.1)	%	0.3	%	0.3	%
Effective tax rate	22.2	%	20.2	%	20.7	%

Schedule Of Deferred Tax Assets And Liabilities

The significant items comprising AES Indiana’s net accumulated deferred tax liability recognized on the audited Consolidated Balance Sheets as of December 31, 2023 and 2022 are as follows: 

	2023		2022
	(In Thousands)
Deferred tax liabilities:
Relating to utility property, net	$	409,675	$	341,473
Regulatory assets recoverable through future rates	108,823		123,669
Other	7,975		22,717
Total deferred tax liabilities	526,473		487,859
Deferred tax assets:
Investment tax credit	5		6
Regulatory liabilities including ARO	168,619		167,726
Investments in tax partnerships	2,483		—
Operating loss carryforwards	9,230		—
Other	3,579		15,020
Total deferred tax assets	183,916		182,752
Deferred income tax liability – net	$	342,557	$	305,107

Reconciliation Of Unrecognized Tax Benefits

The following is a reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2023, 2022 and 2021:

	2023		2022		2021
	(In Thousands)
Unrecognized tax benefits at January 1	$	—	$	—	$	7,368
Gross decreases – prior period tax positions	—		—		(7,368)
Unrecognized tax benefits at December 31	$	—	$	—	$	—

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Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2023

Entity Information [Line Items]

Schedule Of Defined Benefit Plans Disclosures

The following table presents information relating to the Pension Plans: 

	Pension benefits as of December 31,
	2023		2022
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	577,530	$	772,040
Service cost	5,189		8,949
Interest cost	29,818		18,099
Actuarial loss (gain)	9,681		(182,590)
Amendments (primarily increases in pension bands)	653		—
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Projected benefit obligation at December 31	549,546		577,529
Change in plan assets:
Fair value of plan assets at January 1	611,125		820,684
Actual return/(loss) on plan assets	52,905		(171,002)
Employer contributions	114		412
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Fair value of plan assets at December 31	590,819		611,125
Funded status	$	41,273	$	33,596
Amounts recognized in the statement of financial position:
Non-current assets	$	41,273	$	33,611
Non-current liabilities	—		(15)
Net amount recognized at end of year	$	41,273	$	33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	653	$	—
Net (gain)/loss arising during period	(10,117)		24,069
Amortization of prior service cost	(2,172)		(2,589)
Amortization of loss	(6,145)		(2,622)
Total recognized in regulatory assets	$	(17,781)	$	18,858
Amounts included in regulatory assets:
Net loss	$	115,297	$	131,559
Prior service cost	10,136		11,655
Total amounts included in regulatory assets	$	125,433	$	143,214

Schedule Of Net Periodic Benefit Costs

	Pension benefits for years ended December 31,
	2023			2022			2021
	(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost	$	5,189		$	8,949		$	9,339
Interest cost	29,818			18,099			15,660
Expected return on plan assets	(33,107)			(35,656)			(41,815)
Amortization of prior service cost	2,172			2,589			2,944
Amortization of actuarial loss	6,145			2,424			5,529
Amortization of settlement loss	—			199			—
Net periodic benefit cost / (credit)	10,217			(3,396)			(8,343)
Less: amounts capitalized	1,689			(316)			(771)
Amount charged to expense	$	8,528		$	(3,080)		$	(7,572)
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	5.41		%	2.83		%	2.46		%
Discount rate – supplemental retirement plan	5.32		%	2.62		%	2.31		%
Expected return on defined benefit pension plan assets	5.60		%	4.45		%	5.05		%
Expected return on supplemental retirement plan assets	6.45		%	5.50		%	3.60		%

Schedule Of Asset Allocation Guidelines

The following table summarizes the Company’s target pension plan allocation for 2023:

Asset Category:	Target Allocations
Equity Securities	13.5%
Debt Securities	86.5%

Schedule Of Fair Value Of Pension Plan Assets

	Fair Value Measurements at
	December 31, 2023
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	82,652	$	2,267	$	80,385	14	%
Debt securities (b)	387,979		1,168		386,811		66	%
Government debt securities (c)	117,397		178		117,219		20	%
Total common collective trusts	588,028		3,613		584,415		100	%
Cash and cash equivalents (d)	2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

	Fair Value Measurements at
	December 31, 2022
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	85,341	$	2,017	$	83,324	14	%
Debt securities (b)	400,291		1,254		399,037		66	%
Government debt securities (c)	122,704		420		122,284		20	%
Total common collective trusts	608,336		3,691		604,645		100	%
Cash and cash equivalents (d)	2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645	100	%

Schedule Of Expected Benefit Payments

Benefit payments, which reflect future service, are expected to be paid out of the Pension Plans as follows:

Year	Pension Benefits
	(In Thousands)
2024	$	37,997
2025	38,794
2026	39,665
2027	40,085
2028	41,477
2029 through 2033	200,574

Indianapolis Power And Light Company

Entity Information [Line Items]

Schedule Of Defined Benefit Plans Disclosures

	Pension benefits as of December 31,
	2023		2022
	(In Thousands)
Change in benefit obligation:
Projected benefit obligation at January 1	$	577,530	$	772,040
Service cost	5,189		8,949
Interest cost	29,818		18,099
Actuarial loss (gain)	9,681		(182,590)
Amendments (primarily increases in pension bands)	653		—
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Projected benefit obligation at December 31	549,546		577,529
Change in plan assets:
Fair value of plan assets at January 1	611,125		820,684
Actual return/(loss) on plan assets	52,905		(171,002)
Employer contributions	114		412
Settlements	—		(394)
Benefits paid	(73,325)		(38,575)
Fair value of plan assets at December 31	590,819		611,125
Funded status	$	41,273	$	33,596
Amounts recognized in the statement of financial position:
Non-current assets	$	41,273	$	33,611
Non-current liabilities	—		(15)
Net amount recognized at end of year	$	41,273	$	33,596
Sources of change in regulatory assets(1):
Prior service cost arising during period	$	653	$	—
Net (gain)/loss arising during period	(10,117)		24,069
Amortization of prior service cost	(2,172)		(2,589)
Amortization of loss	(6,145)		(2,622)
Total recognized in regulatory assets	$	(17,781)	$	18,858
Amounts included in regulatory assets:
Net loss	$	115,297	$	131,559
Prior service cost	10,136		11,655
Total amounts included in regulatory assets	$	125,433	$	143,214

Schedule Of Net Periodic Benefit Costs

	Pension benefits for years ended December 31,
	2023			2022			2021
	(In Thousands)
Components of net periodic benefit cost / (credit):
Service cost	$	5,189		$	8,949		$	9,339
Interest cost	29,818			18,099			15,660
Expected return on plan assets	(33,107)			(35,656)			(41,815)
Amortization of prior service cost	2,172			2,589			2,944
Amortization of actuarial loss	6,145			2,424			5,529
Amortization of settlement loss	—			199			—
Net periodic benefit cost / (credit)	10,217			(3,396)			(8,343)
Less: amounts capitalized	1,689			(316)			(771)
Amount charged to expense	$	8,528		$	(3,080)		$	(7,572)
Rates relevant to each year’s expense calculations:
Discount rate – defined benefit pension plan	5.41		%	2.83		%	2.46		%
Discount rate – supplemental retirement plan	5.32		%	2.62		%	2.31		%
Expected return on defined benefit pension plan assets	5.60		%	4.45		%	5.05		%
Expected return on supplemental retirement plan assets	6.45		%	5.50		%	3.60		%

Schedule Of Asset Allocation Guidelines

Asset Category:	Target Allocations
Equity Securities	13.5%
Debt Securities	86.5%

Schedule Of Fair Value Of Pension Plan Assets

	Fair Value Measurements at
	December 31, 2023
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	82,652	$	2,267	$	80,385	14	%
Debt securities (b)	387,979		1,168		386,811		66	%
Government debt securities (c)	117,397		178		117,219		20	%
Total common collective trusts	588,028		3,613		584,415		100	%
Cash and cash equivalents (d)	2,791		2,791		—		—	%
Total pension plan assets	$	590,819	$	6,404	$	584,415	100	%

(a) This category represents investments that invest in equity securities of U.S. companies of any market capitalization and other investments (i.e.: futures, swaps, currency forwards) of foreign, emerging markets and seeks to provide long-term total return, which includes capital appreciation and income. The funds are valued using the net asset value method.

(b) This category represents investments that invest in high quality issues within the U.S. corporate bond markets and global high yield bonds and emerging markets debt denominated in local currency. The funds seek to provide current income and long-term capital preservation along with access to higher yielding, relatively liquid fixed income securities. The funds are valued using the net asset value method.

(c) This category represents investments that invest in U.S. treasury strips, U.S. government agency obligations, and U.S. treasury obligations. The funds seek investment returns over the long term and are valued using the net asset value method.

(d) This category represents an investment that seeks to maximize current income on cash reserves to the extent consistent with principal preservation and maintenance of liquidity from a portfolio of obligations of the U.S. Government, its agencies or municipalities, and related money market instruments. Principal preservation is a primary objective. The fund is valued at cost.

	Fair Value Measurements at
	December 31, 2022
	(in thousands)
			Quoted Prices in Active Markets for Identical Assets		Significant Observable Inputs
Asset Category	Total		(Level 1)		(Level 2)		%
Common collective trusts:
Equities (a)	$	85,341	$	2,017	$	83,324	14	%
Debt securities (b)	400,291		1,254		399,037		66	%
Government debt securities (c)	122,704		420		122,284		20	%
Total common collective trusts	608,336		3,691		604,645		100	%
Cash and cash equivalents (d)	2,789		2,789		—		—	%
Total pension plan assets	$	611,125	$	6,480	$	604,645	100	%

Schedule Of Expected Benefit Payments

Year	Pension Benefits
	(In Thousands)
2024	$	37,997
2025	38,794
2026	39,665
2027	40,085
2028	41,477
2029 through 2033	200,574

XML

Commitment and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Oil and Gas, Delivery Commitment

	Payments due in:
	Total		Less Than 1 Year		1 – 3 Years		3 – 5 Years		More Than 5 Years
	(In Millions)
Purchase obligations:
Coal, gas, purchased power and
related transportation	$	933.5	$	249.7	$	267.3	$	225.7	$	190.8
Other	$	409.1	$	355.0	$	32.8	$	20.2	$	1.1

XML

Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Summary Of Company's Reporting Segments

The following table provides information about IPALCO’s business segments (in thousands):

	2023						2022						2021
	Utility		Other		Total		Utility		Other		Total		Utility		Other		Total
Revenue	$	1,649,917	$	—	$	1,649,917	$	1,791,711	$	—	$	1,791,711	$	1,426,132	$	—	$	1,426,132
Depreciation and amortization	$	287,863	$	—	$	287,863	$	266,504	$	—	$	266,504	$	256,085	$	—	$	256,085
Interest expense	$	99,051	$	43,875	$	142,926	$	87,428	$	43,804	$	131,232	$	84,256	$	41,370	$	125,626
Income/(loss) before income tax	$	115,763	$	(44,021)	$	71,742	$	162,862	$	(44,377)	$	118,485	$	189,548	$	(41,425)	$	148,123
Capital expenditures(1)	$	902,705	$	—	$	902,705	$	496,510	$	—	$	496,510	$	291,546	$	—	$	291,546
(1) Capital expenditures includes $0 thousand, $0 thousand and $36 thousand of payments for financed capital expenditures in 2023, 2022 and 2021, respectively.
	As of December 31, 2023						As of December 31, 2022						As of December 31, 2021
Total assets	$	6,129,581	$	51,942	$	6,181,523	$	5,559,977	$	29,237	$	5,589,214	$	5,222,987	$	16,780	$	5,239,767

XML

Revenue (Tables)

12 Months Ended

Dec. 31, 2023

Disaggregation of Revenue [Line Items]

Disaggregation of Revenue [Table Text Block]

’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

Revenue from Contract with Customer [Text Block]

REVENUE

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents our revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

The Company has elected to apply the optional disclosure exemptions under ASC 606. Therefore, the Company has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which we expect to be entitled.

Indianapolis Power And Light Company

Disaggregation of Revenue [Line Items]

Disaggregation of Revenue [Table Text Block]

he following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

Revenue from Contract with Customer [Text Block]

Revenue is primarily earned from retail and wholesale electricity sales and electricity transmission and distribution delivery services. Revenue is recognized upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Revenue is recorded net of any taxes assessed on and collected from customers, which are remitted to the governmental authorities.

Retail revenue - AES Indiana energy sales to utility customers are based on the reading of meters at the customer’s location that occurs on a systematic basis throughout the month. AES Indiana sells electricity directly to end-users, such as homes and businesses, and bills customers directly. Retail revenue have a single performance obligation, as the promise to transfer energy and other distribution and/or transmission services are not separately identifiable from other promises in the contracts and, therefore, are not distinct. Additionally, as the performance obligation is satisfied over time as energy is delivered, and the same method is used to measure progress, the performance obligation meets the criteria to be considered a series.

In exchange for the exclusive right to sell or distribute electricity in our service area, AES Indiana is subject to rate regulation by federal and state regulators. This regulation sets the framework for the prices (“tariffs”) that AES Indiana is allowed to charge customers for electric services. Since tariffs are approved by the regulator, the price that AES Indiana has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period. Therefore, revenue under these contracts is recognized using an output method measured by the MWhs delivered each month at the approved tariff. Customer payments are typically due on a monthly basis.

Wholesale revenue - Power produced at the generation stations in excess of our retail load is sold into the MISO market. Such sales are made at either the day-ahead or real-time hourly market price, and these sales are classified as wholesale revenue. We sell to and purchase power from MISO, and such sales and purchases are settled and accounted for on a net hourly basis.

In the MISO market, wholesale revenue is recorded at the spot price based on the quantities of MWh delivered in each hour during each month. As a member of MISO, we are obligated to declare the availability of our energy production into the wholesale energy market, but we are not obligated to commit our previously declared availability. As such, contract terms end as the energy for each day is delivered to the market in the case of the day-ahead market and for each hour in the case of the real-time market.

Miscellaneous revenue - Miscellaneous revenue is mainly comprised of MISO transmission revenue and capacity revenue. MISO transmission revenue is earned when AES Indiana’s power lines are used in transmission of energy by power producers other than AES Indiana. As AES Indiana owns and operates transmission lines in central and southern Indiana, demand charges collected from network customers by MISO are allocated to the appropriate transmission owners (including AES Indiana) and recognized as transmission revenue. Capacity revenue is also included in miscellaneous revenue, and represent compensation received from MISO for making installed generation capacity available to satisfy system integrity and reliability requirements through the annual MISO capacity auction. Capacity, which is a stand-ready obligation to deliver energy when called upon by the RTO, is measured using MWs.

Transmission and capacity revenue each have a single performance obligation, as they each represent a distinct service or good. Additionally, as these performance obligations are satisfied over time and the same method is used to measure progress, the performance obligations meet the criteria to be considered a series. For transmission revenue, the price that the transmission operator has the right to bill corresponds directly with the value to the customer of AES Indiana’s performance completed in each period as the price paid is the transmission operator's allocation of the tariff rate (as approved by the regulator) charged to network participants. For capacity revenue, the capacity price that clears at the auction is fixed and AES Indiana is compensated based on the cleared MWs and cleared price.

AES Indiana’s revenue from contracts with customers was $1,616.5 million, $1,760.0 million and $1,389.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. The following table presents AES Indiana's revenue from contracts with customers and other revenue (in thousands):

	For the Years Ended December 31,
	2023		2022		2021
Retail Revenue
Retail revenue from contracts with customers:
Residential	$	660,559	$	688,487	$	595,692
Small commercial and industrial	241,800		247,655		211,997
Large commercial and industrial	619,899		625,351		518,069
Public lighting	9,767		9,832		8,888
Other (1)	14,016		17,845		16,785
Total retail revenue from contracts with customers	1,546,041		1,589,170		1,351,431
Alternative revenue programs	30,414		29,171		35,248
Wholesale Revenue
Wholesale revenue from contracts with customers	56,557		148,517		25,059
Miscellaneous Revenue
Capacity revenue	8,210		11,750		734
Transmission and other revenue	5,654		10,534		11,480
Total miscellaneous revenue from contracts with customers	13,864		22,284		12,214
Other miscellaneous revenue (2)	3,041		2,569		2,180
Total Revenue	$	1,649,917	$	1,791,711	$	1,426,132

(1) Other retail revenue from contracts with customers includes miscellaneous charges to customers, including reconnection and late fee charges.

(2) Other miscellaneous revenue includes lease and other miscellaneous revenue not accounted for under ASC 606.

The balances of receivables from contracts with customers were $218.8 million and $198.3 million as of December 31, 2023 and 2022, respectively. Payment terms for all receivables from contracts with customers typically do not extend beyond 30 days, unless a customer qualifies for payment extension.

AES Indiana has elected to apply the optional disclosure exemptions under ASC 606. Therefore, AES Indiana has not included disclosure pertaining to revenue expected to be recognized in any future year related to remaining performance obligations, as we exclude contracts with an original length of one year or less, contracts for which we recognize revenue based on the amount we have the right to invoice for services performed, and contracts with variable consideration allocated entirely to a wholly unsatisfied performance obligation when the consideration

relates specifically to our efforts to satisfy the performance obligation and depicts the amount to which AES Indiana expects to be entitled.

XML

Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Lease Balance Sheet Components

The following table summarizes the amounts recognized on the Consolidated Balance Sheets related to lease asset and liability balances as of the periods indicated (in thousands):

	Consolidated Balance Sheet Classification	December 31, 2023		December 31, 2022
Assets
Right-of-use assets — finance leases	Other non-current assets	$	16,357	$	15,819
Liabilities
Finance lease liabilities (noncurrent)	Long-term debt	$	17,769	$	16,361
Total finance lease liabilities		$	17,769	$	16,361

Lease Term and Discount Rate

The following table summarizes supplemental balance sheet information related to leases as of the periods indicated:

Lease Term and Discount Rate	December 31, 2023		December 31, 2022
Weighted-average remaining lease term — finance leases	35 years		36 years
Weighted-average discount rate — finance leases	5.30	%	5.650	%

Lease, Cost

The following table summarizes the components of lease expense recognized in "Operating Costs and Expenses" on the accompanying Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021, respectively (in thousands):

	For the Year Ended December 31,
Components of Lease Cost	2023		2022		2021
Finance lease cost:
Amortization of right-of-use assets	$	445	$	542	$	—
Interest on lease liabilities	933		782		—
Total lease cost	$	1,378	$	1,324	$	—

Schedule of Future Minimum Rental Payments for Operating Leases

The following table shows the future lease payments under finance leases together with the present value of the net lease payments as of December 31, 2023 for 2024 through 2028 and thereafter (in thousands):

	Finance Leases
2024	$	891
2025	909
2026	927
2027	945
2028	965
Thereafter	39,958
Total	$	44,595
Less: Imputed interest	(26,826)
Present value of lease payments	$	17,769

Operating Lease, Lease Income

	For the Year Ended December 31,
	2023		2022		2021
Total lease revenue	$	1,537	$	1,134	$	1,439

Schedule of Capital Leased Assets

Property, Plant and Equipment, Net	December 31, 2023		December 31, 2022
Gross assets	$	4,341	$	4,334
Less: Accumulated depreciation	(1,222)		(1,060)
Net assets	$	3,119	$	3,274

XML

Overview and Summary of Significant Accounting Policies (Details)

12 Months Ended

Feb. 16, 2026

Dec. 31, 2023

USD ($)

customer

generating_station

item

MW

Dec. 31, 2022

USD ($)

Dec. 31, 2021

USD ($)

Dec. 31, 2019

segment

May 31, 2021

Dec. 31, 2020

USD ($)

Significant Accounting Policies [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax

$ 29,294,000

$ 22,269,000

$ (29,407,000)

$ (43,420,000)

Other Comprehensive Income (Loss), Net of Tax

7,025,000

51,676,000

14,013,000

Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax

1,594,000

46,245,000

10,393,000

Public Utilities, Approved Rate Increase (Decrease), Amount

43,900,000

Public Utilities, Inventory

77,198,000

60,497,000

Receivables from Customers

125,715,000

125,540,000

Cash and Cash Equivalents, at Carrying Value

28,579,000

201,548,000

Service cost

5,189,000

8,949,000

9,339,000

Interest cost

$ 29,818,000

18,099,000

$ 15,660,000

Ownership interest in IPALCO by AES U.S. Investments (percent)

82.35%

Ownership interest in IPALCO by CDPQ (percent)

17.65%

Number of customers | customer

523,000

Number of generating stations | generating_station

4

Electric generation capability for winter, megawatts | MW

3,070

Electric generation capability for summer, megawatts | MW

2,925

Total other non-current assets

$ 1,120,591,000

849,054,000

Unbilled energy revenues

91,463,000

74,488,000

Loans and Leases Receivable, Related Parties, Description

5,178,000

239,000

Provision for doubtful accounts

$ 7,413,000

$ 5,851,000

Number of suppliers | item

1

Capitalized amount, rate

7.10%

5.40%

5.70%

Depreciation rate

3.70%

3.80%

3.70%

Depreciation expense

$ 244,800,000

$ 247,500,000

$ 239,100,000

Utility plant assets

4,500,000,000

4,000,000,000

Number of segments | segment

2

Intangible assets - net

235,656,000

138,978,000

Restricted Cash and Cash Equivalents

5,000

5,000

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents

28,584,000

201,553,000

6,917,000

26,622,000

Other Receivables

13,848,000

17,373,000

Accounts Receivable, Allowance for Credit Loss

(2,283,000)

(1,117,000)

Receivables, Net, Current

233,921,000

216,523,000

Materials and Supplies, Average Cost

66,392,000

63,111,000

Inventory, Net

143,590,000

123,608,000

Other Comprehensive Income (Loss), before Reclassifications, Net of Tax

1,594,000

46,245,000

10,393,000

Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent

5,431,000

5,431,000

3,620,000

Accounts receivable and unbilled revenue, allowance for doubtful accounts

2,283,000

1,117,000

647,000

Accounts Receivable, Allowance for Credit Loss, Writeoff

(7,764,000)

(7,008,000)

Accounts Receivable, Allowance for Credit Loss, Recovery

1,517,000

1,627,000

Income Tax Expense (Benefit)

(14,715,000)

(21,859,000)

(28,941,000)

Regulatory assets, non-current

541,784,000

593,939,000

Provision for Expected Credit Losses

$ 7,500,000

5,900,000

3,000,000

Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023

630

Hardy Hills Solar Project MW

195

Public Utilities, Property, Plant and Equipment, Net

$ 4,500,000,000

4,000,000,000

Other Assets, Noncurrent

$ 1,120,591,000

849,054,000

Gain on acquisition

$ 5,600,000

Petersburg Unit 1 Retired MW

230

Petersburg Unit 2 Planned Retirement MW in 2023

415

Gain on remeasurement of contingent consideration

$ 3,200,000

Petersburg Energy Center Project MW

250

Public Utilities, Allowance for Funds Used During Construction, Description

9,315

4,784

5,412

Allowance for Funds Used During Construction, Capitalized Interest

$ 13,739,000

$ 8,215,000

$ 4,815,000

Pike Co BESS Project MW

200

Petersburg Energy Storage Project MW

45

Petersburg Energy Storage Project MwH

180

Pike Co BESS Project MwH

800

Software and Software Development Costs

Significant Accounting Policies [Line Items]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

8 years

Deferred Project Costs [Member]

Significant Accounting Policies [Line Items]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

28 years

Prepaid Implementation Costs for Software as a Service

Significant Accounting Policies [Line Items]

Total other non-current assets

$ 7,100,000

8,200,000

Other Assets, Noncurrent

$ 7,100,000

8,200,000

Harding Street [Member]

Significant Accounting Policies [Line Items]

Amount of New Operation for Battery Storage Unit, megawatts | MW

20

Labor Force Concentration Risk [Member]

Significant Accounting Policies [Line Items]

Concentration risk percentage

68.00%

Parent Company [Member]

Significant Accounting Policies [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax

$ 29,294,000

22,269,000

(29,407,000)

(43,420,000)

Other Comprehensive Income (Loss), Net of Tax

7,025,000

51,676,000

14,013,000

Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax

1,594,000

46,245,000

10,393,000

Cash and Cash Equivalents, at Carrying Value

537,000

191,000

Total other non-current assets

1,925,088,000

1,960,939,000

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents

537,000

191,000

1,902,000

6,417,000

Other Comprehensive Income (Loss), before Reclassifications, Net of Tax

1,594,000

46,245,000

10,393,000

Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent

5,431,000

5,431,000

3,620,000

Income Tax Expense (Benefit)

10,928,000

11,027,000

10,364,000

Other Assets, Noncurrent

1,925,088,000

1,960,939,000

Indianapolis Power And Light Company

Significant Accounting Policies [Line Items]

Public Utilities, Inventory

77,198,000

60,497,000

Receivables from Customers

125,715,000

125,540,000

Cash and Cash Equivalents, at Carrying Value

25,767,000

199,103,000

Capitalized Computer Software, Gross

261,872,000

205,910,000

Emissions Allowance

797,000

797,000

Service cost

5,189,000

8,949,000

9,339,000

Interest cost

$ 29,818,000

18,099,000

$ 15,660,000

Number of customers | customer

523,000

Electric generation capability for winter, megawatts | MW

3,070

Electric generation capability for summer, megawatts | MW

2,925

Total other non-current assets

$ 1,117,051,000

833,536,000

Unbilled energy revenues

91,463,000

74,488,000

Loans and Leases Receivable, Related Parties, Description

5,227,000

288,000

Provision for doubtful accounts

$ 7,413,000

$ 5,851,000

Capitalized amount, rate

7.10%

5.40%

5.70%

Depreciation rate

3.70%

3.80%

3.70%

Depreciation expense

$ 244,800,000

$ 247,500,000

$ 239,100,000

Utility plant assets

4,500,000,000

4,000,000,000

Capitalized Computer Software, Accumulated Amortization

(111,110,000)

(107,184,000)

Intangible assets - net

235,656,000

138,978,000

Capitalized Computer Software, Amortization

14,570,000

10,122,000

11,241,000

Finite-Lived Intangible Asset, Expected Amortization, Year One

20,764,000

Finite-Lived Intangible Asset, Expected Amortization, Year Two

20,764,000

Finite-Lived Intangible Asset, Expected Amortization, Year Three

22,550,000

Finite-Lived Intangible Asset, Expected Amortization, Year Four

22,550,000

Finite-Lived Intangible Asset, Expected Amortization, Year Five

22,550,000

Finite-Lived Intangible Assets, Amortization Expense, Rolling after Year Five

109,178,000

Restricted Cash and Cash Equivalents

5,000

5,000

Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents

25,772,000

199,108,000

2,761,000

$ 17,951,000

Other Receivables

13,848,000

17,373,000

Accounts Receivable, Allowance for Credit Loss

(2,283,000)

(1,117,000)

Receivables, Net, Current

233,970,000

216,572,000

Materials and Supplies, Average Cost

66,392,000

63,111,000

Inventory, Net

$ 143,590,000

123,608,000

Allowance for Credit Losses

The following table is a rollforward of our allowance for credit losses related to the accounts receivable balances for the periods indicated:

	For the Years Ended December 31,
	2023		2022
	(In Thousands)
Allowance for credit losses:
Beginning balance	$	1,117	$	647
Current period provision	7,413		5,851
Write-offs charged against allowance	(7,764)		(7,008)
Recoveries collected	1,517		1,627
Ending Balance	$	2,283	$	1,117

Accounts receivable and unbilled revenue, allowance for doubtful accounts

$ 2,283,000

1,117,000

647,000

Accounts Receivable, Allowance for Credit Loss, Writeoff

(7,764,000)

(7,008,000)

Accounts Receivable, Allowance for Credit Loss, Recovery

1,517,000

1,627,000

Income Tax Expense (Benefit)

(25,666,000)

(32,887,000)

(39,305,000)

Regulatory assets, non-current

541,784,000

593,939,000

Provision for Expected Credit Losses

$ 7,500,000

5,900,000

3,000,000

Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023

630

Hardy Hills Solar Project MW

195

Public Utilities, Property, Plant and Equipment, Net

$ 4,500,000,000

4,000,000,000

Project Development Intangible Assets

84,097,000

39,455,000

Other Assets, Noncurrent

$ 1,117,051,000

833,536,000

Gain on acquisition

$ 5,600,000

Gain on remeasurement of contingent consideration

$ 3,200,000

Petersburg Energy Center Project MW

250

Public Utilities, Allowance for Funds Used During Construction, Description

9,315

4,784

5,412

Allowance for Funds Used During Construction, Capitalized Interest

$ 13,739,000

$ 8,215,000

$ 4,815,000

Pike Co BESS Project MW

200

Pike Co BESS Project MwH

800

Indianapolis Power And Light Company | Software and Software Development Costs

Significant Accounting Policies [Line Items]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

8 years

Indianapolis Power And Light Company | Deferred Project Costs [Member]

Significant Accounting Policies [Line Items]

Acquired Finite-Lived Intangible Assets, Weighted Average Useful Life

28 years

Indianapolis Power And Light Company | Prepaid Implementation Costs for Software as a Service

Significant Accounting Policies [Line Items]

Total other non-current assets

$ 7,100,000

8,200,000

Other Assets, Noncurrent

$ 7,100,000

8,200,000

Indianapolis Power And Light Company | Harding Street [Member]

Significant Accounting Policies [Line Items]

Amount of New Operation for Battery Storage Unit, megawatts | MW

20

Indianapolis Power And Light Company | Labor Force Concentration Risk [Member]

Significant Accounting Policies [Line Items]

Concentration risk percentage

68.00%

AES U.S. Holdings, LLC [Member]

Significant Accounting Policies [Line Items]

Ownership Interest in Parent Company, Percent

85.00%

CDPQ [Member]

Significant Accounting Policies [Line Items]

Ownership Interest in Parent Company, Percent

15.00%

Physical Unit [Member]

Significant Accounting Policies [Line Items]

Collective bargaining agreement expiration date

Dec. 04, 2024

Subsequent Event [Member] | Clerical-Technical Unit [Member]

Significant Accounting Policies [Line Items]

Collective bargaining agreement expiration date

Feb. 12, 2026

Petersburg Unit 1 retirement

Significant Accounting Policies [Line Items]

Regulatory assets, non-current

$ 35,700,000

Petersburg Unit 1 retirement | Indianapolis Power And Light Company

Significant Accounting Policies [Line Items]

Regulatory assets, non-current

287,463,000

Petersburg Unit 1 retirement and 2 retirement costs

Significant Accounting Policies [Line Items]

Regulatory assets, non-current

259,892,000

287,463,000

Petersburg Unit 1 retirement and 2 retirement costs | Indianapolis Power And Light Company

Significant Accounting Policies [Line Items]

Regulatory assets, non-current

259,892,000

Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Significant Accounting Policies [Line Items]

Interest and Debt Expense

(7,229,000)

(7,229,000)

(4,819,000)

Income Tax Expense (Benefit)

(1,798,000)

(1,798,000)

(1,199,000)

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

$ 5,431,000

$ 5,431,000

$ 3,620,000

XML

Regulatory Matters (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MW	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2023 USD ($)	Jul. 24, 2019 USD ($)
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	$ 23,371	$ 23,348
Regulatory assets, current	89,419	119,723
Regulatory assets, non-current	$ 541,784	$ 593,939
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
Equipment recovery approved amount	$ 129,700
Revenue requirement to be included in rate	8,900
Public Utlities, Approved Shareholder Incentives	2,700	$ 8,300	$ 7,200
Regulatory Assets	631,203	713,662
Regulatory assets	89,419	119,723
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 43,900
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.20%
TDSIC Eligible Cost Recovery Through Periodic Rate Adjustment Mechanism Plan, Percent	80.00%
TDSIC Planned Recoverable Costs Deferred For Future Recovery, Percent	20.00%
Periodic Rate Adjustment Mechanism Cap, Percent	2.00%
TDSIC Plan Improvement Costs							$ 1,200,000
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023	630
Inventory Write-down	$ 700	2,100
Reduction to Revenue	0	300	$ 5,500
Regulatory Liability, Noncurrent	527,224	612,585
Tax rate before change due to Tax Cuts and Jobs Act of 2017				35.00%
Tax rate after Tax Cuts and Jobs Act of 2017			21.00%
COVID-19 related uncollectible and incremental bad debt expense	5,400
Regulatory Liabilities	550,595	635,933
Regulatory liabilities	527,224	612,585
Jurisdictional Revenue Requirement Approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022	$ 56,500
Hardy Hills Solar Project MW	195
Total Assets Recorded in the Accompanying Consolidated Balance Sheets Associated with the Hardy Hills Solar Project Acquisition	$ 51,600
Asset Acquisition, Consideration Transferred, Contingent Consideration		0	$ 3,200
Estimated Projected Costs to Successfully Implement the Services Proposed in the EV Portfolio	16,200
AES Indiana’s equipment approved for TDSIC recovery	399,600
Eagle Valley uncollectible outage costs, net	21,000
Customer Credit	6,800
Eagle Valley uncollectible outage costs, gross	27,800
Capital Projects, Write-Offs		1,500
Public Utilities, Requested Rate Increase (Decrease), Amount	73,000
Limited Partners' Contributed Capital	79,300
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Asset Acquisition, Indemnification Asset, Amount	$ 48,700
Petersburg Energy Center Project MW	250
Petersburg Energy Center Project MW Unit 1	230
Petersburg Energy Center Project MW Unit 2	415
Hoosier Wind Project MW	106
Pike Co BESS Project MwH	800
Pike Co BESS Project MW	200
Petersburg Energy Storage Project MW	45
Petersburg Energy Storage Project MwH	180
Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	$ 19,649	15,803
Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Regulatory liabilities	451,886	518,797
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Regulatory liabilities	0	5,126
Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	23,371	23,348
Regulatory assets, current	89,419	119,723
Regulatory assets, non-current	$ 541,784	$ 593,939
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
Equipment recovery approved amount	$ 129,700
Revenue requirement to be included in rate	8,900
Public Utlities, Approved Shareholder Incentives	2,700	$ 8,300	$ 7,200
Regulatory Assets	631,203	713,662
Regulatory assets	$ 89,419	119,723
TDSIC Eligible Cost Recovery Through Periodic Rate Adjustment Mechanism Plan, Percent	80.00%
TDSIC Planned Recoverable Costs Deferred For Future Recovery, Percent	20.00%
Periodic Rate Adjustment Mechanism Cap, Percent	2.00%
TDSIC Plan Improvement Costs						$ 1,200,000
Preferred Resource Portfolio Coal-Fired Generation Retirement MW by 2023	630
Inventory Write-down			800
Reduction to Revenue	$ 0	300	$ 5,500
Regulatory Liability, Noncurrent	527,224	612,585
Tax rate before change due to Tax Cuts and Jobs Act of 2017				35.00%
Tax rate after Tax Cuts and Jobs Act of 2017			21.00%
COVID-19 related uncollectible and incremental bad debt expense	5,400
Regulatory Liabilities	550,595	635,933
Regulatory liabilities	527,224	612,585
Jurisdictional Revenue Requirement Approved by the IURC to be included in AES Indiana’s rates for the twelve-month period ending October 2022	$ 56,500
Hardy Hills Solar Project MW	195
AES Indiana’s equipment approved for TDSIC recovery	$ 399,600
Public Utilities, Requested Rate Increase (Decrease), Amount	73,000
Net Income (Loss) Attributable to Noncontrolling Interest	(26,093)
Asset Acquisition, Indemnification Asset, Amount	$ 48,700
Petersburg Energy Center Project MW	250
Petersburg Energy Center Project MW Unit 1	230
Petersburg Energy Center Project MW Unit 2	415
Hoosier Wind Project MW	106
Pike Co BESS Project MwH	800
Pike Co BESS Project MW	200
Subsidiaries [Member] | HLBV Method
Regulatory Assets And Liabilities [Line Items]
Net Income (Loss) Attributable to Noncontrolling Interest	$ 26,100
Subsidiaries [Member] | Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	19,649	15,803
Subsidiaries [Member] | Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Subsidiaries [Member] | Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Regulatory liabilities	451,886	518,797
Subsidiaries [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,800	88,662
Regulatory liabilities	74,800	88,662
Subsidiaries [Member] | Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Regulatory liabilities	$ 0	5,126
Indiana [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	100
Minnesota [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	200
Solar Generated Electricity [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	94.5
Solar Generated Electricity in Operation | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Amount of electricity required to be purchased under purchase power agreement | MW	94.0
Minimum [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period	1 year
Environmental Costs Amortization Period	3 years
TDSIC Costs Amortization Period	1 year
Minimum [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period					1 year
Environmental Costs Amortization Period	3 years
TDSIC Costs Amortization Period	1 year
Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period	43 years
Environmental Costs Amortization Period	43 years
TDSIC Costs Amortization Period	36 years
ECCRA Rider Amortization Recovery Period	30 years
Maximum [Member] | Pike Co BESS Project
Regulatory Assets And Liabilities [Line Items]
ECCRA Rider Amortization Recovery Period	20 years
Maximum [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets Amortization Period					43 years
Environmental Costs Amortization Period	43 years
TDSIC Costs Amortization Period	36 years
Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	$ 74,796	88,662
Regulatory liabilities	74,796	88,662
Deferred Income Tax Charge [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,796
Regulatory liabilities	74,796
Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Regulatory assets	75,416	26,047
Undercollections of rate riders [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Regulatory assets	75,416	26,047
Amounts being recovered through base rates [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Regulatory assets	13,815	13,815
Amounts being recovered through base rates [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Regulatory assets	13,815	13,815
Pension Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	115,847	131,907
Pension Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	115,847	131,907
Deferred Project Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current		34,483
Deferred Project Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current		34,483
Unamortized Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,812	3,866
Unamortized Carrying Charges And Certain Other Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,812	3,866
Loss on Reacquired Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	13,379	14,429
Loss on Reacquired Debt [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	13,379	14,429
Environmental Restoration Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	66,837	68,947
Environmental Restoration Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	66,837	68,947
Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,887	1,027
Other Miscellaneous [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,887	1,027
Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	21,091
Deferred MISO Non-fuel Costs [Member] | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	21,091
COVID-19
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	5,426	5,426
COVID-19 | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	5,426	5,426
TDSIC projects
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	35,979	18,547
TDSIC projects | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	35,979	18,547
Petersburg Unit 1 retirement
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	35,700
Petersburg Unit 1 retirement | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current		287,463
Petersburg Unit 2 retirement
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	224,200
Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	6,774	5,744
Hardy Hills Solar Project | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	6,774	5,744
Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,469	1,582
Petersburg Solar Project | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,469	1,582
Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	0	79,861
Regulatory assets, non-current	4,275	20,518
Regulatory assets	0	79,861
Fuel Costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	4,275	20,518
Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	259,892	287,463
Petersburg Unit 1 retirement and 2 retirement costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	259,892
Major Storm Damage
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	1,493	0
Major Storm Damage | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	1,493	0
Pike Co BESS Project Development Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,623	0
Pike Co BESS Project Development Costs | Subsidiaries [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, non-current	2,623	0
Unamortized Investment Tax Credit [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	542	0
Regulatory liabilities	542	0
Unamortized Reacquisition Debt Premium
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	188	0
Regulatory assets	188	$ 0
Benchmark for annual wholesale margins [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	16,300
Benchmark for annual capacity sales [Member]
Regulatory Assets And Liabilities [Line Items]
Approved Rate Order Benefits to Customers	$ 11,300

XML

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	$ 89,419	$ 119,723
Regulatory assets, noncurrent	541,784	593,939
Total regulatory assets	631,203	713,662
Regulatory liabilities, current	23,371	23,348
Regulatory Liability, Noncurrent	527,224	612,585
Total regulatory liabilities	550,595	635,933
Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	19,649	15,803
Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Amounts being recovered through base rates [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Unrecognized Pension And Other Post Retirement Benefit Plan Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	115,847	131,907
Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,796	88,662
Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	21,091
Unamortized Petersburg Unit 4 Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,812	3,866
Unamortized Reacquisition Premium On Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	13,379	14,429
Environmental Projects [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	66,837	68,947
Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,887	1,027
Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	6,774	5,744
Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,469	1,582
Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	0	79,861
Regulatory assets, noncurrent	4,275	20,518
Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	259,892	287,463
Major Storm Damage
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,493	0
Pike Co BESS Project Development Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,623	0
Unamortized Reacquisition Debt Premium
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	188	0
Indianapolis Power And Light Company
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	89,419	119,723
Regulatory assets, noncurrent	541,784	593,939
Total regulatory assets	631,203	713,662
Regulatory liabilities, current	23,371	23,348
Regulatory Liability, Noncurrent	527,224	612,585
Total regulatory liabilities	550,595	635,933
Indianapolis Power And Light Company | Overcollection and other credits passed to customers through rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	19,649	15,803
Indianapolis Power And Light Company | Financial Transmission Rights [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities, current	3,722	7,545
Indianapolis Power And Light Company | Asset Retirement Obligation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	451,886	518,797
Indianapolis Power And Light Company | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,800	88,662
Indianapolis Power And Light Company | Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	0	5,126
Indianapolis Power And Light Company | Investment Tax Credit Carryforward
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent		0
Indianapolis Power And Light Company | Undercollections of rate riders [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	75,416	26,047
Indianapolis Power And Light Company | Amounts being recovered through base rates [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, current	13,815	13,815
Indianapolis Power And Light Company | Unrecognized Pension And Other Post Retirement Benefit Plan Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	115,847	131,907
Indianapolis Power And Light Company | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	74,796
Indianapolis Power And Light Company | Deferred MISO Non-fuel Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	21,091
Indianapolis Power And Light Company | Unamortized Petersburg Unit 4 Carrying Charges And Certain Other Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,812	3,866
Indianapolis Power And Light Company | Unamortized Reacquisition Premium On Debt [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	13,379	14,429
Indianapolis Power And Light Company | Environmental Projects [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	66,837	68,947
Indianapolis Power And Light Company | Other Miscellaneous [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,887	1,027
Indianapolis Power And Light Company | Hardy Hills Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	6,774	5,744
Indianapolis Power And Light Company | Petersburg Solar Project
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	2,469	1,582
Indianapolis Power And Light Company | Fuel Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	4,275	20,518
Indianapolis Power And Light Company | Petersburg Unit 1 retirement and 2 retirement costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	259,892
Indianapolis Power And Light Company | Investment Tax Credit Carryforward
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Noncurrent	542
Indianapolis Power And Light Company | Major Storm Damage
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	1,493	0
Indianapolis Power And Light Company | Pike Co BESS Project Development Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, noncurrent	$ 2,623	$ 0

XML

Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Public Utility, Property, Plant and Equipment [Line Items]
Revisions to cash flow and timing estimates	$ 12,921	$ 44,679
Direct first mortgage lien	2,153,800
Non-contractually required removal costs of utility plant in service	680,900	694,000
Contractually required removal costs of utility plant in service	249,900	218,700
Regulatory assets, non-current	541,784	593,939
Regulatory assets, non-current	541,784	593,939
Entity Information [Line Items]
Regulatory assets, non-current	541,784	593,939
Contractually required removal costs of utility plant in service	249,900	218,700
Non-contractually required removal costs of utility plant in service	680,900	694,000
Direct first mortgage lien	2,153,800
Petersburg Unit 1 retirement
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	35,700
Regulatory assets, non-current	35,700
Entity Information [Line Items]
Regulatory assets, non-current	35,700
Petersburg Unit 1 retirement and 2 retirement costs
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	259,892	287,463
Regulatory assets, non-current	259,892	287,463
Entity Information [Line Items]
Regulatory assets, non-current	259,892	287,463
Subsidiaries [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Revisions to cash flow and timing estimates	12,921	44,679
Direct first mortgage lien	2,153,800
Non-contractually required removal costs of utility plant in service	680,900	694,000
Contractually required removal costs of utility plant in service	249,900	218,700
Regulatory assets, non-current	541,784	593,939
Regulatory assets, non-current	541,784	593,939
Entity Information [Line Items]
Regulatory assets, non-current	541,784	593,939
Contractually required removal costs of utility plant in service	249,900	218,700
Non-contractually required removal costs of utility plant in service	680,900	694,000
Direct first mortgage lien	2,153,800
Subsidiaries [Member] | Petersburg Unit 1 retirement
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current		287,463
Regulatory assets, non-current		287,463
Entity Information [Line Items]
Regulatory assets, non-current		$ 287,463
Subsidiaries [Member] | Petersburg Unit 1 retirement and 2 retirement costs
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets, non-current	259,892
Regulatory assets, non-current	259,892
Entity Information [Line Items]
Regulatory assets, non-current	$ 259,892

XML

Property, Plant and Equipment (Schedule Of Original Cost Of Utility Plant In Service) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Production	$ 3,942,052	$ 4,164,416
Transmission	487,527	461,245
Distribution	2,304,526	2,045,579
General plant	348,338	311,074
Total utility plant in service	7,082,443	6,982,314
Indianapolis Power And Light Company
Entity Information [Line Items]
Production	3,942,052	4,164,416
Transmission	487,527	461,245
Distribution	2,304,526	2,045,579
General plant	348,338	311,074
Total utility plant in service	$ 7,082,443	$ 6,982,314

XML

Property, Plant and Equipment ARO (Reconciliation of Asset Retirement Obligation Liability) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1	$ 218,729	$ 189,509
Liabilities settled	(11,902)	(24,699)
Revisions to cash flow and timing estimates	12,921	44,679
Accretion expense	13,102	8,081
Balance as of December 31	249,930	218,729
Asset Retirement Obligation, Liabilities Incurred	17,080	1,159
Indianapolis Power And Light Company
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of January 1	218,729	189,509
Liabilities settled	11,902	24,699
Revisions to cash flow and timing estimates	12,921	44,679
Accretion expense	13,102	8,081
Balance as of December 31	249,930	$ 218,729
Asset Retirement Obligation, Liabilities Incurred	$ 17,080

XML

Fair Value (Narrative) (Details) MWh in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,552	$ 3,228
Revisions to cash flow and timing estimates	12,921	44,679
Deferred financing costs, net	23,612
Unamortized debt discount	6,768
Asset retirement obligations	249,930	218,729
Regulatory assets, non-current	541,784	593,939
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	19,234	22,945
Unamortized Debt Discount
Entity Information [Line Items]
Unamortized debt discount	6,800	7,100
Unamortized Deferred Financing Cost
Entity Information [Line Items]
Deferred financing costs, net	24,800	26,300
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Entity Information [Line Items]
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Purchase of Derivative Instruments Interest Rate Swap	400,000
Sale of Derivative Instruments Interest Rate Swap	$ 0
FTR [Member] | Not Designated as Hedging Instrument [Member]
Entity Information [Line Items]
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Petersburg Unit 1 retirement
Entity Information [Line Items]
Regulatory assets, non-current	$ 35,700
Indianapolis Power And Light Company
Entity Information [Line Items]
Revisions to cash flow and timing estimates	12,921	44,679
Deferred financing costs, net	20,200	20,400
Unamortized debt discount	6,449	6,651
Asset retirement obligations	249,930	218,729
Regulatory assets, non-current	541,784	593,939
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Indianapolis Power And Light Company | Variable Rate [Member]
Entity Information [Line Items]
Unamortized debt discount	$ (6,400)	6,700
Indianapolis Power And Light Company | FTR [Member] | Not Designated as Hedging Instrument [Member]
Entity Information [Line Items]
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Indianapolis Power And Light Company | Petersburg Unit 1 retirement
Entity Information [Line Items]
Regulatory assets, non-current		287,463
Money Market Funds [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 127	5
Mutual Fund [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Fair Value, Inputs, Level 1 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Financial transmission rights	0	0
Total financial assets measured at fair value	3,552	3,228
Fair Value, Inputs, Level 1 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Fair Value, Inputs, Level 2 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	0	0
Total financial assets measured at fair value	14,294	12,172
Fair Value, Inputs, Level 2 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Fair Value, Inputs, Level 3 [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Fair Value, Inputs, Level 3 [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	$ 1,388	$ 7,545

XML

Fair Value (Summary Of Fair Value Assets And Liabilities Measured On A Recurring Basis, Level 3) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,552	$ 3,228
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	19,234	22,945
Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Financial transmission rights	0	0
Total financial assets measured at fair value	3,552	3,228
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Significant Observable Inputs (Level 2) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	0	0
Total financial assets measured at fair value	14,294	12,172
Significant Observable Inputs (Level 2) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	0	0
Total financial assets measured at fair value	0	0
Unobservable Inputs (Level 3) [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	0	0
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Unobservable Inputs (Level 3) [Member] | Indianapolis Power And Light Company
Entity Information [Line Items]
Financial transmission rights	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Money Market Funds [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	127	5
Mutual Fund [Member]
Entity Information [Line Items]
Investments, Fair Value Disclosure	$ 3,425	$ 3,223

XML

Fair Value (Reconciliation Of Financial Instruments Classified As Level 3) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	$ 14,294	$ 12,172
Total financial assets measured at fair value	19,234	22,945
Financial transmission rights	1,388	7,545
Investments, Fair Value Disclosure	3,552	3,228
Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,425	3,223
Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	127	5
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	3,552	3,228
Financial transmission rights	0	0
Investments, Fair Value Disclosure	3,552	3,228
Significant Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	14,294	12,172
Financial transmission rights	0	0
Investments, Fair Value Disclosure	0	0
Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	1,388	7,545
Financial transmission rights	1,388	7,545
Investments, Fair Value Disclosure	0	0
Derivative Financial Instruments, net Liabilities [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	7,545	1,235
Issuances	3,624	15,338
Settlements	(9,781)	(9,028)
Ending balance	1,388	7,545
Indianapolis Power And Light Company
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	1,388	7,545
Financial transmission rights	1,388	7,545
Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	0	0
Financial transmission rights	0	0
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	0	0
Financial transmission rights	0	0
Indianapolis Power And Light Company | Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total financial assets measured at fair value	1,388	7,545
Financial transmission rights	1,388	7,545
Parent Company [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	17,846	15,400
Investments, Fair Value Disclosure	3,552	3,228
Parent Company [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,425	3,223
Parent Company [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	127	5
Parent Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	3,552	3,228
Investments, Fair Value Disclosure	3,552	3,228
Parent Company [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	3,425	3,223
Parent Company [Member] | Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	127	5
Parent Company [Member] | Significant Observable Inputs (Level 2) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	14,294	12,172
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Significant Observable Inputs (Level 2) [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Significant Observable Inputs (Level 2) [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	0	0
Investments, Fair Value Disclosure		0
Parent Company [Member] | Unobservable Inputs (Level 3) [Member] | Mutual Fund [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	0	0
Parent Company [Member] | Unobservable Inputs (Level 3) [Member] | Money Market Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Investments, Fair Value Disclosure	$ 0	$ 0

XML

Fair Value (Schedule Of Face And Fair Value Of Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unamortized discounts	$ 6,768
Face Value	3,488,800	$ 3,033,800
Fair Value	3,315,467	2,775,644
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Unamortized discounts	6,449	6,651
Face Value	2,608,800	2,153,800
Fair Value	2,475,997	1,959,233
Fixed Rate [Member]
Debt Instrument [Line Items]
Face Value	3,033,800	3,033,800
Fair Value	2,860,467	2,775,644
Fixed Rate [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Face Value	2,153,800	2,153,800
Fair Value	2,020,997	1,959,233
Variable Rate [Member]
Debt Instrument [Line Items]
Face Value	455,000	0
Fair Value	455,000	0
Variable Rate [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Unamortized discounts	(6,400)	6,700
Face Value	455,000	0
Fair Value	$ 455,000	$ 0

XML

Derivative Instruments and Hedging Activities (Details) MWh in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Apr. 08, 2020 USD ($)
Interest Rate Derivative Assets, at Fair Value	$ 14,294,000	$ 0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (528,000)	(15,309,000)	$ (3,441,000)
Number of Interest Rate Swaps	3
Other Comprehensive Income (Loss), Net of Tax	$ 1,594,000	46,245,000	10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Interest Rate Swap [Member]
Accumulated Other Income (Loss)					$ 72,300,000
Accumulated Other Income (Loss)					$ 72,300,000
Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
Not Designated as Hedging Instrument [Member] | Realized Gains Forward Power Contracts
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 0	1,300,000
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Derivative Asset, Fair Value, Gross Asset	1,388,000	7,545,000
Derivative Liability, Current | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	0	12,172,000
Parent Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528,000)	(15,309,000)	(3,441,000)
Other Comprehensive Income (Loss), Net of Tax	1,594,000	46,245,000	10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Parent Company [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	$ (29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	$ 400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Parent Company [Member] | Derivative Liability, Current | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative Liability, Fair Value, Gross Liability	$ 0	12,172,000,000
Subsidiaries [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
Subsidiaries [Member] | Not Designated as Hedging Instrument [Member] | Realized Gains Forward Power Contracts
Derivative Instruments Not Designated as Hedging Instruments, Gain	$ 0	1,300,000
Subsidiaries [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | FTR [Member]
Derivative Asset, Fair Value, Gross Asset	$ 1,388,000,000	$ 7,545,000,000

XML

Debt (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Secured debt gross	$ 3,003,420,000
Aggregate principal amount	3,488,800,000	$ 3,033,800,000
Net proceeds from debt issuance	0	350,000,000	$ 95,000,000
Long-term debt	3,003,420,000	3,000,450,000
Maximum borrowing capacity	350,000,000
Line of Credit Facility, Remaining Borrowing Capacity	100,000,000
Maximum amount of short-term indebtedness outstanding	750,000,000
Authorized amount of debt to be issued	740,000,000
Preferred Stock Issuable in Lieu of Portion of Maximum Authorized Amount of Debt	65,000,000
Debt Instrument, Unused Borrowing Capacity, Amount	390,000,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility, accordion feature	150,000,000
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Secured debt gross	2,128,293,000
Aggregate principal amount	2,608,800,000	2,153,800,000
Net proceeds from debt issuance	0	350,000,000	$ 95,000,000
Long-term debt	2,128,293,000	2,126,787,000
Maximum borrowing capacity	350,000,000
Line of Credit Facility, Remaining Borrowing Capacity	100,000,000
Maximum amount of short-term indebtedness outstanding	750,000,000
Authorized amount of debt to be issued	740,000,000
Preferred Stock Issuable in Lieu of Portion of Maximum Authorized Amount of Debt	65,000,000
First mortgage bonds	$ 2,128,293,000	2,126,787,000
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100.00%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 390,000,000
Maximum long-term credit agreements and liquidity facilities	750,000,000
Indianapolis Power And Light Company | Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility, accordion feature	150,000,000
Indianapolis Power And Light Company | Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Line of Credit	155,000,000	0
Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Aggregate principal amount	880,000,000	880,000,000
Long-term debt	470,653,000	873,663,000
First Mortgage Bonds [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Secured debt gross	$ 2,153,800,000
FMB Twenty [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.05%
First mortgage bonds	$ 350,000,000	350,000,000
First Mortgage Bond Nine [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	3.125%
First mortgage bonds	$ 40,000,000	40,000,000
First Mortgage Bond 4.65% Due June 2043 [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.65%
First mortgage bonds	$ 170,000,000	170,000,000
First Mortgage Bond 4.70% Due September 2045 [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%
First mortgage bonds	$ 130,000,000	130,000,000
First Mortgage Bond Nineteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.70%
First mortgage bonds	$ 260,000,000	260,000,000
Three Point Seven Zero Percent Senior Secured Notes [Domain] | Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	3.70%
Long-term debt	$ 405,000,000	405,000,000
FMB Twenty - one [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.875%
First mortgage bonds	$ 105,000,000	105,000,000
First Mortgage Bond Thirteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.60%
First mortgage bonds	$ 100,000,000	100,000,000
First Mortgage Bond Fourteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.05%
First mortgage bonds	$ 158,800,000	158,800,000
First Mortgage Bond Fifteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	6.60%
First mortgage bonds	$ 165,000,000	165,000,000
First Mortgage Bond Sixteen [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.875%
First mortgage bonds	$ 140,000,000	140,000,000
FMB Twenty - three | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.95%
First mortgage bonds	$ 60,000,000	60,000,000
Aggregated Principal Amount of Environmental Facilities Refunding Revenue Bonds Series 2021 A&B | Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 95,000,000
FMB Twenty - Four | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	1.40%
First mortgage bonds	$ 55,000,000	55,000,000
FMB Twenty - five | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.65%
First mortgage bonds	$ 40,000,000	40,000,000
FMB Twenty - two | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.75%
First mortgage bonds	$ 30,000,000	30,000,000
First Mortgage Bond Twenty Two
Debt Instrument [Line Items]
Long-term debt	345,600,000
First mortgage bonds	$ 350,000,000
First Mortgage Bond Twenty Two | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.65%
Long-term debt	$ 345,600,000
First mortgage bonds	$ 350,000,000	350,000,000
Four Point Two Five Percent Senior Secured Notes | Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.25%
Long-term debt	$ 475,000,000	475,000,000
$200M Term Loan Maturing June 2023
Debt Instrument [Line Items]
Short-Term Bank Loans and Notes Payable	200,000,000
$200M Term Loan Maturing June 2023 | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Short-Term Bank Loans and Notes Payable	200,000,000
$300M Term Loan Maturing November 2024 | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Short-Term Bank Loans and Notes Payable	$ 300,000,000
Series 2021A bonds | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	1.40%
Series 2021B bonds | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Debt instrument, stated interest rate	0.65%
Aggregated Principal Amount of Environmental Facilities Refunding Revenue Bonds Series 2011 A&B | Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 95,000,000
Line of Credit [Member] | Committed Line of Credit
Debt Instrument [Line Items]
Long-term Line of Credit	$ 155,000,000	$ 0

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Debt (Schedule Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unamortized discount - net	$ (6,768)
Debt Issuance Costs, Net	(23,612)
Long-term debt	3,003,420	$ 3,000,450
Current portion of long-term debt	445,000	0
Long-term debt	2,558,420	3,000,450
First Mortgage Bond Twenty Two
Debt Instrument [Line Items]
First mortgage bonds	350,000
Long-term debt	345,600
Ipalco Enterprises, Inc. [Member]
Debt Instrument [Line Items]
Unamortized discount - net	(319)	(425)
Debt Issuance Costs, Net	(4,554)	(5,912)
Debt, Long-Term and Short-Term, Combined Amount	875,127	873,663
Long-term debt	470,653	873,663
Current portion of long-term debt	405,000	0
Long-term debt	470,127	873,663
Ipalco Enterprises, Inc. [Member] | Three Point Seven Zero Percent Senior Secured Notes [Domain]
Debt Instrument [Line Items]
Long-term debt	$ 405,000	405,000
Debt, stated interest rate	3.70%
Ipalco Enterprises, Inc. [Member] | Four Point Two Five Percent Senior Secured Notes
Debt Instrument [Line Items]
Long-term debt	$ 475,000	475,000
Debt, stated interest rate	4.25%
Indianapolis Power And Light Company
Debt Instrument [Line Items]
First mortgage bonds	$ 2,128,293	2,126,787
Unamortized discount - net	(6,449)	(6,651)
Debt Issuance Costs, Net	(20,200)	(20,400)
Long-term debt	2,128,293	2,126,787
Current portion of long-term debt	40,000	0
Long-term debt	2,088,293	2,126,787
Indianapolis Power And Light Company | First Mortgage Bond 4.55% Due December 2024 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 40,000	40,000
Debt, stated interest rate	3.125%
Indianapolis Power And Light Company | First Mortgage Bond 6.60% Due January 2034 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 100,000	100,000
Debt, stated interest rate	6.60%
Indianapolis Power And Light Company | First Mortgage Bond 6.05% Due October 2036 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 158,800	158,800
Debt, stated interest rate	6.05%
Indianapolis Power And Light Company | First Mortgage Bond 6.60% Due June 2037 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 165,000	165,000
Debt, stated interest rate	6.60%
Indianapolis Power And Light Company | First Mortgage Bond 4.875% Due November 2041 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 140,000	140,000
Debt, stated interest rate	4.875%
Indianapolis Power And Light Company | First Mortgage Bond 4.65% Due June 2043 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 170,000	170,000
Debt, stated interest rate	4.65%
Indianapolis Power And Light Company | First Mortgage Bond 4.70% Due September 2045 [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 130,000	130,000
Debt, stated interest rate	4.50%
Indianapolis Power And Light Company | First Mortgage Bond Nineteen [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 260,000	260,000
Debt, stated interest rate	4.70%
Indianapolis Power And Light Company | FMB Twenty [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 350,000	350,000
Debt, stated interest rate	4.05%
Indianapolis Power And Light Company | FMB Twenty - one [Member]
Debt Instrument [Line Items]
First mortgage bonds	$ 105,000	105,000
Debt, stated interest rate	4.875%
Indianapolis Power And Light Company | FMB Twenty - two
Debt Instrument [Line Items]
First mortgage bonds	$ 30,000	30,000
Debt, stated interest rate	0.75%
Indianapolis Power And Light Company | FMB Twenty - three
Debt Instrument [Line Items]
First mortgage bonds	$ 60,000	60,000
Debt, stated interest rate	0.95%
Indianapolis Power And Light Company | FMB Twenty - Four
Debt Instrument [Line Items]
First mortgage bonds	$ 55,000	55,000
Debt, stated interest rate	1.40%
Indianapolis Power And Light Company | FMB Twenty - five
Debt Instrument [Line Items]
First mortgage bonds	$ 40,000	40,000
Debt, stated interest rate	0.65%
Indianapolis Power And Light Company | First Mortgage Bond Twenty Two
Debt Instrument [Line Items]
First mortgage bonds	$ 350,000	350,000
Long-term debt	$ 345,600
Debt, stated interest rate	5.65%
Secured Debt [Member] | Indianapolis Power And Light Company
Debt Instrument [Line Items]
Unamortized discount - net	$ (6,449)
Debt Issuance Costs, Net	$ (19,058)	$ (20,362)

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Debt (Schedule Of Maturities On Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
2024	$ 445,000
2025	40,000
2026	90,000
2027	0
2028	0
Thereafter	2,458,800
Long-Term Debt, Gross	3,033,800
Unamortized discounts	(6,768)
Debt Issuance Costs, Net	(23,612)
Deferred financing costs, net	3,003,420
Subsidiaries [Member]
Entity Information [Line Items]
Debt Issuance Costs, Net	(19,058)
Subsidiaries [Member]
Entity Information [Line Items]
2024	40,000
2025	40,000
2026	90,000
2027	0
2028	0
Thereafter	1,983,800
Long-Term Debt, Gross	2,153,800
Unamortized discounts	(6,449)	$ (6,651)
Debt Issuance Costs, Net	(20,200)	$ (20,400)
Deferred financing costs, net	$ 2,128,293

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Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Entity Information [Line Items]
Income taxes	$ 0	$ 31,000,000	$ 27,500,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
Unrecognized Tax Benefits	$ 0	$ 0	$ 0	$ 7,368,000
Indianapolis Power And Light Company
Entity Information [Line Items]
Income taxes	$ 0	$ 39,500,000	$ 40,800,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
Unrecognized Tax Benefits	$ 0	$ 0	$ 0	$ 7,368,000

XML

Income Taxes (Schedule Of Federal And State Income Taxed Charged To Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Line Items]
Income tax expense	$ 14,715	$ 21,859	$ 28,941
Charged To Utility Operating Expense [Member]
Income Taxes [Line Items]
Current income taxes, Federal	(14,222)	22,539	28,100
Current income taxes, State	(3,716)	6,026	8,218
Total current income taxes	(17,938)	28,565	36,318
Deferred income taxes, Federal	24,885	(6,920)	(7,286)
Deferred income taxes, State	7,768	214	(91)
Total deferred income taxes	32,653	(6,706)	(7,377)
Indianapolis Power And Light Company
Income Taxes [Line Items]
Income tax expense	25,666	32,887	39,305
Indianapolis Power And Light Company | Charged To Utility Operating Expense [Member]
Income Taxes [Line Items]
Current income taxes, Federal	1,816	31,286	36,353
Current income taxes, State	268	8,185	10,325
Total current income taxes	2,084	39,471	46,678
Deferred income taxes, Federal	17,631	(6,822)	(7,283)
Deferred income taxes, State	5,951	238	(90)
Total deferred income taxes	23,582	(6,584)	(7,373)
Income tax expense	$ 25,666	$ 32,887	$ 39,305

XML

Income Taxes (Schedule Of Effective Income Tax Rate) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
State income tax, net of federal tax benefit	3.90%	3.90%	4.00%
Depreciation flow through and amortization	(12.90%)	(7.80%)	(6.30%)
Effective Income Tax Rate Reconciliation, Funds Used during Construction, Equity	(0.30%)	0.90%	0.40%
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Percent	9.00%	0.00%	0.00%
Other - net	(0.20%)	0.40%	0.40%
Effective tax rate	20.50%	18.40%	19.50%
Indianapolis Power And Light Company
Entity Information [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
State income tax, net of federal tax benefit	3.90%	3.90%	4.00%
Depreciation flow through and amortization	(8.00%)	(5.70%)	(4.90%)
Effective Income Tax Rate Reconciliation, Funds Used during Construction, Equity	(0.20%)	0.70%	0.30%
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Percent	5.60%	0.00%	0.00%
Other - net	(0.10%)	0.30%	0.30%
Effective tax rate	22.20%	20.20%	20.70%

XML

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Relating to utility property, net	$ 409,675	$ 341,473
Regulatory assets recoverable through future rates	108,823	123,669
Other	17,694	17,953
Total deferred tax liabilities	536,192	483,095
Investment tax credit	5	6
Regulatory liabilities including ARO	168,619	167,725
Deferred Tax Assets, Investment in Subsidiaries	2,501	0
Other	3,579	2,723
Total deferred tax assets	174,704	170,454
Deferred Income Tax Liabilities, Net	361,488	312,641
Indianapolis Power And Light Company
Entity Information [Line Items]
Relating to utility property, net	409,675	341,473
Regulatory assets recoverable through future rates	108,823	123,669
Other	7,975	22,717
Total deferred tax liabilities	526,473	487,859
Investment tax credit	5	6
Regulatory liabilities including ARO	168,619	167,726
Deferred Tax Assets, Investment in Subsidiaries	2,483	0
Operating Loss Carryforwards	9,230	0
Other	3,579	15,020
Total deferred tax assets	183,916	182,752
Deferred Income Tax Liabilities, Net	$ 342,557	$ 305,107

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Income Taxes (Reconciliation Of Unrecognized Tax Benefits) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	$ 0	$ 0	$ 7,368,000
Gross decreases - prior period tax positions	0	0	(7,368,000)
Unrecognized tax benefits at December 31	0	0	0
Indianapolis Power And Light Company
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at January 1	0	0	7,368,000
Gross decreases - prior period tax positions	0	0	(7,368,000)
Unrecognized tax benefits at December 31	$ 0	$ 0	$ 0

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Benefit Plans (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($) employee	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Jan. 01, 2023 USD ($)	Jan. 01, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liabilities		$ 0	$ 15
Benefit obligation in excess of plan assets		41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent		41,273	33,611
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		9,681	(182,590)
Net loss (gain) arising during period		(10,117)	(24,069)
Pension liability actuarial loss, change in discount rate			(182,600)
Amount included in regulatory assets and liabilities		115,297	131,559
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets		$ 590,800
Expected return on plan assets		5.60%
Effect of 25 basis point increase in discount rate on pension expense		$ (800)
Effect of 25 basis point decrease in discount rate on pension expense		800
Employer contributions during quarter		$ 114	412	$ 0
Funded target liability (percent)		98.00%
Pension expense		$ 73,300	38,600	63,200
Service cost		5,189	8,949	9,339
Interest cost		29,818	18,099	15,660
Deferred Compensation Arrangement with Individual, Compensation Expense		300	200	$ 200
Defined Benefit Plan, Benefit Obligation		549,546	$ 577,529		$ 577,530	$ 772,040
Pension Liability Actuarial Gain, Change in Discount Rate		9,700
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		10,100
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		$ 19,800
Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		65.00%
Discount rate		5.41%	2.83%	2.46%
Expected return on plan assets		5.60%	4.45%	5.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.15%	5.41%
Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants | employee		19
Discount rate		5.32%	2.62%	2.31%
Expected return on plan assets		6.45%	5.50%	3.60%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.66%	5.32%
Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants, active | employee		123
Number of plan participants, retired | employee		26
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation		$ 549,500
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets, Plan Assets		590,800
Noncurrent liabilities		0	$ 15
Benefit obligation in excess of plan assets		41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent		41,273	33,611
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		9,681	182,590
Net loss (gain) arising during period		10,100	(24,069)
Amount included in regulatory assets and liabilities		$ 115,297	$ 131,559
Minimum percentage of unrecognized net loss over benefit obligation or assets in order to be amortized		10.00%
Amortization period of unrecognized loss		11 years 7 months 28 days
Expected return on plan assets		5.60%	5.60%
Effect of 25 basis point increase in discount rate on pension expense		$ (800)
Effect of 25 basis point decrease in discount rate on pension expense		800
Employer contributions during quarter		$ 114	$ 412	$ 0
Funded target liability (percent)		98.00%
Pension expense		$ 73,300	38,600	63,200
Service cost		5,189	8,949	9,339
Interest cost		29,818	18,099	15,660
Deferred Compensation Arrangement with Individual, Compensation Expense		300	200	$ 200
Defined Benefit Plan, Benefit Obligation		549,546	$ 577,529		$ 577,530	$ 772,040
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax		$ (10,117)
Indianapolis Power And Light Company | Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		65.00%
Discount rate		5.41%	2.83%	2.46%
Expected return on plan assets		5.60%	4.45%	5.05%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.15%	5.41%
Indianapolis Power And Light Company | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants | employee		19
Discount rate		5.32%	2.62%	2.31%
Expected return on plan assets		6.45%	5.50%	3.60%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		5.66%	5.32%
Indianapolis Power And Light Company | Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of plan participants, active | employee		123
Number of plan participants, retired | employee		26
Indianapolis Power And Light Company | Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 3,000	$ 3,200
Indianapolis Power And Light Company | Change in Assumptions for Defined Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets		5.20%
Subsequent Event [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Normal service cost	$ 6,300
Plan expenses	$ 400
Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		77.00%
Defined contripution plan contributions		$ 3,700	3,600	$ 3,400
Thrift Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		77.00%
Defined contripution plan contributions		$ 3,700	3,600	3,400
Retirement Savings Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		23.00%
Percentage of employee's base compensation matched		5.00%
Defined Contribution, Employer Matching Contribution, Non-discretionary, percent of match		4.00%
Defined contripution plan contributions		$ 2,500	2,100	1,900
Retirement Savings Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		23.00%
Percentage of employee's base compensation matched		5.00%
Defined Contribution, Employer Matching Contribution, Non-discretionary, percent of match		4.00%
Defined contripution plan contributions		$ 2,500	$ 2,100	$ 1,900
Union Employees [Member] | Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		12.00%
Union Employees [Member] | Thrift Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Percentage of employees covered by the plan		12.00%
Expected Increase or Decrease in Discount Rate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Effect of Twenty Five Basis Point Increase Or Decrease In Discount Rate On Pension Expense		2500.00%
Expected Increase or Decrease in Discount Rate [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Effect of Twenty Five Basis Point Increase Or Decrease In Discount Rate On Pension Expense		2500.00%
Forecast [Member] | Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	5.20%
Forecast [Member] | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.35%
Forecast [Member] | Indianapolis Power And Light Company | Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.35%

XML

Benefit Plans (Schedule Of Defined Benefit Plans Disclosures) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	$ 577,529
Service cost	5,189	$ 8,949	$ 9,339
Interest cost	29,818	18,099	15,660
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(9,681)	182,590
Amendments (primarily increases in pension bands)	653	0
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	0	(394)
Benefits paid	73,325	38,575
Projected benefit obligation at ending Measurement Date	549,546	577,529
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	611,125	820,684
Actual return on plan assets	52,905	(171,002)
Employer contributions during quarter	114	412	0
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	394
Benefits paid	(73,325)	(38,575)
Defined Benefit Plan Fair Value of plan assets	590,819	611,125
Fair value of plan assets at ending Measurement Date	590,819	611,125	820,684
Unfunded status	41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent	(41,273)	(33,611)
Amounts recognized in the statement of financial position under ASC 715:
Noncurrent liabilities	0	(15)
Asset, Defined Benefit Plan, Noncurrent, Net	41,273	33,596
Sources of change in regulatory assets(1):
Prior service cost (credit) arising during period	653	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	10,100
Net loss (gain) arising during period	(10,117)	(24,069)
Amortization of prior service cost	(2,172)	(2,589)
Amortization of gain (loss)	(6,145)	(2,622)
Total recognized in regulatory assets	(17,781)	18,858
Net loss (gain)	115,297	131,559
Prior service cost (credit)	10,136	11,655
Total amounts included in regulatory assets (liabilities)	$ 125,433	$ 143,214
Percentage by asset category	100.00%	100.00%
Assets for Plan Benefits, Defined Benefit Plan	$ 41,172	$ 33,611
Expected return on plan assets	5.60%
Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 6,480
Fair value of plan assets at ending Measurement Date	6,404	6,480
Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
Indianapolis Power And Light Company
Change in benefit obligation:
Projected benefit obligation at beginning Measurement Date (see below)	577,529
Service cost	5,189	8,949	9,339
Interest cost	29,818	18,099	15,660
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(9,681)	(182,590)
Amendments (primarily increases in pension bands)	653	0
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	0	(394)
Benefits paid	(73,325)	38,575
Projected benefit obligation at ending Measurement Date	549,546	577,529
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	611,125	820,684
Actual return on plan assets	52,905	(171,002)
Employer contributions during quarter	114	412	0
Defined Benefit Plan, Plan Assets, Payment for Settlement	0	(394)
Benefits paid	(73,325)	(38,575)
Fair value of plan assets at ending Measurement Date	590,819	611,125	$ 820,684
Unfunded status	41,273	33,596
Asset, Defined Benefit Pension Plan, Noncurrent	(41,273)	(33,611)
Amounts recognized in the statement of financial position under ASC 715:
Noncurrent liabilities	0	(15)
Asset, Defined Benefit Plan, Noncurrent, Net	41,273	33,596
Sources of change in regulatory assets(1):
Prior service cost (credit) arising during period	653	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	(10,117)
Net loss (gain) arising during period	10,100	(24,069)
Amortization of prior service cost	(2,172)	(2,589)
Amortization of gain (loss)	(6,145)	(2,622)
Total recognized in regulatory assets	(17,781)	18,858
Net loss (gain)	115,297	131,559
Prior service cost (credit)	10,136	11,655
Total amounts included in regulatory assets (liabilities)	$ 125,433	$ 143,214
Percentage by asset category	100.00%	100.00%
Assets for Plan Benefits, Defined Benefit Plan	$ 41,172	$ 33,611
Expected return on plan assets	5.60%	5.60%
Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 6,480
Fair value of plan assets at ending Measurement Date	6,404	$ 6,480
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
US Government Debt Securities [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,704
Fair value of plan assets at ending Measurement Date	$ 117,397	$ 122,704
Sources of change in regulatory assets(1):
Percentage by asset category	20.00%	20.00%
US Government Debt Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 420
Fair value of plan assets at ending Measurement Date	178	$ 420
US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,284
Fair value of plan assets at ending Measurement Date	117,219	122,284
US Government Debt Securities [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,704
Fair value of plan assets at ending Measurement Date	$ 117,397	$ 122,704
Sources of change in regulatory assets(1):
Percentage by asset category	20.00%	20.00%
US Government Debt Securities [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 420
Fair value of plan assets at ending Measurement Date	178	$ 420
US Government Debt Securities [Member] | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	122,284
Fair value of plan assets at ending Measurement Date	117,219	122,284
Defined Benefit Plan, Common Collective Trust
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	608,336
Fair value of plan assets at ending Measurement Date	$ 588,028	$ 608,336
Sources of change in regulatory assets(1):
Percentage by asset category	100.00%	100.00%
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 3,691
Fair value of plan assets at ending Measurement Date	3,613	$ 3,691
Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	608,336
Fair value of plan assets at ending Measurement Date	$ 588,028	$ 608,336
Sources of change in regulatory assets(1):
Percentage by asset category	100.00%	100.00%
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 3,691
Fair value of plan assets at ending Measurement Date	3,613	$ 3,691
Defined Benefit Plan, Common Collective Trust | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	604,645
Fair value of plan assets at ending Measurement Date	584,415	604,645
Short-Term Investments [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,789
Fair value of plan assets at ending Measurement Date	$ 2,791	$ 2,789
Sources of change in regulatory assets(1):
Percentage by asset category	0.00%	0.00%
Short-Term Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,789
Fair value of plan assets at ending Measurement Date	2,791	$ 2,789
Short-Term Investments [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	0
Fair value of plan assets at ending Measurement Date	0	0
Short-Term Investments [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,789
Fair value of plan assets at ending Measurement Date	$ 2,791	$ 2,789
Sources of change in regulatory assets(1):
Percentage by asset category	0.00%	0.00%
Short-Term Investments [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,789
Fair value of plan assets at ending Measurement Date	2,791	$ 2,789
Equity Securities | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	85,341
Fair value of plan assets at ending Measurement Date		$ 85,341
Sources of change in regulatory assets(1):
Percentage by asset category		14.00%
Equity Securities | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	2,017
Fair value of plan assets at ending Measurement Date		$ 2,017
Equity Securities | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	83,324
Fair value of plan assets at ending Measurement Date		83,324
Fixed Income [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	400,291
Fair value of plan assets at ending Measurement Date	$ 387,979	$ 400,291
Sources of change in regulatory assets(1):
Percentage by asset category	66.00%	66.00%
Fixed Income [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 1,254
Fair value of plan assets at ending Measurement Date	1,168	$ 1,254
Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	399,037
Fair value of plan assets at ending Measurement Date	386,811	399,037
Fixed Income [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	400,291
Fair value of plan assets at ending Measurement Date	$ 387,979	$ 400,291
Sources of change in regulatory assets(1):
Percentage by asset category	66.00%	66.00%
Fixed Income [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 1,254
Fair value of plan assets at ending Measurement Date	1,168	$ 1,254
Fixed Income [Member] | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	399,037
Fair value of plan assets at ending Measurement Date	386,811	399,037
Equity Funds [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	85,341
Fair value of plan assets at ending Measurement Date	$ 82,652	$ 85,341
Sources of change in regulatory assets(1):
Percentage by asset category	14.00%	14.00%
Equity Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	$ 2,017
Fair value of plan assets at ending Measurement Date	2,267	$ 2,017
Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date	83,324
Fair value of plan assets at ending Measurement Date	80,385	$ 83,324
Equity Funds [Member] | Indianapolis Power And Light Company
Change in plan assets:
Fair value of plan assets at beginning Measurement Date
Fair value of plan assets at ending Measurement Date	$ 82,652
Sources of change in regulatory assets(1):
Percentage by asset category	14.00%
Equity Funds [Member] | Indianapolis Power And Light Company | Fair Value, Inputs, Level 1 [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date
Fair value of plan assets at ending Measurement Date	$ 2,267
Equity Funds [Member] | Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Change in plan assets:
Fair value of plan assets at beginning Measurement Date
Fair value of plan assets at ending Measurement Date	$ 80,385

XML

Benefit Plans (Information For Pension Plans With A Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Plan Assets	$ 590,800
Benefit obligation in excess of plan assets	(41,273)	$ (33,596)
Indianapolis Power And Light Company
Entity Information [Line Items]
Defined Benefit Plan, Pension Plan with Projected Benefit Obligation in Excess of Plan Assets, Projected Benefit Obligation	549,500
Benefit obligation in excess of plan assets	$ (41,273)	$ (33,596)

XML

Benefit Plans (Information For Pension Plans With An Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) $ in Millions	Dec. 31, 2023 USD ($)
Indianapolis Power And Light Company
Entity Information [Line Items]
Plan assets	$ 590.8

XML

Benefit Plans (Schedule Of Net Periodic Benefit Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 5,189	$ 8,949	$ 9,339
Interest cost	29,818	18,099	15,660
Expected return on assets	(33,107)	(35,656)	(41,815)
Defined Benefit Plan Amortization of prior service cost net of acceleration component of curtailment charge	2,172	2,589	2,944
Amortization of actuarial loss	6,145	2,424	5,529
Amortization of settlement loss	0	199	0
Net periodic benefit cost	10,217	(3,396)	(8,343)
Less: amounts capitalized	(1,689)	(316)	(771)
Amount charged to expense	$ 8,528	(3,080)	(7,572)
Expected return on plan assets	5.60%
Asset, Defined Benefit Pension Plan, Noncurrent	$ 41,273	33,611
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Service cost	5,189	8,949	9,339
Interest cost	29,818	18,099	15,660
Expected return on assets	(33,107)	(35,656)	(41,815)
Defined Benefit Plan Amortization of prior service cost net of acceleration component of curtailment charge	2,172	2,589	2,944
Amortization of actuarial loss	6,145	2,424	5,529
Amortization of settlement loss	0	199	0
Net periodic benefit cost	10,217	(3,396)	(8,343)
Less: amounts capitalized	1,689	(316)	(771)
Amount charged to expense	$ 8,528	$ (3,080)	$ (7,572)
Expected return on plan assets	5.60%	5.60%
Asset, Defined Benefit Pension Plan, Noncurrent	$ 41,273	$ 33,611
Pension Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.41%	2.83%	2.46%
Expected return on plan assets	5.60%	4.45%	5.05%
Pension Benefit [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.41%	2.83%	2.46%
Expected return on plan assets	5.60%	4.45%	5.05%
Supplemental Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.32%	2.62%	2.31%
Expected return on plan assets	6.45%	5.50%	3.60%
Supplemental Retirement Plan [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.32%	2.62%	2.31%
Expected return on plan assets	6.45%	5.50%	3.60%

XML

Benefit Plans (Schedule Of Asset Allocation Guidelines) (Details)	Dec. 31, 2023
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	13.50%
Equity Securities [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	13.50%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	86.50%
Debt Securities [Member] | Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	86.50%

XML

Benefit Plans (Schedule Of Fair Value Of Pension Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 590,819	$ 611,125	$ 820,684
Percentage by asset category	100.00%	100.00%
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 6,404	$ 6,480
Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	584,415	604,645
Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Percentage by asset category	0.00%	0.00%
Short-Term Investments [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Short-Term Investments [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	0	0
US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 117,397	$ 122,704
Percentage by asset category	20.00%	20.00%
US Government Debt Securities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 178	$ 420
US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	117,219	122,284
Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 82,652	$ 85,341
Percentage by asset category	14.00%	14.00%
Equity Funds [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,267	$ 2,017
Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	80,385	83,324
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 387,979	$ 400,291
Percentage by asset category	66.00%	66.00%
Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 1,168	$ 1,254
Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	386,811	399,037
Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 588,028	$ 608,336
Percentage by asset category	100.00%	100.00%
Defined Benefit Plan, Common Collective Trust | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 3,613	$ 3,691
Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	584,415	604,645
Indianapolis Power And Light Company
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 590,819	$ 611,125	$ 820,684
Percentage by asset category	100.00%	100.00%
Indianapolis Power And Light Company | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 6,404	$ 6,480
Indianapolis Power And Light Company | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	584,415	604,645
Indianapolis Power And Light Company | Short-Term Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Percentage by asset category	0.00%	0.00%
Indianapolis Power And Light Company | Short-Term Investments [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,791	$ 2,789
Indianapolis Power And Light Company | US Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 117,397	$ 122,704
Percentage by asset category	20.00%	20.00%
Indianapolis Power And Light Company | US Government Debt Securities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 178	$ 420
Indianapolis Power And Light Company | US Government Debt Securities [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	117,219	122,284
Indianapolis Power And Light Company | Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 82,652
Percentage by asset category	14.00%
Indianapolis Power And Light Company | Equity Funds [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 2,267
Indianapolis Power And Light Company | Equity Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	80,385
Indianapolis Power And Light Company | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 387,979	$ 400,291
Percentage by asset category	66.00%	66.00%
Indianapolis Power And Light Company | Fixed Income [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 1,168	$ 1,254
Indianapolis Power And Light Company | Fixed Income [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	386,811	399,037
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 588,028	$ 608,336
Percentage by asset category	100.00%	100.00%
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 3,613	$ 3,691
Indianapolis Power And Light Company | Defined Benefit Plan, Common Collective Trust | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of benefit plan assets	$ 584,415	$ 604,645

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Benefit Plans (Schedule Of Expected Benefit Payments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Entity Information [Line Items]
2016	$ 37,997
2017	38,794
2018	39,665
2019	40,085
2020	41,477
2021 through 2025 (in total)	$ 200,574
Expected return on plan assets	5.60%
Pension Benefit [Member]
Entity Information [Line Items]
Expected return on plan assets	5.60%	4.45%	5.05%
Indianapolis Power And Light Company
Entity Information [Line Items]
2016	$ 37,997
2017	38,794
2018	39,665
2019	40,085
2020	41,477
2021 through 2025 (in total)	$ 200,574
Expected return on plan assets	5.60%	5.60%
Indianapolis Power And Light Company | Pension Benefit [Member]
Entity Information [Line Items]
Expected return on plan assets	5.60%	4.45%	5.05%

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Equity (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Class of Stock [Line Items]
Ownership percentage by parent	82.35%
Equity contributions from AES		$ 253,000	$ 275,000
Equity contributions from shareholders	$ 0	253,000	275,000
Debt to Capitalization Ratio, Maximum	1
Interest Coverage Ratio	2.50
Interest Coverage Ratio, Minimum	1
Leverage Ratio	0.67
Payments of Ordinary Dividends, Common Stock	$ 104,287	101,986	131,476
Number of separate series of cumulative preferred stock	5
Total preferred stock dividends declared	$ 0	3,213
Equity Capital Contributions	208,300		226,500
Preferred Stock Redemption Premium	300
Limited Partners' Contributed Capital	79,300
$200M Term Loan Maturing June 2023
Class of Stock [Line Items]
Short-Term Bank Loans and Notes Payable	200,000
Indianapolis Power And Light Company
Class of Stock [Line Items]
Equity contributions from AES	$ 0	253,000	275,000
Debt to capitalization ratio	0.67
Debt to Capitalization Ratio, Maximum	1
Dividends, Common Stock, Cash	$ 140,200	127,200	155,700
Payments of Ordinary Dividends, Common Stock	$ 140,200	127,200	155,700
Number of separate series of cumulative preferred stock	5
Total preferred stock dividends declared	$ 3,200
Preferred Stock, Voting Rights	2
Equity Capital Contributions	$ 253,000	275,000
Preferred Stock, Redemption Amount		60,100
Dividends, Preferred Stock, Stock	0	3,200	3,200
Indianapolis Power And Light Company | $200M Term Loan Maturing June 2023
Class of Stock [Line Items]
Short-Term Bank Loans and Notes Payable	200,000
AES U.S. Investments [Member]
Class of Stock [Line Items]
Equity Capital Contributions	$ 208,300		226,500
AES U.S. Holdings, LLC [Member]
Class of Stock [Line Items]
Ownership Interest in Parent Company, Percent	85.00%
CDPQ [Member]
Class of Stock [Line Items]
Ownership Interest in Parent Company, Percent	15.00%
Equity Capital Contributions	$ 31,300		34,000
Equity Capital Contribution to IPALCO	44,700		48,500
AES US Holdings LLC
Class of Stock [Line Items]
Equity Capital Contributions	$ 177,000		192,500
Minimum [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock	4.00%
Minimum [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividend rate on preferred stock	4.00%
Maximum [Member]
Class of Stock [Line Items]
Dividend rate on preferred stock	5.65%
Maximum [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividend rate on preferred stock	5.65%
Additional Paid-in Capital [Member]
Class of Stock [Line Items]
Equity contributions from AES		253,000	275,000
Equity contributions from shareholders
Additional Paid-in Capital [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Equity contributions from AES	0	253,000	275,000
Retained Earnings [Member] | Indianapolis Power And Light Company
Class of Stock [Line Items]
Dividends, Common Stock, Cash	$ 140,200	127,200	155,700
Total preferred stock dividends declared		$ 3,213	$ 3,213

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Commitments and Contingencies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Entity Information [Line Items]
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations, Net	$ 933,500
Other Purchase Obligations, Net	409,100
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Less Than 1 Year	249,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations in Years 1 through 3	267,300
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Years 3 through 5	225,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations After Year 5	190,800
Other Purchase Obligations, After Year 5	1,100
Other Purchase Obligations Years 3 through 5	20,200
Other Purchase Obligations Years 1 through 3	32,800
Other Purchase Obligations Less than 1 Year	355,000.0
Other Assets, Noncurrent	1,120,591,000	$ 849,054,000
Civil penalty	1,525,000
Payments for Environmental Liabilities	5,000,000
Prepaid Implementation Costs for Software as a Service
Entity Information [Line Items]
Other Assets, Noncurrent	7,100,000	8,200,000
Indianapolis Power And Light Company
Entity Information [Line Items]
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations, Net	933,500
Other Purchase Obligations, Net	409,100
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Less Than 1 Year	249,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations in Years 1 through 3	267,300
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations Years 3 through 5	225,700
Coal, Gas, Purchased Power and Related Transportation Purchase Obligations After Year 5	190,800
Other Purchase Obligations, After Year 5	1,100
Other Purchase Obligations Years 3 through 5	20,200
Other Purchase Obligations Years 1 through 3	32,800
Other Purchase Obligations Less than 1 Year	355,000.0
Other Assets, Noncurrent	1,117,051,000	833,536,000
Civil penalty	1,525,000
Payments for Environmental Liabilities	5,000,000
Indianapolis Power And Light Company | Prepaid Implementation Costs for Software as a Service
Entity Information [Line Items]
Other Assets, Noncurrent	$ 7,100,000	$ 8,200,000

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Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Self-insured retention per occurrence	$ 5,000
Insurance expense	11,700	$ 9,500	$ 7,000
Prepaid insurance	7,500	3,400
Health coverage expense	19,000	25,200	23,700
Income taxes receivable	36,500	18,000
Deferred Compensation Arrangement with Individual, Compensation Expense	300	200	200
Billings from related party	7,400	5,700	4,300
Parent Loan Repayment	6,100
Service Company [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	73,800	60,300	58,400
Receivables from Related Party	25,600	2,100
Affiliated Entity
Related Party Transaction [Line Items]
Billings from related party	223,300
Ipalco Enterprises, Inc. [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	11,900	10,000	10,400
Indianapolis Power And Light Company
Related Party Transaction [Line Items]
Self-insured retention per occurrence	5,000
Insurance expense	11,700	9,500	7,000
Prepaid insurance	7,500	3,400
Health coverage expense	19,000	25,200	23,700
Income taxes receivable	5,100	6,700
Deferred Compensation Arrangement with Individual, Compensation Expense	300	200	200
Costs incurred by related party	11,900	10,000	10,400
Billings from related party	7,400	5,700	4,300
Indianapolis Power And Light Company | Service Company [Member]
Related Party Transaction [Line Items]
Costs incurred by related party	$ 73,600	$ 60,100	$ 58,200

XML

Business Segment Information (Details)	12 Months Ended
	Dec. 31, 2023 segment
Indianapolis Power And Light Company
Debt Instrument [Line Items]
Reportable segments	1

XML

Business Segment Information (Summary Of Company's Reporting Segments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132
Depreciation and amortization	287,863	266,504	256,085
Interest Expense	142,926	131,232	125,626
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	71,742	118,485	148,123
Property, Plant and Equipment, Additions	902,705	496,510	291,546
Tax benefit	14,715	21,859	28,941
Net income	57,027	96,626	119,182
TOTAL ASSETS	6,181,523	5,589,214	5,239,767
Accruals for capital expenditures	124,626	66,949	81,325
Financed Capital Expenditures	0	0	36
Electric [Member]
Segment Reporting Information [Line Items]
REVENUE	1,649,917	1,791,711	1,426,132
Depreciation and amortization	287,863	266,504	256,085
Interest Expense	99,051	87,428	84,256
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	115,763	162,862	189,548
Property, Plant and Equipment, Additions		496,510	291,546
TOTAL ASSETS	6,129,581	5,559,977	5,222,987
Other Segments [Member]
Segment Reporting Information [Line Items]
Depreciation and amortization	0	0	0
Interest Expense	43,875	43,804	41,370
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(44,021)	(44,377)	(41,425)
Property, Plant and Equipment, Additions	0	0	0
TOTAL ASSETS	$ 51,942	$ 29,237	$ 16,780

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Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,616,500			$ 1,760,000	$ 1,389,200
REVENUE	1,649,917	$ 1,791,711	$ 1,426,132
Contract with Customer, Asset, before Allowance for Credit Loss	218,800	198,300
Retail Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,546,041	1,589,170	1,351,431
Other non-606 revenue	30,414	29,171	35,248
Retail Revenue [Member] | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	14,016	17,845	16,785
Retail Revenue [Member] | Residential Revenue | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	660,559	688,487	595,692
Retail Revenue [Member] | Small Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	241,800	247,655	211,997
Retail Revenue [Member] | Large Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	619,899	625,351	518,069
Retail Revenue [Member] | Public Lighting | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,767	9,832	8,888
Wholesale Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	56,557	148,517	25,059
Miscellaneous revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	13,864	22,284	12,214
RTO Capacity Revenue	8,210	11,750	734
Other non-606 revenue	3,041	2,569	2,180
Miscellaneous revenue [Member] | Transmission revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,654	10,534	11,480
Electricity [Member]
Disaggregation of Revenue [Line Items]
REVENUE	1,649,917	1,791,711	1,426,132
Indianapolis Power And Light Company
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,616,500	1,760,000	1,389,200
REVENUE	1,649,917	1,791,711	1,426,132
Contract with Customer, Asset, before Allowance for Credit Loss				$ 218,800		$ 198,300
Indianapolis Power And Light Company | Retail Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,546,041	1,589,170	1,351,431
Other non-606 revenue	30,414	29,171	35,248
Indianapolis Power And Light Company | Retail Revenue [Member] | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	14,016	17,845	16,785
Indianapolis Power And Light Company | Retail Revenue [Member] | Residential Revenue | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	660,559	688,487	595,692
Indianapolis Power And Light Company | Retail Revenue [Member] | Small Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	241,800	247,655	211,997
Indianapolis Power And Light Company | Retail Revenue [Member] | Large Commercial and Industrial | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	619,899	625,351	518,069
Indianapolis Power And Light Company | Retail Revenue [Member] | Public Lighting | Utility
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,767	9,832	8,888
Indianapolis Power And Light Company | Wholesale Revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	56,557	148,517	25,059
Indianapolis Power And Light Company | Miscellaneous revenue [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	13,864	22,284	12,214
RTO Capacity Revenue	8,210	11,750	734
Other non-606 revenue	3,041	2,569	2,180
Indianapolis Power And Light Company | Miscellaneous revenue [Member] | Transmission revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,654	10,534	11,480
Indianapolis Power And Light Company | Electricity [Member]
Disaggregation of Revenue [Line Items]
REVENUE	$ 1,649,917	$ 1,791,711	$ 1,426,132

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Leases (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Lessee, Lease, Description [Line Items]

Property Subject to or Available for Operating Lease, Accumulated Depreciation

$ (1,222)

$ (1,060)

Property, Plant, and Equipment, Lessor Asset under Operating Lease, after Accumulated Depreciation

3,119

3,274

Property Subject to or Available for Operating Lease, Gross

4,341

4,334

Lessor, Operating Lease, Payment to be Received, Year One

544

Lessor, Operating Lease, Payment to be Received, Year Two

553

Lessor, Operating Lease, Payment to be Received, Year Three

554

Lessor, Operating Lease, Payment to be Received, Year Four

554

Lessor, Operating Lease, Payment to be Received, Year Five

354

Lessor, Operating Lease, Payment to be Received, after Year Five

$ 891

Future Minimum Lease Receipts

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

Operating Lease, Lease Income

$ 1,537

1,134

$ 1,439

Lessor, Operating Lease, Payments to be Received

3,450

Finance Lease, Liability, Noncurrent

17,769

16,361

Finance Lease, Liability

$ 17,769

$ 16,361

Finance Lease, Weighted Average Remaining Lease Term

35 years

36 years

Finance Lease, Weighted Average Discount Rate, Percent

5.30%

5.65%

Finance Lease, Liability, to be Paid, Next Rolling 12 Months

$ 891

Finance Lease, Liability, Payments, Due in Rolling Year Two

909

Finance Lease, Liability, to be Paid, Year Three

927

Finance Lease, Liability, to be Paid, Year Four

945

Finance Lease, Liability, to be Paid, Year Five

965

Finance Lease, Liability, to be Paid, after Year Five

39,958

Total Future Lease Payments

44,595

Imputed interest

(26,826)

Finance Lease, Right-of-Use Asset, Amortization

445

$ 542

0

Finance Lease, Interest Expense

933

782

0

Lease, Cost

1,378

1,324

0

Operating Lease, Payments, Use

600

300

0

Finance Lease, Right-of-Use Asset, before Accumulated Amortization

16,357

15,819

Subsidiaries [Member]

Lessee, Lease, Description [Line Items]

Property Subject to or Available for Operating Lease, Accumulated Depreciation

1,222

1,060

Property, Plant, and Equipment, Lessor Asset under Operating Lease, after Accumulated Depreciation

3,119

3,274

Property Subject to or Available for Operating Lease, Gross

4,341

4,334

Lessor, Operating Lease, Payment to be Received, Year One

544

Lessor, Operating Lease, Payment to be Received, Year Two

553

Lessor, Operating Lease, Payment to be Received, Year Three

554

Lessor, Operating Lease, Payment to be Received, Year Four

554

Lessor, Operating Lease, Payment to be Received, Year Five

354

Lessor, Operating Lease, Payment to be Received, after Year Five

$ 891

Future Minimum Lease Receipts

The following table shows the future minimum lease receipts through 2028 and thereafter (in thousands):

	Operating Leases
2024	$	544
2025	553
2026	554
2027	554
2028	354
Thereafter	891
Total	$	3,450

Operating Lease, Lease Income

$ 1,537

1,134

1,439

Lessor, Operating Lease, Payments to be Received

3,450

Finance Lease, Liability, Noncurrent

17,769

16,361

Finance Lease, Liability

$ 17,769

$ 16,361

Finance Lease, Weighted Average Remaining Lease Term

35 years

36 years

Finance Lease, Weighted Average Discount Rate, Percent

530.00%

565.00%

Finance Lease, Liability, to be Paid, Remainder of Fiscal Year

$ 891

Finance Lease, Liability, Payments, Due in Rolling Year Two

909

Finance Lease, Liability, to be Paid, Year Three

927

Finance Lease, Liability, to be Paid, Year Four

945

Finance Lease, Liability, to be Paid, Year Five

965

Finance Lease, Liability, to be Paid, after Year Five

39,958

Total Future Lease Payments

44,595

Imputed interest

(26,826)

Finance Lease, Right-of-Use Asset, Amortization

445

$ 542

0

Finance Lease, Interest Expense

933

782

0

Lease, Cost

1,378

1,324

$ 0

Operating Lease, Payments, Use

600

Finance Lease, Right-of-Use Asset, before Accumulated Amortization

$ 16,357

$ 15,819

XML

Schedule I - Condensed Financial Information Of Registrant (Narrative) (Details) MWh in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Condensed Financial Statements, Captions [Line Items]
Equity contributions from AES		$ 253,000	$ 275,000
Ownership percentage by parent	82.35%
Equity contributions from shareholders	$ 0	253,000	275,000
Investments, Fair Value Disclosure	3,552	3,228
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	19,234	22,945
Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	1,388	7,545
Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	3,552	3,228
Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	14,294	12,172
Mutual Fund [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Money Market Funds [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	127	5
Ipalco Enterprises, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Equity contributions from AES		253,000
Equity contributions from shareholders	0	253,000	275,000
Investments, Fair Value Disclosure	3,552	3,228
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	17,846	15,400
Ipalco Enterprises, Inc. [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure		0
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	0	0
Ipalco Enterprises, Inc. [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,552	3,228
Forward Power Contracts Fair Value Disclosure	0	0
Total financial assets measured at fair value	3,552	3,228
Ipalco Enterprises, Inc. [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Forward Power Contracts Fair Value Disclosure	14,294	12,172
Total financial assets measured at fair value	14,294	12,172
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	3,425	3,223
Ipalco Enterprises, Inc. [Member] | Mutual Fund [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	127	5
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	127	5
Ipalco Enterprises, Inc. [Member] | Money Market Funds [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0	0
Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Equity contributions from AES	0	253,000	$ 275,000
Total financial assets measured at fair value	1,388	7,545
Subsidiaries [Member] | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	1,388	7,545
Subsidiaries [Member] | Fair Value, Inputs, Level 1 [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	0	0
Subsidiaries [Member] | Significant Observable Inputs (Level 2) [Member]
Condensed Financial Statements, Captions [Line Items]
Total financial assets measured at fair value	0	$ 0
Parent | Unobservable Inputs (Level 3) [Member]
Condensed Financial Statements, Captions [Line Items]
Investments, Fair Value Disclosure	0
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Derivative Instruments Interest Rate Swap	400,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Ipalco Enterprises, Inc. [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Derivative Instruments Interest Rate Swap	400,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	$ 400,000
FTR [Member] | Not Designated as Hedging Instrument [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
FTR [Member] | Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919

XML

Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 28,579	$ 201,548
Total current assets	574,030	706,829
Derivative Asset, Noncurrent	0	12,172
Total other non-current assets	1,120,591	849,054
TOTAL ASSETS	6,181,523	5,589,214	$ 5,239,767
Short-term debt	899,159	0
Accounts payable	292,851	189,845
Accumulated deficit	25,182	(108)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,129,722	1,090,518
Total common shareholder's deficit	1,076,468	1,090,518	794,600	$ 520,988
Long-term debt	2,558,420	3,000,450
Deferred Income Taxes and Other Tax Liabilities, Noncurrent	18,931	7,329
Accrued interest	33,639	33,447
Total current liabilities	1,328,455	323,225
Total non-current liabilities	3,723,346	4,175,471
Liabilities	5,051,801	4,498,696
Additional Paid in Capital	1,021,992	1,068,357
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294	22,269	(29,407)	(43,420)
TOTAL LIABILITIES AND EQUITY	6,181,523	5,589,214
Restricted Cash and Cash Equivalents	5	5
Income Taxes Receivable, Current	36,481	18,000
Other Assets, Current	26,358	19,882
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	537	191
Total current assets	53,798	19,018
Investment in subsidiaries	1,921,548	1,945,556
Other Assets	3,540	3,211
Total other non-current assets	1,925,088	1,960,939
TOTAL ASSETS	1,978,886	1,979,957
Short-term debt	404,474	0
Accounts payable	0	87
Accumulated deficit	25,182	(108)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,076,468	1,090,518	794,600	520,988
Long-term debt	470,127	873,663
Accrued interest	8,360	8,360
Total current liabilities	412,834	8,447
Total non-current liabilities	489,584	880,992
Liabilities	902,418	889,439
Additional Paid in Capital	1,021,992	1,068,357
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294	22,269	$ (29,407)	$ (43,420)
TOTAL LIABILITIES AND EQUITY	1,978,886	1,979,957
Income Taxes Receivable, Current	14,294	0
Other Assets, Current	$ 7,626	$ 7,509

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Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements Of Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Financial Statements, Captions [Line Items]
Interest Expense	$ (142,926)	$ (131,232)	$ (125,626)
Other (expense) / income, net	(410)	11,783	17,667
Total other expense, net	(134,021)	(114,665)	(102,547)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	71,742	118,485	148,123
Income tax expense	14,715	21,859	28,941
Net income	57,027	96,626	119,182
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Equity in earnings of subsidiaries	116,190	126,466	147,030
Interest Expense	(43,877)	(43,805)	(41,380)
Other (expense) / income, net	(121)	(571)	(45)
Total other expense, net	72,192	82,090	105,605
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	72,192	82,090	105,605
Income tax expense	(10,928)	(11,027)	(10,364)
Net income	$ 83,120	$ 93,117	$ 115,969

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Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Financial Statements, Captions [Line Items]
Net income	$ 57,027	$ 96,626	$ 119,182
Amortization of debt issuance costs and discounts	(3,880)	(3,914)	(3,915)
Increase (Decrease) in Accounts Payable	46,993	32,038	21,417
Accrued taxes payable/receivable	(18,375)	(5,858)	638
Other - net	(4,268)	5,335	(2,026)
Distributions to shareholders	104,287	101,986	131,476
Equity contributions from shareholders	0	253,000	275,000
Other - net	313	35	131
Net change in cash, cash equivalents and restricted cash	(172,969)	194,636	(19,705)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	28,584	201,553	6,917	$ 26,622
Interest Paid, Excluding Capitalized Interest, Operating Activities	129,113	115,277	118,052
Income Taxes Paid, Net	0	31,000	27,500
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Net income	83,120	93,117	115,969
Equity in earnings of subsidiaries	(116,190)	(126,466)	(147,030)
Cash dividends received from subsidiary companies	140,200	127,200	155,700
Amortization of debt issuance costs and discounts	(1,474)	(1,403)	(1,379)
Deferred income taxes - net	9,276	(121)	(5)
Increase (Decrease) in Accounts Payable	(23)	(194)	(85)
Accrued taxes payable/receivable	(20,022)	(2,406)	2,940
Other - net	6,798	7,744	4,265
Net cash provided by operating activities	104,633	100,277	133,133
Investment in subsidiaries	0	(253,000)	(275,000)
Net cash used in investing activities	0	(253,000)	(275,000)
Repayments of Loans to Subsidiary	0	0	6,110
Distributions to shareholders	104,287	101,986	(131,476)
Equity contributions from shareholders	0	253,000	275,000
Other - net	0	2	62
Net cash provided by financing activities	(104,287)	151,012	137,352
Net change in cash, cash equivalents and restricted cash	346	(1,711)	(4,515)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	537	191	1,902	$ 6,417
Interest Paid, Excluding Capitalized Interest, Operating Activities	35,569	35,173	35,172
Income Taxes Paid, Net	$ 0	$ 31,000	$ 27,500

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Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements Of Common Shareholders' Equity (Deficit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	$ 7,025	$ 51,676	$ 14,013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,090,518
Net income / (loss)	83,120	93,117	115,969
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Distributions to AES	(104,287)	(101,986)	(131,476)
Equity contributions from shareholders	0	253,000	275,000
Other	92	111	106
Ending Balance	1,129,722	1,090,518
Contributions from shareholders		253,000	275,000
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,090,518	794,600	520,988
Net income / (loss)	83,120	93,117	115,969
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Distributions to AES	104,287	101,986	131,476
Equity contributions from shareholders	0	253,000	275,000
Other	92	111	106
Ending Balance	1,076,468	1,090,518	794,600
Net cash used in investing activities	0	(253,000)	(275,000)
Contributions from shareholders		253,000
Subsidiaries [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,943,710
Net income / (loss)	116,190	126,466	147,030
Other	92	114	107
Ending Balance	1,973,046	1,943,710
Contributions from shareholders	0	253,000	275,000
Paid In Capital [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Return of Capital	(46,500)	(33,300)	(15,500)
Equity contributions from shareholders
Other	92	111	106
Contributions from shareholders		253,000	275,000
Paid In Capital [Member] | Parent Company [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	1,068,357	848,565	588,966
Return of Capital	(46,457)	(33,319)	(15,507)
Other	92	111	106
Ending Balance	1,021,992	1,068,357	848,565
Contributions from shareholders		253,000
Paid In Capital [Member] | Subsidiaries [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other	92	114	107
Contributions from shareholders	0	253,000	275,000
AOCI Attributable to Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
AOCI Attributable to Parent [Member] | Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	22,269	(29,407)	(43,420)
Ending Balance	29,294	22,269	(29,407)
Accumulated Deficit [Member]
Condensed Financial Statements, Captions [Line Items]
Other Comprehensive Income (Loss), Net of Tax	0	0	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income / (loss)	83,120	96,626	119,182
Distributions to AES	(57,830)	(68,667)	(115,969)
Accumulated Deficit [Member] | Parent Company [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning Balance	(108)	(24,558)	(24,558)
Net income / (loss)	83,120	93,117	115,969
Distributions to AES	57,830	68,667	115,969
Ending Balance	$ 25,182	$ (108)	$ (24,558)

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Schedule I - Condensed Financial Information Of Registrant (Long-Term Indebtedness) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Condensed Financial Statements, Captions [Line Items]
Unamortized discount - net	$ (6,768)
Debt Issuance Costs, Net	(23,612)
Long-term debt	3,003,420	$ 3,000,450
Current portion of long-term debt	445,000	0
Net Long-term Debt	2,558,420	3,000,450
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Unamortized discount - net	(319)	(425)
Debt Issuance Costs, Net	(4,554)	(5,912)
Debt, Long-Term and Short-Term, Combined Amount	875,127	873,663
Long-term debt	470,653	873,663
Current portion of long-term debt	405,000	0
Net Long-term Debt	470,127	873,663
Parent Company [Member] | Three Point Seven Zero Percent Senior Secured Notes [Domain]
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 405,000	405,000
Debt, stated interest rate	3.70%
Parent Company [Member] | Four Point Two Five Percent Senior Secured Notes
Condensed Financial Statements, Captions [Line Items]
Long-term debt	$ 475,000	$ 475,000
Debt, stated interest rate	4.25%

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Schedule I - Condensed Financial Information Of Registrant Schedule I - Condensed Financial Information Of Registrant (Unconsolidated Statements of Comprehensive Income/(Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ 83,120	$ 93,117	$ 115,969
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594	46,245	10,393
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528)	(15,309)	(3,441)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,798)	(1,199)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	5,431	3,620
Dividends on and redemption of preferred stock	0	3,509	3,213
Parent Company [Member]
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	83,120	93,117	115,969
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594	46,245	10,393
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	7,025	51,676	14,013
Other Comprehensive Income (Loss), Net of Tax	7,025	51,676	14,013
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	90,145	144,793	129,982
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	(528)	(15,309)	(3,441)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	(1,798)	(1,798)	(1,199)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	5,431	5,431	3,620
Subsidiaries [Member]
Condensed Statement of Income Captions [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	116,190	126,466	147,030
Dividends on and redemption of preferred stock	$ 0	$ 3,509	$ 3,213

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Schedule I - Condensed Financial Information Of Registrant Schedule I - Condensed Financial Information Of Registrant (Derivative Instruments and Hedging Activities) (Details) MWh in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MWh	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Number of Interest Rate Swaps	3
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	$ 1,594,000	$ 46,245,000	$ 10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	29,294,000	22,269,000	(29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Not Designated as Hedging Instrument [Member] | FTR [Member]
Purchase of Units Derivative Instruments Financial Transmission Rights | MWh	3,919
Sale of Units Derivative Instruments Financial Transmission Rights | MWh	0
Derivative, Nonmonetary Notional Amount, Purchase (Sales), Net | MWh	3,919
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	$ 400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Derivative Liability, Current
Derivative Liability, Fair Value, Gross Liability	0	12,172,000
Parent Company [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	1,594,000	46,245,000	10,393,000
Accumulated Other Comprehensive Income (Loss), Net of Tax	29,294,000	22,269,000	(29,407,000)	$ (43,420,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1,594,000	46,245,000	10,393,000
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	5,431,000	5,431,000	3,620,000
Parent Company [Member] | Interest Rate Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	29,294,000	22,269,000	$ (29,407,000)
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	$ (5,375)
Maximum Length of Time Hedged in Cash Flow Hedge	9 years
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Purchase of Derivative Instruments Interest Rate Swap	$ 400,000,000
Sale of Derivative Instruments Interest Rate Swap	0
Derivative, Notional Amount, Purchase (Sales), Net	400,000,000
Parent Company [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Derivative Liability, Current
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 12,172,000,000

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Schedule I - Condensed Financial Information Of Registrant (Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Apr. 08, 2020
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	$ 19,234	$ 22,945
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	19,234	22,945
Face Value	3,488,800	3,033,800
Fair Value	3,315,467	2,775,644
Long-term debt	3,003,420	3,000,450
Deferred financing costs, net	23,612
Unamortized discounts	6,768
Interest Rate Swap [Member]
Accumulated Other Income (Loss)			$ 72,300
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Fixed Rate [Member]
Face Value	3,033,800	3,033,800
Fair Value	2,860,467	2,775,644
Variable Rate [Member]
Face Value	455,000	0
Fair Value	455,000	0
Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	17,846	15,400
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	17,846	15,400
Face Value	880,000	880,000
Fair Value	839,471	816,411
Long-term debt	470,653	873,663
Deferred financing costs, net	4,554	5,912
Unamortized discounts	319	425
Parent Company [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative, Notional Amount, Purchase (Sales), Net	400,000
Parent Company [Member] | Fixed Rate [Member]
Face Value	880,000	880,000
Fair Value	$ 839,471	816,411
Parent Company [Member] | Four Point Two Five Percent Senior Secured Notes
Debt instrument, stated interest rate	4.25%
Long-term debt	$ 475,000	475,000
Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Face Value	2,608,800	2,153,800
Fair Value	2,475,997	1,959,233
Long-term debt	2,128,293	2,126,787
First mortgage bonds	2,128,293	2,126,787
Deferred financing costs, net	20,200	20,400
Unamortized discounts	6,449	6,651
Subsidiaries [Member] | Fixed Rate [Member]
Face Value	2,153,800	2,153,800
Fair Value	2,020,997	1,959,233
Subsidiaries [Member] | Variable Rate [Member]
Face Value	455,000	0
Fair Value	455,000	0
Unamortized discounts	$ (6,400)	6,700
Subsidiaries [Member] | FMB Twenty - three
Debt instrument, stated interest rate	0.95%
First mortgage bonds	$ 60,000	60,000
Fair Value, Inputs, Level 1 [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	3,552	3,228
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	3,552	3,228
Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	3,552	3,228
Investments, Fair Value Disclosure	3,552	3,228
Total financial assets measured at fair value	3,552	3,228
Fair Value, Inputs, Level 1 [Member] | Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	0	0
Total financial assets measured at fair value	0	0
Significant Observable Inputs (Level 2) [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	14,294	12,172
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	14,294	12,172
Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	14,294	12,172
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	14,294	12,172
Significant Observable Inputs (Level 2) [Member] | Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	0	0
Total financial assets measured at fair value	0	0
Unobservable Inputs (Level 3) [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	1,388	7,545
Investments, Fair Value Disclosure	0	0
Total financial assets measured at fair value	1,388	7,545
Unobservable Inputs (Level 3) [Member] | Parent Company [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	0	0
Investments, Fair Value Disclosure		0
Total financial assets measured at fair value	0	0
Unobservable Inputs (Level 3) [Member] | Subsidiaries [Member]
Condensed Financial Information Disclosure [Abstract]
Total financial assets measured at fair value	1,388	7,545
Total financial assets measured at fair value	1,388	7,545
Money Market Funds [Member]
Investments, Fair Value Disclosure	127	5
Money Market Funds [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	127	5
Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	127	5
Money Market Funds [Member] | Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	0
Money Market Funds [Member] | Unobservable Inputs (Level 3) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	0
Mutual Fund [Member]
Investments, Fair Value Disclosure	3,425	3,223
Mutual Fund [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	3,425	3,223
Mutual Fund [Member] | Fair Value, Inputs, Level 1 [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	3,425	3,223
Mutual Fund [Member] | Significant Observable Inputs (Level 2) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	0	0
Mutual Fund [Member] | Unobservable Inputs (Level 3) [Member] | Parent Company [Member]
Investments, Fair Value Disclosure	$ 0	$ 0

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Schedule II - Valuation And Qualifying Accounts And Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	$ 1,117	$ 647	$ 3,155
Charged to Income	8,930	7,478	3,940
Net Write-offs	7,764	7,008	6,448
Balance at End of Period	2,283	1,117	647
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	0
SEC Schedule, 12-09, Reserve, Inventory
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	5,160	3,107	6,133
Charged to Income	736	2,053	758
Net Write-offs	2,456	0	3,784
Balance at End of Period	3,440	5,160	3,107
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	0
Indianapolis Power And Light Company | SEC Schedule, 12-09, Allowance, Credit Loss [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	1,117	647	3,155
Charged to Income	8,930	7,478	3,940
Net Write-offs	7,764	7,008	6,448
Balance at End of Period	2,283	1,117	647
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	0	0	0
Indianapolis Power And Light Company | SEC Schedule, 12-09, Reserve, Inventory
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at beginning of period	5,160	3,107	6,133
Charged to Income	736	2,053	758
Net Write-offs	2,456	0	3,784
Balance at End of Period	3,440	5,160	3,107
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Other Account	$ 0	$ 0	$ 0